BG..L Regulatory News (BG.)

BG Group plc

2015 FOURTH QUARTER & FULL YEAR RESULTS

5 February 2016

Full Year Key Points

· E&P production 704 kboed, up 16%; ramp up in both Australia and Brazil; 282 LNG cargoes delivered, up 58%

· Lower commodity prices impacted financial results

· Upstream EBITDA $4 167 million, down 35%

· LNG EBITDA $1 456 million, down 46%

· Business Performance earnings $1 697 million; EPS 49.7 cents; both down 58%

· Total earnings of $2 328 million; Total EPS 68.2 cents

· Capex down 32% to $6 387 million; cost and efficiency savings of $300 million achieved

· Free cash outflow of $2 408 million, down 8%; lower net cash flow from operating activities offset by lower capex

· Gross disposal proceeds of $5 186 million; net cash inflow before dividends and financing of $3 363 million

· No final 2015 dividend; completion of the Combination expected prior to Shell's Q4 2015 dividend record date

BG Group's Chief Executive, Helge Lund said:

"We are pleased to have delivered an excellent operational performance in 2015 with results in line with, or ahead of, our guidance for the year. The ramp up of both LNG trains at our QCLNG project in Australia and the ramp up in Brazil, including the start-up of our sixth FPSO, drove a strong E&P operational performance. Our LNG Shipping & Marketing business delivered 282 cargoes, an increase of 58% on 2014, in difficult market conditions.

"The addition of new low cash cost volumes in Brazil and Australia and delivery of our operating and capital cost savings has helped to partly mitigate the impact of lower commodity prices.

"This strong operational performance is the result of the capability and commitment of our teams across the organisation and we will deliver a high-performing business into the Combination with Shell."

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 15) and notes 1 to 3 (pages 23 to 27). Unless otherwise stated, the results discussed in this release relate to BG Group's Business Performance.

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

c) See 2015 Dividend (page 5) for further details.

Business Review - Group

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

b) Profit before tax for the full year excluding joint ventures and associates was $1 963 million (2014 $6 046 million) giving an effective tax rate of 24.0% (2014 36.9%) and for the quarter was $314 million (2014 $1 111 million) giving an effective tax rate of (17.8)% (2014 21.8%). 

Fourth quarter

Revenue and other operating income decreased 2% to $4 300 million. This reflects the significant fall in realised sales prices impacting both the Upstream and LNG Shipping & Marketing segments, offset by higher volumes in both segments and the start-up of liquefaction operations at Queensland Curtis LNG (QCLNG). E&P production volumes were up 20% with LNG delivered volumes up 110%.

EBITDA decreased 22% to $1 426 million. In the Upstream segment, EBITDA fell 12% to $1 072 million primarily reflecting the lower revenues partly offset by the increased contribution from liquefaction following the start-up of QCLNG operations. In the LNG Shipping & Marketing segment, EBITDA fell 51% to $272 million as margins reduced primarily as a consequence of lower sales prices. The increased contribution from the Other activities segment reflects a reduction in the number of LNG cargoes in transit at the end of the fourth quarter.

Business Review - Group continued

Fourth quarter continued

EBIT decreased by $692 million to $473 million, reflecting the lower EBITDA and higher DD&A charges primarily as a result of increased E&P production and the start-up of QCLNG.

Net finance costs of $106 million included foreign exchange losses of $27 million (2014 net finance costs of $8 million included realised foreign exchange hedge losses of $13 million and other foreign exchange gains of $46 million). Excluding the impact of foreign exchange, net finance costs increased by $38 million to $79 million, reflecting the reduction in the amount of interest on borrowings that can be capitalised against assets under construction following the start-up of QCLNG.

The Group's taxation for the quarter (excluding BG Group's share of joint venture and associates' results and tax) was a credit of $56 million. This reflects the lower profit before tax, combined with the impact of a reduction in the Group's full year effective tax rate recognised in the quarter.

Group earnings of $423 million and EPS of 12.4 cents both decreased 54%, with the reduction in EBIT and higher net finance costs only partially offset by the reduction in taxation.

Net cash flow from operating activities decreased by $101 million to $1 575 million as a result of lower Business Performance EBITDA and lower working capital inflows, partly offset by lower tax payments.

Capital investment on a cash basis was 28% lower at $1 732 million and was almost entirely in the Upstream segment ($1 722 million), where it comprised $1 594 million on development and other activities, and $128 million on exploration. The development spend was concentrated primarily in Brazil ($705 million) and Australia ($597 million).

