Final Results

LONDON--(BUSINESS WIRE)--

CENTRICA PLC

PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2011

OPERATING AND FINANCIAL OVERVIEW

RESILIENT FINANCIAL PERFORMANCE IN CHALLENGING CONDITIONS

• Adjusted earnings^◊ up 3% to £1,333 million; 25.8 pence adjusted basic earnings per share^◊
• British Gas Residential operating profit* down 30% to £522 million
• Upstream UK operating profit* up 33% to £1,023 million
• North America operating profit* up 33% to £312 million
• Adjusted tax charge^{^} increased from £761 million to £891 million; 40% effective tax rate^{^}
• £500 million cost reduction programme underway to maintain competitiveness and enable growth

DELIVERING INVESTMENT FOR GROWTH

• £1.6 billion invested in 2011; already announced a further £1.4 billion of acquisitions for 2012
• Established long term strategic partnerships with Qatargas and Statoil
• Commitments to secure gas for the UK now total over £50 billion
• Upstream UK gas and oil production expected to increase by over 25% in 2012
• Lincs offshore windfarm on track to produce first power this year

DELIVERING FOR OUR CUSTOMERS

• First of the major energy suppliers to cut prices in 2012
• Cheapest standard electricity of any major supplier at average consumption
• Actual household dual fuel bill £37 lower on average in 2011 at £1,024
• Introduced tariff checker for customers
• Widest eligibility for Warm Home Discount

DELIVERING FOR OUR SHAREHOLDERS

• Full year dividend up 8% to 15.4 pence per share, reflecting long-term growth through investment

“2011 was a tough year, both for Centrica and our customers. But the strength of our integrated business and balance sheet means we’ve been able to take the lead in helping customers through these difficult times, as well as delivering growth and making the investments on which Britain’s energy future depends.”

Sam Laidlaw
Chief Executive

STATUTORY RESULTS

• Operating profit^‡: £1,414m (2010: £3,074m)
• Earnings: £421m (2010: £1,942m)
• Basic earnings per ordinary share: 8.2p (2010: 37.6p)
• Earnings include exceptional items relating to provisions for onerous contracts, impairments, restructuring costs, contract migration, a change in the UK upstream tax rate, an exceptional credit relating to pension curtailment and a loss on disposal of Oxxio. The total impact is a charge of £522 million after taxation.

A definition of the profit measures used throughout these results is provided in the Group Financial Review. A reconciliation between operating profit and adjusted operating profit is provided in note 5(b) and a reconciliation between the earnings measures is provided in note 10. Further details on exceptional items are included in the Group Financial Review and in note 6.

FINANCIAL PERFORMANCE AND KPIS

FINANCIAL PERFORMANCE

For the year ended 31 December	2011	2010	∆
Revenue^‡	£22.8bn	£22.4bn	2%
Adjusted operating profit^‡*
Downstream UK
Residential energy supply	£522m	£742m	(30%)
Residential services	£264m	£241m	10%
Business energy supply and services	£219m	£233m	(6%)
Total Downstream UK	£1,005m	£1,216m	(17%)
Upstream UK
Gas	£769m	£566m	36%
Power	£254m	£205m	24%
Total Upstream UK	£1,023m	£771m	33%
Storage UK	£75m	£169m	(56%)
North America	£312m	£234m	33%
Total adjusted operating profit^‡*	£2,415m	£2,390m	1%
Total adjusted taxation charge^^	£891m	£761m	(17%)
Total adjusted effective tax rate^^	40%	37%	(3ppt)
Adjusted earnings^◊	£1,333m	£1,297m	3%
Adjusted basic earnings per share^◊	25.8p	25.2p	2%
Full year dividend per share	15.4p	14.3p	8%

KEY OPERATIONAL PERFORMANCE INDICATORS

For the year ended 31 December	2011	2010	∆
UK residential energy customer accounts (year end, ’000)	15,881	15,978	(1%)
UK residential services product holdings (year end, ’000)	8,862	8,718	2%
UK business energy supply points (year end, ’000)	999	1,044	(4%)
Upstream UK gas production (mmth)	2,160	2,550	(15%)
Upstream UK liquids production (mmboe)	12.5	11.8	6%
Upstream UK total gas and liquids production (mmboe)	48.2	54.2	(11%)
Upstream UK proven and probable reserves (year end, mmboe)	440	434	1%
Upstream UK power generated (TWh)	26.7	32.9	(19%)
North America residential customer accounts (year end, ’000)	5,647	5,155	10%
North America proven and probable reserves (year end, mmboe)	109	96	14%
Group capital and acquisition expenditure (£m)	1,601	1,669	(4%)
Lost time injury frequency (per 100,000 hours worked)	0.25	0.43	42%

Earnings and operating profit numbers are stated, throughout the Chairman’s statement, Chief Executive’s review and Operating Review, before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements where applicable – see note 3 for definitions. In addition, all references to profit and loss are stated before share of joint venture and associate interest and tax. The Directors believe these measures assist with better understanding the underlying performance of the Group. The equivalent amounts after exceptional items and certain re-measurements are reconciled at Group level in the Group Income Statement. Exceptional items and certain re-measurements are described in note 6. Adjusted earnings and adjusted basic earnings per share are reconciled to their statutory equivalents in note 10. All current financial results listed are for the year ended 31 December 2011. All references to ‘the prior period’, ‘the prior year’, ‘2010’ and ‘last year’ mean the year ended 31 December 2010 unless otherwise specified.

* Including share of joint ventures and associates before interest and taxation, and before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements
◊ As above, except joint ventures and associates stated after interest and taxation
^ Includes taxation on profit from continuing operations and tax from joint ventures and associates as reconciled in the Group Financial Review
‡ From continuing operations

CHAIRMAN’S STATEMENT

REVIEW OF THE YEAR

2011 was a year of turbulence and challenge. At the beginning of the year there was little indication how dramatically events would unfold for the world in general or for Centrica in particular.

The Japanese nuclear power disaster at Fukushima in March cast a shadow over the industry as nuclear plants across the globe were shut down, driving up demand for gas and resulting in higher wholesale prices worldwide. Events in the Middle East and North Africa created further political and economic uncertainty as the unrest spread in the spring and energy prices reacted again to the increased risk to supplies.

In the wake of a 30% increase in wholesale gas prices and escalating losses in British Gas, we were faced with the need to implement a significant price increase, in the knowledge that any rise in the cost of living would be very difficult for hard pressed customers, already struggling in a severe economic downturn.

In an effort to mitigate the scale of the increase, whilst preserving a 6% pre-tax residential energy profit margin for the year, management conducted a thorough reappraisal of the cost structure of the Group. With considerable cooperation of the staff and unions, we were able to improve engineers’ rostering and customer service, lower future pension costs and reduce overheads through the loss of some 2,300 roles across the Group. This was painful but necessary to support our competitive position in challenging markets.

Maintaining an efficient cost structure, however, was not done at the expense of building talent for the future. British Gas continued to invest more than £25 million during the year in academies and apprenticeships, helping to train the young and re-skill older employees.

In parallel, we focussed on securing long term supplies of gas to provide security of supply for our customers. This was achieved by the completion of a ground breaking LNG agreement with Qatar, the acquisition of new gas fields for exploration and production and towards the end of the year, a long term supply agreement with Statoil in Norway.

In March however, our investment plans for the UK sector of the North Sea were undermined by the sudden imposition of higher taxes on production of oil and, most harmfully, gas. In spite of the representations made by ourselves and the rest of the industry to Government, no change was forthcoming to this damaging decision.

Centrica, together with other members of the industry, made it clear to Government ministers that capital intensive industries must have long term certainty of both regulatory and tax regimes if they are to be major investors in the UK energy infrastructure. Our own major shareholders echoed this view. As one of the UK’s largest taxpayers, with Centrica contributing around £800 million a year to the Treasury, it is hoped that our case has been heard.

On a more positive note, we have welcomed the Government’s proposals for Electricity Market Reform and the carbon floor price, as well as its commitment to the new nuclear programme. However, the detail still needs to be agreed, pace of progress to accelerate and economic returns to be in keeping with our commitment to shareholder value.

Whilst the upstream team were securing the Group’s future energy requirements, the downstream team continued to work with customers to help reduce consumption.

Household surveys and home insulation were provided free of charge to British Gas customers and new smart meters helped people monitor and manage their energy usage. We continue to pay particular care to the more vulnerable members of society.

As inflation increased and economic conditions became more difficult, energy companies found themselves the target of public criticism. British Gas, as the largest UK supplier, was at the forefront of the debate. The scale of price increases, driven by factors entirely beyond the control of the energy suppliers, were considered by much of the public to be unsupportable whatever the rationale for the increase.

It was for this reason that British Gas decided to embark on its ‘honest conversation’ campaign with customers in the late autumn.

The campaign sought to explain the factors that have given rise to increases in the energy bill, which are faced by all energy suppliers. We also reiterated Ofgem’s findings that there is no collusion in the sector and our view that pre-tax profits averaging 6-7% through the cycle are both modest and necessary to sustain the multi-billion pound investment programme required to secure UK energy supplies and deliver green energy efficiency. In parallel, British Gas led the way in tariff simplification.

There are signs that these actions are starting to resonate with the public and I hope that all commentators and the Regulator will take a more balanced view in the year to come.

We ended the year in the UK with the warmest last quarter on record which reduced consumption and meant that average customer bills for the year were lower than 2010, despite the higher unit prices. Inevitably, there was also an adverse impact on British Gas’ profits.

The challenges in the UK were different from those faced in North America, where the increase in production of shale gas has dramatically reduced wholesale gas prices and unusual weather patterns also caused high volatility in electricity prices. A change in attitude to deregulation eroded our position in Ontario but we continued to increase market share and expanded our services business in the United States, while deploying our upstream capability to good effect.

In spite of everything, through a mixture of tenacity, innovation and endeavour, the management team, led by Sam Laidlaw, delivered a 3% increase in adjusted earnings which facilitated a further 8% increase in the full year dividend to our shareholders of 15.4p per share.

Against that background, I am enormously grateful to all the employees of Centrica for their commitment, flexibility and considerable effort in a testing period. I also appreciate the continued support of our shareholders in an uncertain environment and the loyalty of our customers who we continue to serve with dedicated resolve, providing total service with a competitive edge.

During the course of the year, I have taken measures to refresh the Board, review its effectiveness and ensure continued achievement of the highest corporate standards. Of particular note was our full compliance with the new UK Corporate Governance Code and the Board’s endorsement of the recommendations of the Davies review into Women on Boards.

Economic headwinds continue to prevail as we enter 2012 but I remain confident that the management are both appropriately skilled and suitably determined to meet the challenges that lie ahead. We are closely focused on delivering cost efficiencies, for the benefit of both our customers and our shareholders, while maintaining high levels of service and innovation. In parallel we will continue to invest for the future, driving long-term growth across the Group.

Sir Roger Carr
Chairman
23 February 2012

CHIEF EXECUTIVE’S REVIEW

2011 PERFORMANCE

Centrica faced very difficult market conditions in 2011. Sharply rising wholesale commodity prices in the first half of the year meant that the UK residential energy supply business had become loss making, necessitating a significant increase in retail tariffs in August. Record mild weather, both in the Spring and in the Autumn, led to a 21% reduction in average household gas consumption and a 4% fall in average electricity consumption. As a result, the average domestic customer bill was some 4% lower in 2011 than the year before, despite the increase in unit prices. The squeeze on household disposable income has also put pressure on our residential services business, with customers deferring discretionary spending, especially on new central heating systems.

Upstream in the UK, the business delivered higher profits. This reflects good operational reliability from our assets and the effect of higher commodity prices, with a much improved performance from the nuclear fleet in particular. However, market conditions remained difficult for our gas-fired generation and gas storage businesses. In addition, the unexpected increase in upstream taxation announced in March reduced our upstream earnings. It also unfortunately came at a time when the UK needs to offer a stable tax regime if it is to attract the investment required to meet the country’s future energy needs.

In North America, we delivered significantly higher operating profits, reflecting both the operational improvements we have made and the contribution from acquisitions. Direct Energy provides a strong platform for growth, using our expertise in deregulated markets to add scale upstream and downstream, where we see attractive opportunities.

Despite the difficult economic and political backdrop, which resulted in the business incurring a number of exceptional charges, we are pleased to have delivered further adjusted earnings growth, following a very strong result in 2010. Throughout the challenges faced during the year, we have demonstrated the resilience of the Centrica integrated business model. In addition, the total value of our commitments to secure gas for the UK now stands at more than £50 billion. We can only shoulder responsibilities on this scale with the financial security provided by our growing upstream asset base and a profitable downstream business.

STRATEGIC PRIORITIES AND DIRECTION UNCHANGED

Health and safety is our first priority – a message reinforced through regular management communication, operational practice, corporate policy, procedures and reward structures. During the year, we further strengthened our procedures around both customer safety and process safety and achieved a 42% reduction in our lost time injury frequency rate to 0.25 per 100,000 hours worked.

In these tough economic conditions, we remain focused on maximising the returns from our existing assets, while taking a disciplined approach to investment. We will also maintain a healthy balance between upstream and downstream activities as well as across generation types and geographies. Centrica remains, at its heart, a customer facing business.

Upstream, we continue to focus on reliability, both in gas and oil production and in power generation; and we are making good progress on our investment programme, deploying our expertise to bring new projects on line. We are now widely recognised for our expertise across the energy value chain and have entered into strategic partnerships with other leading players in their field - in gas and oil, in offshore wind and in nuclear. In December we announced an intention to increase our upstream gas and oil production by 50% to 75 million barrels of oil equivalent (mmboe) per annum and to treble our offshore wind capacity, retaining investment options in new nuclear, biomass, new build CCGT and gas storage.

Downstream, the priority is to maintain the efficiency of the business and to benefit fully from our scale and brand, while maintaining high levels of customer service. In North America, we continue to increase the scale of the business, through organic growth and through acquisitions, in key competitive markets. We are making good progress towards our goal of doubling the profitability of the business by 2014, seeking further opportunities for growth where we see value, both upstream and downstream.

Given the need to remain competitive in all our divisions, we are undergoing a Group-wide process to sharpen the business for the benefit of our customers and our shareholders. We expect to deliver £500 million of cost savings over the next two years, allowing us to continue to invest for further growth within the existing cost base. The programme to identify efficiencies is already well under way, and we expect to realise around half of these savings in 2012. As part of these measures, we have taken out 2,300 roles across the business and implemented a pay freeze across much of the Group, including the Board; however, we remain committed to investing in the skills and the people we need to achieve our growth ambitions.

HONEST CONVERSATION

During the year, the energy supply sector faced increased regulatory and political scrutiny, as well as uncertainty surrounding Ofgem’s proposals for Retail Market Reform. We led the way in taking measures to help build customer trust by making the purchase of gas and electricity simpler, more transparent and fairer for consumers. We have simplified our tariffs and have also written to each of our customers, inviting them to check that they are on the most appropriate tariff. We are setting out the facts about energy prices, providing each customer with a full breakdown on their bill of the actual costs of providing the energy they consume. We have also made sure that our most vulnerable customers receive the £120 Warm Home Discount, with the widest eligibility criteria of any major supplier.

However, there is still much to be done before consumer confidence can be fully restored. This will mean being much clearer about the cost of producing and providing energy to the customer’s home, the rising cost of green levies, the impact of growing international demand for gas and the profits the industry makes. All of us – the industry, the Government and the Regulator - have a vital role to play in fostering an honest debate about energy, with affordability now a key issue for our customers.

In January 2012, we were the first of the major energy suppliers to implement a price reduction, with an immediate 5% cut in our standard electricity tariff. Nonetheless, the longer term trend in wholesale energy prices and non-commodity costs remains upwards. That is why the work we are doing to help customers take control of their energy usage is so important – including free loft or cavity wall insulation, a free home energy survey and leading the way on the installation of smart meters for all our customers.

2011 INVESTMENT

We invested £1.6 billion of capital in 2011 across the Group, mainly in upstream gas and oil, in power generation and in North America. We have also already announced £1.4 billion of acquisitions which are expected to complete in 2012.

Upstream, expenditure included investment in our Ensign and York projects and our ongoing exploration programme. Construction of the Lincs offshore wind farm is making good progress and work is ongoing on new nuclear, prior to a final investment decision. In North America we have made significant progress in growing the scale of the business both upstream and downstream, increasing our gas and liquid reserves by 14% and adding over 750,000 customers in our core growth markets, Texas and the US North East.

Building the geographic diversity of our asset portfolio is a key priority, and an increasing proportion of our investment now falls outside the UK. In November, we announced a new 10 year supply contract with Statoil and the acquisition of a package of Norwegian gas and oil assets. This marked a significant step change in the scale of our business, both in terms of production volumes and development opportunities, as well as forging a long term working relationship with one of the leading players in the Norwegian market. Already in 2012 we have announced further upstream investments, to increase our share in the Norwegian Statfjord field and acquire a package of UK North Sea assets from Total, providing further gas reserves for our customers.

Centrica is now seen to fill a key role on the global energy stage, enjoying close working relationships with major partners: in LNG, in nuclear, in offshore wind and in upstream gas and oil. At a time when many British companies are reluctant to invest because of economic uncertainty, we are deploying our capital to generate growth and returns for shareholders.

FUTURE INVESTMENT

Significant investment decisions lie ahead, both for the UK and for Centrica. It is vital that the Government provides the clarity and assurance that will be needed if the industry is to step up and deliver the massive investment – an estimated £200 billion in total by 2020 - that the country requires to secure its energy future and build a low carbon power industry.

Following the publication of the UK Government’s White Paper on Electricity Market Reform, there remains much detail to be resolved to ensure the right framework for investment. We also look to the Government to explain the importance of these investments to the country, balancing energy security, environmental goals and crucially, affordability, for this generation and for generations to come.

The Regulator too has a vital role to play in ensuring that the UK offers a stable and attractive investment climate, both in the upstream and the downstream. The proposed retail market reforms need to encourage investment in propositions for customers and smart meter technologies to improve energy efficiency, reduce complexity and increase customer choice.

The combination of strong cash flows and an attractive range of investment opportunities is a key attribute of the Centrica business model – with options to invest across the energy value chain and in different geographies, to deepen our customer relationships and secure the energy requirements of the Group for the future. We will only deploy capital where we see a strong strategic fit, together with attractive returns commensurate with the risks being undertaken.

OUTLOOK

As we look ahead, the external environment remains challenging. However, the past year has shown our business model to be robust, delivering year-on-year growth in a very difficult trading environment. Against this backdrop, we are taking positive action to sharpen our activities, with Group-wide initiatives already in progress to reduce costs and maintain our competitive edge. We are successfully bringing new investment projects on-stream, and will begin to see a contribution from recent acquisitions, as we integrate them into our portfolio. Overall, we plan to deliver improved year-on-year adjusted earnings growth in 2012, subject to the usual variables of weather patterns and commodity price movements, although we continue to face some of the same headwinds as in 2011, in particular the effects of continued economic pressure on household and business budgets.

Downstream in the UK, we expect further progress in residential services, together with a positive contribution from our new energy activities. In the highly competitive market for residential energy supply, the outcome as ever depends on wholesale prices and the weather. In our Upstream UK business, we will progressively benefit from the higher wholesale commodity price environment, although the outlook for gas-fired generation remains weak and market conditions for new gas storage projects remain challenging. We will also benefit from the recently acquired gas and oil assets in the Norwegian and UK sectors of the North Sea. In North America, we expect to see the positive effect of organic improvements in the business, together with a contribution from recent acquisitions, both upstream and downstream. However, we continue to see customer losses in the Ontario energy supply business, as the regulatory environment has become less conducive to competition.

We are making good progress on our capital investment programme and expect to spend a further £1.4 billion on organic investment in 2012, with around half expected to be in the upstream gas and oil business, in addition to the £1.4 billion already committed for the Statoil assets, the additional stake in Statfjord and the package of UK North Sea assets from Total. In the coming year, we expect the Ensign, Seven Seas, Rhyl and Atla fields all to produce first gas and our Lincs offshore wind farm to generate first power. We also expect to make a final investment decision on the development of the Cygnus gas field towards the middle of 2012, with a decision on the Race Bank offshore wind project expected around the end of the year, in each case subject to appropriate returns. On new nuclear, a final investment decision on Hinkley Point C is targeted for the end of 2012, although much remains to be achieved before this decision can be taken and the economics must prove to be sound. In gas storage, our Caythorpe project remains on hold and we continue to assess the Baird project.

