3rd Quarter Results

Third Quarter Key Points

· Earnings down 4% to $1.1 billion; total operating profit 15% lower at $1.8 billion

· Production down 10%; reduced activity in the US, declines in Egypt and planned shutdowns

· Further progress with 2013 milestones; Margarita Phase 2 and Bongkot North Phase 3K now onstream

· QCLNG entering commissioning phase; entire export pipeline in the ground with testing underway

· Excellent flow rates from FPSOs 1, 2 and 3 in Brazil; gross production around 160 000 boed

· Good progress with portfolio management; agreed sale of US midstream assets, Quintero LNG disposal

· Egyptian domestic offtake higher in Q3; business environment remains difficult

a) 2012 results have been restated to reflect the presentation of the majority of the businesses that comprised the Transmission & Distribution segment as discontinued operations and the adoption of the amended IAS 19 in respect of defined benefit pension obligations (see note 1 page 19).

b) 'Business Performance' excludes disposals, certain re-measurements and impairments as exclusion of these items provides a clear and consistent presentation of the underlying operating performance of the Group's ongoing business. In 2012, total results for the nine months included a pre-tax charge of $1.8 billion (post-tax$1.3 billion) as a result of the impairment of certain assets associated with the shale gas business in the USA. For further information see Presentation of Non-GAAP measures (page 11) and notes 1 to 3 (pages 19 to 22). Unless otherwise stated, the results discussed in this release relate to BG Group's Business Performance.

BG Group's Chief Executive Chris Finlayson said:

"Earnings in the quarter were down 4% to $1.1 billion, largely as a result of lower volumes in both the Upstream and LNG segments. The primary driver for the decline in Upstream volumes is the US, where BG Group has reduced its rig count in line with its strategy of pursuing value over volume. We will see production recover in the fourth quarter with the completion of our North Sea maintenance shutdowns and new projects coming onstream, most notably Jasmine."

Chris continued: "Our current priority is execution: the delivery of our 2013 milestones and of our growth projects. I am very pleased with our progress in Australia where we are moving into the commissioning stages. Gas has already flowed into the collection header system, and the main export pipeline is now in the ground withhydro-testing underway. Construction of the Ruby Jo compression stations and the processing plant is progressing well, ahead of commissioning in December. We expect to flow first gas to the plant around the end of the year. We are on track to deliver the world's first coal seam gas to LNG project on schedule and within the $20.4 billion budget.

"In Brazil, well performance from the Santos Basin continues to exceed expectations. The first three FPSOs have produced around 160 000 boed gross in the quarter, with each well on FPSOs 2 and 3 producing more than30 000 boed gross. The buoyancy supported risers required for new wells to be hooked up to FPSOs 2 and 3 are all in country, with installation of the first unit underway after recent weather delays. The next two FPSOs to be deployed in the Santos Basin are on budget and expected to begin operations in 2014.

"The third quarter also saw us continuing to deliver our milestones with the successful start-up of the Margarita Phase 2 and Bongkot Phase 3K projects in Bolivia and Thailand respectively. The facilities at Itaú in Bolivia are complete, with start-up now expected in the fourth quarter. In the UK, an extensive planned maintenance programme is nearing completion with only the Lomond platform left to re-start in the coming weeks, and the Jasmine field is in the final stages of commissioning."

With regard to Egypt, Chris noted: "The business environment remains difficult. During the third quarter,domestic offtake was higher than expected, averaging almost 1 bcf of gas per day, which was partially offset by receipt of compensatory LNG cargoes from Qatar. In October, domestic gas offtake reduced, with current rates at 700 to 750 mmscfd. The Egyptian government has stated that the domestic offtake will remain around this level during the final quarter. Further assurances regarding future domestic offtake levels and a material improvement in the outstanding debt position are required before releasing funds for the next phase of development."

Chris said: "Our strategy is driven by our world-class exploration and our unique LNG model. In Tanzania, the Pweza-3 drill stem test demonstrated that development wells could flow at significantly higher rates than expected, indicating that the Pweza reservoir has the potential to be the most prolific among our Tanzanian discoveries, reducing the likely well count and development costs.

