2014 FOURTH QUARTER & FULL YEAR RESULTS

BG Group plc

2014 FOURTH QUARTER & FULL YEAR RESULTS 

Full year key points

· E&P production within guidance at 606 kboed; LNG total operating profit ahead of guidance at $2 544 million; both 4% lower than 2013

· First LNG from QCLNG Train 1; five FPSOs onstream in Brazil, net production above 125 kboed in January

· Signed agreements for non-core asset disposals totalling $6.6 billion ($1.1 billion completed in 2014)

· Business Performance earnings $4 035 million, down 8%

· Total earnings down to $(1 051) million, reflecting non-cash post-tax impairments of $5 928 million

· Business Performance EPS down 8% to 118.4 cents; Total EPS down to (30.8) cents

· Full year dividend held flat at 28.75 cents per share (17.99 pence per share)

· 2015 E&P production 650 - 690 kboed; 2015 LNG S&M segment total operating profit $0.7 - 1.0 billion

· 2015 capital investment on a cash basis $6 - 7 billion

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

"BG Group made substantial progress on a number of fronts in 2014. The start-up of QCLNG and the continued introduction of FPSOs in Brazil were notable operational successes. The infrastructure transactions in theNorth Sea and Queensland coupled with improved collections from Egypt provide greater assurance on the Group's cash position. However, the sharp deterioration in commodity prices in the second half of the year has led us to recognise significant asset impairment charges in the fourth quarter. In the new environment we are well placed to manage the downturn as we are reaching the end of a high capital expenditure cycle and will continue to add further production in 2015 from Brazil and Australia. We will proactively manage our costs, both capital and operating, to adapt to the new business circumstances. We look forward to welcoming Helge Lund as our new Chief Executive shortly."

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. Total results include non-cash post-tax impairments of$5.9 billion, relating to Upstream activities primarily as a result of lower commodity price assumptions. For further information see Presentation of Non-GAAP measures (page 16) and notes 1 to 3 (pages 24 to 28). Unless otherwise stated, the results discussed in this release relate to BG Group's Business Performance.

Business Review - Group

a) Includes capital investment relating to discontinued operations for the quarter of $nil (2013 $nil) and for the full 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 39.

Fourth quarter

Revenue and other operating income decreased 19% to $4 403 million, reflecting the significant fall in realised commodity prices combined with lower volumes in both the Upstream and LNG Shipping & Marketing segments, partially offset by hedging gains. Brent oil hedges, entered into in the first quarter of 2014, gave rise to realised gains of $229 million, almost all of which were recognised in the Upstream segment. Further details are given in the Risk management for commodity prices and foreign exchange rates section on page 9.

Total operating profit decreased 36% to $1 224 million. Upstream segment total operating profit decreased 42% to $645 million, reflecting lower revenues. Higher operating costs were more than offset by lower DD&A and exploration charges. LNG Shipping & Marketing segment total operating profit decreased 32% as a result of lower revenues combined with higher costs of supply reflecting the increased number of spot cargo purchases.

Net finance costs of $20 million included realised foreign exchange hedge losses of $13 million and other foreign exchange gains of $46 million (2013 net finance costs of $79 million included foreign exchange losses of $43 million).

Business Review - Group continued

Fourth quarter continued

The Group's taxation for the quarter (including BG Group's share of joint venture and associates' taxation) amounted to a charge of $289 million. This charge was 58% lower than last year, reflecting the fall in taxable profits combined with the impact of a reduction in the Group's 2014 full year effective tax rate recognised in the quarter. The lower effective tax rate includes the impact of changes in the Group's mix of profits across jurisdictions.

Group earnings of $915 million and EPS of 26.8 cents per share decreased by 19% and 20% respectively as a result of the reduction in total operating profit, partly offset by the reduction in the Group's full year effective tax rate.

Net cash flow from operating activities decreased $410 million as a result of lower operating profit, partly offset by lower working capital cash outflow which included partial repayments of outstanding debt in Egypt.

Capital investment on a cash basis of $2 401 million was almost entirely in the Upstream segment ($2 399 million) and concentrated primarily on the Group's key growth projects in Australia and Brazil, together with investments in Egypt, the UK and Norway. Further details are provided in the Fourth quarter business highlights section (see page 6) and the Supplementary information: Operating and financial data section (see page 35).

Free cash flow improved by $347 million to $(945) million with the lower net cash flow from operating activities more than offset by a $782 million reduction in capital investment, mainly in Australia reflecting the Group's lower equity holding and completion of significant development activities ahead of delivery of first LNG in December.

Gearing increased to 29.2% primarily as a result of the non-cash impairments to Upstream activities in Australia, Egypt and certain other assets. Further details are given in the Total Results on page 4 and Note 2, Disposals, re-measurements and impairments on page 25.