In summary, the Centrica business model remains resilient, underpinned by strong cash flows and an attractive pipeline of investment projects. The business is well placed for the long term and we will continue to improve the service offering for our customers, both in the UK and North America. We will also drive further cost savings across the Group to enhance our competitiveness, and deliver increasing value through the efficient deployment of capital, in order to continue to enhance returns for shareholders.

Sam Laidlaw
Chief Executive
23 February 2012

GROUP FINANCIAL REVIEW

Group revenue from continuing operations was up 2% to £22.8 billion (2010: £22.4 billion). Despite higher wholesale gas and electricity prices, revenue decreased in the Downstream UK segment as warmer than normal weather resulted in lower energy consumption. Revenue increased in the Upstream UK segment, reflecting the higher commodity prices. In North America revenue was broadly flat, as higher average customer numbers and total business energy consumption offset lower wholesale energy prices.

Throughout the Operating Review and Group Financial Review, reference is made to a number of different profit measures, which are shown in the table below:

Term	2011 £m	2010 £m	Explanation
Adjusted operating profit*:
Downstream UK	1,005	1,216
Upstream UK	1,023	771
Storage UK	75	169
North America	312	234
Total adjusted operating profit*	2,415	2,390	The principal operating profit measure used by management and used throughout the Operating Review
Impact of fair value uplifts	(105)	(118)	Depreciation of fair value uplifts to property, plant and equipment of Strategic Investments (see note 5(b) and note 10(a) for further information)
Interest and taxation on joint ventures and associates	(102)	(78)
Group operating profit^Ω	2,208	2,194	Operating profit from continuing operations before exceptional items and certain re-measurements, reconciled to statutory profit in the Group Income Statement
Group profit^Ω	1,252	1,221	Profit from continuing operations before exceptional items and certain re-measurements, reconciled to statutory profit in the Group Income Statement
Adjusted earnings^◊	1,333	1,297	Earnings before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements, reconciled to statutory profit in note 10
Statutory profit	421	1,942	Profit including discontinued operations, exceptional items and certain re-measurements

Total adjusted operating profit* was up 1% to £2,415 million (2010: £2,390 million) as increases in Upstream UK and North America profitability* more than offset lower Downstream UK and Storage UK profitability*. In Downstream UK, despite growth in residential services profitability*, higher gas, electricity and non-commodity costs, and lower consumption in energy supply resulted in a reduction in profitability. In Upstream UK, higher gas, oil and power prices, strong nuclear output and increased oil volumes more than offset the impact of lower gas volumes, higher unit gas and oil production costs and reduced gas-fired power generation volumes. In North America, higher volumes and sustained margins in business energy supply, the full year impact of the 2010 acquisition of Clockwork Energy Services in residential and business services and a positive contribution from higher gas and power volumes in the upstream and wholesale business led to higher profitability*, although less favourable market conditions in Ontario resulted in lower residential energy supply profitability*.

Group profit^Ω on a continuing basis was up 3% to £1,252 million (2010: £1,221 million). This reflects the increased Group operating profit^Ω and lower interest charges, largely offset by an increased tax expense. Net interest cost was £146 million (2010: £265 million), reflecting the lower level of average gross debt in the year and early debt repayments in the second half of 2010. The taxation charge was £810 million (2010: £708 million), reflecting a higher mix of more heavily taxed Upstream UK gas operating profit* and the increase in the UK supplementary corporation tax (SCT) rate from 20% to 32% from March. The adjusted tax charge from continuing operations was £891 million (2010: £761 million) and the resultant adjusted effective tax rate^{^} for the Group was 40% (2010: 37%). An effective tax rate calculation is shown on the table on page 11.

Reflecting all of the above, adjusted earnings^◊ increased by 3% to £1,333 million (2010: £1,297 million) while adjusted basic earnings per share (EPS)^◊ increased to 25.8 pence (2010: 25.2 pence).

The statutory profit for the year was £421 million (2010: £1,942 million). The reconciling items between Group profit^Ω and the statutory profit are related to exceptional items, certain re-measurements and discontinued operations. The decrease compared with 2010 was principally due to the effect of a net exceptional charge from continuing operations after taxation of £466 million (2010: net charge of £165 million) and a net loss on certain re-measurements of £322 million (2010: net gain of £891 million). The Group reported a statutory basic EPS of 8.2 pence, down from 37.6 pence in 2010.

In addition to the interim dividend of 4.29 pence per share, we propose a final dividend of 11.11 pence, giving a total ordinary dividend of 15.4 pence for the year (2010: 14.3 pence), an increase of 8%.

Group operating cash flow from continuing operations before movements in working capital was slightly higher at £3,065 million (2010: £3,010 million). After working capital adjustments, tax, operational interest, and cash flows associated with exceptional charges and discontinued operations, this stood at £2,337 million (2010: £2,428 million), mainly due to higher petroleum revenue tax payments.

The net cash outflow from investing activities was £1,400 million (2010: £1,584 million), as described in the business combinations and capital expenditure section on page 10. The 2010 comparative included higher cash out flows on acquisitions.

The net cash outflow from financing activities was £907 million (2010: £1,677 million). This reduction reflects the net cash outflow of £684 million from the repayment of debt during 2010.

The Group’s net debt level at 31 December 2011 was £3,435 million (2010: £3,312 million), reflecting the increase in taxes paid, movement in working capital and other cash flows described above.

During the year net assets decreased to £5,600 million from £5,819 million as at 31 December 2010, reflecting the impact of dividends paid exceeding statutory profit for the year.

EXCEPTIONAL ITEMS

Due to structural shifts in commodity markets, and restructuring as a result of the difficult economic and political environment, net exceptional charges from continuing operations of £331 million were incurred during the year (2010: £283 million). Taxation on these charges generated a credit of £69 million (2010: £118 million).

Following the decision to exit Europe and to close our German wholesale business, a charge of £111 million was recorded for a number of onerous European gas transportation contracts, which are no longer utilised by the business. A further £110 million charge was recorded for the onerous fixed-price Rijnmond tolling contract in the Netherlands due to the impact of low market spark spreads.

As a result of low spark spreads, we are proposing to close two UK CCGT power stations, at Barry and Kings Lynn, while our power stations at Peterborough, Brigg and Roosecote are now configured to run more flexibly and operate in the Short Term Operating Reserve (STOR) market. Impairment charges of £226 million relating to UK generation assets were incurred. These impairment charges are largely non-cash in nature.

A charge of £63 million was recorded following the migration of a significant supplier contract, following its termination in December 2010. Additionally an exceptional restructuring charge of £154 million was recorded, mainly relating to staff reductions following a Group wide cost reduction programme, which is expected to take two years to complete.

During the year the Group announced changes to the terms of the final salary sections of the Centrica Engineers Pension Scheme and the Centrica Pension Plan. Adjustments to projected final pensionable salaries and deferred pensions have resulted in exceptional curtailment gains of £333 million.

A £204 million exceptional deferred tax charge relating to the Group’s UK gas and oil producing assets was recorded in the first half of the year, following the increase in the SCT rate in the UK Government’s March 2011 Budget from 20% to 32%. Also announced in the March Budget was an intention, from 2012, to restrict the rate of tax relief on decommissioning costs to the previous SCT rate of 20%. If enacted, a one-off charge of approximately £60 million will arise from revaluing the related deferred tax provisions.

On 1 June 2011, the Group completed the sale of the trade and assets of Oxxio B.V. in the Netherlands, which resulted in a loss on disposal of £56 million.

CERTAIN RE-MEASUREMENTS

In our business we enter into a portfolio of forward energy contracts which include buying substantial quantities of commodity to meet the future needs of our customers. A number of these arrangements are considered to be derivative financial instruments and are required to be fair-valued under IAS 39 which means that we apply the prevailing forward market prices to these contracts. The Group has shown the fair value adjustments separately as certain re-measurements, as they are unrealised and non-cash in nature. The profits^Ω arising from the physical purchase and sale of commodities during the year, which reflect the prices in the underlying contracts, are not impacted by these re-measurements.

The operating profit in the statutory results includes net losses of £463 million (2010: gains of £1,163 million) relating to these re-measurements, of which there are a number of elements. As gas and power were delivered under these contracts, net out-of-the-money mark-to-market positions from the 2010 year end were unwound generating a net gain to the Group Income Statement in the period of £200 million (2010: £1,023 million). As forward prices decreased in the second half of the year the portfolio of contracts fair valued under IAS 39 reported a net charge of £632 million (2010: gain of £130 million). A loss of £5 million (2010: gain of £24 million) reflects positions relating to cross-border capacity and storage contracts while there were also net losses arising on re-measurement of associates’ energy contracts (net of taxation) of £26 million (2010: £14 million). Net credits on re-measurement on energy contracts of discontinued operations after taxation were £22 million (2010: £67 million).

BUSINESS COMBINATIONS AND CAPITAL EXPENDITURE

On 1 November 2011, Direct Energy acquired Texas based retail electricity supplier FCP Enterprises Inc (First Choice Power) for a total cash consideration of $325 million (£206 million). Goodwill of $146 million (£93 million) arose on the acquisition. The acquisition is included within the North America – Residential energy supply segment.

During the year a number of smaller acquisitions were completed for a total cash consideration of £179 million, including deferred consideration of £6 million. Goodwill of £60 million arose on these acquisitions. These included North American energy retailers Gateway Energy Services Corporation and Vectren Retail LLC, a portfolio of additional interests in natural gas assets within the Wildcat Hills area in Canada and PH Jones Group Limited, an independent provider of central heating services to the UK social housing market.

Further details on capital expenditure and business combinations are included in notes 5(e) and 16 respectively.

RISKS AND CAPITAL MANAGEMENT

The Group’s risk management processes are largely unchanged from 31 December 2010. Some improvements to these processes are described in note 4, along with key financial risk issues addressed during the year.

Details on the Group’s capital management processes are provided under sources of finance in note 11.

EVENTS AFTER THE BALANCE SHEET DATE

On 21 November 2011, Centrica announced that it had signed a 10 year gas supply contract with Statoil starting from 2015, an agreement to pay $1,525 million (£983 million), with an additional payment of up to $100 million (£64 million) contingent on future production performance, for the acquisition of producing and development assets in the Norwegian North Sea and a strategic agreement for partnership on gas exploration activities. On 30 January 2012, Centrica announced the acquisition of an additional interest in the Statfjord asset from ConocoPhillips, for a cash consideration of $223 million (£142 million). On 22 February 2012, Centrica announced an agreement with Total to acquire a portfolio of non-operated producing oil and gas assets for a cash consideration of $388 million (£246 million). These three transactions are expected to complete in 2012. Details on other events after the balance sheet are described in note 19.

ACCOUNTING POLICIES

UK listed companies are required to comply with the European regulation to report consolidated financial statements in conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union. The Group’s specific accounting measures, including changes of accounting presentation and selected key sources of estimation uncertainty, are explained in note 3.

EFFECTIVE TAX RATE RECONCILIATION

	2011 £m	2010 £m
Taxation on profit from continuing operations	810	708
Tax impact of depreciation on Venture fair value uplift	37	30
Share of joint ventures / associates taxation	44	23
Adjusted tax charge from continuing operations^	891	761
Adjusted operating profit*	2,415	2,390
Share of joint ventures / associates interest	(58)	(55)
Net interest expense	(146)	(265)
Adjusted profit from continuing operations before taxation	2,211	2,070
Adjusted effective tax rate^	40%	37%

* Including share of joint ventures and associates before interest and taxation, and before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements
◊ As above, except share of joint ventures and associates stated after interest and taxation
Ω Including share of joint ventures and associates stated after interest and taxation, and before exceptional items and certain re-measurements
^ Including tax from share of joint ventures and associates, and before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements

OPERATING REVIEW

DOWNSTREAM UK

British Gas experienced challenging market conditions in 2011. Rising wholesale gas and power prices during the first half of the year necessitated an increase in residential gas and electricity tariffs in August. And although wholesale prices fell at the end of the year, enabling a reduction in residential electricity tariffs in January 2012, the longer term trends remain upwards. The UK also experienced warmer than normal weather in 2011, compared to exceptionally cold weather in 2010 and the economic environment continues to be challenging, particularly impacting residential services and business energy supply. Against this background, our 2011 performance was good.

In the current economic and political climate it is important that energy suppliers help to build trust in the industry, which is why we launched the ‘honest conversation’ campaign with customers. As part of a series of industry leading measures, we wrote to our customers, highlighting how they could ensure that they were on the best deal with British Gas, and we now provide a complete breakdown of costs on our customers’ energy bills. These are important measures, coming on top of our commitment not to raise prices throughout the winter for residential customers. We also continue to lead the industry in helping our customers reduce their energy usage and in helping the most vulnerable customers. Our free insulation offer remains available to all our customers and we now have over 700,000 EnergySmart accounts, a product which helps customers monitor their energy usage while our social spend in the year exceeded the minimum requirement set out by Government. We now have over 500,000 customer accounts on our Essentials tariff and are actively helping vulnerable customers claim the Warm Home Discount, where we have the broadest eligibility criteria of any major supplier.

The number of residential energy accounts on supply fell slightly, reducing by 97,000 to 15.9 million. We delivered account growth in the first half of the year. However, the increase in wholesale commodity prices during the first half of the year and rising non-commodity costs led to an increase in our residential gas and electricity tariffs in August, by an average of 18% and 16% respectively. This resulted in an increase in churn in the second half of the year. In January 2012, we were the first of the major energy suppliers to reduce our standard residential electricity tariff. This 5% reduction once again placed us as the cheapest major supplier of electricity, on average, in Britain.

In the competitive energy supply market it is important to remain innovative. Our partnerships with Nectar and Sainsbury’s have been highly successful, with over 4 million of our customers now enrolled on the Nectar loyalty programme. These new channels are delivering high value customers, with the Nectar scheme also helping to shape customer behaviour, and more customers are now submitting meter reads online, moving to paperless billing and choosing to pay by Direct Debit. British Gas also appeared top of the best buy league tables for on-line switching for more weeks in 2011 than any other supplier.

Our online platform is also proving increasingly popular with both energy and services customers. In 2011, over 20 million transactions were carried out online, more than double the number from 2010, with increasing levels of meter reads, payments and Annual Service Visit bookings being submitted online. As well as reducing our cost to serve, this change in customer behaviour is also helping to deepen the customer relationship, enabling greater interaction with the customer. Our levels of customer service also remained high in residential energy supply and we were awarded a 4 star service rating from Consumer Focus for the first time.

In residential services, the number of contract holdings increased by 144,000 to 8.9 million, benefiting from stronger customer retention. However, the challenging economy is creating an adverse climate for major consumer purchases, particularly in our central heating installations business and accordingly, the number of central heating systems installed was 15% lower than 2010. Despite this, we made good progress during the year. The roll-over to insurance-based products is now complete, allowing us to offer a more flexible range of products, while the agreement we reached with our service and repair engineers in 2010 means we are now able to meet increased customer demand for evening and weekend appointments. This increased engineer flexibility meant that we were able to visit the vast majority of our customers on the day they reported a fault. Maintaining a high quality of customer service is vital and the contact NPS for our services business grew to 55.

In business energy supply, the number of customer supply points reduced by 45,000 over the year, to 1.00 million (2010: 1.04 million). This reflects our volume to value strategy and also the challenging market conditions. Recognising the impact on our customers, we will continue to focus on delivering high levels of service for each of our customer segments, at competitive prices. Our business services division made further progress during the year with the successful integration of the acquired Connaught services team and the average order value on installations was up 16% on 2010. Over time, this will allow us to grow a differentiated position in this competitive market.

Health and safety is critical to the success of British Gas and we have a good safety record, with the lost time injury frequency rate (LTIFR) falling by 48% this year and the number of lost time incidents reducing by 35%. We continue to monitor employee engagement closely, and are pleased to see that absence and attrition rates were both substantially lower than in 2010. We were also recognised by the Great Places to Work Institute as one of the ‘UK’s 50 Best Workplaces’, for the third year in a row.

We continue to grow our new markets business, which now has gross revenue of over £250 million, capitalising on our broad range of expertise to take advantage of attractive opportunities. Our insulation workforce has now completed 400,000 jobs, achieving growth through organic recruitment and the acquisitions of Hillserve Ltd and ECL Contracts Ltd in 2010. We have also recently entered into our first affinity partnership in the water sector, with an agreement with Thames Water to promote both energy and water saving products – including solar panels, heat pumps, energy efficient boilers, shower savers and free insulation.

On new technologies, we secured contracts with Nissan, Renault, Toyota and Hitachi Capital to become the preferred partner for home charging solutions for their electric vehicles. We also completed substantially more solar installations for both residential and business customers, with 2,400 installations and 12.8 Megawatts-peak (MWp) installed. With the announcement of a halving of the feed-in-tariff for solar installations, demand is expected to reduce, although falling panel prices may help ensure that solar continues to be an attractive investment for residential, business and public sector customers. In December we acquired the remaining 81% of Econergy Ltd, a market leader in biomass heating, while we continue to hold positions in a wide range of other technologies, with capabilities in biomethane gas, heat pump installation and fuel cell boilers.

We continue to lead the industry in the roll-out of smart meters, having insourced our metering operations and installed over 400,000 smart meters for homes and businesses to date. However, we await confirmation from Government of the smart meter national implementation programme and from the Regulator regarding its plans for Retail Market Reform, before we proceed to full scale roll-out. Our focus in the social housing sector continues and we now manage a portfolio in excess of 275,000 homes and in 2011 we acquired PH Jones Group Ltd, a provider of central heating services to the social housing market. We are also undertaking work on the Welsh Assembly Government’s new fuel poverty programme, in addition to the Scottish Government’s Energy Assistance Programme which we won last year. Together, these contracts are expected to generate revenue of over £200 million over the next five years.

Overall, gross revenue in the period fell to £12,319 million (2010: £12,730 million), with higher average retail tariffs for both residential and business energy being more than offset by lower gas and electricity consumption. Operating profit* for residential energy supply fell by 30% and for the operating segment as a whole decreased by 17% to £1,005 million (2010: £1,216 million).

Residential energy supply operating profit* decreased 30% to £522 million (2010: £742 million) and operating margin fell to 6.4% (2010: 8.9%), as the favourable combination of extremely cold weather and low commodity costs in 2010 reversed. Average gas consumption reduced by 21% and average electricity consumption reduced by 4% due to the warmer weather and as energy efficiency measures continue to deliver underlying reductions. Gross revenue decreased to £8,113 million (2010: £8,359 million), reflecting the decline in consumption. Consequently, despite the increase in retail tariffs implemented in August, the average customer bill fell by 4%. In these current market conditions it is important that we focus on reducing our cost base and as a result of improved processes and close management attention, our bad debt charge fell 26% compared to 2010.

Residential services operating profit* increased by 10% to £264 million (2010: £241 million) with the operating margin increasing to 17.6% (2010: 16.5%) in a challenging economic environment, which requires us to remain closely focused on driving cost efficiencies in the business. During the first half of the year, warmer weather resulted in reduced breakdown call out costs compared to the first half of 2010, but we incurred additional costs to complete annual service visits deferred from the prior year, as we had prioritised our workload during the cold weather in late 2010. Gross revenue rose by 3% to £1,504 million (2010: £1,464 million) reflecting a slight increase in the average number of customers and average prices.

Business energy supply and services operating profit* fell by 6% to £219 million (2010: £233 million) while gross revenue fell by 7% to £2,702 million (2010: £2,907 million), reflecting the impact of much warmer weather and the economic environment, partially offset by credits arising from improved revenue and billing processes. As a result, the operating margin remained broadly flat at 8.1% (2010: 8.0%).

Outlook

Our business model remains strong and British Gas delivered a solid financial performance in 2011 in challenging market conditions, underpinned by our scale, our service and our drive for innovation. In residential energy supply, it is critical to maintain a competitive advantage, underpinning our ability to achieve sustained profit. In services, we aim to deliver double digit profit growth, even in an environment of low economic growth, achieving this through cost efficiencies, attractive customer propositions and excellent levels of service. In business energy supply trading conditions remain tough, although operational improvements, opportunities in B2B services and investment for the next phase of growth will leave the business well placed for the long-term.

As part of the Group wide programme to sharpen the business and reduce costs, we are targeting substantial cost reductions in British Gas, with absolute underlying operating costs expected to reduce by 10% over the next two years. We have already announced some 1,800 role reductions across the business, while maintaining our frontline capability and high levels of customer service. We have announced the cessation of our field sales activities, and the scaling down of our solar business. In addition we have reached agreement with our employees and Trade Unions on restructuring pension benefits and have implemented a pay freeze across the whole of British Gas. These measures will help the business to remain competitive, while also enabling investment for future growth.

