Final Results

Final Results

Centrica plc

Centrica plc

Preliminary Results for the year ended 31 December 2013

Group results and highlights

RICK HAYTHORNTHWAITE, CENTRICA CHAIRMAN

“The opportunity to chair Centrica is a great privilege. It is a company with a deep heritage and relevance to the UK, supplying energy or services to over 11 million of the country’s homes, employing over 30,000 people in the UK, and with a responsibility to pension funds and over 700,000 individual shareholders. Our vision remains to be the leading integrated energy company with customers at its core, and our scale is of great benefit to the UK as we secure the future energy needs of our customers. In an increasingly international gas market, our interests and those of our customers remain inextricably linked.”

RICK HAYTHORNTHWAITE
Chairman
20 February 2014

SOLID YEAR ON YEAR EARNINGS IN DIFFICULT MARKET CONDITIONS

Adjusted financial figures for the year ended 31 December	Â	2013	Â	2012	Â	Change
Operating profit	Â	£2,695m	Â	£2,743m	Â	(2%)
Taxation charge		£1,022m		£1,112m		(8%)
Effective tax rate		43%		45%		(2ppt)
Earnings		£1,370m		£1,378m		(1%)
Basic earnings per share		26.6p		26.6p		0%
Full year dividend per share		17.0p		16.4p		4%
Group capital and acquisition expenditure		£2,565m		£2,727m		(6%)
Lost time injury frequency rate (per 100,000 hours worked)	Â	0.11	Â	0.20	Â	(45%)
The Group has applied IAS19 (revised) pensions accounting. As a result, 2012 net finance costs, taxation, earnings and earnings per share have been restated

GOOD STRATEGIC PROGRESS, HELPING SECURE FUTURE GAS SUPPLIES FOR THE UK

• Group wide £500 million cost reduction programme completed
• Engaging with all stakeholders to improve understanding and rebuild trust
• £14 billion of new gas supply agreements signed with Cheniere and Qatargas, taking the Group’s gas and power supply commitments to over £60 billion
• £2.6 billion invested in the year, including:
  • Over £1.5 billion of organic investments, predominantly in North Sea E&P, including in major projects such as Cygnus
  • C$1 billion Canadian upstream gas acquisition, in partnership with Qatar Petroleum International
  • The acquisition of a 25% stake in the Bowland shale exploration licence in the UK
  • $1.2 billion Hess Energy Marketing acquisition, delivering a step-change in North America B2B
  • £650 million of divestments of selected E&P assets, UK wind assets and US power stations, for value
• Adding value through 56mmboe of organic reserve additions, principally in Norway, however £699 million pre-tax (£318 million post-tax) exceptional impairments of UK Southern North Sea projects and existing Canadian gas assets
• £420 million share repurchase programme in 2014 following sale of Texas CCGTs; recommending a 4% increase in the full year dividend to 17.0 pence per share

Unless otherwise stated, all references to operating profit or loss, taxation and earnings numbers throughout the announcement are adjusted figures, as reconciled to their statutory equivalents in the Group Financial Review on pages 12, 13 and 14. Statutory operating profit is £1,892 million (2012: £2,625 million). Statutory profit before taxation is £1,649 million (2012: £2,416 million). Statutory earnings are £950 million (2012: £1,245 million), including post-tax exceptional items of £667 million (£1,064 million before tax) relating to an onerous contract charge on Rijnmond, E&P impairment charges and UK gas storage impairment and provision charges. Statutory basic EPS is 18.4p (2012: 24.0p).

NEW TARGETS FOR EACH AREA OF THE BUSINESS

• Overall, 2014 trading is in line with recent market forecasts, other than a one-off impact from extreme weather conditions in Direct Energy, with Group adjusted EPS for the year expected to be lower than in 2013
• New targets set, creating a platform for long term, sustainable growth, both downstream and upstream
• Targeting a return to account growth in UK residential energy and services, following a 2% decline in 2013
• Aiming to achieve industry leading, high quality service for all our customers
• Efficiency and cost reduction programmes across the Group
• Selective investment, concentrating on the most attractive opportunities
  • Reducing organic E&P capital expenditure by approximately 20% to around £900 million per year on average over the next three years
  • Limited UK power investment against a backdrop of losses in gas-fired generation

SAM LAIDLAW, CENTRICA CHIEF EXECUTIVE

“We have made good strategic progress across the Group in 2013, investing along the gas value chain to secure long term, affordable energy supplies for our customers. We have completed strategic reviews in both British Gas and Direct Energy, and introduced new management structures. These will help us deliver consistent, high quality customer service, reduce costs and drive growth through innovation. In Centrica Energy, we entered into a number of key strategic transactions to drive long term growth and we also added reserves from the drill-bit, mainly in Norway.