Full year

Revenue and other operating income increased 2% to $19 546 million, driven by the LNG Shipping & Marketing segment which benefited from higher realised prices in the first half of 2014 and the end of the Group's historical LNG hedge programme. Upstream revenues reflected a doubling of oil volumes from Brazil (up 39 kboed), which were more than offset by lower net production across other fields, primarily Egypt (down 50 kboed) and the US (down 19 kboed), and lower oil and liquids prices which were not fully hedged.

Total operating profit decreased 14% to $6 537 million. Brazil contributed strong growth in operating profit and E&P unit margins, with revenue growth outstripping the expected cost increases associated with the ramp-up of production. However, this was more than offset by significant profit reductions in the UK, as a result of the higher cost of new developments and shutdowns, and in Kazakhstan, largely reflecting the Group's lower PSC revenue entitlement. LNG Shipping & Marketing total operating profit also decreased as a result of lower realised margins, reflecting an increase in the number of spot cargo purchases and reduced supply from Egyptian LNG.

Net finance costs of $133 million included realised foreign exchange hedge gains of $28 million and other foreign exchange gains of $21 million (2013 net finance costs of $203 million included foreign exchange losses of $44 million).

The Group's effective tax rate for the full year (including BG Group's share of joint venture and associates' taxation) was 37% compared to 41% in 2013. The reduction in the 2014 full year effective rate from the previous guidance of 40%, provided in the third quarter, includes the impact of changes in the Group's mix of profits across jurisdictions.

Group earnings of $4 035 million and EPS of 118.4 cents both decreased 8% as a result of the reduction in total operating profit, partly offset by the reduction in the Group's full year effective tax rate.

Net cash flow from operating activities decreased by $418 million as a result of lower operating profit, partly offset by lower working capital cash outflow.

Capital investment on a cash basis of $9 402 million was almost entirely in the Upstream segment ($9 387 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 35).

Free cash flow improved by $1 398 million to $(2 228) million. The decrease in net cash flow from operating activities was more than offset by a $1 813 million reduction in capital investment, mainly in Australia.

Business Review - Group continued

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

Fourth quarter impairments

A non-cash impairment charge of $8.9 billion pre-tax ($5.9 billion post-tax) has been recognised in the fourth quarter results. This was driven mainly by the significant fall in global commodity prices and reflects a recent forward Brent price curve for five years, reverting to the Group's long-term price assumption for impairment testing of $90 real from 1 January 2020.

In Australia, the total pre-tax non-cash impairment charge was $6.8 billion ($4.5 billion post-tax). With the agreement to sell the wholly-owned subsidiary QCLNG Pipeline Pty Ltd, the remaining QCLNG assets have been impaired by $2.7 billion pre-tax ($1.8 billion post-tax). On completion, expected in the first half of 2015, this charge is expected to be offset by an estimated pre-tax profit on disposal of around $3.3 billion. A further $4.1 billion pre-tax ($2.7 billion post-tax) non-cash impairment charge in Australia is driven mainly by a reduction in the Group's assumptions of future commodity prices.

In Egypt, the total pre and post-tax non-cash impairment charge was $0.8 billion, principally driven by further reserve 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 of future commodity prices has resulted in a $1.3 billion pre-tax ($0.6 billion post-tax) impairment charge of which the most significant charges are in the North Sea $0.6 billion pre-tax ($0.2 billion post-tax), Tunisia $0.5 billion pre-tax ($0.3 billion post-tax), and the USA $0.2 billion pre-tax ($0.1 billion post-tax).

For further information see Note 2, Disposals, re-measurements and impairments (page 25).

Fourth quarter

Total earnings for the quarter were a loss of $5 030 million (loss of 147.5 cents per share). The results for the quarter included the $5 939 million of post-tax impairments outlined above, partially offset by $449 million of exceptional one-off and prior period taxation credits. Further details are provided in Note 2, Disposals, re-measurements and impairments (page 25). Total earnings in 2013 were a loss of $1 066 million (loss of 31.3 cents per share) and included a post-tax charge of $2 201 million in respect of disposals, re-measurements and impairments. Post-tax non-cash impairments in 2013 were $1 286 million in Egypt and $1 105 million in the USA.

Full year

Total earnings for the full year were a loss of $1 051 million (loss of 30.8 cents per share). The results for the year included $5 928 million of post-tax impairments, partially offset by $782 million gain arising on the disposal of the CATS pipeline in the UK and $449 million of exceptional one-off and prior period taxation credits. Total earnings for 2013 were $2 205 million (64.8 cents per share) and included a post-tax charge of $2 169 million in respect of disposals, re-measurements and impairments, primarily reflecting impairments in Egypt and the USA.

For further information see Presentation of Non-GAAP measures (page 16) and notes 1 to 3 (pages 24 to 28).