Free cash flow improved by $597 million to a $348 million outflow, reflecting the reduction in capital investment, partly offset by the decrease in net cash flow from operating activities.

Full year

Revenue and other operating income decreased 16% to $16 419 million, reflecting the significant fall in realised sales prices impacting both the Upstream and LNG Shipping & Marketing segments. The impact of lower prices was partly offset by higher volumes in both segments, the start-up of liquefaction operations at QCLNG and weather-related gains in North America in the LNG Shipping & Marketing segment. E&P production volumes were up 16% and LNG delivered volumes were up 63%.

EBITDA decreased 39% to $5 633 million. In the Upstream segment, EBITDA fell 35% to $4 167 million primarily reflecting the lower revenues, partly offset by the increased liquefaction contribution from QCLNG. In the LNG Shipping & Marketing segment, EBITDA fell 46% to $1 456 million as margins reduced through a combination of lower sales prices and a greater proportion of relatively lower margin spot cargoes.

EBIT decreased by $3 948 million to $2 429 million, reflecting the reduction in EBITDA combined with increased DD&A charges, which resulted from higher E&P production volumes and the start-up of QCLNG.

Net finance costs of $260 million included foreign exchange gains of $nil (2014 net finance costs of $109 million included realised foreign exchange hedge gains of $28 million and other foreign exchange gains of $21 million). Excluding the impact of foreign exchange, net finance costs increased by $102 million to $260 million, reflecting the reduction in the amount of interest on borrowings that can be capitalised against assets under construction following the start-up of QCLNG.

The tax charge for the full year reduced to $472 million and reflects the lower profit before tax and the reduction in the Group's full year effective tax rate (excluding BG Group's share of joint ventures and associates' results and tax) to 24.0% (2014 36.9%), and includes the impact of further changes in the Group's mix of profits and revisions to certain tax positions.

Group earnings of $1 697 million and EPS of 49.7 cents both decreased 58%, with the reduction in EBIT and higher net finance costs only partially offset by the reduction in the Group's tax charge.

Net cash flow from operating activities deteriorated by $3 096 million to $4 303 million as a result of lower Business Performance EBITDA and lower working capital inflows, partially offset by lower tax payments.

Capital investment on a cash basis was 32% lower at $6 387 million and was almost entirely in the Upstream segment ($6 377 million), consisting of $5 779 million on development and other activities, and $598 million on exploration. The development spend was concentrated primarily in Brazil ($2 656 million) and Australia ($1 585 million).

Business Review - Group continued

Full year continued

Free cash flow deteriorated by $180 million to a $2 408 million outflow, primarily reflecting the decrease in net cash flow from operating activities, partly offset by the lower capital investment. Cash inflow prior to dividends and financing was $3 363 million for the year, including $4 597 million gross proceeds from the disposal of the QCLNG pipeline.

Net debt of $10 068 million fell by $1 930 million as a result of the QCLNG pipeline disposal, and gearing was lower at 25.3% reflecting the reduction in net debt. Return on average capital employed reduced to 4.6%, reflecting the lower Business Performance results.

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

Fourth quarter

Total earnings for the fourth quarter of 2015 were a loss of $29 million (loss of 0.8 cents per share) and included apost-tax loss of $452 million in respect of disposals, re-measurements and impairments. This comprised non-cash post-tax impairment charges of $691 million, a net credit of $314 million associated with exceptional one-off and prior period taxation, $49 million of gains reflecting the impact of foreign exchange movements on deferred and current tax balances and a net post-tax charge of $124 million in relation to other re-measurements and exceptional items. The impairment charges reflected the impact of further falls in commodity prices and reserve revisions on certain of the Group's E&P assets, mainly in the North Sea and Tunisia.

Total earnings for the fourth quarter of 2014 were a loss of $5 030 million (loss of 147.5 cents per share) and included a post-tax loss of $5 945 million in respect of disposals, re-measurements and impairments. This included $5 939 million of primarily commodity price-related non-cash post-tax impairment charges, mainly in Australia, Egypt, the North Sea and Tunisia, partly offset by a net credit of $449 million resulting from a number of exceptional one-off and prior period taxation items.

Further details are provided in note 2, Disposals, re-measurements and impairments (page 24).