Recently we have seen unprecedented focus on the energy sector in the UK, with intense political and media scrutiny at a time when many customers have faced declining real disposable income. In British Gas, we have simplified our energy product range to just four residential tariffs, we have made further improvements to the transparency of our reporting, and we were the first energy company to reduce retail tariffs following proposed changes to the ECO programme.

Market conditions are set to remain challenging in 2014 with margin pressures and unusual weather patterns on both sides of the Atlantic, rising unit costs in the North Sea and weak economics for gas storage and gas-fired power generation. However in the short term, we are focused in our downstream businesses on improving service levels, reducing costs and returning to growth through innovation, technology and customer propositions. Upstream, we will continue to drive efficiencies and will be increasingly selective in our investments, focusing on the projects that offer the best returns and the lowest political risk. The acquisitions we announced in 2013 are performing well and together with the positive action we are taking across the Group, position Centrica well for the future, for the benefit of both customers and shareholders.”

SAM LAIDLAW
Chief Executive
20 February 2014

ENQUIRIES

Investors and Analysts:	Â	Andrew Page	Â	01753 494 900
		email:		[e-mail]
Media:		Greg Wood / Sophie Fitton		0800 107 7014
		email:		[e-mail]

Interviews with Rick Haythornthwaite (Chairman), Sam Laidlaw (Chief Executive), Nick Luff (Group Finance Director) and Chris Weston (International Downstream Managing Director) are available on www.centrica.com.

Divisional results and highlights

INTERNATIONAL DOWNSTREAM

British Gas: Focus on service, efficiency and innovation

Adjusted operating profit for the year ended 31 December	Â	2013	Â	2012	Â	Change
Residential energy supply (BGR)	Â	£571m	Â	£606m	Â	(6%)
Residential services (BGS)		£318m		£312m		2%
Business energy supply and services (BGB)	Â	£141m	Â	£175m	Â	(19%)
Total British Gas	Â	£1,030m	Â	£1,093m	Â	(6%)
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Performance indicators for the year ended 31 December	Â	2013	Â	2012	Â	Change
Residential energy customer accounts (year end, ’000) 1		15,256		15,618		(2%)
Residential services product holding (year end, ’000)		8,227		8,402		(2%)
Business energy supply points (year end, ’000)	Â	912	Â	924	Â	(1%)
1. British Gas residential energy customer accounts as at 31 December 2012 have been restated to exclude 38,000 accounts subsequently classified as dormant

• Strategic review complete; new organisational structure in place
• Aiming to deliver industry leading, high quality service for both residential and business customers
• BGR operating profit down due to higher commodity and non-commodity costs, with warm weather towards the end of the year resulting in an 18% decline in operating profit in the second half of the year compared to 2012
  • Targeting a return to customer account growth, following a 2% decline in 2013, helped by our January 2014 price reduction and the introduction of new fixed price propositions
  • Simplified product range to four residential tariffs; further improvements in transparency of reporting
  • First energy supplier to reduce retail tariffs in 2014, following proposed ECO changes
• BGS benefited from cost reduction initiatives
  • Targeting a return to customer account growth, leveraging our insurance capabilities and developing differentiated propositions such as Hive
• BGB operating profit down as a result of difficult trading environment and the ending of auto roll-over of contracts for the benefit of customers
  • £100 million cost reduction programme underway to improve competitiveness
  • Implementation of new billing system proceeding to plan

Direct Energy: Enhanced scale in deregulated markets

Adjusted operating profit for the year ended 31 December	Â	2013	Â	2012	Â	Change
Residential energy supply (DER)	Â	£163m	Â	£156m	Â	4%
Business energy supply (DEB)		£77m		£121m		(36%)
Residential and business services (DES)	Â	£36m	Â	£33m	Â	9%
Total Direct Energy	Â	£276m	Â	£310m	Â	(11%)
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Performance indicators for the year ended 31 December	Â	2013	Â	2012	Â	Change
Residential energy customer accounts (year end, ’000)		3,360		3,455		(3%)
Residential services product holding (year end, ’000)		2,608		2,401		9%
Business energy supply gas volumes (mmth)		1,839		793		132%
Business energy supply electricity volumes (TWh)	Â	63.9	Â	51.4	Â	24%
To reflect a new organisational structure, the North American upstream gas business and North American power and midstream and trading businesses have been reallocated from Direct Energy upstream and wholesale to Centrica Energy International gas and Direct Energy business energy supply respectively