2014 final dividend

Taking into account the current low commodity price environment and consequent outlook for earnings and cash flow, the Board has recommended a final dividend of 14.37 cents per share (9.52 pence per share), bringing the full year dividend to 28.75 cents per share (17.99 pence per share), in line with 2013. The proposed final dividend of 14.37 cents per share is payable on 22 May 2015 to shareholders on the register at close of business on 24 April 2015.

2015 outlook

In 2015, BG Group's production volumes are expected to be in the range of 650 - 690 kboed, excluding any further changes to the portfolio, as continued growth in Brazil and Australia more than offsets lower net volumes elsewhere, primarily in Egypt, Kazakhstan, the UK and Trinidad and Tobago.

In Australia, Train 1 at the Group's QCLNG project should reach plateau output of around 4 million tonnes per annum (mtpa) in the second quarter, with Train 2 expected to come onstream in the third quarter. Plateau production from both trains of around 8 mtpa should be reached by mid-2016. Up to 20% of gas for the two trains will be supplied by third-party contracts during the ramp-up phase.

In Brazil, the fourth and fifth FPSOs, Cidade de Ilhabela and Cidade de Mangaratiba respectively, will continue to ramp-up during 2015 with additional well connections. The operator expects the sixth FPSO, Cidade de Itaguai, onstream in the fourth quarter of 2015.

LNG Shipping & Marketing supply volumes are expected to be slightly lower than 2014, excluding the purchase of spot cargoes and the impact of new volumes from QCLNG. As previously disclosed, the majority of the contribution from QCLNG will be reported in the Upstream segment of the business. Based on recent forward commodity price curves, the Group expects the segment's total operating profit to be between $0.7 - 1.0 billion in 2015.

Planned capital expenditure on a cash basis in 2015 is expected to be significantly lower than 2014, as projects complete and the Group reacts to a lower oil price environment. Capital expenditure on a cash basis is expected to fall to between $6 - 7 billion in 2015.

Based on recent forward commodity price curves, the Group expects its effective tax rate to be around 45% in 2015. However, given the volatility in commodity prices, it is currently anticipated that this effective rate may be subject to significant movements during the year and could therefore outturn in the range 40% to 50%. Further guidance on the effective tax rate will be provided during the course of 2015.

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

Fourth quarter business highlights

Overview

E&P production was 630 thousand barrels of oil equivalent per day (kboed), down 1% from the fourth quarter of 2013, as increased production from Brazil (+59 kboed) and Australia (+22 kboed) was more than offset by declines in Egypt (-34 kboed) and the USA (-13 kboed), timing of shutdowns in the UK (-25 kboed) and PSC impacts in Kazakhstan (-16 kboed).

The LNG Shipping & Marketing segment supplied 44 cargoes (2.7 million tonnes) in the quarter, two fewer than the fourth quarter of 2013 (2.8 million tonnes); 30 of these cargoes were supplied to Asian markets (2013 37).

Australia

In December, BG Group announced the successful start-up of Train 1 at its Queensland Curtis LNG (QCLNG) project, the world's first coal seam gas (CSG) to liquefied natural gas (LNG) facility. The first LNG cargo left QCLNG in early January with a further two cargoes shipped during the month. The Group continues to expect Train 1 to reach plateau output of around 4 mtpa during the second quarter.

Development of the second LNG train on Curtis Island continues. While development and commissioning of an LNG train is a complex process and not without risk, the Group remains on track to start-up Train 2 in the third quarter of 2015. Plateau production from both LNG trains, anticipated by mid-2016, is expected to be around 8 mtpa.

Gas delivery to the LNG plant has increased as commissioning progresses, with equity gas supply increasing in line with expectations. In the fourth quarter, equity production of 46 kboed was more than 30% higher than the third quarter of 2014 and almost double that of the fourth quarter of 2013. In January, net production reached around 60 kboed.

As previously indicated, BG Group will utilise a mix of third-party and equity gas to supply the LNG plant. The Group will manage the optimum supply mix to reflect upstream and plant performance and continues to expect that, on average, up to 20% of gas will be supplied by third-party contracts during the ramp-up phase.

Around 2 350 CSG wells have been drilled as at the end of the fourth quarter, with around 1 600 CSG wells available for production or de-watering. Average flow rates continue to be in line with expectations.

Brazil

Production from the Group's Santos Basin interests continues to grow. With the start-up of the fourth and fifth floating production, storage and offloading (FPSO) vessels in the fourth quarter, average net production was 103 kboed. Further, with subsequent well connections, net production in January reached more than 125 kboed.

Following first production from the 150 kbopd Cidade de Mangaratiba (FPSO 5) at Iracema South in October, initial production rates of around 10 kbopd have increased to greater than 30 kbopd with the commissioning of gas and reinjection systems. The second producer well came onstream in December, further increasing production to over 65 kbopd. With four more producer wells already drilled, production will continue to increase through 2015 with further well connections. The operator expects the FPSO to reach plateau in the first half of 2016.