Downstream UK
Total Downstream UK
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Total customer accounts (period end) ('000)		25,742	25,740	0.0	25,742	25,740	0.0
Total customer households (period end) ('000)		11,997	12,206	(1.7)	11,997	12,206	(1.7)
Joint product households (period end) ('000)		2,207	2,164	2.0	2,207	2,164	2.0
Gross Revenue (£m):		12,319	12,730	(3.2)	5,994	5,996	(0.0)
Operating cost (excluding bad debt) (£m)		1,425	1,358	4.9	678	661	2.6
Operating profit (£m)*		1,005	1,216	(17)	487	374	30
Residential energy supply
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Customer accounts (period end):
	Gas ('000)	9,139	9,332	(2.1)	9,139	9,332	(2.1)
	Electricity ('000)	6,742	6,646	1.4	6,742	6,646	1.4
	Total ('000)	15,881	15,978	(0.6)	15,881	15,978	(0.6)
Estimated market share (%):
	Gas	41.2	42.2	(1.0) ppts	41.2	42.2	(1.0) ppts
	Electricity	25.2	25.0	0.2 ppts	25.2	25.0	0.2 ppts
Average consumption:
	Gas (therms)	443	564	(21)	181	245	(26)
	Electricity (kWh)	3,805	3,982	(4.4)	1,858	1,970	(6)
Total consumption:
	Gas (mmth)	4,099	5,291	(23)	1,669	2,294	(27)
	Electricity (GWh)	25,602	26,002	(1.5)	12,600	13,016	(3.2)
Gross Revenue (£m):
	Gas	5,086	5,570	(9)	2,348	2,460	(4.6)
	Electricity	3,027	2,789	9	1,580	1,416	12
	Total	8,113	8,359	(2.9)	3,928	3,876	1.3
Transmission and metering costs (£m):
	Gas	1,212	1,231	(1.5)	611	620	(1.5)
	Electricity	782	714	10	401	378	6
	Total	1,994	1,945	2.5	1,012	998	1.4
Total environmental costs (£m)		429	288	49	260	138	88
Total social costs (£m)		78	42	86	40	25	60
Operating profit (£m)*		522	742	(30)	252	157	61
Operating margin (%)		6.4	8.9	(2.5) ppts	6.4	4.1	2.3 ppts
Total environmental costs include CERT, CESP and ROCs
Total social costs include social and warm home discounts and winter rebate
Residential services
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Customer product holdings (period end):
	Central heating service contracts ('000)	4,696	4,684	0.3	4,696	4,684	0.3
	Kitchen appliances care (no. of customers) ('000)	476	438	9	476	438	9
	Plumbing and drains care ('000)	1,884	1,781	6	1,884	1,781	6
	Home electrical care ('000)	1,462	1,480	(1.2)	1,462	1,480	(1.2)
	Other contracts ('000)	344	335	2.7	344	335	2.7
	Total holdings ('000)	8,862	8,718	1.7	8,862	8,718	1.7
Domestic central heating installations ('000)		105	124	(15)	51	71	(28)
Gross Revenue (£m):
	Central heating service contracts	807	774	4.3	411	403	2.0
	Central heating installations	295	324	(9)	144	180	(20)
	Other	402	366	10	200	190	5
	Total	1,504	1,464	2.7	755	773	(2.3)
Engineering staff employed (period end)		9,800	9,954	(1.5)	9,800	9,954	(1.5)
Operating profit (£m)*		264	241	10	153	132	16
Operating margin (%)		17.6	16.5	1.1 ppts	20.3	17.1	3.2 ppts
Business energy supply and services
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Customer supply points (period end):
	Gas ('000)	363	389	(7)	363	389	(7)
	Electricity ('000)	636	655	(2.9)	636	655	(2.9)
	Total ('000)	999	1,044	(4.3)	999	1,044	(4.3)
Average consumption:
	Gas (therms)	2,629	3,152	(17)	1,130	1,368	(17)
	Electricity (kWh)	25,732	29,326	(12)	12,895	14,415	(11)
Total consumption:
	Gas (mmth)	986	1,250	(21)	413	538	(23)
	Electricity (GWh)	16,731	19,060	(12)	8,320	9,388	(11)
Gross Revenue (£m):
	Gas	931	1,062	(12)	416	459	(9)
	Electricity	1,771	1,845	(4.0)	895	888	0.8
	Total	2,702	2,907	(7)	1,311	1,347	(2.7)
Transmission and metering costs (£m):
	Gas	188	189	(0.5)	94	88	7
	Electricity	372	382	(2.6)	188	184	2.2
	Total	560	571	(1.9)	282	272	3.7
Operating profit (£m)*		219	233	(6)	82	85	(3.5)
Operating margin (%)		8.1	8.0	0.1 ppts	6.3	6.3	0.0 ppts

UPSTREAM UK

Centrica Energy delivered a significant increase in operating profit* in 2011, up 33% to £1,023 million (2010: £771 million) with the impact of higher wholesale commodity prices and good asset performance more than offsetting the effect of difficult market conditions for our CCGT fleet, resulting in impairment charges being recorded as described in the Group Financial Review. The business also made a strong contribution to both Group earnings and cash flow, despite the increase in SCT during the year.

We continue to see attractive returns upstream and invested over £600 million in our upstream gas and oil business during 2011. We also invested £300 million in our power business, the majority in our Lincs offshore wind farm. Health and safety remains of paramount importance, and we continued to invest in the reliability and safety of our gas and power assets.

Gas

Total gas production volumes reduced by 15% to 2,160 million therms (mmth) (2010: 2,550mmth), with gas volumes from Morecambe down by 41% to 817mmth (2010: 1,381mmth), reflecting the natural decline of the field and the decisions to shut-in South Morecambe for commercial reasons more often than in 2010. Gas production from other fields increased by 15% to 1,343mmth (2010: 1,169mmth) and oil and condensate volumes increased by 6% to 12.5 million barrels of oil equivalent (mmboe) (2010: 11.8mmboe) with strong performance from existing assets, such as Grove and Chiswick, and incremental production from new fields and our enlarged stake in Statfjord.

Upstream gas and oil is an attractive area in which to deploy capital. During 2011 we produced first volumes from F3-FA and the Goosander Crestal well, while the non-operated Babbage field is now fully operational. Our Ensign project is expected to produce first gas in the first half of 2012, with first gas from Seven Seas expected in mid-2012. We are targeting first gas from our Rhyl and Atla projects in the second half of 2012, with first gas from the York project in early 2013. These five developments combined are expected to bring around 50 mmboe of reserves into production. Development of the Valemon field, in which we are acquiring an interest as part of the Statoil transaction, is on track with first gas anticipated towards the end of 2014.

On the Cygnus development, where our share of reserves is 51mmboe, we are working closely with the operator, GdF Suez, to optimise the development plan for the field. Subject to acceptable returns we expect to make a final investment decision around the middle of 2012. We are progressing development of the Kew field and also expect to make final investment decisions on the Annabel East and Olympus developments in 2012. Combined, these three fields are expected to bring around 20mmboe into production.

Our drilling programme delivered good results once again in 2011. We successfully drilled production wells at Chestnut, F3-FA and Goosander. There were also successes at the non-operated North West Seymour field and two wells at the West Brae field. However one of the wells at Ensign failed and will be re-drilled following completion of the other planned Ensign development wells. We had exploration discoveries at the Pegasus prospect in the UK North Sea and the Butch discovery in Norway, both operated by Centrica. However we were unsuccessful with our drilling at the Whitethroat prospect in the UK North Sea.

We added 54mmboe of proven and probable reserves during 2011 primarily due to upgrades of producing fields, such as Grove and Chiswick and bringing new fields, such as Maria, into the development pipeline. After taking account of production during the year, our production replacement ratio was 112% and we ended the year with total reserves of 440mmboe.

The average achieved gas sales price, net of the impact of hedging, increased by 24% to 51.6 pence per therm (p/th) (2010: 41.6p/th), reflecting higher wholesale UK gas prices. The achieved price also reflects production from our activities in Trinidad and Tobago, for which prices are linked to Henry Hub. The average achieved oil and condensate price, net of the impact of hedging, increased by 22% to £57.2 per barrel of oil equivalent (boe) (2010: £46.8/boe), reflecting higher worldwide oil prices. Production costs increased by 15% to £1,127 million (2010: £980 million) reflecting inflationary cost increases, new gas and oil fields coming into production and the full year impact of the acquisitions of an additional stake in Statfjord and some Trinidad and Tobago assets in the second half of 2010. On a per unit of production basis, lifting costs increased to £9.9/boe (2010: £6.6/boe) while DDA costs increased to £10.1/boe (2010: £8.9/boe), reflecting a reduced proportion of low cost Morecambe production in the mix.

In February we entered into a Memorandum of Understanding (MOU) with Qatargas, leading to a three year contract for the delivery of 2.4 million tonnes of LNG per annum, and in December we signed an MOU with Qatar Petroleum International to examine other joint energy-related investment opportunities. In June we took delivery of our first cargo under the Qatargas contract. In November, alongside the acquisition of a package of assets, we signed a new 10 year, NBP-linked gas supply contract with Statoil. The 5 billion cubic metres per annum gas supply contract starts in October 2015 and will replace the existing supply contract with Statoil. In addition we also signed an MOU with Statoil to consider partnering on gas focused exploration opportunities in Norway and the UK.

Overall operating profit* for the gas segment increased by 36% to £769 million (2010: £566 million) with higher achieved prices more than offsetting the impact of reduced gas volumes and higher production costs.

Power

Strong performance from our share of nuclear assets more than offset the impact of weak market conditions for our gas-fired power stations. Our share of nuclear output increased by 16% to 11.2 terawatt hours (TWh) (2010: 9.7TWh), with fewer unplanned outages during the year. Our average achieved nuclear power price, net of the impact of hedging, increased by 13% to £48.5 per megawatt hour (MWh) (2010: £42.9/MWh) reflecting the impact of higher baseload market power prices. As a result of the higher volumes and higher achieved price, nuclear profitability* was much improved compared to 2010.

Our wind assets again benefited from availability of over 90%, and with weather conditions generally more favourable than in 2010, generated volumes increased by 21% to 596 gigawatt hours (GWh) (2010: 493GWh), with the load factor improving to 36% (2010: 29%). The construction of the 270MW Lincs wind farm project is proceeding to schedule, although unfavourable weather conditions at the end of 2011 and early in 2012 delayed installation of the foundations. 48 out of 75 foundations are now complete, while the offshore substation has been installed and commissioning is ongoing. Lincs is expected to generate first power in the second half of 2012 and is expected to be fully operational in the first half of 2013.

Weak market conditions for our gas-fired CCGT fleet resulted in a 34% reduction in generation volume to 15.0TWh (2010: 22.8TWh) and a lower load factor of 35% (2010: 56%). The average spark spread achieved fell to £10.1/MWh (2010: £11.6/MWh) but was still well above the average baseload market spread, reflecting volumes sold at peak times. Plant reliability remained high at 98% (2010: 97%). As a result of the weak market conditions we are in the process of restructuring our CCGT portfolio and are proposing to close two of our plants, at Barry and Kings Lynn, with a total capacity of 555MW. Our plants at Peterborough, Brigg and Roosecote are now configured to run more flexibly and operate in the Short Term Operating Reserve (STOR) market, resulting in lower operating costs.

Overall operating profit* for the power segment increased by 24% to £254 million (2010: £205 million) with higher volumes and achieved prices from our nuclear and wind assets more than offsetting the impact of lower gas-fired generation volumes.

Outlook

Further increases in wholesale gas and power prices would be positive for our upstream gas and oil, nuclear and wind businesses, although market conditions for our gas-fired generation assets are likely to remain challenging and load factors are expected to remain low. In addition, the business will face a full year’s impact from the higher upstream gas and oil taxes in 2012.

Production of both gas and liquids is expected to increase by over 25% in 2012 following the acquisitions of a package of assets in the Norwegian North Sea from Statoil, announced in November, an additional stake in the Statfjord field, announced in January 2012 and a package of UK North Sea assets from Total, announced in February 2012. The Statoil and Statfjord transactions are expected to close in May 2012, with the Total transaction expected to close in July 2012, and in aggregate these three acquisitions are expected to add around 13mmboe of gas and liquids production in 2012.

We will continue to invest in the upstream business where we see value. The focus will remain on growing our upstream gas and oil business, through acquisition and organic development, and on expanding the scale of our offshore wind operations. We expect to make a final investment decision on the Cygnus gas development around the middle of 2012, subject to suitable returns, with a final investment decision expected on the Race Bank offshore wind farm around the end of the year. We also retain further investment options – in new nuclear build, biomass and new build CCGT. With all of our investment options, we will only proceed if appropriate returns are achievable.

Upstream UK
Total Upstream UK
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Operating profit (£m)*		1,023	771	33	492	286	72
Gas
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Gas production volumes (mmth)
	Morecambe	817	1,381	(41)	418	645	(35)
	Other	1,343	1,169	15	663	572	16
	Total	2,160	2,550	(15)	1,081	1,217	(11)
Average gas sales price (p/therm)		51.6	41.6	24	52.5	43.6	20
Oil and condensate production volumes (mmboe)		12.5	11.8	6	5.6	5.5	1.8
Average oil and condensate sales price (£/boe)		57.2	46.8	22	56.9	52.6	8
Production costs (£m)		1,127	980	15	544	509	7
Operating profit (£m)*		769	566	36	355	204	74
Estimated net proven and probable reserves of gas (BCF)		2,201	2,187	0.6	nm	nm	nm
Estimated net proven and probable reserves of liquids (mmboe)		73	69	6	nm	nm	nm
2010 Gas and liquid production volumes restated from sales of production basis; reserves include Rough cushion gas
Power
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Power generated (GWh)
	Gas-fired	14,973	22,786	(34)	7,542	10,458	(28)
	Renewables	596	493	21	321	284	13
	Nuclear	11,157	9,655	16	4,966	4,695	6
	Total	26,726	32,934	(19)	12,829	15,437	(17)
Achieved Clean Spark Spread (£/MWh)		10.1	11.6	(13)	9.3	11.4	(18)
Achieved power price (including ROC's) (£/MWh) - renewables		111.2	109.1	1.9	124.7	125.4	(0.6)
Achieved power price (£/MWh) - Nuclear		48.5	42.9	13	50.4	42.9	17
Operating profit (£m)*		254	205	24	137	82	67

STORAGE UK

Centrica Storage faced difficult trading conditions in 2011, with the differential between summer and winter gas prices remaining narrow for much of the year reflecting an increasing amount of LNG coming to the UK during the winter months.

The Rough asset continued to perform well, with reliability of 96% (2010: 98%) impacted by a small number of disruptions at the Easington terminal in January and essential offshore maintenance work on the asset in June. Warmer weather in the first quarter of the year meant that injection started earlier than usual and further mild weather throughout spring and summer resulted in Rough reaching a record Net Reservoir Volume (NRV) of 132 billion cubic feet (BCF) early in the fourth quarter. Health and safety remains our top priority and during the year we undertook a number of process safety related initiatives, with further work planned in 2012.

Gross revenue fell by 31% to £184 million (2010: £267 million). The narrowing of seasonal spreads resulted in an average Standard Bundled Unit price of 30.0p (2010: 42.1p). In addition, revenue from optimisation and additional space sales was lower, again reflecting the narrowing of seasonal spreads, as well as reduced market volatility. After taking account of higher fuel-gas costs, higher depreciation resulting from previous investment in Rough and inflationary cost increases, operating profit* fell by 56% to £75 million (2010: £169 million).

We have taken the decision to terminate our Bains storage project, following a review of the results of 3D seismic survey data which indicated that the reservoir would not be sufficiently attractive to convert into a storage facility. Centrica Energy now plan to return the field to production, with work expected to commence in the first half of 2012.

We continue to assess our Baird storage project, which remains an attractive investment option subject to an improvement in market conditions. Our Caythorpe fast-cycle project remains on hold and we will continue to monitor market conditions going forward.

In April, the Competition Commission published its final decision on our request for a review of the Undertakings given to the Secretary of State following the acquisition of Rough. A number of variations have been agreed to the Undertakings to reflect the changes in the market, including an increase in the proportion of capacity that Centrica is allowed to acquire for its own use to 25% (from 15%). We expect to sign the revised Undertakings shortly.

While the seasonal spread for the 2012/13 storage year showed some improvement over the fourth quarter of 2011, the forward curve further out indicates that spreads are expected to remain tight for the medium term. With the UK importing an increasing proportion of its gas requirements, there is a general recognition that the UK is in need of further storage capacity; however, we will only invest in new projects if returns are appropriate for the level of risk undertaken.

Storage UK
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Average SBU price (in period) (pence)		30.0	42.1	(29)	25.2	39.7	(37)
Gross Revenue (£m)
	Standard SBUs	136	191	(29)	58	91	(36)
	Optimisation / other	48	76	(37)	29	28	4
	Total	184	267	(31)	87	119	(27)
External revenue (£m)		164	232	(29)	76	104	(27)
Cost of gas (£m)		19	15	27	6	6	0.0
Operating profit (£m)*		75	169	(56)	36	72	(50)

NORTH AMERICA

Direct Energy achieved strong growth in operating profit* in 2011, benefiting from operational improvements and cost efficiencies, both upstream and downstream, and the impact of acquisitions. This improvement came despite more challenging market conditions for the retail energy supply business and continued low gas and power prices in our core geographies.

Gross revenue increased slightly to £6,117 million (2010: £5,997 million) as the impact of lower wholesale energy prices was more than offset by customer growth in residential energy supply and higher volumes in both business energy supply and upstream and wholesale energy. Operating profit* increased by 33% to £312 million (2010: £234 million), with stronger performance from our business energy supply, residential and business services and upstream and wholesale energy divisions. The impact of currency movements on the reported results was not significant in 2011.

Residential energy supply

Direct Energy Residential delivered a good performance in a consolidating competitive landscape, with less favourable market conditions and more extreme weather than in 2010. The total number of customer accounts increased by 18% over the year further building on our leading position in competitive markets in North America, as we significantly expanded the scale of the business through acquisitions and organic growth. We made three acquisitions in residential energy supply in 2011, Gateway Energy Services, First Choice Power and Vectren Retail. These transactions added over 750,000 customer accounts and built on a successful strategy of acquiring smaller suppliers, increasing our market share in deregulated markets, leveraging our existing systems and removing costs.

In the US North East, the acquisitions of Gateway in the first half of the year and Vectren Retail in December have contributed to an almost doubling of the size of our customer base, enhancing our scale in the key states of New York and Ohio, and further consolidating our top three market position in this important region. Our investment in the US North East is delivering returns well in excess of our cost of capital.

The Texas business performed well despite price spikes during extremely cold weather in February and the hottest August on record. After taking account of higher prices and load factors achieved in our upstream power business, profitability* in Texas was not materially impacted by the weather. Our transformation programme has simplified our systems and platforms and is delivering real results. We are making more efficient use of sales channels, our consolidated billing platform and prepaid offering are helping to reduce bad debt and operating costs, and we have improved levels of customer satisfaction and reduced customer churn. Our enhanced segmentation approach has also contributed to improved returns in Texas and we are expanding this approach to our other markets. In addition, the acquisition of First Choice Power, which added 220,000 customer accounts, further strengthens our position as the third largest energy retailer in the state.

In Ontario, the market structure is no longer conducive to competition and has been made even more challenging by the Energy Consumer Protection Act, which makes it substantially more difficult to acquire and retain customers. As expected, the number of customer accounts in the province has fallen significantly and we continue to aggressively manage our cost base in the region, in order to minimise the impact. Although we expect our customer base and profit* to continue to reduce in Ontario as a result, over time we expect this to be offset by growth in the US North East and Texas.

Gross revenue fell by 3% to £2,416 million (2010: £2,502 million) reflecting lower average retail tariffs. Operating profit* fell by 9% to £161 million (2010: £177 million), reflecting the less favourable market conditions, particularly in Ontario, and the spikes in Texas power prices. These impacts were partially offset by US customer growth and operational efficiencies across all core geographies. Operating margin fell slightly to 6.7% (2010: 7.1%).