Full year

Total earnings for the full year were $2 328 million (68.2 cents per share) and included a post-tax gain of $631 million in respect of disposals, re-measurements and impairments. This included a $1 672 million gain from disposal of non-current assets, primarily in relation to the QCLNG pipeline sale, and exceptional one-off and prior period taxation credits of $692 million, partly offset by $691 million of post-tax impairment charges and a net $659 million charge reflecting the impact of foreign exchange movements on deferred and current tax balances.

Total earnings for 2014 were a loss of $1 051 million (loss of 30.8 cents per share) and included a post-tax loss of $5 086 million in respect of disposals, re-measurements and impairments. This included $5 928 million of post-tax impairments, partially offset by a $934 million post-tax gain on disposal of non-current assets, which included the CATS pipeline in the UK, and $449 million of exceptional one-off and prior period taxation credits.

For further information see Presentation of Non-GAAP measures (page 15) and notes 1 to 3 (pages 23 to 27).

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

On 8 April 2015, the Boards of Royal Dutch Shell plc (Shell) and BG Group plc announced that they had reached agreement on the terms of a recommended cash and share offer to be made by Shell for the entire issued and to be issued share capital of BG Group plc to be effected by way of a court-sanctioned scheme of arrangement under Part 26 of the Companies Act 2006 (the Scheme).

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

Please refer to the Rule 2.7 announcement and Scheme Document available at www.bg-group.com/shelloffer for further details on the Combination.

On 27 January 2016, Shell shareholders voted to approve the Combination and on 28 January 2016, BG Group plc shareholders voted to approve the Scheme at a court-convened meeting and to approve a special resolution to implement the Scheme, including amendments to the BG Group plc articles, at a general meeting of BG Group plc.

BG Group plc is now seeking the sanction of the Scheme at the court hearing which is scheduled for 11 February 2016, following which, the Scheme will become effective. This is currently expected to occur on 15 February 2016 (the Effective Date).

2015 dividend

BG Group plc shareholders were paid an interim dividend in respect of the six month period up to 30 June 2015 of 14.38 cents (9.22 pence) per BG Group plc share on 11 September 2015.

If, as is currently expected, the Effective Date of the Combination occurs on 15 February 2016 prior to the record date for Shell's 2015 fourth quarter dividend (being 19 February 2016), BG Group plc shareholders will receive that Shell dividend and will not receive a further BG Group plc dividend for 2015. On 4 February 2016, Shell announced a fourth quarter dividend of 47.00 cents per Shell share (equivalent to 20.93 cents per BG Group share, based on the default consideration of 383 pence in cash and 0.4454 Shell B shares for each BG Group plc share held).

Fourth quarter business highlights

Overview

E&P production was 757 thousand barrels of oil equivalent per day (kboed), up 20% from the fourth quarter of 2014. Growth was driven by Australia, Brazil, the UK and Norway. Volumes in Australia more than doubled to 117 kboed and in Brazil, increased 56% to 161 kboed. Production from the UK was 109 kboed, up 33% reflecting the timing of shutdowns in 2014, while in Norway, Knarr continued to ramp up producing an average of 27 kboed in the quarter. This growth was partially offset by the expected decline in Egypt, down 31 kboed to 37 kboed, combined with lower volumes in Trinidad and Tobago, down 39 kboed to 40 kboed. The Group's strong performance in the fourth quarter resulted in full year production of 704 kboed, ahead of guidance of 680-700 kboed.

The LNG Shipping & Marketing segment delivered 88 cargoes (5.7 million tonnes) in the quarter, double that in 2014 (3.0 million additional tonnes). Increased supply was driven by 32 cargoes from QCLNG and 13 additional spot cargoes. Of the 88 cargoes (2014 44), 69 were supplied to Asian markets (2014 30). The Group delivered its first ever cargo to Jordan during the quarter. With the ramp-up in supply from QCLNG (77 cargoes) and additional spot availability (31 additional cargoes), the Group delivered 282 cargoes (17.9 million tonnes) in 2015, 104 more cargoes than in 2014 (6.9 million additional tonnes). 74% of cargoes were delivered to Asian markets in 2015 (2014 68%) and the Group delivered cargoes to three new markets during the year.

During the quarter, the Group continued to reduce capital expenditure and deliver on its cost and efficiency programme. For the full year, the Group's capital expenditure was $6 387 million, down 32% on 2014 ($9 402 million), while the Group exceeded its $300 million lifting, organisation and infrastructure cost savings target.