In November, the 150 kbopd Cidade de Ilhabela (FPSO 4) began production at Sapinhoá North. This is the second and final FPSO to be deployed on the Sapinhoá field in accordance with the Development Plan approved by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP). Six more producer wells have already been drilled and production will increase through 2015 as further wells are connected to the FPSO. The operator expects the FPSO to reach plateau in the second half of 2015.

Construction of the 150 kbopd Cidade de Itaguai (FPSO 6) for Iracema North is well advanced and in January it arrived in Brazil for integration work. The operator continues to expect first oil in the fourth quarter of 2015.

In 2015, along with a focus on connecting pre-drilled wells to installed FPSOs and the delivery of the sixth FPSO, the second gas evacuation route via the Cabiúnas pipeline will continue to advance. During 2015, the final sections of the offshore pipeline will be installed and the pre-commissioning completed.

Fourth quarter business highlights continued

Brazil continued

The remaining three leased FPSOs (to be deployed at Lula Alto, Lula Central and Lapa) remain on schedule for first production in 2016. Work is ongoing at shipyards in China, Japan and Singapore ahead of integration works to be conducted at the Brasa and BrasFELS shipyards in Rio de Janeiro, Brazil. The first replicant FPSO, P-66, has arrived at the BrasFELS shipyard where integration works have commenced.

In December, the BM-S-11 consortium submitted the Declarations of Commerciality (DoC) to the ANP for three separate oil and gas accumulations in the Iara area, offshore Brazil. As part of the DoC, the consortium has suggested that the new fields be designated Berbigão, Sururu and Atapú West. These three accumulations extend outside the BM-S-11 Iara concession area and into the Entorno de Iara Transfer of Rights area which is 100% operated by Petrobras and will therefore be subject to unitisation agreements. The total amount of resource that BG Group believes will ultimately be recovered post unitisation is not expected to be affected.

UK

The Armada, Everest and Lomond fields were shut in during the fourth quarter for planned asset integrity and maintenance programmes. Planned maintenance work on the Armada hub was completed in December while the asset integrity programme on Lomond is scheduled to complete later in the first quarter. The scope of the Everest campaign was reduced following storm damage to the flotel in October. The outstanding work programme has been added to the next Everest campaign, scheduled for the summer of 2015. Production from all three assets is expected to recommence following the completion of repairs to a valve on the CATS Riser Tower.

In January 2015, production commenced from Phase 2 of the West Franklin development, in which BG Group has a 14.1% interest. The project involved drilling three wells and installing two new platforms that have been tied back to existing facilities. The field is expected to deliver BG Group net production of around 6 kboed.

Norway

In December, all six riser systems were connected to the Petrojarl Knarr FPSO (28 kboed capacity BG Group net). Unfavourable weather conditions have hindered subsequent start-up activities. Production is expected to commence later in the first quarter, subject to favourable weather conditions. The Knarr field, which was discovered in 2008, has estimated gross recoverable reserves of around 80 million barrels of oil equivalent.

Egypt

E&P production in the fourth quarter was 68 kboed, ahead of the second and third quarters of 2014 largely reflecting the impact of new wells from the Phase 9a development, although 33% lower than the fourth quarter of 2013. The reduction reflects deteriorating reservoir performance and the continued high proportion of diversions of gas to the domestic market, where the Group is entitled to a lower share of production. Eight of the nine Phase 9a wells are now onstream. This development will only temporarily offset underlying E&P production declines.

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

BG Group continues to evaluate options for increasing domestic gas supplies to Egypt and gas supplies for Egyptian LNG. In November, BG Group signed an agreement with GDF Suez enabling development of their gas discovery through the utilisation of BG Group's infrastructure for onward delivery of gas to Egypt's domestic market. First gas from GDF Suez is expected in 2018 at rates of around 100 mmscfd.

The Egyptian government continues to demonstrate its commitment to repay outstanding debts to the energy industry. Following partial repayment of the outstanding debt in October and December, the amount owed by the Egyptian government was reduced to $0.9 billion, with $0.7 billion overdue at the year end.

In 2014, activities in Egypt accounted for around 10% of BG Group's production and around 6% of business performance earnings. The Group expects the earnings and production contribution from Egypt to continue to reduce over time.

Fourth quarter business highlights continued

Trinidad and Tobago

In December, BG Group delivered first gas from the Starfish field located in the East Coast Marine Area (BG Group 50% equity and operator). Production from this field is exported via the Dolphin platform and will maintain a reliable flow of gas to the domestic market and to the Atlantic LNG facility. 

Bolivia

In December, BG Group and partners signed an amendment to the Delivery Agreement with Yacimientos Petroliferos Fiscales Bolivianos (YPFB) to allow for the export of additional volumes from Margarita Phase IIb, which is expected to increase production capacity from around 42 kboed to around 47 kboed net to BG Group by 2016.