Business energy supply

Direct Energy Business had another strong year with further volume growth and sustained margins. Electricity volumes increased by 17% to 46.4TWh (2010: 39.7TWh) reflecting high sales productivity, the targeting of key customer segments and high levels of customer service, further consolidating our position as the third largest business energy supplier in North America. During the year we also established ourselves as a leading channel partner in KEMA’s 2011 annual broker satisfaction survey.

Competition in this segment is intensifying, as competitors continue their pursuit of vertical integration and increasingly focus on the small business segment. Our established position and expertise in this area leaves the business well placed and, in addition, we continue to focus on operational and scale efficiencies.

Gross revenue increased by 2% to £2,748 million (2010: £2,682 million) as volume growth offset the impact of the lower commodity price environment. Operating margin improved to 4.0% (2010: 3.3%) reflecting operational improvements and the benefits of scale, while operating profit* increased by 25% to £110 million (2010: £88 million).

Residential and business services

The integration of Clockwork is complete and the business is positioning itself to grow in the highly fragmented North American services market, through expansion of the franchise network and further penetration of the largest metropolitan areas. The announcement in November of the acquisition of the home services protection plan business, Home Warranty of America (HWA), provides a further platform for growth and enhances our ability to cross-sell energy and services. HWA is one of the few home warranty providers with the necessary licences to operate across the United States and the acquisition will allow Direct Energy to build an extensive protection plan business, complementing Clockwork’s current nationwide on-demand offering.

Overall, the number of customer accounts was broadly flat, with the number of installations and on-demand jobs up materially, largely as a result of the full year impact of the Clockwork acquisition. In Canada, we continued to improve retention in our water heater customer base and drive broader cost efficiencies in a challenging market environment. Although weak economic conditions in North America and a slow housing market have continued to impact our business, including our legacy new construction business in the United States, customer satisfaction remained high, with an NPS of 58, and customer retention remained strong.

Gross revenue increased by 7% to £520 million (2010: £485 million) and operating profit* nearly doubled to £28 million (2010: £15 million), mainly as a result of a full year’s impact from the Clockwork acquisition in July 2010 and cost efficiencies, partially offset by the impact of the continued weak housing market and the removal of some energy efficiency tax incentives.

Upstream and wholesale energy

Profitability* in our Direct Energy Upstream business improved significantly compared to 2010, despite the impact of low natural gas prices. This improvement was driven by a full year’s contribution from the Wildcat Hills assets in Alberta and improved power asset performance in Texas, particularly during the price spikes in February and August.

Gas production volumes increased by 39% to 567mmth (2010: 409mmth) while unit costs fell by 10%, reflecting the impact of the Wildcat Hills acquisition, completed in 2010, with a subsequent interest acquired in March 2011. Our North America 2P reserves increased by 14% over the year, reflecting this acquisition and operational improvements. We have also now completed the acquisition of a package of liquids-rich natural gas assets in the Carrot Creek region of Alberta.

Power generation volumes increased by 36% to 5,247GWh (2010: 3,851GWh), with improved asset availability and optimisation performance allowing the upstream business to benefit from the spikes in power prices experienced during the extremely cold weather in February and during the record high temperatures in August. As a result, the power generation business broke-even in 2011.

Overall, the upstream and wholesale division made an operating profit* of £13 million (2010: operating loss* of £46 million) reflecting improved performance from both our gas and power businesses.

Outlook

The outlook for Direct Energy remains positive. Our residential energy supply business is making good progress in Texas and the US North East, although a mild winter may affect first half profitability, while the unfavourable market conditions in Ontario will continue to impact both our business and residential energy supply activities in the region. We will continue to pursue our successful strategy of acquiring energy retailers, to deliver cost synergies and scale, while at the same time improving the efficiency of our operations. We expect continued growth in both our business energy supply and services divisions, although both are significantly affected by the strength of the US economic recovery. In services, we will use the platform created by Clockwork and HWA to drive organic growth and over time increasingly cross-sell to our energy customer base.

Our upstream business continues to be impacted by low gas prices in Alberta and spark spreads in Texas. With shale gas in plentiful supply, gas prices are expected to remain low across North America. In power generation, the outlook for Texas spreads will depend on the outlook for reserve margins, which was lowered last year by ERCOT, and to a certain extent on the impact of United States Environmental Protection Agency (EPA) legislation on regional power markets. The benefits of vertical integration were clearly seen during 2011, as the business coped well during periods of high power prices in Texas. We continue to seek opportunities in both upstream gas and power, subject to investments delivering appropriate returns.

We continue to drive organic improvements across the business, streamlining our operations to create an improved, cost-efficient organisation, while seeking investment opportunities both downstream and upstream for further growth. We have therefore announced the relocation of our North American head office from Toronto to Houston, to enable us to focus more attention on our growth opportunities, in Texas and the US North East.

North America
Total North America
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Revenue (£m)		6,117	5,997	2.0	3,021	2,914	3.7
Operating profit (£m)*		312	234	33	138	95	45
Residential energy supply
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Customer accounts (period end) ('000)		3,364	2,855	18	3,364	2,855	18
Revenue (£m)		2,416	2,502	(3.4)	1,126	1,133	(0.6)
Operating profit (£m)*		161	177	(9)	56	67	(16)
Operating margin (%)		6.7	7.1	(0.4) ppts	5.0	5.9	(0.9) ppts
2011 period end customer numbers exclude 66,000 customers re-classified as business energy supply customers
Business energy supply
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Gas sales (mmth)		714	633	13	297	272	9
Electricity sales (GWh)		46,350	39,722	17	24,159	21,442	13
Revenue (£m)		2,748	2,682	2.5	1,372	1,363	0.7
Operating profit (£m)*		110	88	25	52	44	18
Operating margin (%)		4.0	3.3	0.7 ppts	3.8	3.2	0.6 ppts
Residential and business services
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Contract relationships (period end) ('000)		2,283	2,300	(0.7)	2,283	2,300	(0.7)
On demand customers ('000)		703	582	21	658	469	40
Revenue (£m)		520	485	7	271	277	(2.2)
Operating profit (£m)*		28	15	87	19	7	171
Operating margin (%)		5.4	3.1	2.3 ppts	7.0	2.5	4.5 ppts
Upstream and wholesale energy
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Gas production volumes (mmth)		567	409	39	287	232	24
Power generated (GWh)		5,247	3,851	36	2,924	1,661	76
Revenue (£m)		433	328	32	252	141	79
Operating profit / (loss) (£m)*		13	(46)	nm	11	(23)	nm
Estimated net proven and probable reserves of gas (BCF)		603	538	12	nm	nm	nm
Estimated net proven and probable reserves of liquids (mmboe)		8	6	33	nm	nm	nm
North America with comparator year of 2010 restated to remove effect of foreign exchange movements
For the year ended 31 December		FY 2011	FY 2010	Δ%	H2 2011	H2 2010	Δ%
Revenue (£m)
	Residential energy supply	2,416	2,488	(2.9)	1,126	1,126	0.0
	Business energy supply	2,748	2,591	6	1,372	1,333	2.9
	Residential and business services	520	479	9	271	275	(1.5)
	Upstream and wholesale energy	433	316	37	252	138	83
North America revenue		6,117	5,874	4	3,021	2,872	5
Operating profit (£m)*
	Residential energy supply	161	174	(7)	56	65	(14)
	Business energy supply	110	83	33	52	43	21
	Residential and business services	28	15	87	19	8	138
	Upstream and wholesale energy	13	(44)	nm	11	(23)	nm
North America operating profit*		312	228	37	138	93	48
2010 figures restated at 2011 weighted average exchange rate

* Including share of joint ventures and associates before interest and taxation, and before depreciation of fair value uplifts to property, plant and equipment from Strategic Investments and exceptional items and certain re-measurements

STATEMENT OF DIRECTORS’ RESPONSIBILITIES

The Directors are responsible for preparing the Group Financial Statements in accordance with applicable law, regulations and accounting standards. In preparing the Group Financial Statements, the Directors are required to:

• select suitable accounting policies and then apply them consistently;
• make judgements and accounting estimates that are reasonable and prudent;
• state whether IFRSs as adopted by the European Union have been followed, subject to any material departures disclosed and explained in the Group Financial Statements; and
• prepare the Group Financial Statements on the going concern basis unless it is inappropriate to presume that the company will continue in business.

Each of the Directors confirm that, to the best of their knowledge:

• the Group Financial Statements, which have been prepared in accordance with IFRSs as adopted by the EU, give a true and fair view of the assets, liabilities, financial position and profit of the Group; and
• the Directors’ Report – Business Review contained in the Annual Report and Accounts, from which this narrative is extracted, includes a fair review of the development and performance of the business and the position of the Group, together with a description of the principal risks and uncertainties that it faces.

By order of the Board

Sam Laidlaw	Nick Luff
23 February 2012	23 February 2012
Chief Executive	Group Finance Director

GROUP INCOME STATEMENT

					2011		2010
Year ended 31 December	Notes	Business performance £m	Exceptional items and certain re-measurements £m		Results for the year £m	Business performance £m	Exceptional items and certain re-measurements £m	Results for the year £m
Group revenue	5	22,824	–		22,824	22,423	–	22,423
Cost of sales before exceptional items and certain re-measurements		(17,959)	–		(17,959)	(17,595)	–	(17,595)
Exceptional items	6	–	(221)		(221)	–	(102)	(102)
Re-measurement of energy contracts	6	–	(437)		(437)	–	1,177	1,177
Cost of sales		(17,959)	(658)		(18,617)	(17,595)	1,075	(16,520)
Gross profit		4,865	(658)		4,207	4,828	1,075	5,903
Operating costs before exceptional items		(2,750)	–		(2,750)	(2,641)	–	(2,641)
Exceptional items	6	–	(110)		(110)	–	(181)	(181)
Operating costs		(2,750)	(110)		(2,860)	(2,641)	(181)	(2,822)
Share of profits/(losses) in joint ventures and associates, net of interest and taxation	13	93	(26)		67	7	(14)	(7)
Group operating profit		2,208	(794)		1,414	2,194	880	3,074
Interest income	7	212	–		212	214	–	214
Interest expense	7	(358)	–		(358)	(479)	–	(479)
Net interest expense		(146)	–		(146)	(265)	–	(265)
Profit from continuing operations before taxation		2,062	(794)		1,268	1,929	880	2,809
Taxation on profit from continuing operations	8	(810)	(16)		(826)	(708)	(221)	(929)
Profit from continuing operations after taxation		1,252	(810)		442	1,221	659	1,880
Profit/(loss) from discontinued operations	17	13	22		35	(8)	67	59
(Loss)/profit on disposal of discontinued operations	17	–	(56)		(56)	3	–	3
Discontinued operations		13	(34)		(21)	(5)	67	62
Profit for the year		1,265	(844)		421	1,216	726	1,942
Attributable to:
Equity holders of the parent		1,265	(844)		421	1,209	726	1,935
Non-controlling interests		–	–		–	7	–	7
		1,265	(844)		421	1,216	726	1,942
Earnings per ordinary share					Pence			Pence
From continuing and discontinued operations:
Basic	10			8.2					37.6
Diluted	10			8.1					37.3
From continuing operations:
Basic	10			8.6					36.4
Diluted	10			8.5					36.1
Interim dividend paid per ordinary share	9			4.29					3.84
Final dividend proposed per ordinary share	9			11.11					10.46

The notes on pages 29 to 57 form part of these Financial Statements.

GROUP STATEMENT OF COMPREHENSIVE INCOME

Year ended 31 December	2011 £m	2010 £m
Profit for the year	421	1,942
Other comprehensive income/(losses):
Transfer of available-for-sale reserve to income statement	23	–
Losses on revaluation of available-for-sale securities	(4)	(4)
Taxation on revaluation of available-for-sale securities	(2)	(1)
	17	(5)
Unrealised (losses)/gains on cash flow hedges	(99)	10
Transferred to income and expense on cash flow hedges	42	236
Transferred to assets and liabilities on cash flow hedges	2	19
Recycling of foreign exchange gains on cash flow hedges on disposal of business	–	9
Exchange differences on cash flow hedges	(3)	(8)
Taxation on cash flow hedges	23	(79)
	(35)	187
Exchange differences on translation of foreign operations	(12)	70
Recycling of foreign exchange loss on disposal of business	(3)	(1)
Taxation on related exchange differences	–	14
	(15)	83
Net actuarial gains/(losses) on defined benefit pension schemes	198	(9)
Exchange loss on translation of actuarial reserve	–	(1)
Taxation on net actuarial gains/(losses) on defined benefit pension schemes	(59)	(2)
	139	(12)
Share of joint ventures/associates actuarial (loss)/gain (post tax)	(24)	14
Share of joint ventures/associates cash flow hedge reserve (loss)/gain (post tax)	(1)	1
	(25)	15
Other comprehensive income net of taxation	81	268
Total comprehensive income for the year	502	2,210

GROUP STATEMENT OF CHANGES IN EQUITY

	Attributable to equity holders of the parent
	Share capital £m	Share premium £m	Retained earnings £m	Accumulated other comprehensive income/(loss) £m	Other equity £m	Total £m	Non-controlling interests £m	Total equity £m
1 January 2010	317	778	3,103	(587)	581	4,192	63	4,255
Total comprehensive income	–	–	1,935	268	–	2,203	7	2,210
Employee share schemes	1	55	16	–	(3)	69	–	69
Liquidation of subsidiaries	–	–	–	–	–	–	(70)	(70)
Dividends	–	–	(668)	–	–	(668)	–	(668)
Taxation	–	–	–	–	20	20	–	20
Exchange adjustments	–	–	–	–	3	3	–	3
31 December 2010	318	833	4,386	(319)	601	5,819	–	5,819
Total comprehensive income	–	–	421	81	–	502	–	502
Employee share schemes	1	41	5	–	10	57	–	57
Dividends	–	–	(762)	–	–	(762)	–	(762)
Purchase of non-controlling interest	–	–	(7)	–	–	(7)	–	(7)
Taxation	–	–	–	–	(8)	(8)	–	(8)
Exchange adjustments	–	–	–	–	(1)	(1)	–	(1)
31 December 2011	319	874	4,043	(238)	602	5,600	–	5,600

The notes on pages 29 to 57 form part of these Financial Statements.

GROUP BALANCE SHEET

31 December	Notes	2011 £m	2010 £m
Non-current assets
Goodwill		2,518	2,370
Other intangible assets		1,221	1,084
Property, plant and equipment		6,412	6,398
Interests in joint ventures and associates	13	2,620	2,507
Deferred tax assets		235	238
Trade and other receivables		74	97
Derivative financial instruments	14	290	341
Securities	11	190	234
Retirement benefit assets	15	413	–
		13,973	13,269
Current assets
Inventories		442	344
Current tax assets		81	81
Trade and other receivables		4,212	4,187
Derivative financial instruments	14	315	449
Securities	11	28	23
Cash and cash equivalents	11	518	467
		5,596	5,551
Assets of disposal groups classified as held for sale	17	–	455
Total assets		19,569	19,275
Current liabilities
Trade and other payables		(4,094)	(4,059)
Current tax liabilities		(226)	(182)
Bank overdrafts, loans and other borrowings	11	(502)	(77)
Derivative financial instruments	14	(1,140)	(755)
Provisions for other liabilities and charges		(308)	(195)
		(6,270)	(5,268)
Net current (liabilities)/assets		(674)	283
Non-current liabilities
Trade and other payables		(33)	(56)
Bank overdrafts, loans and other borrowings	11	(3,669)	(3,959)
Derivative financial instruments	14	(505)	(648)
Deferred tax liabilities		(1,506)	(1,367)
Provisions for other liabilities and charges		(1,903)	(1,551)
Retirement benefit obligations	15	(83)	(239)
		(7,699)	(7,820)
Liabilities of disposal groups classified as held for sale		–	(368)
Net assets		5,600	5,819
Equity
Share capital		319	318
Share premium		874	833
Retained earnings		4,043	4,386
Accumulated other comprehensive loss		(238)	(319)
Other equity		602	601
Total shareholders’ equity		5,600	5,819

The notes on pages 29 to 57 form part of these Financial Statements.

GROUP CASHFLOW STATEMENT

Year ended 31 December	Notes	2011 £m	2010 (restated) (i) £m
Cash generated from continuing operations	12	3,229	3,190
Income taxes paid		(430)	(412)
Net petroleum revenue tax paid		(262)	(128)
Interest received		20	5
Interest paid		(3)	(11)
Payments relating to exceptional charges		(194)	(223)
Net cash flow from continuing operating activities		2,360	2,421
Net cash flow from discontinued operating activities		(23)	7
Net cash flow from operating activities		2,337	2,428
Purchase of businesses net of cash and cash equivalents acquired	16	(394)	(606)
Sale of businesses net of cash and cash equivalents disposed of	17	78	9
Purchase of intangible assets	5	(299)	(406)
Purchase of property, plant and equipment	5	(765)	(547)
Disposal of property, plant and equipment and intangible assets		6	47
Investments in joint ventures and associates	13	(236)	(149)
Dividends received from joint ventures and associates	13	147	83
Repayments of loans to, and disposal of investments in, joint ventures and associates	13	10	26
Interest received		6	19
Net sale/(purchase) of securities	12	48	(56)
Net cash flow from continuing investing activities		(1,399)	(1,580)
Net cash flow from discontinued investing activities		(1)	(4)
Net cash flow from investing activities		(1,400)	(1,584)
Issue of ordinary share capital		23	31
Purchase of treasury shares		(6)	(9)
Financing interest received		9	–
Financing interest paid		(202)	(292)
Cash inflow from additional debt		114	267
Cash outflow from payment of capital element of finance leases		(25)	(23)
Cash outflow from repayment of other debt		(30)	(928)
Net cash flow from increase/(reduction) in debt	12	59	(684)
Realised net foreign exchange loss on cash settlement of derivative contracts		(28)	(55)
Equity dividends paid	9	(762)	(668)
Net cash flow from continuing financing activities		(907)	(1,677)
Net increase/(decrease) in cash and cash equivalents		30	(833)
Cash and cash equivalents at 1 January		451	1,285
Effect of foreign exchange rate changes		(2)	(1)
Cash and cash equivalents at 31 December		479	451
Included in the following lines of the Balance Sheet:
Cash and cash equivalents	11	518	467
Bank overdrafts, loans and other borrowings		(39)	(19)
Assets of disposal groups classified as held for sale	17	–	3
		479	451

(i) The 2010 comparatives have been restated for a change in presentation of emission certificate/allowance cash flows. See note 2(d).

The notes on pages 29 to 57 form part of these Financial Statements.

NOTES TO THE FINANCIAL STATEMENTS

1. GENERAL INFORMATION AND BASIS OF PREPARATION

Centrica plc is a Company domiciled and incorporated in the UK. The address of the registered office is Millstream, Maidenhead Road, Windsor, Berkshire, SL4 5GD. The Company has its listing on the London Stock Exchange.

The Financial Statements for the year ended 31 December 2011 included in this announcement were authorised for issue in accordance with a resolution of the Board of Directors on 23 February 2012.

The preliminary results of the year ended 31 December 2011 have been extracted from audited accounts (with the exception of notes 21 to 27 which have not been audited) which have not yet been delivered to the Registrar of Companies. The Financial Statements set out in this announcement do not constitute statutory accounts for the year ended 31 December 2011 or 31 December 2010. The financial information for the year ended 31 December 2010 is derived from the statutory accounts for that year. The report of the auditors on the statutory accounts for the year ended 31 December 2011 was unqualified and did not contain a statement under Section 498 of the Companies Act 2006.

2. SUMMARY OF SIGNIFICANT NEW ACCOUNTING POLICIES AND REPORTING CHANGES

The accounting policies applied in these condensed Financial Statements for the year ended 31 December 2011 are consistent with those of the annual Financial Statements for the year ended 31 December 2010, as described in those Financial Statements, with the exception of standards, amendments and interpretations effective in 2011.

(a) Standards, amendments and interpretations effective in 2011

There are no International Financial Reporting Standards (IFRSs) or IFRIC interpretations that are effective for the first time for the current financial year that have had a material impact on the Group.

(b) Standards, amendments and interpretations that are not yet effective and that have not been early adopted by the Group

At the date of authorisation of these Financial Statements, a number of standards, amendments to existing standards and interpretations have been issued but are not yet effective. The Group has not early adopted any of these. The standards and amendments to standards that could have an impact on the Group’s future financial statements are: IFRS 9, 10, 11, 12, 13 and amendments to IAS 19. The Group is currently assessing the impact these may have.