Australia

In November, BG Group assumed operational control of Train 2 at QCLNG and commenced full commercial operations. Both LNG trains are now running at plateau, with 31 cargoes produced in the fourth quarter, making a total of 83 cargoes since the start of 2015. 32 cargoes were delivered during the fourth quarter.

E&P production in Australia has continued to ramp-up according to plan, achieving its highest level in a single day of around 130 kboed in January and averaging 117 kboed for the fourth quarter, net to BG Group. During the quarter, less than 20% of the gas supplied to QCLNG was from third-party gas contracts, in line with expectations during the ramp-phase.

In November, BG Group and partners announced approval of a $1.4 billion (gross) development programme, known as Charlie, as part of the continuous development of tenements in the Surat Basin to sustain gas supply to both domestic customers and to QCLNG. BG Group's equity share of the investment (73.75%) is within the Group's previously disclosed ongoing capital expenditure programme. The development involves the construction of 300-400 wells, a large field compression station and associated pipelines and facilities which will feed into existing gas processing and water infrastructure at Woleebee Creek.

Brazil

In December, BG Group achieved record net production from the Santos Basin, reaching 188 kboed. Across the Santos Basin, BG Group had 25 wells in production which are flowing at an average rate of around 26 kbopd (gross).

In the quarter, FPSO 5 (Cidade de Mangaratiba) reached plateau production and gross production averaged 130 kbopd from five producer and five injector wells. Gross production from FPSO 4 (Cidade de Ilhabela) has averaged 87 kbopd with three producer wells and one injector well, while FPSO 6 (Cidade de Itaguaí), where three producer and three injector wells are now connected, achieved average production rates of around 63 kbopd.

In December, FPSO 7 (Cidade de Maricá) arrived on location on the Lula area and mooring operations are ongoing. Final integration works for FPSO 8 have now commenced at the Brasa shipyard with integration works continuing on FPSO 9 in Singapore.

For all replicant FPSOs, construction and integration works continue in both Brazilian and Asian shipyards. The consortium continues to closely monitor developments, including any potential impacts of the Lava Jato investigation, establishing and implementing mitigation plans where necessary.

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

Fourth quarter business highlights continued

Egypt

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

USA

In December, the Lake Charles LNG project received approval from the US Federal Energy Regulatory Commission to construct and operate a gas liquefaction and export facility in Lake Charles, Louisiana. The project has conditional authorisation from the US Department of Energy for the export of up to 2 billion cubic feet of gas per day or approximately 15 million tonnes of LNG per annum.

Canada

In November, BG Group acquired non-operated interests in two blocks offshore Newfoundland with equity stakes of 30% in block EL1138 and 25% in block EL1139. These blocks are adjacent to the Group's existing licences.

Cyprus

In November, BG Group acquired a 35% holding in Block 12 offshore Cyprus which includes the Aphrodite gas discovery. This upstream position provides a potential source of gas to Egypt where BG Group holds equity in the two-train LNG export facility at Idku as well as LNG offtake rights to lift 3.6 mtpa.

Portfolio management

In October, the Agência Nacional do Petróleo, Gás Natural e Biocombustíveis (ANP) approved the farm down of 10% equity on four frontier exploration blocks in the Barreirinhas Basin, northern Brazil, to Mitsui E&P Brasil. BG Group remains operator with 65% equity in these blocks. The farm down was originally announced in May 2015.

Upstream

a) Margins calculated on the basis of E&P EBIT or EBITDA before exploration charge, based on E&P production volumes. Additional operating and financial data is given on page 32.

Upstream continued

a) Excludes fuel gas.

Upstream continued

Fourth quarter

E&P production volumes increased 20% reflecting the ramp-up in Australia, Brazil and Norway, and fewer shutdowns in the UK, partly offset by lower production in Trinidad and Tobago and Egypt.

Revenue and other operating income decreased 5% to $2 583 million. E&P revenues decreased 24% reflecting significantly lower commodity prices, partly offset by higher volumes and an improved product mix with additional oil, primarily from Brazil. Liquefaction revenues increased by $495 million following the start-up of QCLNG.