USA

The Lake Charles project remains one of the most competitive new supply sources for LNG benefitting from existing infrastructure and access to a highly developed and liquid gas market. The Federal Energy Regulatory Commission (FERC) issued its Notice of Schedule for Environmental Approval for the project on 26 January 2015, and BG Group expects FERC authorisation for the project in late 2015. The Group continues to monitor the commodity price environment and any impact this may have on construction costs. BG Group now expects a sanction decision for the project in 2016.

Portfolio management

In December, BG Group agreed to sell its wholly-owned subsidiary QCLNG Pipeline Pty Ltd, the owner of the543 kilometre pipeline network linking the Group's gas fields to its two-train LNG export facility, for approximately $5.0 billion. BG Group and its partners have firm capacity rights in the pipeline for 20 years, with options to extend.The sale of this non-core infrastructure is consistent with BG Group's strategy of actively managing its global asset portfolio and is conditional on the start of commercial LNG deliveries (post commissioning) from the QCLNG export facility and on partner consent. On completion, forecast for the first half of 2015, the transaction is now expected to result in a pre-tax profit on disposal of around $3.3 billion. The proceeds will be used to reduce net debt and to fund future growth investment.

Also in December, BG Group entered into an agreement for the sale of two modern tri-fuel diesel electric LNG carriers for proceeds of $460 million. BG Group will charter back the two vessels for nine and 11 years with further options to extend the term for each vessel by either three or five years. The transactions provide BG Group with flexibility in managing its future fleet requirements while leaving day-to-day operations broadly unchanged.

The LNG carriers are currently associated with a Pension Funding Partnership which is one element of the Group's funding arrangements for the BG Pension Scheme. Consequently, the majority of the proceeds from this sale will be utilised to support the funding of that scheme. The remaining net proceeds from the transaction of around $100 million will be used to reduce the Group's net debt.

Closing of the transaction is subject to the satisfaction of certain conditions, including completion of definitive documentation, and is expected in the first quarter of 2015, with the charter agreement expected to commence at the same time.

Board appointment

Following extensive shareholder consultation and in response to shareholder concerns, the BG Group Board and incoming Chief Executive Helge Lund agreed in December revisions to Mr Lund's remuneration package.The revised package brings all elements of Mr Lund's remuneration within the Company's remuneration policy approved by shareholders in May 2014. Mr Lund will be joining BG Group shortly.

Capital and Liquidity

The Group maintains a strong liquidity position. At the end of 2014, BG Group had cash and cash equivalents of $5.3 billion. The Group also expects to receive cash disposal proceeds of approximately $5.5 billion in the first half of 2015 from the sale of QCLNG Pipeline Pty Ltd and two LNG carriers. Further details of these sales are given in the Portfolio management section on page 8. The proceeds from these sales will be used primarily to reduce net debt and to fund future investment growth.

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).

At the end of 2014, 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 $7.0 billion was unutilised.

BGEH also 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. In addition, BGEH had an undrawn £250 million committed revolving bank borrowing facility which expires in 2015 and a further credit facility provided by an export credit agency, of which $1.7 billion was undrawn.

During the fourth quarter of 2014, the Group issued €1.575 billion (around $2.0 billion equivalent) of bonds in tranches of €775 million and €800 million, maturing in 2022 and 2029, respectively.

Risk management for commodity prices and foreign exchange rates 

Commodity prices

In the first quarter of 2014, BG Group entered into Brent oil swaps at an average price of $106 per barrel for the period of April through December 2014. The Brent oil price in the fourth quarter was $73 per barrel. As a result of the fall in the Brent oil price, $229 million pre-tax realised gains were recognised in the fourth quarter, almost all of which was recognised in the Upstream segment in accordance with the Group's actual Brent exposure. The total pre-tax realised gain in 2014 was $222 million, with an additional $17 million of pre-tax unrealised gains as at year end.

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.

BG Group has no material commodity price hedges in place for 2015.

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 were 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 fourth quarter, $13 million pre-tax realised losses and $3 million pre-tax unrealised gains were recognised in the income statement with a further $4 million realised gains capitalised as assets under construction. For the full year, $28 million pre-tax realised gains were recognised in the income statement, with a further $23 million realised gains capitalised as assets under construction.

Upstream

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

Additional operating and financial data is given on page 35. 

Upstream continued

Upstream continued

Fourth quarter

Production volumes decreased 1% as additional installed capacity and ramp-up in Brazil, the ramp-up in Australia as part of the commissioning process for Train 1 at QCLNG, and new developments onstream in Bolivia and the UK, were more than offset by reservoir decline and lower entitlement in Egypt, deferred shutdowns in the UK, lower entitlement in Kazakhstan and declines in the USA.