(c) Change to operating segments

The Upstream UK operating structure is now presented in two segments, Gas and Power. These new segments are each based on the prior year segments of Upstream gas and oil and Power generation respectively. The remaining segments of Industrial and commercial and Proprietary energy trading have been allocated between the new Gas and Power segments. The new structure is consistent with how the Group reports to the Chief Operating Decision Maker defined in IFRS 8. Prior period comparatives have been restated accordingly.

(d) Change to cash flow presentation in relation to emissions certificates/allowances

Cash flows in relation to the purchase of emissions certificates/allowances have previously been classified within investing cash flows as emissions certificates/allowances are accounted for as intangible assets. The Group continues to account for emissions certificates/allowances as intangible assets in the Group Balance Sheet but the associated cash flows have now been included within working capital movements in operating cash flows in the Group Cash Flow Statement as this presentation better reflects the nature of the cash flows. In 2011, the cash outflow amounts to £216 million (2010: £255 million). Prior period comparatives have been restated accordingly.

3. CENTRICA SPECIFIC ACCOUNTING MEASURES AND SELECTED KEY SOURCES OF ESTIMATION UNCERTAINTY

Use of adjusted profit measures

The Directors believe that reporting adjusted profit and adjusted earnings per share measures provides additional useful information on business performance and underlying trends. These measures are used for internal performance purposes. The adjusted measures in this report are not defined terms under IFRS and may not be comparable with similarly titled measures reported by other companies.

The measure of operating profit used by management to evaluate segment performance is adjusted operating profit. Adjusted operating profit is defined as operating profit before:

• exceptional items
• certain re-measurements
• depreciation resulting from fair value uplifts to property, plant and equipment (PP&E) on the acquisition of Strategic Investments

but including:

• the Group’s share of the results from joint ventures and associates before interest and taxation.

Note 5 contains an analysis of adjusted operating profit by segment and a reconciliation of adjusted operating profit to operating profit after exceptional items and certain re-measurements.

Adjusted earnings is defined as earnings before:

• exceptional items net of taxation
• certain re-measurements net of taxation and
• depreciation of fair value uplifts to PP&E on the acquisition of Strategic Investments, net of taxation.

A reconciliation of earnings is provided in note 10.

The Directors have determined that for Strategic Investments it is important to separately identify the earnings impact of increased depreciation arising from the acquisition-date fair value uplifts made to PP&E over their useful economic lives. As a result of the nature of fair value assessments in the energy industry the value attributed to strategic assets is a subjective judgement based on a wide range of complex variables at a point in time. The subsequent depreciation of the fair value uplifts bears little relationship to current market conditions, operational performance or underlying cash generation. Management therefore reports and monitors the operational performance of Strategic Investments before the impact of depreciation on fair value uplifts to PP&E and the segmental results are presented on a consistent basis.

The Group has two Strategic Investments for which reported profits have been adjusted due to the impact of fair value uplifts. These Strategic Investments relate to the 2009 acquisitions of Venture Production plc (‘Venture’) the operating results of which are included within the Upstream UK – Gas segment and the acquisition of the 20% interest in Lake Acquisitions Limited (‘British Energy’), which owned the British Energy Group, the results of which are included within the Upstream UK – Power segment.

(i) Venture

Significant adjustments have been made to the acquired PP&E to report the acquired oil and gas field interests at their acquisition-date fair values which are subsequently depreciated through the Group Income Statement over their respective useful economic lives using the unit of production method.

Whilst the impact of unwinding the PP&E at their acquisition-date fair values is included in overall reported profit for the year, the Directors have reversed the earnings impact of the increased depreciation and related taxation resulting from fair value uplifts to the acquired oil and gas interests in order to arrive at adjusted profit from continuing operations after taxation.

(ii) British Energy

The 20% interest in British Energy is accounted for as an investment in an associate using the equity method. Hence, the Group reports its share of the associate’s profit or loss, which is net of interest and taxation, within the Group Income Statement.

The most significant fair value adjustments arising on the acquisition of the 20% investment in British Energy relate to the fair value uplifts made to the British Energy nuclear power stations to report the PP&E at their acquisition-date fair values and fair value uplifts made to British Energy’s energy procurement contracts and energy sales contracts to report these at their acquisition-date fair values.

Whilst the impact of increased depreciation and related taxation through unwinding the fair value uplifts to the nuclear power stations is included in the share of associate’s post-acquisition result included in overall reported Group profit for the year, the Directors have reversed these impacts in arriving at adjusted profit from continuing operations for the year. The impact of unwinding the acquisition-date fair values attributable to the acquired energy procurement and sales contracts is included within certain re-measurements.

Exceptional items and certain re-measurements

The Group reflects its underlying financial results in the ‘business performance’ column of the Group Income Statement. To be able to provide readers with this clear and consistent presentation, the effects of ‘certain re-measurements’ of financial instruments, and ’exceptional items’, are reported separately in a different column in the Income Statement.

Certain re-measurements predominantly relate to fair value movements on a number of contracts (derivative instruments) entered into as part of the Group’s energy procurement or sales activities. Primarily because these contracts include terms that permit net settlement, the rules within IAS 39 require the contracts to be individually fair valued. These individual, unrealised fair value movements do not reflect the underlying performance of the business because they are economically related to our Upstream assets or Downstream demand, which are not fair valued. Therefore, these certain re-measurements are reported separately.

Exceptional items are those items which are of a non-recurring nature and, in the judgement of the Directors, need to be disclosed separately by virtue of their nature, size or incidence. Again, to ensure the business performance column reflects the underlying results of the Group, these exceptional items are also reported in a separate column in the Group Income Statement. Items which may be considered exceptional in nature include disposals of businesses, business restructurings, significant onerous contract charges, and asset write-downs.

Selected key sources of estimation uncertainty

Impairment of long-lived assets

The Group has several material long-lived assets that are assessed or tested for impairment at each reporting date in accordance with the Group’s accounting policy. The Group make judgements and estimates in considering whether the carrying amounts of these assets or cash generating units (CGUs) are recoverable. The key assets that are subjected to impairment tests are upstream gas and oil assets, power generation assets, storage facility assets, nuclear investment (investment in associate) and goodwill.

Upstream gas and oil assets

The recoverable amount of the Group’s gas and oil assets is determined by discounting the post-tax cash flows expected to be generated by the assets over their lives. The cash flows are derived from projected production profiles of each field, based predominantly on expected 2P reserves and take into account forward prices for gas and liquids over the relevant period. Where forward market prices are not available, prices are determined based on internal model inputs. The recoverable amount also takes into account assumptions market participants would use in estimating fair value.

Power generation assets

The recoverable amount of the Group’s power generation assets is calculated by discounting the pre-tax cash flows expected to be generated by the assets and is dependent on views of forecast power generation, forecast power, gas and carbon prices (where applicable) and the timing and extent of capital expenditure. Where forward market prices are not available, prices are determined based on internal model inputs. The current year impairment charge in relation to UK gas-fired power stations assumes overcapacity in the UK power generation market post-2018 will diminish and normal returns will be achievable on our most efficient assets. Should the overcapacity not diminish, there is a risk of further impairment to assets with a total net book value of £664 million.

Storage facility assets

The recoverable amount of our planned storage facilities is calculated by discounting the post-tax cash flows expected to be generated by the assets based on predictions of seasonal gas price differentials and shorter term price volatilities less any related capital and operating expenditure. This is then compared to the book value. Should the business cases not support the planned investments, this risks a loss of pre-development costs incurred to date of £176 million (which includes £33 million of goodwill).

Nuclear investment

The recoverable amount of the Nuclear investment is based on the value of the existing British Energy nuclear fleet and the value of Nuclear New Build (NNB). The existing fleet value is calculated by discounting post-tax cash flows derived from the stations based on forecast power generation and power prices, whilst taking account of planned outages and the possibility of life extensions. The NNB value is similarly dependent on power prices and generation but also on build cost, decommissioning assessments and government support for nuclear. Should the business case not support the new nuclear investment, this would risk a loss of pre-development costs invested to date of £158 million.

Goodwill

Goodwill does not generate independent cash flows and accordingly is allocated at inception to specific CGUs or groups of CGUs for impairment testing purposes. The recoverable amounts of these CGUs are derived from estimates of future cash flows (as described in the asset classes above). The goodwill impairment tests are also subject to these key estimates.

Pensions and other post–employment benefits

The cost of providing benefits under defined benefit schemes is determined separately for each of the Group’s schemes under the projected unit credit actuarial valuation method. Actuarial gains and losses are recognised in full in the period in which they occur. The key assumptions used for the actuarial valuation are based on the Group’s best estimate of the variables that will determine the ultimate cost of providing post-employment benefits.

Provisions for onerous contracts

The Group has entered into a number of commodity procurement and capacity contracts related to specific assets in the ordinary course of its business. Where the unavoidable costs of meeting the obligations under these contracts exceed the associated, expected future net revenues, an onerous contract provision is recognised. The calculation of these provisions will involve the use of estimates. The key onerous provisions are as follows:

Rijnmond power station operating lease

The onerous provision is calculated using net revenue estimates related to power, gas, and carbon forward prices less the tolling costs. The contract runs until 2030 and so there is currently no liquid market for these commodities for much of this period.

European gas transportation capacity contracts

The onerous provision is calculated using capacity costs incurred under the contracts, less any predicted income. The current year charge assumes that all contracts are onerous for the period to 2018 but that post-2018 the remaining capacities could still be necessary to secure supplies of gas into the UK. Therefore no provision has been recognised relating to this latter period.

North American wind farm power purchase agreements

The onerous nature of the power purchase agreements is measured using estimates relating to wind forecasts, forward curves for energy prices, balancing costs and renewable energy certificates for which there is not a liquid market for the full term of all the contracts.

4. RISK MANAGEMENT

The Group’s normal operating, investing and financing activities expose it to a variety of risks. The processes for managing these risks are set out in the 2010 Annual Report and Accounts. The Group took the following steps to improve the risk reporting process in 2011:

• reporting of risks and audit activity against the risk themes;
• upgrade of the Group’s risk assessment matrices;
• introduction of new red/amber/green controls guidance;
• endorsement of the updated business risk policy and standards; and
• increased focus on tracking of mitigating actions.

Centrica believes that these steps will help maintain good governance for the business going forward.

During 2011 financial risk management was overseen by the Group Financial Risk Management Committee (GFRMC) according to objectives, targets and policies set by the Board. Commodity price risk management is carried out in accordance with individual business unit Financial Risk Management Committees and their respective financial risk management policies, as approved by the GFRMC under delegated authority of the Board. Treasury risk management, including management of currency risk, interest rate risk, equity price risk and liquidity risk is approved by the Board. The wholesale credit risk associated with commodity trading and treasury positions are managed in accordance with the Group’s credit risk policy. Downstream credit risk management is carried out in accordance with individual business unit credit policies.

Credit risk for financial assets

Credit risk from financial asset transactions is generated by the potential for the counterparty to default on its contractual obligations. 2011 was marked by a continuing shortage of available credit in European energy markets due to general economic conditions and the continuing impact of the European Sovereign debt concerns. The Group does not hold any financial instruments issued by any of Portugal, Ireland, Italy, Greece and Spain governments. Further consolidation of energy market participants in key European markets has also impacted overall market activity. Credit markets in North America have followed suit and have been volatile due to ongoing US economy and European Sovereign debt concerns. The Group continues to be vigilant and manage credit risk in accordance with its risk management policy.

Liquidity risk

The Group has a number of treasury and risk policies to monitor and manage liquidity risk. Cash forecasts identifying the Group’s liquidity requirements are produced regularly and are stress-tested for different scenarios, including, but not limited to, reasonably possible increases or decreases in commodity prices and the potential cash implications of a credit rating downgrade. The Group seeks to ensure that sufficient financial headroom exists for at least a 12-month period to safeguard the Group’s ability to continue as a going concern. It is the Group's policy to maintain committed facilities and/or available surplus cash resources of at least £1,200 million, raise at least 75% of its net debt (excluding non-recourse debt) in the long-term debt market and to maintain an average term to maturity in the recourse long-term debt portfolio greater than five years.

At 31 December 2011, the Group had undrawn committed credit facilities of £3,254 million (2010: £2,873 million) and £518 million (2010: £467 million) of cash and cash equivalents. These facilities include a £500 million facility to aid the purchase of the Statoil gas and oil assets as described in note 19. 115% (2010: 121%) of the Group’s net debt has been raised in the long-term debt market and the average term to maturity of the long-term debt portfolio was 9.6 years (2010: 10.5 years).

5. SEGMENTAL ANALYSIS

Year ended 31 December			2011			2010 (restated) (ii)
(a) Revenue	Gross segment revenue £m	Less inter- segment revenue (i) £m	Group revenue £m	Gross segment revenue £m	Less inter- segment revenue (i) £m	Group revenue £m
Continuing operations:
Residential energy supply	8,113	(3)	8,110	8,359	(4)	8,355
Residential services	1,504	–	1,504	1,464	–	1,464
Business energy supply and services	2,702	(1)	2,701	2,907	(1)	2,906
Downstream UK	12,319	(4)	12,315	12,730	(5)	12,725
Gas ^(ii)	3,571	(521)	3,050	2,490	(431)	2,059
Power ^(ii)	1,588	(179)	1,409	1,519	(13)	1,506
Upstream UK	5,159	(700)	4,459	4,009	(444)	3,565
Storage UK	184	(20)	164	267	(35)	232
Residential energy supply	2,416	–	2,416	2,502	–	2,502
Business energy supply	2,748	–	2,748	2,682	–	2,682
Residential and business services	520	–	520	485	–	485
Upstream and wholesale energy	433	(231)	202	328	(96)	232
North America	6,117	(231)	5,886	5,997	(96)	5,901
	23,779	(955)	22,824	23,003	(580)	22,423
Discontinued operations:
European Energy (note 17)	167	–	167	590	–	590

(i) Inter-segment revenue is subject to year on year fluctuations due to the change in the mix of internal and external energy sales by Upstream UK.

(ii) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

Year ended 31 December
(b) Operating profit	2011   £m	2010 (restated) (i) £m
Continuing operations:
Residential energy supply	522	742
Residential services	264	241
Business energy supply and services	219	233
Downstream UK	1,005	1,216
Gas ^(i) (ii)	769	566
Power ^(i) (ii)	254	205
Upstream UK	1,023	771
Storage UK	75	169
Residential energy supply	161	177
Business energy supply	110	88
Residential and business services	28	15
Upstream and wholesale energy	13	(46)
North America	312	234
Adjusted operating profit – segment operating profit before exceptional items, certain re-measurements and impact of fair value uplifts from Strategic Investments ^(iii)	2,415	2,390
Share of joint ventures/associates’ interest and taxation	(102)	(78)
Depreciation of fair value uplifts to property, plant and equipment – Venture ^(ii)	(64)	(60)
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – British Energy ^(ii)	(41)	(58)
	2,208	2,194
Exceptional items (note 6)	(331)	(283)
Certain re-measurements included within gross profit (note 6)	(437)	1,177
Certain re-measurements of associates’ energy contracts (net of taxation) (note 6)	(26)	(14)
Operating profit after exceptional items and certain re-measurements	1,414	3,074
Discontinued operations:
European Energy (note 17) ^(iv)	13	(5)

(i) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(ii) See note 3 and note 10 for explanation of the depreciation on fair value uplifts to property, plant and equipment (PP&E) on acquiring Strategic Investments.

(iii) Includes results of equity-accounted interests before interest and taxation.

(iv) Represents profit/(loss) after taxation and before exceptional items and certain re-measurements of Oxxio B.V. up to the date of disposal. This is the measure of results of discontinued operations that is reported regularly to the Group’s Executive Committee.

Year ended 31 December	Share of results of joint ventures and associates before interest and taxation		Depreciation and impairments of property, plant and equipment (i)			Amortisation, write-downs and impairments of intangibles
(c) Included within adjusted operating profit	2011 £m	2010 (restated) (iii) £m		2011 £m	2010 (restated) (iii) £m	2011 £m	2010 (restated) (iii) £m
Continuing operations:
Residential energy supply	–	–		8	6	23	38
Residential services	–	–		18	9	6	1
Business energy supply and services	–	–		2	2	7	7
Downstream UK	–	–		28	17	36	46
Gas ^(i) (ii) (iii)	(1)	3		503	487	52	91
Power ^(i) (iii) (iv)	237	140		112	120	4	1
Upstream UK	236	143		615	607	56	92
Storage UK	–	–		30	26	–	–
Residential energy supply	–	–		1	–	9	5
Business energy supply	–	–		1	1	4	4
Residential and business services	–	–		3	2	6	5
Upstream and wholesale energy ^(ii)	–	–		89	88	4	3
North America	–	–		94	91	23	17
Other ^(v)	–	–		19	15	25	19
	236	143		786	756	140	174

(i) Depreciation of PP&E is stated before depreciation of fair value uplifts for Strategic Investments.

(ii) During 2011, £46 million of write downs relating to exploration and evaluation assets were incurred in Upstream UK (2010: £81 million in Upstream UK and £2 million in Upstream North America).

(iii) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(iv) Share of results of joint ventures and associates is before interest, certain re-measurements, depreciation of fair value uplifts to PP&E on Strategic Investments and taxation.

(v) Other comprises depreciation of PP&E and amortisation and write-downs of intangibles on Corporate Centre assets which are charged out to other Group segments.

31 December	Net segment assets/(liabilities)		Average capital employed Year ended 31 December
(d) Assets and liabilities	2011 £m	2010 (restated) (i) £m	2011 £m	2010 (restated) (i) £m
Residential energy supply	125	27	151	195
Residential services	254	225	258	95
Business energy supply and services	558	516	569	552
Downstream UK	937	768	978	842
Gas ^(i)	2,427	2,894	1,500	1,240
Power ^(i)	3,534	3,677	3,335	3,446
Upstream UK	5,961	6,571	4,835	4,686
Storage UK	517	347	221	206
Residential energy supply	925	731	715	709
Business energy supply	459	441	315	288
Residential and business services	377	400	366	323
Upstream and wholesale energy	733	784	677	659
North America	2,494	2,356	2,073	1,979
	9,909	10,042	8,107	7,713
Unallocated current and deferred tax balances	186	217
Derivative financial instruments held for energy procurement ^(ii)	(1,214)	(715)
Bank overdrafts and loans, securities and treasury derivatives	(3,868)	(3,716)
Retirement benefit assets/(obligations)	330	(239)
Corporate centre assets and discontinued operations ^(iii)	257	230
Non-operating liabilities	(4,309)	(4,223)
	5,600	5,819

(i) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(ii) Includes balances held by joint ventures/associates.

(iii) During 2010 assets and liabilities of discontinued operations were classified as held for sale.

Capital employed represents the investment required to operate each of the Group’s segments. Capital employed is used by the Group to calculate the return on capital employed for each of the Group’s segments as part of the Group’s managing for value concept. Additional value is created when the return on capital employed exceeds the cost of capital. Net segment assets of the Group can be reconciled to the Group’s capital employed as follows:

	2011 £m	2010 £m
Net segment assets at 31 December	9,909	10,042
Deduct:
Intra-Group balances	56	26
Pre-productive assets	(2,287)	(1,659)
Margin call debtor	(188)	(161)
Cash at bank, in transit and in hand excluding certain restricted cash	(44)	(117)
Effect of averaging	661	(418)
Average capital employed for year ended 31 December	8,107	7,713

Year ended 31 December	Capital expenditure on property, plant and equipment		Capital expenditure on intangible assets other than goodwill
(e) Capital expenditure	2011   £m	2010 (restated) (i) £m	2011   £m	2010 (restated) (i) (ii) £m
Continuing operations:
Residential energy supply	48	15	240	256
Residential services	6	6	22	15
Business energy supply and services	3	1	75	68
Downstream UK	57	22	337	339
Gas ^(i)	488	383	97	230
Power ^(i)	89	82	6	28
Upstream UK	577	465	103	258
Storage UK	59	33	–	–
Residential energy supply	–	–	4	2
Business energy supply	1	–	18	10
Residential and business services	2	2	1	5
Upstream and wholesale energy	36	20	8	10
North America	39	22	31	27
Other	26	16	49	29
Capital expenditure on continuing operations	758	558	520	653
(Decrease)/increase in prepayments related to capital expenditure	(15)	18	–	6
Capitalised borrowing costs	(46)	(37)	–	–
Decrease/(increase) in trade payables related to capital expenditure	68	8	(5)	2
Purchases of emissions allowances and renewable obligations certificates ^(ii)	–	–	(216)	(255)
Net cash outflow	765	547	299	406

(i) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(ii) The 2010 comparatives have been restated for a change in presentation of emission certificate/allowance cash flows. See note 2(d).