"We are currently advancing four new LNG supply projects, and as the projects mature we will look for opportunities to manage our capital commitments through partnering. Working with the Block 2 partners in Tanzania, we have submitted our proposal for the LNG plant site for consideration by the government. Additionally, we made good progress with the Lake Charles LNG export project where the Department ofEnergy gave conditional approval for exports to non-free trade agreement countries and where we signed an agreement with Energy Transfer to develop the terminal."

Chris added: "We continued to demonstrate our commitment to more active portfolio management with deals which will generate some $400 million of cash consideration from the disposal of our remaining 20% interest in the Quintero LNG terminal and the signing of a sales agreement for our entire 50% equity holding in TGGT."

In conclusion, Chris said: "As we enter the final quarter, we remain focused on execution. I also look forward to welcoming Simon Lowth on 2 December as BG Group's Chief Financial Officer and Executive Director."

Business Review - Group

a) See note 1 (page 19).

b) Includes capital investment relating to discontinued operations for the quarter of $nil (2012 $85 million) and for the nine months of $10 million (2012 $246 million).

Third quarter

Revenue and other operating income decreased 6% to $4 397 million, reflecting a 10% decrease in E&P production volumes and fewer LNG cargo deliveries, partly offset by favourable changes in the product mix.

Total operating profit decreased 15% to $1 773 million, reflecting the lower volumes combined with higher operating costs and depreciation in the Upstream segment.

Net finance costs of $63 million included foreign exchange losses of $24 million (2012 net finance costs of $42 million included foreign exchange losses of $18 million).

The tax charge for the quarter reflects a reduction in the Group's 2013 effective tax rate (including BG Group's share of joint venture and associates' tax) to 42% from previous guidance of 44% (2012: 44.5%). The reduction comprised 1% from the revision of opening deferred tax balances following changes to UK taxation rates enacted in the quarter, and 1% from a change in the expected mix of profits.

Cash generated by operations decreased 25% to $2 036 million as a result of reduced operating profits and a higher working capital cash outflow, including an increase in LNG and oil cargoes in transit and higher receivables in Egypt. Working capital in the third quarter of 2012 also benefitted from higher margin inflows in relation to the Group's hedged LNG contracts.

As at 30 September 2013, the Group's net debt was $13 001 million and the gearing ratio was 27.6%. The average maturity of the Group's gross borrowings was around 16 years.

Capital investment (excluding acquisitions and on a cash basis) of $2 792 million was almost entirely in the Upstream segment ($2 787 million). This investment was focused primarily on the Group's major projects in Australia, Brazil, Egypt and the UK. Further details on project developments are provided in the third quarter business highlights section. 

Nine months

Revenue and other operating income decreased 4% to $13 675 million, reflecting fewer LNG cargo deliveries and lower E&P production volumes, partly offset by reduced hedging losses in the LNG Shipping & Marketing business.

Total operating profit decreased 8% to $5 708 million, reflecting the decrease in revenue and other operating income combined with higher operating costs and depreciation in the Upstream segment.

Net finance costs of $124 million included foreign exchange losses of $1 million (2012 net finance costs of $91 million included foreign exchange losses of $9 million and $21 million of interest received on tax refunds).

Cash generated by operations decreased 11% to $7 542 million reflecting the combined result of the decrease in operating profit and adverse working capital movements, including the effect of lower margin inflows on the Group's hedged LNG contracts and an increase in LNG and oil cargoes in transit.

Capital investment (excluding acquisitions and on a cash basis) of $8 032 million was almost entirely in the Upstream segment ($8 005 million). This investment was focused primarily on the Group's major projects in Australia, Brazil,the UK and Egypt. Further details on project developments are provided in the third quarter business highlights section.

Disposals, re-measurements and impairments 

Total results included a pre-tax gain of $236 million ($160 million post-tax; 2012 pre-tax gain $132 million, $99 million post-tax) for the third quarter in respect of disposals, re-measurements and impairments, and a pre-tax charge of $5 million for the nine months ($32 million post-tax gain; 2012 pre-tax charge $1 243 million, $996 million post-tax).The results for the nine months of 2012 included a $1 800 million pre-tax ($1 295 million post-tax) impairment of certain assets associated with the shale gas business in the USA. For further information see Presentation of Non-GAAP measures (page 11) and notes 1 to 3 (pages 19 to 22).