E&P EBITDA before exploration was 30% lower at $1 021 million, primarily reflecting the decrease in revenues, partially offset by lower costs. E&P operating costs decreased 7% to $808 million as a 1% increase in lifting costs was more than offset by a 17% fall in royalties and other operating costs, primarily associated with the lower commodity prices. The 1% increase in lifting costs reflected the ramp-up of production in Brazil and Australia, partially offset by lower maintenance costs in the UK. Other E&P costs decreased 37% to $229 million as 2014 included the elimination of profit on oil sales associated with the Lula and Iara extended well tests in Brazil, together with a number of other one-off items.

E&P DD&A increased 46% to $826 million, reflecting higher production volumes and production from new developments at higher rate fields in the North Sea and Trinidad and Tobago.

The Group's average realised oil price decreased 40% to $45.79 per barrel, the liquids price decreased 43% to $36.68 per barrel, and the gas price per produced therm decreased 35% to 29.12 cents, reflecting lower market prices. As a result, unit revenues reduced $16.86 per boe to $29.29 per boe.

Unit operating expenditure decreased to $11.60 per boe (2014 $14.98 per boe), mainly due to a reduction in royalty costs per boe reflecting the lower commodity prices. Lifting costs per boe also decreased as a result of the reduction in shutdowns in the UK. Other E&P unit costs decreased to $3.29 per boe (2014 $6.30 per boe). 

Consequently, the Group's unit E&P EBITDA margin was $10.60 per boe lower at $14.67 per boe.

The unit DD&A charge increased to $11.87 per boe (2014 $9.74 per boe) as a result of changes in the production mix, including production from new developments at higher rate fields in the North Sea and Trinidad and Tobago.

The E&P EBIT margin (excluding exploration charge) was $12.73 per boe lower at $2.80 per boe.

The exploration charge of $285 million increased 20%, due to higher well write-off costs partially offset by reduced seismic activities. Gross exploration expenditure was lower at $212 million and included spend in Trinidad and Tobago ($79 million), Canada ($45 million) and Tanzania ($11 million). 

Liquefaction EBITDA increased $348 million to $336 million, principally reflecting a first full quarter of commercial operations at QCLNG Train 1 and common facilities, together with the commencement of commercial operations at Train 2.

Capital investment on a cash basis of $1 722 million consisted of $1 594 million on development and other activities, and $128 million on exploration. The development spend was concentrated primarily on projects in Brazil ($705 million) and Australia ($597 million).

Upstream continued

Full year

Production volumes increased 16% primarily as a result of the ramp-up in Brazil, Australia and Norway, and a higher share of production in Kazakhstan, partly offset by lower production in Egypt, Trinidad and Tobago, and the UK.

Revenue and other operating income decreased 19% to $9 792 million. E&P revenues fell 27%, reflecting significantly lower commodity prices, partly offset by higher volumes and an improved product mix with additional oil, particularly from Brazil. This was partly offset by the growth in liquefaction revenues, which increased $875 million following the start-up of QCLNG.

E&P EBITDA before exploration was 40% lower at $4 257 million, primarily reflecting the decrease in revenues. Operating costs increased 1% as a 12% increase in lifting costs was largely offset by a 11% reduction in royalties and other costs mainly as a result of lower commodity prices. The 12% increase in lifting costs reflected the ramp-up of production in Brazil and Australia, partially offset by lower maintenance costs in the UK. Other E&P costs decreased 26% to $866 million reflecting the impacts in Brazil of movements in the volume of oil held in stock, with around 6.8 mmboe of oil in stock at the end of 2015 (2014 2.5 mmboe), partially offset by higher Brazil oil shipping costs. In addition, Other E&P costs in 2014 included the elimination of profit on oil sales associated with the Lula and Iara extended well tests, together with a number of one-off items.

E&P DD&A increased 12% to $2 733 million reflecting the higher production volumes, including new production from higher rate fields, partly offset by favourable changes in the mix of fields, including increased production from Brazil and Australia.

The Group's average realised oil price decreased 46% to $52.98 per barrel, the liquids price decreased 46% to $43.73 per barrel and the gas price per produced therm decreased 28% to 35.39 cents, reflecting lower market prices. As a result, unit revenues reduced $19.45 per boe to $33.24 per boe.

Unit operating expenditure decreased to $13.55 per boe (2014 $15.54 per boe). Lifting costs per boe decreased primarily as a result of the reduction in shutdowns in the UK. Lower commodity prices led to a decrease in royalty costs, although this was partly offset by an increased proportion of production from royalty paying fields, principally in Brazil. Other E&P unit costs decreased to $3.37 per boe (2014 $5.29 per boe).