6. EXCEPTIONAL ITEMS AND CERTAIN RE-MEASUREMENTS

(a) Exceptional items for the year ended 31 December	2011 £m	2010 £m
Continuing operations:
Provision for European onerous capacity contracts ^(i)	(221)	–
Provision for North American and UK onerous commodity contracts	–	(102)
Exceptional items from continuing operations included within gross profit	(221)	(102)
Impairments:
Impairment of UK generation assets ^(ii)	(226)	(68)
Impairment of North American and UK exploration and production assets	–	(95)
	(226)	(163)
Downstream UK contract migration ^(iii)	(63)	(43)
Restructuring charges ^(iv)	(154)	–
Profit on disposal of investments	–	25
Pension curtailment (note 15)	333	–
	(110)	(181)
Exceptional items from continuing operations included within Group operating profit	(331)	(283)
Taxation on exceptional items (note 8)	69	118
Effect of change in UK supplementary tax charge (note 8)	(204)	–
Net exceptional items from continuing operations after taxation	(466)	(165)
Discontinued operations:
Loss on disposal of Oxxio B.V. after taxation (note 17)	(56)	–
Total exceptional items after taxation	(522)	(165)

(b) Certain re-measurements for the year ended 31 December	2011 £m	2010 £m
Continuing operations:
Certain re-measurements recognised in relation to energy contracts:
Net gains arising on delivery of contracts ^(v)	200	1,023
Net (losses)/gains arising on market price movements and new contracts ^(vi)	(632)	130
Net (losses)/gains arising on positions in relation to cross-border transportation or capacity contracts	(5)	24
Net re-measurements from continuing operations included within gross profit	(437)	1,177
Net losses arising on re-measurement of associates’ energy contracts (net of taxation) ^(vii)	(26)	(14)
Net re-measurements included within Group operating profit	(463)	1,163
Taxation on certain re-measurements (note 8)	119	(339)
Net re-measurements from continuing operations after taxation	(344)	824
Discontinued operations:
Net re-measurements on energy contracts of discontinued operations after taxation	22	67
Total re-measurements after taxation	(322)	891

(i) As a result of the decision to withdraw from Europe the Group recorded onerous contract charges of £111 million for a number of European gas transportation capacity contracts and a further £110 million for the fixed price Rijnmond tolling contract due to the impact of low spark spreads.

(ii) Impairment charges have been recognised on a number of UK generation assets (including PP&E and inventory) as a result of low spark spreads, which led to the impairment of Killingholme, proposed closure of Barry and Kings Lynn and the operational reconfiguration of Brigg, Peterborough and Roosecote.

(iii) Exceptional charges have been recorded following the termination in December 2010 and subsequent migration of a significant supplier contract.

(iv) Relates to a Group-wide cost reduction programme leading to staff redundancies, see Operating Review for more details.

(v) As energy is delivered or consumed from previously contracted positions the related fair value recognised in the opening balance sheet (representing the discounted difference between forward energy prices at the opening balance sheet date and the contract price of energy to be delivered) is charged or credited to the Income Statement.

(vi) Represents fair value (losses)/gains arising from the change in fair value of future contracted sales and purchase contracts as a result of changes in forward energy prices between reporting dates (or date of inception and the reporting date, where later).

(vii) Includes fair value unwinds relating to the recognition of energy procurement contracts and energy sales contracts at their acquisition-date fair values.

7. NET INTEREST

			2011		2010
Year ended 31 December	Interest expense £m	Interest income £m	Total £m	Interest expense £m	Interest income £m	Total £m
Continuing operations: Cost of servicing net debt:
Interest income	–	37	37	–	30	30
Interest expense on bonds, bank loans and overdrafts ^(i)	(176)	–	(176)	(284)	–	(284)
Interest expense on finance leases	(19)	–	(19)	(21)	–	(21)
	(195)	37	(158)	(305)	30	(275)
(Losses)/gains on revaluation:
(Losses)/gains on fair value hedges	(83)	72	(11)	(47)	47	–
Fair value (losses)/gains on other derivatives ^(ii)	(71)	35	(36)	(121)	9	(112)
Fair value gains on other securities measured at fair value	–	14	14	–	10	10
Net foreign exchange translation of monetary assets and liabilities ^(iii)	–	19	19	–	85	85
	(154)	140	(14)	(168)	151	(17)
Notional interest arising from discounting and other interest ^(iv)	(55)	35	(20)	(43)	33	(10)
	(404)	212	(192)	(516)	214	(302)
Capitalised borrowing costs ^(v)	46	–	46	37	–	37
Interest (expense)/income	(358)	212	(146)	(479)	214	(265)

(i) During December 2010 Centrica reduced its outstanding bond debt principal by £151 million and €383 million.

(ii) Primarily reflects changes in the fair value of derivatives used to hedge the foreign exchange exposure associated with inter-company loans denominated in foreign currencies.

(iii) Primarily reflects foreign exchange gains on loans denominated in foreign currencies.

(iv) Other interest includes interest received for cash collateral balances and interest on supplier early payment arrangements.

(v) Borrowing costs have been capitalised using an average rate of 4.94% (2010: 4.78%).

8. TAXATION

			2011			2010
Analysis of tax charge for the year	Business performance £m	Exceptional items and certain re-measurements £m	Results for the year £m	Business performance £m	Exceptional items and certain re-measurements £m	Results for the year £m
Current tax
UK corporation tax	(529)	69	(460)	(464)	23	(441)
UK petroleum revenue tax	(220)	–	(220)	(223)	–	(223)
Foreign tax	(107)	10	(97)	(15)	(6)	(21)
Adjustments in respect of prior years	23	–	23	171	–	171
Total current tax	(833)	79	(754)	(531)	17	(514)
Deferred tax
Current year	(40)	90	50	(81)	(235)	(316)
UK petroleum revenue tax	46	–	46	7	–	7
Foreign deferred tax	(24)	17	(7)	(39)	7	(32)
Change in tax rates	30	(201)	(171)	15	(1)	14
Adjustments in respect of prior years	11	(1)	10	(79)	(9)	(88)
Total deferred tax	23	(95)	(72)	(177)	(238)	(415)
Total tax on profit from continuing operations ^(i)	(810)	(16)	(826)	(708)	(221)	(929)

(i) Total tax on profit from continuing operations excludes taxation on the Group’s share of profits in joint ventures and associates.

The Group earns its profits primarily in the UK, therefore the tax rate used for tax on profit from ordinary activities is the standard rate for UK corporation tax, which from 1 April 2011 was 26% (2010: 28%), with the exception of upstream profits, which were taxed at a UK corporation tax rate of 30% (2010: 30%) plus a supplementary charge. From 29 March 2011, the supplementary charge was increased to 32% (2010: 20%). Also announced in March 2011, was an intention to restrict from 2012, the rate of tax relief on decommissioning costs from the current 62% to 50%. If enacted, a one-off charge of approximately £60 million will arise from revaluing the related deferred tax provisions.

Certain upstream assets also bear petroleum revenue tax at 50% (2010: 50%). Taxation for other jurisdictions is calculated at the rates prevailing in those respective jurisdictions.

The UK Government has announced its intention to propose Parliament reduce the main rate of UK corporation tax to 23% by 1 April 2014. At 31 December 2011 a reduction in the rate to 25% had been substantively enacted so the relevant UK deferred tax assets and liabilities included in these Financial Statements have been based on that rate. The effect of the additional proposed reduction in the UK corporation tax rate by 2014 would be to decrease the net deferred tax liability by £11 million.

9. DIVIDENDS

			2011			2010
	£m	Pence per share	Date of payment	£m	Pence per share	Date of payment
Prior year final dividend	540	10.46	15 Jun 2011	470	9.14	16 Jun 2010
Interim dividend	222	4.29	16 Nov 2011	198	3.84	17 Nov 2010
	762			668

The Directors propose a final dividend of 11.11 pence per ordinary share (totalling £575 million) for the year ended 31 December 2011. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 11 May 2012 and, subject to approval, will be paid on 13 June 2012 to those shareholders registered on 27 April 2012.

10. EARNINGS PER ORDINARY SHARE

Basic earnings per ordinary share has been calculated by dividing the earnings attributable to equity holders of the Company for the year of £421 million (2010: £1,935 million) by the weighted average number of ordinary shares in issue during the year of 5,159 million (2010: 5,146 million). The number of shares excludes seven million ordinary shares (2010: six million), being the weighted average number of the Company’s own shares held in the employee share trust which are treated as treasury shares. The Directors believe that the presentation of adjusted basic earnings per ordinary share, being the basic earnings per ordinary share adjusted for certain re-measurements, exceptional items and the impact of Strategic Investments, assists with understanding the underlying performance of the Group, as explained in note 3.

The reconciliation of basic to adjusted basic earnings per ordinary share is as follows:

Year ended 31 December		2011		2010
(a) Continuing and discontinued operations	£m	Pence per ordinary share	£m	Pence per ordinary share
Earnings – basic	421	8.2	1,935	37.6
Net exceptional items after taxation (note 6)	522	10.1	165	3.2
Certain re-measurement losses/(gains) after taxation (note 6)	322	6.2	(891)	(17.3)
Depreciation of fair value uplifts to property, plant and equipment from Strategic Investments, after taxation	68	1.3	88	1.7
Earnings – adjusted basic	1,333	25.8	1,297	25.2
Earnings – diluted	421	8.1	1,935	37.3
Earnings – adjusted diluted	1,333	25.6	1,297	25.0

Strategic Investments

During 2009, the Group acquired a 20% interest in British Energy and the entire share capital of Venture. As explained in note 3, the depreciation relating to fair value uplifts of the acquired Venture PP&E and associated taxation is excluded in arriving at adjusted earnings for the year, which amounted to £64 million (2010: £60 million) depreciation and a taxation credit of £37 million (2010: £30 million) in the period. Additionally, the impact of depreciation arising on fair value uplifts attributed to the British Energy nuclear power stations and related taxation included within the Group’s share of the post-taxation results of the associate is excluded in arriving at adjusted earnings for the period, which amounted to £41 million (2010: £58 million) net of taxation.

Year ended 31 December		2011		2010
(b) Continuing operations	£m	Pence per ordinary share	£m	Pence per ordinary share
Earnings – basic	442	8.6	1,873	36.4
Net exceptional items after taxation (note 6)	466	9.0	165	3.2
Certain re-measurement losses/(gains) after taxation (note 6)	344	6.7	(824)	(16.0)
Depreciation of fair value uplifts to property, plant and equipment from Strategic Investments, after taxation	68	1.3	88	1.7
Earnings – adjusted basic	1,320	25.6	1,302	25.3
Earnings – diluted	442	8.5	1,873	36.1
Earnings – adjusted diluted	1,320	25.4	1,302	25.1

Year ended 31 December		2011		2010
(c) Discontinued operations	£m	Pence per ordinary share	£m	Pence per ordinary share
(Loss)/earnings – basic and diluted	(21)	(0.4)	62	1.2

Certain re-measurements (note 6) included within operating profit and discontinued operations comprise re-measurements arising on energy procurement activities and re-measurements of proprietary trades in relation to cross-border transportation or capacity contracts. All other re-measurements are included within results before exceptional items and certain re-measurements.

In addition to basic and adjusted basic earnings per ordinary share, information is presented for diluted and adjusted diluted earnings per ordinary share. Under this presentation, no adjustments are made to the reported earnings for either 2011 or 2010, however the weighted average number of shares used as the denominator is adjusted for potentially dilutive ordinary shares.

(d) Weighted average number of shares	2011 Million shares	2010 Million shares
Weighted average number of shares used in the calculation of basic earnings per ordinary share	5,159	5,146
Dilutive impact of share-based payment schemes	44	45
Weighted average number of shares used in the calculation of diluted earnings per ordinary share	5,203	5,191

11. SOURCES OF FINANCE

The Group funds its business using a combination of debt and shareholders’ equity.

31 December	2011 £m	2010 £m
Net debt	3,435	3,312
Shareholders’ equity	5,600	5,819
Capital	9,035	9,131

The Group seeks to maintain an efficient capital structure with a balance of debt and equity. Debt levels are restricted to limit the risk of financial distress and, in particular, to maintain strong credit ratings. The Group’s credit ratings are important in keeping the cost of debt down, in limiting collateral requirements in energy trading and hedging, and in ensuring the Group is an attractive counterparty to gas and power producers and to customers for longer term energy contracts.

The Group monitors its current and projected capital position on a regular basis, considering a medium-term view of three to five years, and different stress case scenarios, including the impact of changes in the Group’s credit ratings and significant movements in commodity prices. A number of financial ratios are monitored, including those used by the credit rating agencies, such as debt to cash flow ratios and EBITDA to gross interest expense. At 31 December 2011, the ratio of the Group’s net debt to EBITDA was 1.1 (2010: 1.0). EBITDA to gross interest expense for the year ended 31 December 2011 was 8.7 (2010: 6.7).

British Gas Insurance Limited (BGIL) is required under FSA regulations to hold a minimum capital amount and has complied with this requirement in 2011 (and 2010). For the remainder of the Group, the level of debt that can be raised is restricted by the Company’s Articles of Association. Net debt is limited to the greater of £5.0 billion and a gearing ratio of three times adjusted capital and reserves. Based on adjusted capital and reserves as at 31 December 2011 of £5.6 billion, the limit for net debt was £16.8 billion. The Group funds its debt principally through issuing bonds. In addition the Group also maintains substantial committed facilities from banks (see note 4), but generally uses these to provide backup liquidity and does not typically draw on them.

(a) Net debt summary	2011 £m	2010 £m
Cash at bank, in transit and in hand	94	114
Short-term deposits	424	353
Cash and cash equivalents ^(i)	518	467
Securities – current ^(ii)	28	23
Securities – non-current ^(ii)	190	234
Current and non-current borrowings	(4,171)	(4,036)
Net debt at the end of the year	(3,435)	(3,312)

(i) Cash and cash equivalents includes £262 million (2010: £206 million) mostly held by the Group’s insurance subsidiary undertakings that is not readily available to be used for other purposes within the Group.

(ii) Securities balances include £91 million of available for sale financial assets (2010: £93 million).

					2011			2010
(b) Borrowings summary	Coupon rate %	Principal m	Current £m	Non-current £m	Total £m	Current £m	Non-current £m	Total £m
Bank overdrafts and loans			69	198	267	52	225	277
Bonds (by maturity date):
2 November 2012	5.875	£284	291	–	291	–	296	296
27 February 2013	1.045	¥3,000	–	26	26	–	25	25
9 December 2013	7.125	€367	–	317	317	–	326	326
4 November 2014	Floating	$100	–	64	64	–	64	64
10 December 2014	5.125	£315	–	335	335	–	329	329
31 March 2015	Floating	$70	–	45	45	–	45	45
24 October 2016	5.500	£300	–	336	336	–	320	320
19 September 2018	7.000	£400	–	473	473	–	444	444
10 March 2022	6.375	£500	–	527	527	–	527	527
4 September 2026	6.400	£200	–	224	224	–	209	209
16 April 2027	5.900	$70	–	45	45	–	45	45
19 September 2033	7.000	£770	–	777	777	–	777	777
			291	3,169	3,460	–	3,407	3,407
Commercial paper			114	–	114	–	–	–
Obligations under finance leases			28	302	330	25	327	352
			502	3,669	4,171	77	3,959	4,036

12. NOTES TO THE GROUP CASH FLOW STATEMENT

(a) Reconciliation of Group operating profit to cash generated from continuing operations	2011 £m	2010 (restated) (i) £m
Continuing operations
Group operating profit including share of result of joint ventures and associates	1,414	3,074
Less share of (profit)/loss of joint ventures and associates	(67)	7
Group operating profit before share of results of joint ventures and associates	1,347	3,081
Add back/(deduct):
Amortisation and write-down of intangible assets	140	176
Depreciation and write-down of property, plant and equipment	1,055	973
Recycling of write-down of available-for-sale financial assets ^(ii)	23	4
Loss/(profit) on sale of businesses, property, plant and equipment and other intangible assets	5	(22)
Increase in provisions	395	159
Net pension curtailment (gain)/loss	(332)	14
Pension service cost	118	115
Pension contributions	(130)	(441)
Employee share scheme costs	40	48
Re-measurement of energy contracts ^(iii)	404	(1,097)
Operating cash flows before movements in working capital	3,065	3,010
(Increase)/decrease in inventories	(79)	31
Decrease in trade and other receivables ^(iv)	201	162
Increase/(decrease) in trade and other payables ^(i) (iv)	42	(13)
Cash generated from continuing operations	3,229	3,190

(i) The 2010 comparatives have been restated for a change in presentation of emission certificate/allowance cash flows. See note 2(d).

(ii) The 2010 comparative of £4 million is impairment of joint ventures and associates.

(iii) Adds back unrealised losses/(gains) arising from re-measurement of energy contracts.

(iv) Includes net outflow of £26 million of cash collateral in 2011 (2010: net inflow of £466 million).

(b) Reconciliation of net increase in cash and cash equivalents to movement in net debt	2011 £m	2010 £m
Net increase/(decrease) in cash and cash equivalents	30	(833)
Increase in cash and cash equivalents of disposal groups classified as held for sale	–	16
	30	(817)
Add back/(deduct):
Net (sale)/purchase of securities	(48)	56
Cash inflow from additional debt	(114)	(267)
Cash outflow from payment of capital element of finance leases	25	23
Cash outflow from repayment of other debt	30	928
	(77)	(77)
Revaluation of:
Securities	10	7
Loans and other borrowings	(59)	(40)
	(126)	(110)
Increase in interest payable on loans and other borrowings	(2)	(2)
Acquisitions	(3)	–
Disposals	–	(56)
Exchange adjustments	8	(8)
Movement in net debt	(123)	(176)
Net debt at 1 January	(3,312)	(3,136)
Net debt at the end of the year	(3,435)	(3,312)

13. INTERESTS IN JOINT VENTURES AND ASSOCIATES

			2011			2010
(a) Interest in joint ventures and associates	Investments in joint ventures and associates £m	Shareholder loans £m	Total £m	Investments in joint ventures and associates £m	Shareholder loans £m	Total £m
1 January	2,343	164	2,507	2,356	66	2,422
Additions	113	115	228	66	124	190
Decrease in shareholder loans	–	(10)	(10)	–	(26)	(26)
Share of profits/(losses) for the year	67	–	67	(7)	–	(7)
Share of reserve movements	(25)	–	(25)	15	–	15
Dividends	(147)	–	(147)	(83)	–	(83)
Impairments	–	–	–	(4)	–	(4)
31 December	2,351	269	2,620	2,343	164	2,507

(b) Share of joint ventures’ and associates’ assets and liabilities

The Group’s share of joint ventures’ and associates’ gross assets and gross liabilities at 31 December 2011 principally comprised of its interests in the following entities (all reported in Upstream UK – Power segment):

• Wind farms – Braes of Doune Wind Farm (Scotland) Limited, Barrow Offshore Wind Limited, GLID Wind Farms TopCo Limited ⁽ⁱ⁾ and Lincs Wind Farm Limited
• Nuclear – Lake Acquisitions Limited (British Energy) and NNB Holding Company Limited

				2011	2010
	Joint ventures	Associates
	Wind farms £m	Nuclear £m	Other (ii) £m	Total £m	Total £m
Share of non-current assets	590	3,744	50	4,384	4,169
Share of current assets	52	622	2	676	698
	642	4,366	52	5,060	4,867
Share of current liabilities	(112)	(203)	–	(315)	(270)
Share of non-current liabilities	(422)	(1,950)	(13)	(2,385)	(2,250)
	(534)	(2,153)	(13)	(2,700)	(2,520)
Restricted interest on shareholder loan ^(iii)	(9)	–	–	(9)	(4)
Share of net assets of joint ventures and associates ^(iv)	99	2,213	39	2,351	2,343
Shareholder loans	252	–	17	269	164
Interests in joint ventures and associates	351	2,213	56	2,620	2,507
Net (debt)/cash included in share of net assets	(376)	105	(12)	(283)	(205)

(i) As part of a finance arrangement entered into by GLID Wind Farms TopCo Limited, the Group’s shares in GLID Wind Farms TopCo Limited are pledged to a third party. The pledge will only come into force should GLID Wind Farms TopCo Limited default on any of its obligations under the finance arrangement.