Third quarter business highlights

Australia

The Queensland Curtis LNG (QCLNG) project remains on schedule for first gas to the liquefaction plant around the end of the year and first LNG in 2014, within the project's Phase 1 $20.4 billion budget.

Following the completion of hydro-testing, gas flowed from the Kenya central processing plant (CPP) into the gas collection header system in August, while the Narrows Crossing has also now been completed. Testing of the entire export pipeline is underway with commissioning to follow.

Elsewhere in the upstream, three of six planned field compression stations (FCSs) and the one CPP in the Ruby Jo block are expected to begin commissioning in December. Meanwhile, 225 new wells were drilled taking the total at the end of the third quarter to more than 1 700. Additionally, all major contracts for Phase 1 have now been awarded, including the remaining field compression infrastructure contract in the Surat Basin.

The extensive exploration and appraisal programme continues, with production testing of two pilot coal seam gas wells in the Bowen Basin commencing and a seismic survey of the Bowen Basin deep gas sands having started in August. Additionally, the first of a four-well Cooper Basin programme, targeting shale gas and tight gas sands, started in September.

Bolivia

First gas from the Margarita Phase 2 development was achieved almost four weeks ahead of schedule and under budget. This increased total production capacity at Margarita from around 25 000 barrels of oil equivalent per day (boed) to around 42 000 boed, net to BG Group.

At the Itaú development, the central processing facility was completed. Net production capacity will be raised from around 3 000 boed to approximately 10 000 boed by the end of the year with the connection of two new wells.The facility was previously expected to come onstream in the third quarter.

Brazil

Gross production from the three installed floating production, storage and offloading (FPSO) vessels in the Santos Basin continued to exceed expectations at around 160 000 boed in the quarter, with each well on FPSOs 2 and 3 producing more than 30 000 boed. All four buoyancy supported risers (BSR) needed for FPSOs 2 and 3 are in Brazil. Installation of the first unit is underway following recent adverse weather delays, and is expected to be completed in the fourth quarter, with the second BSR to follow. As a result, the connection of new producing wells on both FPSOs 2 and 3 is now expected during the first quarter of 2014.

The next two FPSOs, to be deployed on Sapinhoá and Iracema in 2014, are on budget and around 80% and 70% complete respectively. FPSO 5 is already in Brazil for topsides integration, with FPSO 4 due to depart China in November. The consortium partners signed a contract for construction of a ninth leased FPSO, to be deployed on the Carioca discovery on BM-S-9 in 2016. This FPSO will have capacity of 100 000 barrels of oil per day.

Drilling performance for development wells continued to improve. The average spud-to-target-depth in 2013 is around 57 days, down from 69 in 2012, providing further cost savings.

In September, the National Agency of Petroleum, Natural Gas and Biofuels (ANP) approved the consortium's request to submit a Declaration of Commerciality (DoC) for the giant Iara discovery in December 2014, allowing for further appraisal to optimise development planning. There is no change to the expected first oil date in 2017.

Egypt

During the third quarter, domestic offtake from the West Delta Deep Marine (WDDM) development averaged close to the technical maximum of approximately 1 billion cubic feet of gas per day. The Egyptian LNG plant continued to operate throughout the quarter, but at lower than planned levels. Five Qatari cargoes, with two allocated to BG Group, were lifted as expected as partial compensation for the shortfall in export gas.

Third quarter business highlights continued

Egypt continued

In October, domestic gas offtake reduced with current rates at 700 to 750 million standard cubic feet of natural gas per day (mmscfd). The Group has received assurances from Egyptian authorities that this offtake level will continue through the fourth quarter. However, BG Group also requires assurances regarding future domestic offtake and a material improvement in the outstanding debt position before releasing funds for the next phase of development.

BG Group continues to closely monitor the repayment of the receivables balance in respect of domestic gas sales. As at 30 September 2013, the Group's receivable balance from Egypt General Petroleum Corporation was $1.4 billion, an increase of $0.1 billion from the end of the second quarter, although partial payments have continued to be made to the Group. The overdue balance increased by $0.1 billion to $0.7 billion. The recovery of receivables and the full realisation of the carrying value of the Group's Egyptian operations remain dependent on the business environment in Egypt.

As announced in September, ongoing civil unrest has delayed expected first gas from the Phase 9a development of the WDDM concession to later in 2014. Operation of the Rosetta and WDDM production facilities, along with the drilling of the Notus exploration well, have not been materially affected.