Revenue and other operating income decreased 20% to $2 723 million, primarily reflecting lower commodity prices, particularly oil and liquids, partially offset by a $228 million gain on the Group's oil hedging programme.

The Group's average realised oil price (unhedged) decreased 31% to $75.83 per barrel and the liquids price decreased 32% to $64.34 per barrel, reflecting movements in market prices. The average realised gas price per produced therm decreased 9% to 42.88 cents, with lower international gas price realisations (down 6%) and lower market prices in the UK (down 7%).

E&P operating profit, before exploration, of $862 million was down 42%, largely reflecting lower revenues. Higher operating costs, primarily in Brazil and the UK, were offset by lower DD&A, mainly in Egypt. Consequently, the Group's unit E&P EBIT margin was $10.55 per barrel of oil equivalent (boe) lower at $14.88 per boe and the unit EBITDA margin was $12.77 per boe lower at $24.61 per boe.

Unit operating expenditure increased to $14.98 per boe (2013 $13.02 per boe), reflecting the higher royalty costs and special participation fees in Brazil, and additional maintenance costs in the UK, as well as lower Group volumes.

Other E&P unit costs were broadly flat at $6.56 per boe (2013 $6.65 per boe).

The unit DD&A charge decreased to $9.73 per boe (2013 $11.95 per boe) as a result of a reduced depreciation charge in Egypt following the impairment in 2013, as well as reserves maturation in Brazil and a change in the UK production mix resulting from the planned shutdowns in 2014.

The exploration charge of $238 million decreased 36% principally as a result of lower well write offs. Gross exploration expenditure of $347 million included spend in Australia ($86 million), Trinidad and Tobago ($32 million), Norway ($27 million), Tanzania ($23 million) and UK ($21 million).

BG Group's share of operating profit from liquefaction activities decreased 16% to $49 million, as a result of significantly lower throughput at Egyptian LNG which is expected to continue for the foreseeable future, and initial commissioning costs and depreciation charges at QCLNG.

Business development costs of $28 million were incurred as the Group progressed potential integrated LNG projects in Tanzania and western Canada.

Capital investment on a cash basis of $2 399 million included investment in Australia ($901 million), Brazil ($719 million), Egypt ($172 million), the UK ($151 million) and Norway ($85 million).

Full year

Production volumes decreased 4%. The continued ramp-up of production from new developments in Brazil, Bolivia, Australia and the UK were more than offset by reservoir decline and lower entitlement in Egypt, declines in the USA, lower entitlement in Kazakhstan and shutdowns in Tunisia.

Revenue and other operating income decreased 1% to $12 026 million. Revenue declines primarily reflected lower oil and liquids prices, which were not fully hedged. This was offset by a material increase in the proportion of oil in the portfolio, primarily associated with the ramp-up of production in Brazil where production doubled.

The Group's average realised oil price (unhedged) decreased 9% to $98.78 per barrel. The liquids price decreased 13% to $80.74 per barrel, reflecting movements in market prices, coupled with the lower revenue entitlement in Kazakhstan. The Group's average realised gas price per therm increased 2%, as a favourable change in the mix of fields was partly offset by a 19% reduction in the average realised UK gas price reflecting lower market prices.

E&P operating profit, before exploration, of $4 448 million was down 18%. Brazil contributed strong growth in operating profit and E&P unit margins, with revenue growth outstripping the expected cost increases associated with the ramp-up of production. However, this was more than offset by significant reductions in profit in the UK, as a result of the increased cost of new developments coming onstream and additional maintenance, and in Kazakhstan as a result of revenue declines including a lower revenue entitlement.

Upstream continued

Full year continued

Consequently, the Group's unit E&P EBIT margin was $3.40 per boe lower at $20.12 per boe and the unit E&P EBITDA margin was $3.71 per boe lower at $31.11 per boe.

Unit operating expenditure increased to $15.54 per boe (2013 $12.16 per boe) reflecting higher royalty costs and special participation fees in Brazil, higher royalties from new developments in Bolivia and additional maintenance and tariff costs in the UK (the latter including the impact of the disposal of the CATS pipeline in the third quarter).

Other E&P unit costs increased to $6.04 per boe (2013 $3.87 per boe) and included a number of one-off items combined with the impacts in Brazil of the timing of oil liftings, increased oil shipping activity and eliminations of profit on oil sales from extended well tests.

The unit DD&A charge decreased to $10.99 per boe (2013 $11.30 per boe) as a result of the non-cash impairment in Egypt in 2013 and reserves maturation in Brazil, partly offset by a higher charge from new developments in the UK.

The exploration charge of $751 million increased 6% as a result of higher seismic acquisition costs, partly offset by lower well write offs. Gross exploration expenditure of $1 260 million included spend in Australia ($257 million), Tanzania ($256 million), Trinidad and Tobago ($153 million), Brazil ($70 million) and Kenya ($67 million).