(ii) Other includes joint ventures of North Sea Infrastructure Partners Limited, Bacton Storage Company Limited and Secure Electrans Limited.

(iii) The Group restricts the amount of interest receivable on the shareholder loan from Lincs Wind Farm Limited to 50% of the interest capitalised by the joint venture.

(iv) Includes £158 million of assets and £21 million of liabilities of NNB Holding Company Limited (2010: £106 million of assets and £21 million of liabilities).

(c) Share of profits/(losses) in joint ventures and associates				2011	2010
	Joint ventures	Associates
	Wind farms £m	Nuclear £m	Other £m	Total £m	Total £m
Income	62	532	–	594	468
Expenses excluding certain re-measurements ^(i)	(26)	(417)	(1)	(444)	(422)
Certain re-measurements	–	(33)	–	(33)	(31)
	36	82	(1)	117	15
Interest paid	(17)	(37)	(4)	(58)	(55)
Taxation excluding certain re-measurements ^(i)	(4)	7	(2)	1	16
Taxation on certain re-measurements	–	7	–	7	17
Share of post-taxation results of joint ventures and associates	15	59	(7)	67	(7)

(i) Includes £86 million (2010: £97 million) relating to depreciation of fair value uplifts to PP&E on acquiring the British Energy investments. The associated tax impact is £45 million credit (2010: £39 million).

British Energy

During November 2009 the Group acquired a 20% interest in British Energy for £2,255 million and NNB Holding Company Limited for £32 million. The Group’s share of profit arising from its investment in British Energy for the year to 31 December 2011 as set out in the table above includes the effect of unwinding the fair value adjustments. As explained in note 3 the depreciation, net of taxation, arising on fair value uplifts attributed to the nuclear power stations is reversed in arriving at adjusted profit for the period as shown in the reconciliation table below and as set out in note 5(b).

(d) Reconciliation of share of profits/(losses) in joint ventures and associates to share of adjusted profits/(losses) in joint ventures and associates				2011	2010
	Joint ventures	Associates
	Wind farms £m	Nuclear £m	Other £m	Total £m	Total £m
Share of post-taxation results of joint ventures and associates	15	59	(7)	67	(7)
Certain re-measurements (net of taxation)	–	26	–	26	14
Depreciation – British Energy (net of taxation) ^(i)	–	41	–	41	58
Interest	17	37	4	58	55
Taxation (excluding certain re-measurements and British Energy depreciation)	4	38	2	44	23
Share of adjusted results of joint ventures and associates	36	201	(1)	236	143

(i) Relates to depreciation of fair value uplifts to PP&E on acquiring the British Energy investments.

14. DERIVATIVE FINANCIAL INSTRUMENTS

Derivative financial instruments are held for the following purposes and accounted for accordingly:

Purpose	Accounting treatment
Proprietary energy trading and treasury management	Carried at fair value with changes in fair value recognised in the Group’s results for the year before exceptional items and certain re-measurements (i)
Energy procurement	Carried at fair value, with changes in the fair value reflected in certain re-measurements (ii)

(i) With the exception of certain energy derivatives related to cross-border transportation and capacity contracts.

(ii) Energy contracts designated at fair value through profit and loss include certain energy contracts that the Group has, at its option, designated at fair value through profit and loss under IAS 39 because the energy contract contains one or more embedded derivatives that significantly modify the cash flows under the contract.

In cases where a derivative qualifies for hedge accounting, derivatives are classified as fair value hedges, cash flow hedges or hedges of a net investment in a foreign operation.

The carrying values of derivative financial instruments by product type for accounting purposes are as follows:

		2011		2010
	Assets £m	Liabilities £m	Assets £m	Liabilities £m
Derivative financial instruments – held for trading under IAS 39:
Energy derivatives – for procurement	332	(1,390)	538	(1,022)
Energy derivatives – for proprietary trading	61	(14)	47	(31)
Interest rate derivatives	22	(79)	3	(16)
Foreign exchange derivatives	23	(37)	53	(100)
Energy derivative contracts designated at fair value through profit and loss	7	(46)	1	(143)
Derivative financial instruments in hedge accounting relationships:
Energy derivatives	–	(65)	25	(86)
Interest rate derivatives	157	(7)	105	–
Foreign exchange derivatives	3	(7)	18	(5)
Total derivative financial instruments	605	(1,645)	790	(1,403)
Included within:
Derivative financial instruments – current	315	(1,140)	449	(755)
Derivative financial instruments – non-current	290	(505)	341	(648)

The contracts included within energy derivatives are subject to a wide range of detailed specific terms but comprise the following general components, analysed on a net carrying value basis:

	2011 £m	2010 £m
Short-term forward market purchases and sales of gas and electricity:
UK and Europe	(458)	24
North America	(406)	(451)
Structured gas purchase contracts	(91)	89
Structured gas sales contracts	(120)	(176)
Other	(40)	(157)
Net total	(1,115)	(671)

15. PENSIONS

(a) Summary of main defined benefit schemes

Name of scheme	Section	Status	Funding/tax status	Country
Centrica Engineers Pension Scheme	Final salary section	Closed to new members	Funded/tax-registered	UK
	Career average section	Open to new members	Funded/tax-registered	UK
Centrica Pension Plan	Management section	Closed to new members	Funded/tax-registered	UK
	2008 section	Closed to new members	Funded/tax-registered	UK
Centrica Pension Scheme	Final salary section	Closed to new members	Funded/tax-registered	UK
	Career average section	Closed to new members	Funded/tax-registered	UK
Centrica Unapproved Pension Scheme		Closed to new members	Unfunded/non-registered	UK
Direct Energy Marketing Ltd pension plan		Closed to new members	Funded/tax-registered	Canada

The Centrica Pension Scheme also has a defined contribution section which is open to new members.

The Centrica Engineers Pension Scheme (CEPS), Centrica Pension Plan (CPP) and Centrica Pension Scheme form the majority of the Group’s defined benefit obligation and are referred to below as the ‘Registered Pension Schemes’.

(b) 2011 curtailment gain

During the year, the Company announced changes to the terms of the final salary sections of the CEPS and the CPP with the changes taking effect from 1 January 2012 and 1 March 2012 respectively. Employees’ annual increases in pensionable pay will be capped to 2% and annual increases in respect of future years’ service for pensions in deferment will be the lower of CPI and 2.5%. Following agreement of the changes in October 2011 (for CEPS) and December 2011 (for CPP) with the trade unions and the Trustees, the Company has recognised exceptional curtailment gains of £333 million, as disclosed in note 6.

The other final salary defined benefit obligations in the UK are within the Centrica Pension Scheme and the Centrica Unapproved Pension Scheme, which have a combined active membership of approximately 100 employees.

(c) Accounting assumptions

The accounting assumptions for the Registered Pension Schemes have been given below.

Major assumptions used for the actuarial valuation	31 December 2011 %	31 December 2010 %
Rate of increase in employee earnings
Subject to cap	2.0	n/a
Other	4.3	4.7
Rate of increase in pensions in payment	3.3	3.7
Rate of increase in deferred pensions
In line with CPI capped at 2.5%	2.3	n/a
In line with RPI	3.3	3.7
Discount rate	5.4	5.7

The assumptions relating to longevity underlying the pension liabilities at the balance sheet date have been based on a combination of standard actuarial mortality tables, scheme experience and other relevant data, and include a medium cohort allowance, as published by the Institute and Faculty of Actuaries, with an underpin. The assumptions are equivalent to future longevity for members in normal health approximately as follows:

	2011		2010
Life expectancy at age 65 for a member	Male Years	Female Years	Male Years	Female Years
Currently aged 65	22.7	24.0	22.6	24.0
Currently aged 45	24.5	25.4	24.4	25.3

At 31 March 2009, the date of the most recent actuarial review, the schemes had approximately 34,900 members and beneficiaries. The other demographic assumptions have been set having regard to the latest trends in scheme experience and other relevant data. The assumptions are reviewed and updated as necessary as part of the periodic actuarial valuation of the pension schemes.

	2011		2010
Impact of changing material assumptions	Increase/ decrease in assumption	Indicative effect on scheme liabilities %	Increase/ decrease in assumption	Indicative effect on scheme liabilities %
Rate of increase in employee earnings	0.25%	nil	0.25%	+/–1
Rate of increase in pensions in payment and deferred pensions	0.25%	+/–5	0.25%	+/–5
Discount rate	0.25%	–/+6	0.25%	–/+6
Inflation assumption	0.25%	+/–5	0.25%	+/–6
Longevity assumption	1 year	+/–2	1 year	+/–2

The remaining disclosures in this note cover all of the Group’s defined benefit schemes.

(d) Amounts included in the Group Balance Sheet	2011 £m	2010 £m
Fair value of plan assets	4,670	4,335
Present value of defined benefit obligation	(4,340)	(4,574)
Net asset/(liability) recognised in the Balance Sheet	330	(239)
Associated deferred tax (liability)/asset recognised in the Balance Sheet	(81)	67
Net pension asset/(liability) after deferred tax	249	(172)
Pension asset/(liability) presented in the Balance Sheet as:
Retirement benefit assets	413	–
Retirement benefit liabilities	(83)	(239)
Net pension asset/(liability)	330	(239)

(e) Movement in the year	Pension liabilities		Pension assets
	2011 £m	2010 £m	2011 £m	2010 £m
1 January	(4,574)	(4,098)	4,335	3,533
Items included in the Group Income Statement:
Current service cost	(118)	(115)	–	–
Loss on curtailment	(1)	(14)	–	–
Exceptional gains on curtailment	333	–	–	–
Interest on scheme liabilities	(258)	(249)	–	–
Expected return on scheme assets	–	–	285	275
Items included in Other Comprehensive Income:
Actuarial gain/(loss)	198	(163)	–	154
Exchange adjustments	1	(7)	(1)	3
Items included in the Group Cash Flow Statement:
Employer contributions	–	–	130	441
Other movements:
Plan participants’ contributions	(29)	(33)	29	33
Benefits paid from schemes	108	105	(108)	(104)
31 December	(4,340)	(4,574)	4,670	4,335

In addition to current service cost on the Group’s defined benefit pension schemes, the Group also charged £10 million (2010: £5 million) to operating profit in respect of defined contribution pension schemes.

(f) Pension schemes assets

The expected long-term rate of return and the market value of plan assets is illustrated below:

		2011		2010
	Fair Value £m	Expected long term rate of return per annum %	Fair Value £m	Expected long term rate of return per annum %
UK equities	400	7.5	659	8.0
Non-UK equities	1,337	7.7	1,261	8.0
Fixed-interest bonds	1,370	5.3	1,182	5.5
Inflation-linked assets	1,067	3.9	773	4.2
High-yield debt	292	6.3	229	7.5
Property	168	6.8	134	7.6
Cash pending investment	36	4.6	97	5.6
	4,670	6.0	4,335	6.6

16. BUSINESS COMBINATIONS

Fair values of the identifiable assets acquired and liabilities assumed

	First Choice Power £m	Other £m	Total £m
Balance Sheet items Intangible assets	84	49	133
Property, plant and equipment	2	41	43
Other non-current assets	–	9	9
Current assets ^(i)	71	91	162
Current liabilities	(44)	(51)	(95)
Non-current liabilities	–	(20)	(20)
Net assets acquired	113	119	232
Goodwill	93	60	153
Total consideration	206	179	385
Consideration comprises:
Cash consideration	206	173	379
Deferred cash consideration	–	6	6
Income statement items Revenue recognised since the acquisition date and included within the Group Income Statement	37	159	196
Profit recognised since the acquisition date and included within the Group Income Statement	1	–	1

(i) Includes a bad debt provision of £11 million, predominantly in relation to First Choice Power trade receivables

First Choice Power

On 1 November 2011, the Group acquired 100% of the shares in FCP Enterprises Inc (‘First Choice Power’) for cash consideration of $325 million (£206 million). First Choice Power is a Texas based independent retail electricity supplier with more than 220,000 residential and small commercial customers. The acquisition is another important step towards growing scale and leadership in North America, and significantly enlarges the business in one of the key US deregulated residential markets. The acquisition is included within the North America - Residential energy supply segment. Goodwill of $146 million (£93 million) arose, principally attributable to expected cost savings and synergies and is expected to be deductible for tax purposes. Acquisition costs of $0.2 million (£0.1 million) were expensed as part of operating costs. The fair values disclosed in the table are provisional pending finalisation of the completion accounts process.

Other acquisitions

The Group also acquired the following companies and interests during the year. Goodwill of £60 million is attributable to enhanced geographic presence, cost savings, synergies and growth opportunities, £4 million of which is expected to be deductible for tax purposes. Acquisition costs of £1.5 million were expensed as operating costs. The fair values are provisional unless stated otherwise.

Project	Description of business acquired	Date of control	Consideration^(i)	Equity acquired
Wildcat Hills	Additional natural gas and infrastructure interests within the Wildcat Hills area. Increases natural gas reserves to meet North American supply requirements.	31 Mar 2011	CA$45m (£29m)	Various operating interests. No gain/loss on revaluation of existing interests
Gateway Energy Services Corporation	Independent retail energy supplier focused on residential and commercial customers. Increases customer relationships in US North-East and Mid-Atlantic.	1 May 2011	$108m including $10m deferred (£65m including £6m deferred)	100% of shares
PH Jones Group Limited	Independent provider of central heating services to social housing market. Increases business growth opportunities and helps cut customer carbon and fuel bills.	13 May 2011	£26m	100% of shares
Vectren Retail LLC	Supplier of gas to residential and small business customers. Increases customer relationships in US North-East.	30 Dec 2011	$84m (£54m)	100% of shares

(i) A small number of other businesses have been acquired for total consideration of £5 million.

17. DISPOSALS, DISCONTINUED OPERATIONS AND DISPOSAL GROUPS HELD FOR SALE

The European segment was classified as a discontinued operation during 2009 following the Group’s decision to dispose of its 100% interests in Segebel S.A. (Segebel), Centrica Energía S.L. (Centrica Energía) in Spain and Oxxio B.V. (Oxxio) in The Netherlands. The disposal of Segebel was completed in 2009. The sale of Centrica Energía was completed in November 2010.

On 1 June 2011, the Group completed its planned disposal of its European segment with the sale of the trade and assets of Oxxio which resulted in a loss on disposal of £56 million.

	Oxxio £m
Non-current assets ^(i)	115
Current assets ^(ii)	287
Current liabilities	(236)
Total net assets disposed	166
Total consideration ^(iii)	111
Net assets disposed	(166)
Foreign exchange recycled from reserves	3
Disposal costs	(4)
Loss on disposal after taxation	(56)

(i) Includes PP&E of £35 million and intangible assets and goodwill of £80 million, which were included in assets held for sale.

(ii) Includes cash and cash equivalents of £8 million.

(iii) Includes deferred consideration of £25 million.

18. COMMITMENTS AND CONTINGENCIES

(a) Commitments

The Group procures commodities through a mixture of production from gas fields, power stations, wind farms and procurement contracts. Procurement contracts include short-term forward market purchases of gas and electricity at fixed and floating prices. They also include gas and electricity contracts indexed to market prices and long-term gas contracts with non-gas indexation. The commitments in relation to commodity purchase contracts disclosed below are stated net of amounts receivable under commodity sales contracts, where there is a right of set-off with the counterparty.

The total volume of gas to be taken under certain long-term structured contracts depends on a number of factors, including the actual reserves of gas that are eventually determined to be extractable on an economic basis. The commitments disclosed below are based on the minimum quantities of gas that the Group is contracted to buy at estimated future prices.

	2011 £m	2010 (restated) (i) £m
Commitments in relation to the acquisition of property, plant and equipment:
Acquisition of Statoil oil and gas assets	983	–
Development of York gas field	82	–
Other gas field developments	13	119
Other capital expenditure	74	65
Commitments in relation to the acquisition of intangible assets:
Renewable obligation certificates to be purchased from joint ventures^(ii)	1,377	1,145
Renewable obligation certificates to be purchased from other parties	774	631
EUAs and CERs	44	166
Exploration activity	122	80
Other intangible asset purchase commitments	71	66
Other commitments:
Commodity purchase contracts	58,311	40,420
LNG capacity	844	874
Transportation capacity	969	771
Outsourcing of services	348	444
Commitments to invest in joint ventures	234	319
Other long term commitments	777	661
Operating lease commitments:
Future minimum lease payments under non-cancellable operating leases ^(iii)	950	963

(i) Restated to correct prior year comparatives.

(ii) Renewable obligation certificates are purchased from several joint ventures which produce power from wind energy under long term offtake agreements (up to 15 years). The commitments disclosed above are the gross contractual commitments and do not take into account the Group’s economic interest in the joint venture.

(iii) At 31 December the maturity analysis for the total minimum lease payments under non-cancellable operating leases was: <1 year £157 million, 1-2 years £130 million, 2-3 years £88 million, 3-4 years £65 million, 4-5 years £54 million and >5 years £456 million (2010: <1 year £146 million, 1-5 years £331 million and >5 years £486 million).

(b) Contingent liabilities

There are no material contingent liabilities.

19. EVENTS AFTER THE BALANCE SHEET DATE

The Directors propose a final dividend of 11.11 pence per ordinary share (totalling £575 million) for the year ended 31 December 2011. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 11 May 2012 and, subject to approval, will be paid on 13 June 2012 to those shareholders registered on 27 April 2012.

North American acquisitions

On 11 November 2011 Direct Energy announced the purchase of Home Warranty of America, a US nationwide home warranty protection plan company, for $48 million (£31 million). The acquisition involves the purchase of 100% of the shares of the company and it is anticipated this transaction will close in March 2012, pending regulatory approval. The acquisition allows Direct Energy to sell nationwide home protection plans and provides further growth and integration opportunities. A provisional goodwill value of $43 million (£27 million) is expected to arise, 40% of which is expected to be deductible for tax purposes.

On 8 December 2011 Direct Energy announced that it had agreed to acquire a package of natural gas assets located in west central Alberta (Carrot Creek assets) from Encana Corporation for CA$58 million (£37 million) in cash and Direct Energy’s existing Entice asset with fair value of CA$48 million (£30 million). The Group obtained control of the business on 10 January 2012. The acquisition allows the Group to grow its North American upstream gas business. No goodwill is expected to arise.

Strategic partnership with Statoil and Norwegian asset acquisition

On 21 November 2011 Centrica Energy announced that it had signed a 10-year gas supply contract with Statoil starting from 2015, an agreement to pay $1,525 million (£983 million) with an additional payment of up to $100 million (£64 million) contingent on future production performance for the acquisition of producing and development assets in the Norwegian North Sea and a strategic agreement for partnership on gas exploration activities. As part of the transaction the relevant parts of Statoil’s capacity rights in the gas export system from Norway to the UK and the Continent will be transferred to Centrica. The transaction is expected to complete in May 2012 and will help to deliver UK energy security, develop our strategic relationship with Statoil and further expand Centrica Energy’s upstream business.

Statfjord asset acquisition

On 30 January 2012, Centrica Energy announced that it has reached agreement with ConocoPhillips to acquire its non-operated interests in the gas and oil producing Statfjord field and associated satellites for a total cash consideration of $223 million (£142 million). The deal is expected to complete in May 2012. The acquisition further strengthens Centrica’s integrated business model and provides another source of gas for our UK customers.

Asset acquisition from Total

On 22 February 2012, Centrica announced an agreement with Total to acquire a portfolio of UK North Sea non-operated producing oil and gas assets for a cash consideration of $388 million (£246 million). The transaction is expected to close on a field by field basis. The earliest closing date is expected to be around July 2012. The acquisition increases the reserves of the Group and provides additional gas to meet supply requirements of our UK customers.

20. SEASONALITY OF OPERATIONS

Certain activities of the Group are affected by weather and temperature conditions. As a result of this, amounts reported for the six months ended 31 December 2011 may not be indicative of the amounts that would be reported for a full year due to seasonal fluctuations in customer demand for gas, electricity and services, the impact of weather on demand and commodity prices, market changes in commodity prices and changes in retail tariffs.

Customer demand for gas in the UK and North America is driven primarily by heating load and is generally higher in the winter than in the summer, and higher from January to June than from July to December. Customer demand for electricity in the UK generally follows a similar pattern to gas, but is more stable. Customer demand for electricity in North America is also more stable than gas but is driven by heating load in the winter and cooling load in the summer. Generally demand for electricity in North America is higher in the winter and summer than it is in the spring and autumn, and higher from July to December than it is from January to June.