Upstream and LNG activities in Egypt are expected to account for around 18% of the Group's production and around 14% of earnings from continuing operations in 2013. The current book value of BG Group's investment in Egypt, including receivables, represents around 12% of the Group's net assets.

Norway

As announced in September, first production from the Knarr project in Norway is likely to be delayed by approximately four months into the second half of 2014.

Tanzania

In October, BG Group announced that the drill stem test on the Pweza-3 well, the first in Block 4, flowed at a maximum 57 mmscfd, constrained by equipment. Importantly, the test demonstrated that development wells could flow at significantly higher rates than anticipated and that the Pweza reservoir is potentially the most prolific in BG Group's Tanzanian portfolio, reducing the likely well count and development costs. Block 4 is now fully appraised and, with gross total recoverable resources in the order of 4 trillion cubic feet (tcf) of natural gas, can be developed as a northern production hub to feed a potential LNG project. Meanwhile, BG Group, along with the Block 2 partners, submitted a proposal for the onshore LNG plant site to the government for its consideration.

Thailand

The Bongkot North Phase 3K development, consisting of two remote wellhead platforms and 16 wells, started in August. The development, one of BG Group's third quarter milestones, will allow for plateau extension of the Bongkot field.

United Kingdom

An extensive planned maintenance programme is nearing completion with only the Lomond platform left to re-start in the coming weeks, while the Jasmine field is expected to start up in the fourth quarter.

USA

As announced in September, BG Group expects to continue to operate fewer rigs in the USA, in line with the Group's strategy of pursuing value over volume and the continuing low US natural gas price.

The Lake Charles liquefaction project received conditional approval from the Department of Energy (DoE) for sales of up to 15 million tonnes per annum (mtpa) of LNG to non-free trade agreement countries.

BG Group also signed a project development agreement for Lake Charles with partners setting out commercial arrangements for the project. Energy Transfer will own and finance the new liquefaction facility, with a subsidiary providing the pipeline to supply natural gas to the project. BG Group will contract for the majority of the offtake. 

The project is in the Federal Energy Regulatory Commission's (FERC) pre-filing environmental review process, with a formal application expected to be filed with the FERC by the end of the first quarter of 2014.

Third quarter business highlights continued

Portfolio rationalisation

In September, BG Group announced it had completed the sale of the Group's remaining 20% equity in the Quintero LNG terminal in Chile for $176 million. This follows the sale of an initial 20% equity in Quintero which completed in September 2012.

In October, BG Group announced that it signed a definitive agreement, including a net cash consideration of $231 million, with Azure Midstream Energy, LP for the sale of its entire 50% equity holding in TGGT - a joint venture midstream company operating in east Texas and north Louisiana, USA. Completion of the deal is expected by the end of the year.

Board changes

Following the announcement in July of his appointment as Chief Financial Officer and as an Executive Director, Mr Simon Lowth will join BG Group on 2 December 2013. Den Jones will stand down as Interim Chief Financial Officer and as an Executive Director on the same date. 

Upstream

a) See note 1 (page 19)

Additional operating and financial data is given on page 30.

Third quarter

Revenue and other operating income decreased 6% to $2 783 million, reflecting a 10% decrease in production volumes, partly offset by an increased proportion of oil in the portfolio. Around half of the volume decline resulted from the Group's decision to reduce activity in the USA, with other major effects being reservoir decline in Egypt and the impact of planned shutdowns, partially offset by new developments coming onstream.

The Group's average realised oil price increased 4% to $111.72 per barrel and the liquids price increased 1% to $96.42 per barrel. The Group's average realised gas price decreased 5% to 45.42 cents per therm. International gas price realisations were 5% lower at 43.87 cents per therm, reflecting generally lower market prices. The average realised UK gas price increased 7% to 44.61 pence per therm as a result of higher UK market prices and increased spot sales.

Total E&P operating profit of $1 114 million was 17% lower as a result of the decrease in revenue and other operating income combined with higher operating costs and depreciation. Unit operating expenditure increased to $13.36 per barrel of oil equivalent (boe), principally due to higher royalties and lifting costs from new developments in Brazil and Bolivia, higher lifting costs in the UK which include the impact of increased maintenance activity, and lower overall volumes.