Consequently, the Group's unit E&P EBITDA margin was $15.44 per boe lower at $16.57 per boe.

The unit DD&A charge decreased to $10.64 per boe (2014 $10.99 per boe) as a result of a change in the mix of production, with lower production from higher rate fields in the UK and increased production from lower rate fields in Brazil and Australia. This was partly offset by reserve revisions in Trinidad and Tobago, and higher-rate new developments coming onstream in Trinidad and Tobago and in the North Sea. 

The E&P EBIT margin (excluding exploration charge) was $15.09 per boe lower at $5.93 per boe.

The exploration charge decreased 10% to $676 million primarily as a result of reduced seismic activities. Gross exploration expenditure decreased 25% to $942 million and included spend in Trinidad and Tobago ($274 million), Canada ($119 million), the UK ($111 million), Australia ($110 million) and Tanzania ($57 million).

Liquefaction EBITDA increased $460 million to $586 million, with the start of production from QCLNG only partly offset by lower prices and volumes at Atlantic LNG. 

Capital investment on a cash basis of $6 377 million consisted of $5 779 million on development and other activities, and $598 million on exploration. The development spend was concentrated primarily on projects in Brazil ($2 656 million) and Australia ($1 585 million), together with investments in the UK ($267 million) and Kazakhstan ($240 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 32.

LNG Shipping & Marketing continued

Fourth quarter

Delivered volumes increased 110%, with 88 cargoes delivered. The increase included 32 cargoes from QCLNG and 13 additional spot cargoes, partially offset by one less cargo from the Group's Atlantic Basin supply contracts.

Revenue and other operating income was up 18%, as the benefit of higher delivered volumes was partially offset by lower LNG sales prices.

LNG Shipping & Marketing EBITDA decreased 51% to $272 million, reflecting lower margins primarily as a result of the fall in sales prices. In addition, the majority of EBITDA associated with supply from QCLNG is recorded in the Upstream segment.

LNG Shipping & Marketing EBITDA unit margin fell 77% to $48 per tonne.

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

DD&A decreased 21% to $27 million following the sale and leaseback of two LNG vessels during the first quarter of 2015.

LNG Shipping & Marketing EBIT decreased to $245 million, as the fall in EBITDA was partially offset by the lower DD&A charges.

LNG Shipping & Marketing continued

Full year

Delivered volumes increased 63% with 282 cargoes delivered. The increase included 77 cargoes from QCLNG and 31 additional spot cargoes, partially offset by four fewer cargoes from the Group's Atlantic Basin supply contracts.

Revenue and other operating income increased 1% as the benefit of higher delivered volumes and weather-related gains in the Group's North American gas marketing business due to particularly cold weather in the first quarter of 2015 were offset by lower LNG sales prices.

LNG Shipping & Marketing EBITDA decreased 46% to $1 456 million, reflecting lower margins primarily as a result of the fall in sales prices combined with a greater proportion of relatively lower margin spot cargoes. The majority of EBITDA associated with supply from QCLNG is recorded in the Upstream segment.

LNG Shipping & Marketing EBITDA unit margin fell 67% to $81 per tonne.

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

DD&A decreased 24% to $108 million following the sale and leaseback of six LNG vessels during 2014 and two further vessels in the first quarter of 2015.

LNG Shipping & Marketing EBIT decreased to $1 348 million, as the fall in EBITDA was partially offset by the lower DD&A charges.

Presentation of Non-GAAP measures

Legal Notice

Consolidated Income Statement

Fourth Quarter

a) See Presentation of Non-GAAP measures (page 15) for an explanation of results excluding disposals, certain re-measurements and impairments.

The notes on pages 23 to 31 form an integral part of these financial statements.

Consolidated Income Statement

Full Year

a) See Presentation of Non-GAAP measures (page 15) for an explanation of results excluding disposals, certain re-measurements and impairments.

The notes on pages 23 to 31 form an integral part of these financial statements.

For information on dividends paid in the period, see note 7 (page 31).

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $52 million credit for the quarter (2014 $82 million credit) and a $156 million credit for the full year(2014 $125 million credit).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $3 million credit for the quarter (2014 $43 million credit) and a $6 million charge for the full year (2014 $45 million credit).

The notes on pages 23 to 31 form an integral part of these financial statements.