Customer demand for home services in the UK is generally higher in the winter than it is in the summer, and higher in the earlier part of the winter as that is typically when heating systems tend break down most, so that customer demand from July to December is higher than from January to June. Customer demand for home services in North America follows a similar pattern, but is also higher in the summer as a result of residential new construction in the US and the servicing of cooling systems.

Gas production volumes in the UK are generally higher in the winter when gas prices are higher. Gas production volumes are generally higher from January to June than they are from July to December as outages are generally planned for the summer months when gas demand and prices are lowest. Gas production volumes in North America are generally not seasonal.

Power generation volumes are dependent on spark spread prices, which is the difference between the price of electricity and the price of gas multiplied by a conversion rate and, as a result, are not as seasonal as gas production volumes in the UK, as wholesale prices for both gas and electricity are generally higher in the winter than they are in the summer. Power generation volumes in North America are generally higher in the summer than in the winter and can be higher or lower from January to June compared to July to December.

The impact of seasonality on customer demand and wholesale prices has a direct effect on the Group’s financial performance and cash flows.

NOTES TO THE FINANCIAL STATEMENTS (UNAUDITED)

21. GROUP INCOME STATEMENT FOR THE SIX MONTHS ENDED 31 DECEMBER

				2011		2010
Six months ended 31 December	Business performance £m	Exceptional items and certain re-measurements £m		Results for the period £m	Business performance £m	Exceptional items and certain re-measurements £m	Results for the period £m
Group revenue	11,315	–		11,315	10,716	–	10,716
Cost of sales before exceptional items and certain re-measurements	(8,944)	–		(8,944)	(8,674)	–	(8,674)
Exceptional items	–	(221)		(221)	–	(102)	(102)
Re-measurement of energy contracts	–	(598)		(598)	–	499	499
Cost of sales	(8,944)	(819)		(9,763)	(8,674)	397	(8,277)
Gross profit	2,371	(819)		1,552	2,042	397	2,439
Operating costs before exceptional items	(1,353)	–		(1,353)	(1,311)	–	(1,311)
Exceptional items	–	(110)		(110)	–	(181)	(181)
Operating costs	(1,353)	(110)		(1,463)	(1,311)	(181)	(1,492)
Share of profits in joint ventures and associates, net of interest and taxation	46	25		71	12	(2)	10
Group operating profit	1,064	(904)		160	743	214	957
Interest income	127	–		127	–	–	–
Interest expense	(195)	–		(195)	(152)	–	(152)
Net interest expense	(68)	–		(68)	(152)	–	(152)
Profit from continuing operations before taxation	996	(904)		92	591	214	805
Taxation on profit from continuing operations	(369)	230		(139)	(220)	(37)	(257)
Profit from continuing operations after taxation	627	(674)		(47)	371	177	548
Profit from discontinued operations	–	–		–	–	5	5
Profit on disposal of discontinued operations	–	–		–	3	–	3
Discontinued operations	–	–		–	3	5	8
Profit/(loss) for the period	627	(674)		(47)	374	182	556
Earnings per ordinary share
From continuing and discontinued operations:
Basic			(0.9)					10.8
Diluted			(0.9)					10.7
From continuing operations:
Basic			(0.9)					10.6
Diluted			(0.9)					10.6

22. GROUP CASH FLOW STATEMENT FOR THE SIX MONTHS ENDED 31 DECEMBER

Six months ended 31 December	2011 £m	2010 (restated) (i) £m
Cash generated from continuing operations	1,767	1,275
Income taxes paid	(329)	(302)
Net petroleum revenue tax paid	(110)	(137)
Interest received	7	–
Interest paid	(3)	(8)
Payments relating to exceptional charges	(63)	(100)
Net cash flow from continuing operating activities	1,269	728
Net cash flow from discontinued operating activities	–	33
Net cash flow from operating activities	1,269	761
Purchase of businesses net of cash and cash equivalents acquired	(280)	(592)
Sale of businesses net of cash and cash equivalents disposed of	–	20
Purchase of intangible assets	(175)	(276)
Purchase of property, plant and equipment	(463)	(176)
Disposal of property, plant and equipment and intangible assets	3	40
Investments in joint ventures and associates	(191)	(114)
Dividends received from joint ventures and associates	84	83
Repayments of loans to, and disposal of investments in, joint ventures and associates	3	17
Interest received	3	14
Net sale/(purchase) of securities	74	(33)
Net cash flow from continuing investing activities	(942)	(1,017)
Net cash flow from discontinued investing activities	–	3
Net cash flow from investing activities	(942)	(1,014)
Issue of ordinary share capital	6	7
Purchase of treasury shares	(2)	(1)
Financing interest received	9	–
Financing interest paid	(120)	(206)
Cash inflow from additional debt	114	–
Cash outflow from payment of capital element of finance leases	(12)	(11)
Cash outflow from repayment of other debt	(11)	(651)
Net cash flow from increase/(reduction) in debt	91	(662)
Realised net foreign exchange loss on cash settlement of derivative contracts	(23)	(36)
Equity dividends paid	(222)	(198)
Net cash flow from continuing financing activities	(261)	(1,096)
Net cash flow from discontinued financing activities	–	2
Net cash flow from financing activities	(261)	(1,094)
Net increase/(decrease) in cash and cash equivalents	66	(1,347)
Cash and cash equivalents at beginning of period	418	1,795
Effect of foreign exchange rate changes	(5)	3
Cash and cash equivalents at 31 December	479	451
Included in the following lines of the Balance Sheet:
Cash and cash equivalents	518	467
Bank overdrafts, loans and other borrowings	(39)	(19)
Assets of disposal groups classified as held for sale	–	3
	479	451

(i) The 2010 comparatives have been restated for a change in presentation of emission certificate/allowance cash flows. See note 2(d).

23. SEGMENTAL ANALYSIS FOR THE SIX MONTHS ENDED 31 DECEMBER

The Group’s results are discussed in the Operating Review (page 12 to 23). The Group’s segmental results are as follows:

			2011			2010 (restated) (ii)
(a) Revenue for the six months ended 31 December	Gross segment revenue £m	Less inter- segment revenue (i) £m	Group revenue £m	Gross segment revenue £m	Less inter- segment revenue (i) £m	Group revenue £m
Continuing operations:
Residential energy supply	3,928	(1)	3,927	3,876	(4)	3,872
Residential services	755	–	755	773	–	773
Business energy supply and services	1,311	–	1,311	1,347	–	1,347
Downstream UK	5,994	(1)	5,993	5,996	(4)	5,992
Gas ^(ii)	1,814	(187)	1,627	1,190	(181)	1,009
Power ^(ii)	822	(93)	729	762	(7)	755
Upstream UK	2,636	(280)	2,356	1,952	(188)	1,764
Storage UK	87	(11)	76	119	(15)	104
Residential energy supply	1,126	–	1,126	1,133	–	1,133
Business energy supply	1,372	–	1,372	1,363	–	1,363
Residential and business services	271	–	271	277	–	277
Upstream and wholesale energy	252	(131)	121	141	(58)	83
North America	3,021	(131)	2,890	2,914	(58)	2,856
	11,738	(423)	11,315	10,981	(265)	10,716
Discontinued operations:
European Energy	–	–	–	245	1	246

(i) Inter-segment revenue is subject to period on period fluctuations due to the change in the mix of internal and external energy sales by Upstream UK.

(ii) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(b) Operating profit for the six months ended 31 December	2011 £m	2010 (restated) (i) £m
Continuing operations:
Residential energy supply	252	157
Residential services	153	132
Business energy supply and services	82	85
Downstream UK	487	374
Gas ^(i) (ii)	355	204
Power ^(i) (ii)	137	82
Upstream UK	492	286
Storage UK	36	72
Residential energy supply	56	67
Business energy supply	52	44
Residential and business services	19	7
Upstream and wholesale energy	11	(23)
North America	138	95
Adjusted operating profit – segment operating profit before exceptional items, certain re-measurements and impact of fair value uplifts from Strategic Investments ^(iii)	1,153	827
Share of joint ventures/associates’ interest and taxation	(41)	(34)
Depreciation of fair value uplifts to property, plant and equipment – Venture ^(ii)	(27)	(27)
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – British Energy ^(ii)	(21)	(23)
	1,064	743
Exceptional items (note 6)	(331)	(283)
Certain re-measurements included within gross profit (note 6)	(598)	499
Certain re-measurements of associates’ energy contracts (net of taxation) (note 6)	25	(2)
Operating profit after exceptional items and certain re-measurements	160	957
Discontinued operations:
European Energy^(iv)	–	3

(i) The Industrial and commercial and Proprietary energy trading businesses have been reallocated into the new Power and Gas segments. See note 2(c).

(ii) See note 3 and 10 for explanation of the depreciation on fair value uplifts to PP&E on acquiring Strategic Investments.

(iii) Includes results of equity-accounted interests before interest and taxation.

(iv) Represents loss after taxation and before exceptional items and certain re-measurements of Oxxio B.V. and Centrica Energia up to the date of disposal. This is the measure of results of discontinued operations that is reported regularly to the Group’s Executive Committee.

24. EXCEPTIONAL ITEMS AND CERTAIN RE-MEASUREMENTS FOR THE SIX MONTHS ENDED 31 DECEMBER

(a) Exceptional items for the six months ended 31 December	2011 £m	2010 £m
Continuing operations:
Provision for European onerous capacity contracts ^(i)	(221)	(35)
Provision for North American and UK onerous commodity contracts	–	(67)
Exceptional items from continuing operations included within gross profit	(221)	(102)
Impairments:
Impairment of UK generation assets ^(ii)	(226)	(68)
Impairment of North American and UK exploration and production assets	–	(95)
	(226)	(163)
Downstream UK contract migration ^(iii)	(63)	(43)
Restructuring charges ^(iv)	(154)	–
Profit on disposal of investments	–	25
Pension curtailment (note 15(b))	333	–
	(110)	(181)
Exceptional items from continuing operations included within Group operating profit	(331)	(283)
Taxation on exceptional items (note 8)	69	118
Total exceptional items after taxation	(262)	(165)

(b) Certain re-measurements for the six months ended 31 December	2011 £m	2010 £m
Continuing operations:
Certain re-measurements recognised in relation to energy contracts:
Net gains arising on delivery of contracts ^(v)	90	382
Net (losses)/gains arising on market price movements and new contracts ^(vi)	(685)	114
Net (losses)/gains arising on positions in relation to cross-border transportation or capacity contracts	(3)	3
Net re-measurements from continuing operations included within gross profit	(598)	499
Net gains/(losses) arising on re-measurement of associates’ energy contracts (net of taxation) ^(vii)	25	(2)
Net re-measurements included within Group operating profit	(573)	497
Taxation on certain re-measurements (note 8)	161	(155)
Net re-measurements from continuing operations after taxation	(412)	342
Discontinued operations:
Net re-measurements on energy contracts of discontinued operations after taxation	–	5
Total re-measurements after taxation	(412)	347

(i) As a result of the decision to withdraw from Europe the Group recorded onerous contract charges of £111 million for a number of European gas transportation capacity contracts and a further £110 million for the fixed price Rijnmond tolling contract due to the impact of low market spark spreads.

(ii) Impairment charges have been recognised on a number of UK generation assets (including PP&E and inventory) as a result of low spark spreads, which led to the impairment of Killingholme, proposed closure of Barry and Kings Lynn and the operational reconfiguration of Brigg, Peterborough and Roosecote.

(iii) Exceptional charges have been recorded following the termination in December 2010 and subsequent migration of a significant supplier contract.

(iv) Relates to a Group-wide cost reduction programme leading to staff reductions. See Operating Review for more details.

(v) As energy is delivered or consumed from previously contracted positions the related fair value recognised in the opening balance sheet (representing the discounted difference between forward energy prices at the opening balance sheet date and the contract price of energy to be delivered) is charged or credited to the Income Statement.

(vi) Represents fair value (losses)/gains arising from the change in fair value of future contracted sales and purchase contracts as a result of changes in forward energy prices between reporting dates (or date of inception and the reporting date, where later).

(vii) Includes fair value unwinds relating to the recognition of energy procurement contracts and energy sales contracts at their acquisition-date fair values.

25. EARNINGS PER ORDINARY SHARE FOR THE SIX MONTHS ENDED 31 DECEMBER

Six months ended 31 December		2011			2010
(a) Continuing and discontinued operations	£m	Pence per ordinary share		£m	Pence per ordinary share
(Loss)/earnings – basic	(47)	(0.9)		556	10.8
Net exceptional items after taxation (note 6)	262	5.1		165	3.2
Certain re-measurement losses/(gains) after taxation (note 6)	412	8.0		(347)	(6.7)
Depreciation of fair value uplifts to property, plant and equipment from Strategic Investments, after taxation	33	0.6		37	0.7
Earnings – adjusted basic	660	12.8		411	8.0
(Loss)/earnings – diluted	(47)	(0.9)		556	10.7
Earnings – adjusted diluted	660	12.7		411	7.9
Six months ended 31 December			2011		2010
(b) Continuing operations	£m		Pence per ordinary share	£m	Pence per ordinary share
(Loss)/earnings – basic	(47)		(0.9)	548	10.6
Net exceptional items after taxation (note 6)	262		5.1	165	3.2
Certain re-measurement losses/(gains) after taxation (note 6)	412		8.0	(342)	(6.6)
Depreciation of fair value uplifts to property, plant and equipment from Strategic Investments, after taxation	33		0.6	37	0.7
Earnings – adjusted basic	660		12.8	408	7.9
(Loss)/earnings – diluted	(47)		(0.9)	548	10.6
Earnings – adjusted diluted	660		12.7	408	7.9
Six months ended 31 December			2011		2010
(c) Discontinued operations	£m		Pence per ordinary share	£m	Pence per ordinary share
Earnings – basic and diluted	–		–	8	0.2

26. NOTES TO THE GROUP CASH FLOW STATEMENT FOR THE SIX MONTHS ENDED 31 DECEMBER

Reconciliation of Group operating profit to cash generated from continuing operations	2011 £m	2010 (restated) (i) £m
Continuing operations:
Group operating profit including share of result of joint ventures and associates	160	957
Less share of profit of joint ventures and associates	(71)	(10)
Group operating profit before share of results of joint ventures and associates	89	947
Add back/(deduct):
Amortisation and write-down of intangible assets	68	105
Depreciation and write-down of property, plant and equipment	611	547
Recycling of write-down of available-for-sale financial assets	23	–
Loss/(profit) on sale of businesses, property, plant and equipment and other intangible assets	8	(22)
Increase in provisions	401	144
Pension curtailment gain	(332)	–
Pension service cost	56	64
Pension contributions	(70)	(169)
Employee share scheme costs	16	28
Re-measurement of energy contracts ^(ii)	539	(490)
Operating cash flows before movements in working capital	1,409	1,154
Decrease/(increase) in inventories	58	(6)
Decrease in trade and other receivables ^(iii)	(138)	(558)
Increase in trade and other payables ^(i) (iii)	438	685
Cash generated from continuing operations	1,767	1,275

(i) The 2010 comparatives have been restated for a change in presentation of emission certificate/allowance cash flows.

(ii) Adds back unrealised losses arising from re-measurement of energy contracts.

(iii) Includes net outflow of £149 million of cash collateral in 2011 (2010: net inflow of £56 million).

GAS AND LIQUIDS RESERVES (UNAUDITED)

The Group’s estimates of reserves of gas and liquids are reviewed as part of the half-year and full-year reporting process and updated accordingly. A number of factors affect the volumes of gas and liquids reserves, including the available reservoir data, commodity prices and future costs. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

The Group discloses 2P gas and liquids reserves, representing the central estimate of future hydrocarbon recovery. Reserves for Centrica-operated fields are estimated by in-house technical teams composed of geoscientists and reservoir engineers. Reserves for non-operated fields are estimated by the operator, but are subject to internal review and challenge.

As part of the internal control process related to reserves estimation, an assessment of the reserves, including the application of the reserves definitions is undertaken by an independent technical auditor. An annual reserves assessment has been carried out by DeGoyler and MacNaughton for the Group’s global reserves. Reserves are estimated in accordance with a formal policy and procedure standard.

The Group has estimated 2P gas and liquids reserves in Europe, North America and Trinidad and Tobago.

The principal fields in UK Upstream are South Morecambe, Cygnus, Statfjord, Chiswick, NCMA Poinsettia, Ensign, York, Olympus, Grove and Kew fields associated with Upstream UK, and the Rough field associated with Storage UK. The European and Trinidad and Tobago reserves estimates are consistent with the guidelines and definitions of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers and the World Petroleum Council’s Petroleum Resources Management System using accepted principles.

The principal fields in North America are Foothills, Medicine Hat, Entice and Central Alberta located in the province of Alberta, Canada. The North American reserves estimates have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook. (COGEH) reserves definitions and are consistent with the guidelines and definitions of the Society of Petroleum Engineers and the World Petroleum Council.

Estimated net 2P reserves of gas (billion cubic feet)	Europe	Trinidad and Tobago (iv)	UK Upstream	North America	Total
1 January 2011	2,026	161	2,187	538	2,725
Revisions of previous estimates ^(i)	8	15	23	58	81
Purchases/(disposals) of reserves in place ^(ii)	–	–	–	43	43
Extensions, discoveries and other additions ^(iii)	199	–	199	20	219
Production ^(v)	(193)	(15)	(208)	(56)	(264)
31 December 2011	2,040	161	2,201	603	2,804

Estimated net 2P reserves of liquids (million barrels)	Europe	Trinidad and Tobago (iv)	UK Upstream	North America	Total
1 January 2011	64	5	69	6	75
Revisions of previous estimates ^(i)	8	–	8	2	10
Purchases/(disposals) of reserves in place	–	(5)	(5)	–	(5)
Extensions, discoveries and other additions ^(iii)	14	–	14	1	15
Production ^(v)	(13)	–	(13)	(1)	(14)
31 December 2011	73	–	73	8	81

Estimated net 2P reserves (million barrels of oil equivalent)	Europe	Trinidad and Tobago (iv)	UK Upstream	North America	Total
31 December 2011 ^(vi)	413	27	440	109	549

(i) Includes minor reserves revisions to a number of fields in Europe, North America and Trinidad and Tobago.

(ii) Reflects the acquisition of additional equity in the Foothills properties in North America.

(iii) Recognition of reserves predominantly associated with Chiswick, Olympus, Grove, Kew and Foothills.

(iv) The Trinidad and Tobago reserves are subject to a production sharing contract and accordingly have been stated on an entitlement basis (including tax barrels).

(v) Represents total gas and oil produced from the Group’s reserves.

(vi) Includes the total of estimated gas and liquid reserves at 31 December 2011 in million barrels of oil equivalent.

Liquids reserves include oil, condensate and natural gas liquids.

DISCLOSURES

DISCLAIMERS

This announcement does not constitute an invitation to underwrite, subscribe for, or otherwise acquire or dispose of any Centrica shares or other securities.

This announcement contains certain forward-looking statements with respect to the financial condition, results, operations and businesses of Centrica plc. These statements and forecasts involve risk and uncertainty because they relate to events and depend on circumstances that will occur in the future. There are a number of factors that could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts.

Past performance is no guide to future performance and persons needing advice should consult an independent financial adviser.

FOR FURTHER INFORMATION

Centrica will hold its 2011 Preliminary Results presentation for analysts and institutional investors at 9.30am (UK) on Thursday 23 February 2012. There will be a live audio webcast of the presentation and slides from 9.30am at www.centrica.com/investors.

A live audio broadcast of the presentation will be available by dialling in using the following number:

+ 44 20 3059 8125

The call title is “Centrica plc Preliminary Results 2011 Announcement” and the conference password is “Results“.

An archived webcast and full transcript of the presentation and the question and answer session will be available on the website on Friday 24 February.

ENQUIRIES

Investors and Analysts:	Andrew Page	Director of Investor Relations
	Telephone:	01753 494 900
	email:	[e-mail]
Media:	Centrica Media Relations
	Telephone:	0800 107 7014
	email:	[e-mail]

FINANCIAL CALENDAR

Ex-dividend date for 2011 final dividend	25 April 2012
Record date for 2011 final dividend	27 April 2012
2011 final dividend payment date	13 June 2012
Interim Management Statement	11 May 2012
Annual General Meeting	11 May 2012
2012 Interim results announcement	26 July 2012

REGISTERED OFFICE

Millstream, Maidenhead Road, Windsor, Berkshire SL4 5GD

Category Code: FR

Sequence Number: 314635

Time of Receipt (offset from UTC): 20120222T124736+0000