The unit depreciation charge increased to $10.91 per boe due to a combination of new developments coming onstream and the impact of minor reserves revisions in previous quarters.

Gross exploration expenditure of $586 million included spend in Brazil ($288 million), Tanzania ($108 million), Australia ($85 million), Egypt ($41 million) and the UK ($18 million).

Business development costs of $29 million were incurred in progressing the Group's potential integrated LNG projects in western Canada and Tanzania.

Capital investment on a cash basis of $2 787 million included investment in Australia ($1 428 million), Brazil ($608 million), Egypt ($184 million) and the UK ($145 million).

Upstream continued

Nine months

Revenue and other operating income decreased 3% to $8 771 million, reflecting a 5% reduction in production volumes and lower realised oil and liquids prices, partly offset by an improved production mix including an increased proportion of oil in the portfolio.

The Group's average realised oil price decreased 3% to $108.11 per barrel and the liquids price decreased 4% to $91.53 per barrel, reflecting movements in market prices. The Group's average realised gas price increased 4% to 46.41 cents per therm, reflecting generally higher market prices.

Total E&P operating profit was 11% lower as a result of the decrease in revenue and other operating income, combined with higher operating costs and depreciation charges. Unit operating expenditure increased to $11.89 per boe, principally reflecting the impact of higher royalty costs as production increased from new royalty-paying fields, and higher lifting costs, principally in the UK. The unit depreciation charge increased to $11.08 per boe due to a combination of new developments coming onstream and the impact of minor reserves revisions.

BG Group's share of operating profit from liquefaction activities increased 17% to $302 million, primarily as a result of higher prices at Atlantic LNG.

Business development costs of $57 million were incurred in progressing the Group's potential integrated LNG projects in western Canada and Tanzania.

Capital investment on a cash basis of $8 005 million included investment in Australia ($4 155 million), Brazil ($1 661 million), the UK ($546 million) and Egypt ($448 million).

LNG Shipping & Marketing

a) See note 1 (page 19)

Additional operating and financial data is given on page 30.

Third quarter

LNG Shipping & Marketing total operating profit decreased 12% to $602 million, as the impact of fewer cargo deliveries and reduced margins was partly offset by lower hedging losses.

During the quarter, BG Group delivered 44 LNG cargoes, six fewer than in the third quarter of 2012, including two fewer cargoes from Egypt and three fewer from Nigeria as a result of disruptions in the quarter. Cargo deliveries comprised 32 to Asia, 10 to South America, one to the USA and one to the UAE (2012: 50 cargoes: 31 Asia,eight South America, six USA, four Europe and one UAE).

Nine months

LNG Shipping & Marketing total operating profit decreased 3% to $1 865 million, with the impact of fewer cargo deliveries and reduced margins, including the impact of the pricing change on cargoes delivered to Chile, largely offset by lower hedging losses.

BG Group delivered 132 LNG cargoes, 17 fewer than in 2012, including six fewer spot cargoes, five fewer cargoes from Egypt and five fewer cargoes from Nigeria as a result of disruptions. Deliveries comprised 90 to Asia, 32 to South America, six to the USA, two to Europe, one to Mexico and one to the UAE (2012: 149 cargoes: 92 Asia, 34 South America, 15 USA, seven Europe and one UAE).

Presentation of Non-GAAP measures

Legal Notice

Consolidated Income Statement

Third Quarter

a) See note 1 (page 19).

b) See Presentation of Non-GAAP measures (page 11) for an explanation of results excluding disposals, certain re-measurements and impairments and presentation of the results of joint ventures and associates.

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

d) Comprises earnings from continuing operations of $1 230 million (2012 $1 208 million) and from discontinued operations of $(11) million (2012 $77 million).

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

The notes on pages 19 to 29 form an integral part of these condensed financial statements.

Consolidated Income Statement

Nine Months

a) See note 1 (page 19).

b) See Presentation of Non-GAAP measures (page 11) for an explanation of results excluding disposals, certain re-measurements and impairments and presentation of the results of joint ventures and associates.

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

d) Comprises earnings from continuing operations of $3 271 million (2012 $2 358 million) and from discontinued operations of $249 million (2012 $424 million).

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

The notes on pages 19 to 29 form an integral part of these condensed financial statements.

For information on dividends paid in the period, see note 9 (page 28).