Consolidated Balance Sheet

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

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

The notes on pages 23 to 31 form an integral part of these financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 23 to 31 form an integral part of these financial statements.

Consolidated Cash Flow Statement

The cash flows above are inclusive of discontinued operations.

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

b) Excludes $4 million cash receipts recognised in profits and losses on disposal of non-current assets and impairments in the Income Statement.

The notes on pages 23 to 31 form an integral part of these financial statements.

Notes

1. Basis of preparation

These results which are unaudited and approved by the Board on 4 February 2016, are the financial statements ('the financial statements') of BG Group plc for the quarter ended and the full year ended 31 December 2015. The financial statements do not comprise statutory accounts within the meaning of Section 434 of the Companies Act 2006, and should be read in conjunction with the Annual Report and Accounts for the year ended 31 December 2014 which have been prepared in accordance with IFRS as adopted by the EU. The latest statutory accounts delivered to the registrar were for the year ended 31 December 2014 which were audited by Ernst & Young LLP and on which the Auditors' Report was unqualified and did not contain statements under Sections 498(2) or 498(3) of the Companies Act 2006. These financial statements have been prepared in accordance with the accounting policies, methods of computation and presentation as set out in the Annual Report and Accounts 2014.

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

Presentation of results

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

· The re-measurement of certain financial instruments; and

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

These items, which are detailed in note 2 to the financial statements (page 24), are excluded from Business Performance in order to provide readers with a clear and consistent presentation of the underlying operating performance of the Group's ongoing businesses.

2. Disposals, re-measurements and impairments

Fourth quarter and full year: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a charge of $16 million for the quarter (2014 $17 million credit), of which a credit of $14 million (2014 $126 million credit) represents non-cash mark-to-market movements on certain gas contracts. For the full year, a charge of $117 million in respect of re-measurements is included (2014 $403 million credit), of which a charge of $4 million represents non-cash mark-to-market movements on certain gas contracts (2014 $280 million credit). Whilst the activity surrounding these contracts involves the physical delivery of gas, the contracts fall within the scope of IAS 39 and meet the definition of a derivative instrument. In addition, re-measurements include a net $30 million charge for the quarter (2014 $110 million charge) and a net $113 million charge for the full year (2014 $17 million credit) representing unrealised mark-to-market movements associated with economic hedges.

Other operating income in 2014 for the quarter also includes a $1 million credit and the full year also includes a $106 million credit in respect of final settlement of a legacy treaty dispute relating to investments formerly held by the Group.

Fourth quarter and full year: Operating costs

Operating costs in 2015 for the quarter and full year include a $50 million pre and post-tax charge relating to the downward re-measurement of trade receivables in Egypt to reflect the time value of money associated with the outstanding debt based on a revised assumed repayment profile. This increases the total discount recognised to $150 million following the $100 million pre-tax charge ($79 million post-tax) recorded in the fourth quarter of 2014.

Fourth quarter and full year: Disposals of non-current assets

In 2015, the full year included a pre-tax gain of $2 538 million (post-tax $1 663 million) following the disposal of the QCLNG pipeline. The first quarter of 2015 included a pre-tax loss of $15 million (post-tax $14 million) in respect of the sale of two LNG vessels.

In 2014, the full year included a pre and post-tax gain of $782 million in respect of the disposal of the Central Area Transmission System (CATS) gas pipeline in the UK, of which a pre and post-tax gain of $11 million arose in the fourth quarter. The second quarter of 2014 included a pre-tax gain of $216 million (post-tax $170 million) in respect of the sale of six LNG vessels, which were previously held as finance leases and have subsequently been leased back under operating leases.

Other disposals in 2015 resulted in a pre-tax gain to the income statement of $53 million (2014: $6 million charge) in the quarter (post-tax $46 million, 2014 $6 million gain) and a pre-tax gain of $30 million (2014 $31 million charge) for the full year (post-tax $23 million, 2014 $18 million charge).

2. Disposals, re-measurements and impairments continued

Fourth quarter and full year: Impairments

In 2015, the fourth quarter and full year included non-cash pre-tax impairment charges of $1 452 million (post-tax $691 million) primarily reflecting the impact of further falls in commodity prices and reserves revisions on certain of BG Group's E&P assets, mainly in the North Sea and Tunisia.