BG Group's share of operating profit from liquefaction activities decreased 20% to $289 million, as a result of significantly lower throughput at Egyptian LNG, partly offset by higher sales prices at Atlantic LNG Train 1.

Business development costs of $39 million were incurred as the Group progressed potential integrated LNG projects in Tanzania and western Canada, and includes the reimbursement of previous business development expenditure from a partner.

Capital investment on a cash basis of $9 387 million included investment in Australia ($3 871 million), Brazil ($2 435 million), the UK ($549 million), Egypt ($485 million) and Norway ($429 million).

LNG Shipping & Marketing

Additional operating and financial data is given on page 35.

Fourth quarter

Revenue and other operating income was 9% lower, as a result of lower LNG sales prices and lower delivered volumes. Overall, volumes decreased 4% with fewer cargoes from Egypt (from 6 cargoes in 2013 to zero in 2014) and Equatorial Guinea, partly offset by more cargoes from Trinidad and Tobago and additional spot cargo purchases. 

Shipping and marketing operating profit decreased 32% to $556 million, reflecting lower revenues combined with higher costs of supply, including the increase in spot cargo purchases.

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

LNG Shipping & Marketing continued

Full year

Revenue and other operating income was 7% higher as a result of lower losses from the Group's historical LNG hedging programme, which completed in the first quarter of 2014, and favourable LNG sales prices in the first half of 2014. Overall volumes increased 1% despite fewer cargoes delivered from Egypt (falling from 25 in 2013 to one in 2014) primarily as a result of an increase in spot cargo purchases.

Shipping and marketing operating profit decreased 4% to $2 668 million, reflecting lower margins from higher costs of supply primarily as a result of the increase in spot cargo purchases.

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

Presentation of Non-GAAP measures

Legal Notice

Consolidated Income Statement

Fourth Quarter

a) See Presentation of Non-GAAP measures (page 16) 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 $(5 030) million (2013 $(1 066) million) and from discontinued operations of $nil (2013 $(13) 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 24 to 34 form an integral part of these condensed financial statements.

Consolidated Income Statement

Full Year

a) See Presentation of Non-GAAP measures (page 16) 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 $(1 051) million (2013 $2 205 million) and from discontinued operations of $7 million (2013 $236 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 24 to 34 form an integral part of these condensed financial statements.

For information on dividends paid in the period, see note 9 (page 34).

Consolidated Statement of Comprehensive Income

a) Income tax relating to hedge adjustments is a $82 million credit for the quarter (2013 $54 million charge) and a $125 million credit for the full year (2013 $90 million charge).

b) Income tax relating to the re-measurement of defined benefit pension obligations is a $43 million credit for the quarter (2013 $4 million charge) and a $45 million credit for the full year (2013 $nil).

The notes on pages 24 to 34 form an integral part of these condensed financial statements.

Consolidated Balance Sheet

(a) Assets and liabilities classified as held for sale includes QCLNG Pipeline Pty in Australia and two LNG ships.

The notes on pages 24 to 34 form an integral part of these condensed financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 24 to 34 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 32).

a) Includes profit before tax from discontinued operations for the quarter of $nil (2013 $12 million loss) and for the full year of $9 million (2013 $258 million).

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

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

The notes on pages 24 to 34 form an integral part of these condensed financial statements.

Notes

1. Basis of preparation

These results which are unaudited and approved by the Board on 2 February 2015, are the condensed financial statements ('the financial statements') of BG Group plc for the quarter ended and the full year ended 31 December 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 Auditor's 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 2013, except as stated below.

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

A single amount is presented on the income statement for discontinued operations, comprising the post-tax results of these businesses and the post-tax profit or loss recognised on re-measurement to fair value less costs of disposal and on disposal of the businesses.

Presentation of results

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

· The re-measurement of certain financial instruments; and

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

These items, which are detailed in note 2 to the financial statements (page 25), 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 31 December 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

Fourth quarter and full year: Revenue and other operating income

Re-measurements included within revenue and other operating income amount to a credit of $17 million for the quarter (2013 $2 million), of which a credit of $126 million (2013 $35 million debit) represents non-cash mark-to-market movements on certain gas contracts. For the full year, a credit of $403 million in respect of re-measurements is included within revenue and other operating income (2013 $210 million), of which a credit of $280 million represents non-cash mark-to-market movements on certain gas contracts (2013 $34 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 $110 million debit for the quarter (2013 $37 million credit) and a net $17 million credit for the full year (2013 $176 million) representing unrealised mark-to-market movements associated with economic hedges, including a debit of $82 million in the quarter and a credit of $17 million in the full year associated with Brent oil swaps partially hedging the Group's exposure to commodity prices in 2014. Other operating income in 2014 for the quarter also includes $1 million credit and the full year includes $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 for the quarter include a $100 million pre-tax ($79 million 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. 2014 also includes a $79 million pre-tax charge (post-tax $62 million) in the full year relating to restructuring costs in the UK, Egypt and Australia. Operating costs in 2013 comprise a curtailment gain of $154 million in respect of the closure of the BG Group UK defined benefit pension scheme to future accrual of benefits on 31 December 2013.