Consolidated Statement of Comprehensive Income

a) See note 1 (page 19).

b) Income tax relating to hedge adjustments is a $180 million charge for the quarter (2012 $208 million charge) and a $36 million charge for the nine months(2012 $258 million charge).

c) Income tax relating to fair value movements on 'available-for-sale' assets is $nil for the quarter (2012 $2 million credit) and $nil for the nine months (2012 $6 million credit).

d) Income tax relating to the re-measurement of defined benefit pension obligations is a $4 million charge for the quarter (2012 $3 million charge) and a $4 million credit for the nine months (2012 $18 million charge).

The notes on pages 19 to 29 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

a) See note 1 (page 19).

The notes on pages 19 to 29 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

a) See note 1 (page 19).

b) Includes $26 million in respect of dividends attributable to holders of American Depositary Receipts in prior periods.

The notes on pages 19 to 29 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 26).

a) See note 1 (page 19).

b) Includes loss before tax from discontinued operations for the quarter of $6 million (2012 $169 million profit) and for the nine months of $270 million profit (2012 $611 million profit).

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

d) The balance at 30 September 2013 includes cash and cash equivalents of $3 193 million (31 December 2012 $4 434 million; 30 September 2012 $4 598 million) and cash included within assets held for sale of $nil (31 December 2012 $86 million; 30 September 2012 $69 million).

The notes on pages 19 to 29 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These primary statements are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended and the nine months ended 30 September 2013. 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 2012 which have been prepared in accordance with IFRS as adopted by the EU, as they provide an update of previously reported information. The latest statutory accounts delivered to the registrar were for the year ended 31 December 2012 which were audited by PricewaterhouseCoopers 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 2012, 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.

In the fourth quarter of 2012, BG Group announced agreements to sell both the Group's interest in Gujarat Gas Company Limited in India and the Group's interest in the Brazil-Bolivia Pipeline as well as the disposals of Comgás in Brazil and BG Italia Power in Italy. As a result, these operations, which represented the majority of the Group's Transmission and Distribution business segment and were considered to be a separate major line of business for BG Group, have been treated as discontinued. 

The Transmission and Distribution businesses remaining with BG Group, principally Mahanagar Gas in India, are now included within the Other business segment. 

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. Comparative information has also been restated to reflect the presentation of discontinued operations as a separate line item.

In its 2012 fourth quarter and full year results, BG Group announced that following a review of the remaining business segments, the liquefaction businesses were combined with the previous E&P segment to form the 'Upstream' segment, and the remaining businesses which comprised the LNG segment were renamed 'LNG Shipping & Marketing'. The new segmental presentation is consistent with the basis used to present information for internal reporting purposes.

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 21) 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 an amended IAS 19 'Employee Benefits' in June 2011. The main amendment is to eliminate the option to defer the recognition of actuarial gains and losses, known as the 'corridor method'. The impact on the Group is that all actuarial gains and losses are recognised in other comprehensive income as they occur. In addition, net interest expense is calculated based on applying a single discount rate to the net deficit, replacing interest cost and expected return on plan assets. The amended standard has been adopted by the Group for the year ended 31 December 2013 and comparative information has been restated. The impact on the balance sheet as at 1 January 2012 is a reduction in net assets of $164 million. For the period ended 30 September 2012, the impact on profit before tax was a $15 million reduction ($5 million for the quarter) and the impact on other comprehensive income was a $43 million gain ($3 million gain for the quarter). The impact on the balance sheet as at 1 January 2013 is a reduction in net assets of $146 million. The impact on the balance sheet as at 30 September 2012 is a reduction in net assets of $132 million.

The IASB issued an amended IAS 1 'Presentation of Financial Statements' in June 2011. The main amendment is a requirement to group items presented in other comprehensive income on the basis of whether they are potentially reclassifiable to the income statement. The amended standard has been adopted by the Group as of 1 January 2013 and has not had a material impact on the Group's financial statements for the nine months ended 30 September 2013.

A number of other amendments to accounting standards issued by the IASB are applicable from 1 January 2013. They have not had a material impact on the Group's financial statements for the nine months ended 30 September 2013.

2. Disposals, re-measurements and impairments

a) See note 1 (page 19).