In the North Sea, the non-cash pre-tax impairment charge was $787 million (post-tax $307 million), driven by lower commodity prices, a reserves downgrade reflecting underlying reservoir performance, and higher decommissioning costs on certain fields.

In Tunisia, the pre-tax impairment charge was $534 million (post-tax $307 million) driven by lower commodity prices and a reserves downgrade reflecting reservoir performance.

Elsewhere, reduction in the Group's assumptions of future commodity prices resulted in pre-tax impairment charges of $131 million (post-tax $77 million) in relation to certain other E&P assets.

In 2014, the fourth quarter included a non-cash pre-tax impairment charge of $8 872 million (post-tax $5 939 million) relating to Upstream activities in Australia, Egypt and certain other assets. This was driven mainly by the significant fall in global commodity prices.

In Australia, the total pre-tax impairment charge was $6 824 million ($4 540 million post-tax). With the agreement to sell the wholly-owned subsidiary QCLNG Pipeline Pty Ltd in 2015, the remaining QCLNG assets were impaired by $2 747 million pre-tax ($1 828 million post-tax). A further $4 077 million pre-tax ($2 712 million post-tax) impairment charge in Australia was driven mainly by a reduction in the Group's assumptions for future commodity prices.

In Egypt, the total pre-tax impairment charge was $750 million ($775 million post-tax), principally driven by further reserves downgrades reflecting underlying reservoir performance, and a write-down of the Group's investment in Egyptian LNG reflecting the Group's expectation of limited LNG exports for the foreseeable future.

Elsewhere, the reduction in the Group's assumptions for future commodity prices resulted in a $1 298 million pre-tax ($624 million post-tax) impairment charge of which the most significant charges were in the North Sea $566 million pre-tax ($172 million post-tax), Tunisia $450 million pre-tax ($255 million post-tax) and the USA $227 million pre-tax ($148 million post-tax).

The third quarter of 2014 included a pre-tax charge of $44 million (post-tax $27 million) and the second quarter of 2014 included a pre-tax charge of $40 million (post-tax $38 million gain) in respect of the impairment of certain E&P assets.

Fourth quarter and full year: Other

Other items in 2015 resulted in a pre-tax charge of $120 million (2014 $89 million) in the fourth quarter (post-tax $85 million, 2014 $58 million) and a pre-tax charge of $142 million (2014 $131 million) in the full year (post-tax $109 million, 2014 $95 million).

Fourth quarter and full year: Share of post-tax results from joint ventures and associates

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

In 2014, a pre and post-tax charge of $56 million was recognised, being the Group's share of a write-off of assets under construction in Brazil following the bankruptcy of a contractor.

2. Disposals, re-measurements and impairments continued

Fourth quarter and full year: Net finance income/(costs)

Re-measurements presented in net finance income/(costs) include net foreign exchange movements on the associated borrowings and certain intercompany balances, offset by mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk. In addition, re-measurements include a $76 million increase in interest recognised on a consortium loan, and a $15 million gain (2014 $3 million gain) in the fourth quarter and $nil in the full year (2014 $nil) relating to derivatives partially hedging the Group's Brazilian Real and Australian Dollar foreign exchange exposures that do not qualify for hedge accounting under IAS 39.

Fourth quarter and full year: Taxation

The fourth quarter of 2015 included a net taxation credit of $1 084 million. This comprised a net credit of $721 million relating to disposals, re-measurements and impairments, a net credit of $314 million resulting from a number of exceptional one-off and prior period taxation items and a net credit of $49 million reflecting the net impact of foreign exchange movements on deferred and current tax balances, especially in Brazil and Australia.

In 2015, the full year included a net taxation charge of $171 million. This comprised a net charge of $204 million relating to disposals, re-measurements and impairments, a net charge of $659 million reflecting the impact of foreign exchange movements on deferred and current tax balances, especially in Brazil and Australia, a $388 million credit relating to changes in deferred tax balances due to changes in UK taxation rates and a net $304 million credit resulting from a number of exceptional one-off and prior period taxation items.

In 2014, the fourth quarter included a taxation credit of $3 546 million (full year $3 512 million), primarily in relation to the impairment charges. Also included in taxation was a net credit of $449 million resulting from a number of exceptional one-off and prior period taxation items recognised in the quarter. This included the full recognition of taxable losses in Australia following commencement of QCLNG operations in the fourth quarter, and exceptional prior period adjustments and one-off changes to tax positions in a number of jurisdictions.

3. Segmental analysis