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

The quarter included a further pre and post-tax gain of $11 million in respect of the disposal of the Central Area Transmission System (CATS) gas pipeline in the UK. The third quarter of 2014 included a pre and post-tax gain of $771 million in respect of the disposal of CATS. 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.

In the fourth quarter of 2013, BG Group completed transactions with China National Offshore Oil Corporation (CNOOC) for the sale of certain additional interests in the QCLNG project in Australia for total consideration of $3.8 billion, resulting in a pre and post-tax profit on disposal of $31 million, and the sale of its 50% holding in TGGT in the USA, resulting in a pre-tax profit on disposal of $187 million (post-tax $98 million). The third quarter of 2013 included a pre-tax profit of $140 million (post-tax $107 million) in respect of the disposal of the Group's remaining 20% equity in the Quintero LNG regasification facility in Chile, partially offset by a pre-tax charge of $10 million (post-tax $8 million) as a result of land relinquishments in the USA. The second quarter of 2013 included a pre-tax charge of $116 million (post-tax $75 million) as a result of land relinquishments in the USA.

2. Disposals, re-measurements and impairments continued

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

Other disposals in 2014 resulted in a pre-tax charge to the income statement of $6 million (2013 $1 million loss) in the fourth quarter (post-tax $6 million gain, 2013 $5 million loss) and a pre-tax charge of $31 million (2013 $21 million gain) for the full year (post-tax $18 million, 2013 $21 million gain).

Fourth quarter and full year: Impairments

In 2014, the fourth quarter included a 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 is driven mainly by the significant fall in global commodity prices and reflects a recent forward Brent price curve for five years, reverting to the Group's long-term price assumption for impairment testing of $90 real from 1 January 2020.

In Australia, the total pre-tax non-cash impairment charge was $6 824 million ($4 540 million post-tax). With the agreement to sell the wholly-owned subsidiary QCLNG Pipeline Pty Ltd, the remaining QCLNG assets have been impaired by $2 747 million pre-tax ($1 828 million post-tax). On completion, expected in the first half of 2015, this charge is expected to be offset by an estimated pre-tax profit on disposal of around $3.3 billion. A further $4 077 million pre-tax ($2 712 million post-tax) non-cash impairment charge in Australia is driven mainly by a reduction in the Group's assumptions of future commodity prices.

In Egypt, the total pre-tax non-cash impairment charge was $750 million ($775 million post-tax), principally driven by further reserve 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 of future commodity prices has resulted in a $1 298 million pre-tax ($624 million post-tax) impairment charge of which the most significant charges are 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.

In 2013, the fourth quarter included a pre-tax charge of $2 000 million (post-tax $1 286 million) in relation to the Group's upstream operations in Egypt. The impairment charge resulted from reserve revisions and revised expectations of the value of its Egyptian operations, given continuing uncertainty over the business environment in Egypt. In addition, there was a pre-tax charge of $1 700 million (post-tax $1 105 million) in relation to the impairment of the Group's shale gas business in the USA. The impairment was against the backdrop of lower forward gas market prices, lower production expectations based on well performance and the continued low rig count.

Other impairments in 2014 resulted in a pre-tax charge to the income statement of $55 million (2013 $56 million) in the fourth quarter (post-tax $49 million, 2013 $40 million) and a pre-tax charge of $55 million (2013 $359 million) for the full year (post-tax $49 million, 2013 $179 million).

Fourth quarter and full year: Other

Other items in 2014 resulted in a pre-tax charge of $89 million (2013 $1 million) in the fourth quarter (post-tax $58 million, 2013 $2 million gain) and a pre-tax charge of $131 million (2013 $11 million) for the full year (post-tax $95 million; 2013 $5 million).

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

Re-measurements presented in net finance costs includes mark-to-market movements on certain derivatives used to hedge foreign exchange and interest rate risk and foreign exchange movements on borrowings and certain intercompany balances. In addition, re-measurements include a gain of $3 million in the fourth quarter and $nil for the full 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.

2. Disposals, re-measurements and impairments continued

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

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.

Fourth quarter and full year: Taxation

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 these amounts is a net credit of $449 million resulting from a number of exceptional one-off and prior period taxation items recognised in the quarter. These items 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

a) Business Performance Other operating income is attributable to segments as follows: Upstream $194 million (2013 $6 million) and LNG Shipping & Marketing $3 million (2013 $(30) million).

3. Segmental analysis continued