Third quarter and nine months: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a credit of $48 million for the quarter (2012 $2 million charge), of which a credit of $28 million (2012 $2 million credit) represents non-cash mark-to-market movements on certain long-term gas contracts. For the nine months, a credit of $208 million in respect of re-measurements is included within revenue and other operating income (2012 $148 million credit), of which a credit of $69 million represents non-cash mark-to-market movements on certain long-term gas contracts (2012 $74 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 $20 million credit for the quarter (2012 $4 million charge) and a $139 million credit for the nine months (2012 $74 million credit) representing unrealised mark-to-market movements associated with economic hedges.

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

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 $58 million (post-tax $22 million) following the write-off of certain E&P assets. In addition, there was a pre-tax charge of $10 million (post-tax $8 million) as a result of land relinquishments in the USA.

The second quarter included a pre-tax charge of $171 million (post-tax $94 million) in respect of the impairment of certain E&P assets as a result of a reserves revision and a pre-tax charge of $116 million (post-tax $75 million) as a result of land relinquishments in the USA.

In 2012, nine months results included a $1 800 million pre-tax charge in respect of the impairment of certain assets associated with the shale gas business in the USA (post-tax $1 295 million) in the second quarter, partially offset by a pre-tax profit of $400 million on the disposal of 10% of the Group's interest in the Karachaganak gas-condensate project (post-tax $164 million). In the third quarter of 2012, BG Group completed the sale of the initial tranche of 20% equity in the Quintero LNG regasification facility in Chile which resulted in a pre-tax profit on disposal of $146 million (post-tax $110 million).

Other disposals and impairments in 2013 resulted in a pre-tax charge to the income statement of $26 million (2012 $15 million charge) in the third quarter (post-tax charge $21 million, 2012 $15 million charge) and a pre-tax charge of $62 million (2012 $126 million charge) in the nine months (post-tax $17 million charge, 2012 $67 million charge).

Third quarter and nine months: Net finance costs

Re-measurements presented in net finance costs include mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk, offset by foreign exchange movements on certain borrowings and movements on monetary items that form part of the Group's net investment in foreign operations.

3. Segmental analysis

a) See note 1 (page 19).

b) External sales are attributable to segments as follows: Upstream $2 636 million (2012 $2 787 million), LNG Shipping & Marketing $1 789 million (2012 $1 881 million) and other $1 million (2012 $3 million). Intra-group sales are attributable to segments as follows: Upstream $144 million (2012 $183 million) and LNG Shipping & Marketing $nil (2012 $80 million).

c) Business Performance Other operating income is attributable to segments as follows: Upstream $3 million (2012 $3 million), LNG Shipping & Marketing $(33) million (2012 $(2) million) and Other $1 million (2012 $nil).

3. Segmental analysis continued

a) See note 1 (page 19).

b) External sales are attributable to segments as follows: Upstream $8 199 million (2012 $8 451 million), LNG Shipping & Marketing $5 540 million (2012 $5 736 million) and other $3 million (2012 $9 million). Intra-group sales are attributable to segments as follows: Upstream $563 million (2012 $564 million) and LNG Shipping & Marketing $15 million (2012 $226 million).

c) Business Performance Other operating income is attributable to segments as follows: Upstream $9 million (2012 $11 million) and LNG Shipping & Marketing $(76) million (2012 $3 million).

3. Segmental analysis continued

a) See note 1 (page 19).

a) See note 1 (page 19).

4. Net finance (costs)/income

a) See note 1 (page 19).

b) In 2013, interest payable includes foreign exchange losses of $24 million for the quarter (2012 $18 million losses) and foreign exchange losses of $1 million for the nine months (2012 $9 million losses).

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

d) Net finance (costs)/income in disposals, re-measurements and impairments for the quarter of $142 million (2012 $3 million) and for the nine months of $64 million(2012 $(11) million) is included in note 2 (page 21). For the nine months, this principally reflects mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk, partly offset by foreign exchange movements on certain borrowings.

e) Excludes Group share of net finance costs from joint ventures and associates for the quarter of $6 million (2012 $4 million) and for the nine months of $19 million(2012 $31 million).

5. Taxation

a) See note 1 (page 19).

5. Taxation continued

a) See note 1 (page 19).

Business Performance taxation for the nine months, including share of taxation from joint ventures and associates, was $2 345 million (2012 $2 775 million). The Group's effective tax rate is based on the best estimate of the weighted average annual income tax rate expected for the full year. In the third quarter, the rate reduced to 42% from 44% (2012: 44.5%), comprising a 1% reduction in respect of the revision of opening deferred tax balances following changes to UK taxation rates enacted in the quarter and 1% from a change in the expected mix of profits.

6. Discontinued operations

The post-tax result of the businesses comprising discontinued operations for the quarter, including profits and losses on disposals and impairments, was a loss of $11 million (2012 $119 million profit) and for the nine months was a profit of $258 million (2012 $500 million profit).

In June 2013, BG Group disposed of its 65.12% interest in Gujarat Gas Company Limited in India for consideration of $422 million, which resulted in a pre and post-tax profit of $245 million in the second quarter of 2013.

In May 2012, the Group disposed of its 40% equity interest in two gas-fired power generation plants in the Philippines to its partner, First Gen Corporation, for net cash proceeds of $360 million. This resulted in a pre and post-tax profit of $252 million in the second quarter of 2012.

Other disposals and impairments resulted in a post-tax result of $nil in the third quarter (2012 $1 million profit) and a post-tax loss of $2 million for the nine months (2012 $1 million profit).

Excluding profits and losses on disposals and impairments, the post-tax result of the businesses comprising discontinued operations for the third quarter was a loss of $11 million (2012 $118 million profit) and for the nine months was a profit of $15 million (2012 $247 million profit).

7. Earnings per ordinary share - continuing operations

a) See note 1 (page 19).

Basic earnings per share calculations in 2013 are based on the weighted average number of shares in issue of3 402 million for the quarter and 3 401 million for the nine months. The earnings figure used to calculate diluted earnings per ordinary share is the same as that used to calculate earnings per ordinary share given above, divided by 3 419 million for the quarter and 3 417 million for the nine months, being the weighted average number of ordinary shares in issue during the period as adjusted for dilutive equity instruments. 

8. Reconciliation of net borrowings(a) - Nine Months

As at 30 September 2013, BG Group's share of the net borrowings in joint ventures and associates amounted to approximately $0.9 billion, including BG Group shareholder loans of approximately $0.7 billion. These net borrowings are included in BG Group's share of the net assets in joint ventures and associates which are consolidated inBG Group's accounts.

a) Net borrowings are defined on page 33.

Net borrowings comprise:

a) These items are included within commodity contracts and other derivative financial instrument balances on the balance sheet.

b) Includes finance lease receivable of $172 million (2012 $195 million) included within non-current assets on the balance sheet.

8. Reconciliation of net borrowings - Nine Months continued

Liquidity and Capital Resources

All the information below is as at 30 September 2013

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

BGEH had a $4.0 billion US Commercial Paper Programme and a $2.0 billion Euro Commercial Paper Programme, both of which were unutilised. BGEH also had a $15.0 billion Euro Medium Term Note Programme, of which $9.1 billion was unutilised.

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

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

9. Dividends

The final dividend of 14.26 cents per ordinary share ($478 million) in respect of the year ended 31 December 2012 was paid on 31 May 2013 to shareholders on the register at the close of business on 19 April 2013. The interim dividend of 13.07 cents per ordinary share ($448 million) in respect of the year ending 31 December 2013 was paid on 6 September 2013 to shareholders on the register as at 9 August 2013.

10. Quarterly information: earnings and earnings per share

a) See note 1 (page 19).

11. Commitments and contingencies

Details of the Group's commitments and contingent liabilities as at 31 December 2012 can be found in note 24, page 120 of the Annual Report and Accounts 2012. The Group's capital expenditure commitments have decreased by approximately $1 billion in the nine month period to 30 September 2013, primarily due to progress on the Group's major growth projects. There have been no material changes to the Group's other commitments or contingent liabilities in the period.

12. Related party transactions

The Group provides goods and services to, and receives goods and services from, its joint ventures and associates.In addition, the Group provides financing to some of these parties by way of loans. Details of related party transactions for the year ended 31 December 2012 can be found in note 25, page 122 of the Annual Report and Accounts 2012. There have been no material changes in these relationships in the nine month period to 30 September 2013. No related party transactions have taken place in the first nine months of the current financial year that have materially affected the financial position or the performance of the Group during that period.

Supplementary information: Operating and financial data