• Strategic review complete, new organisational structure in place
• Overall Direct Energy profitability down, reflecting challenging market conditions leading to a narrowing of energy supply margins
• $100 million cost reduction programme launched to improve competitiveness, driving synergies from enhanced scale
• Profit growth in DER, as we benefitted from previous acquisitions
  • Innovative products and enhanced digital capability key to future growth; ‘Power To Go and ‘Free Electricity Saturdays’ both proving popular with customers
• Decline in DEB margins and profitability, with rising wholesale costs and a highly competitive power supply market resulting in difficult trading conditions
  • Hess integration proceeding well; EBITDA in first three months ahead of our expectations
  • Growth potential through enhanced scale, dual fuel capabilities, advantaged positions along the gas value chain, long term customer relationships
• Increase in DES profitability, with services accounts up by more than 200,000
  • Services protection plans a unique differentiating factor
  • Significant potential for bundling of energy and services over time

INTERNATIONAL UPSTREAM

Centrica Energy: Securing energy supplies for our customers

Adjusted operating profit/(loss) for the year ended 31 December	Â	2013	Â	2012	Â	Change
International gas (E&P)	Â	£1,155m	Â	£940m	Â	23%
UK Power		£171m		£311m		(45%)
Gas-fired		(£133m)		(£4m)		nm
Renewables		£25m		£56m		(55%)
Nuclear		£250m		£237m		5%
Midstream	Â	£29m	Â	£22m	Â	32%
Total Centrica Energy	Â	£1,326m	Â	£1,251m	Â	6%
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Adjusted operating profit after tax for the year ended 31 December	Â	2013	Â	2012	Â	Change
International gas		£325m		£198m		64%
UK Power	Â	£143m	Â	£243m	Â	(41%)
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Performance indicators for the year ended 31 December	Â	2013	Â	2012	Â	Change
International gas production (mmth)1		3,557		2,990		19%
International liquids production (mmboe) 1		18.7		17.4		7%
International total gas and liquids production (mmboe) 1		77.3		66.8		16%
International Upstream proven and probable reserves (mmboe) 2		711		633		12%
Total UK power generated (TWh)	Â	21.7	Â	21.5	Â	1%
To reflect a new organisational structure, the North American upstream gas business has been reallocated from Direct Energy upstream and wholesale to Centrica Energy International gas 1. Includes a 100% share of Canadian assets acquired from Suncor in partnership with QPI 2. Centrica’s share of reserves, including a 60% share of Canadian assets acquired in partnership with QPI from Suncor, and excluding Rough cushion gas of 30mmboe

• Increased international gas operating profit, with strong production from recently acquired assets and the impact of higher UK gas prices more than offsetting North Sea cost pressures
  • 155mmboe of 2P reserves added in total; 56mmboe added organically, predominantly in Norway; 2C resource base up by 28%
  • £318 million of post-tax exceptional impairments relating to UK Southern North Sea projects and existing Canadian gas assets
• Reducing organic E&P capital expenditure by approximately 20% to around £900 million per year on average over the next three years, against a backdrop of rising costs and lower wholesale market prices
• Targeting flat E&P unit lifting and cash production costs over the next three years
• Power profit down significantly despite strong nuclear performance
  • Gas-fired fleet loss making, reflecting weak spark spreads and following the loss of free carbon allowances
• Near term investment in the UK power sector likely to be limited

Centrica Storage: Making an important contribution to the UK’s security of supply

Adjusted operating profit for the year ended 31 December

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Centrica Storage

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£63m

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£89m

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(29%)

• Profitability impacted by continuing low seasonal gas spreads; further significant decline expected in 2014
• Decision not to proceed with new gas storage projects at Caythorpe and Baird resulted in post-tax exceptional impairments and provisions of £224 million
• Programme launched to deliver £15 million of cost reductions through operational efficiencies over the next three years

Chairman’s Statement

I regard the opportunity to chair Centrica as a great privilege. It is a company with a strong heritage and deep relevance to the UK, serving over 11 million UK households, employing over 30,000 people in the UK and contributing around £1 billion of tax across the Group each year. With approximately 700,000 individual shareholders and numerous pension fund investors, Centrica also forms an important part of the savings and pension plans of millions of people across the country. In other words, Centrica is essential to the quality of life and competitiveness of the UK.

But beyond the statistics, Centrica also has an important role to play in the resolution of some of the most pressing issues for the UK – energy security, climate change and affordability. It has the know-how, balance sheet and assets to play a leading role in helping to deliver a solution to these issues. And yet, the company is sometimes regarded as part of the problem rather than the solution. Levels of trust between energy companies and wider society have come under severe pressure. I therefore believe that it will be essential to establish common ground between the participants in the debate, to enable us to meet the energy challenges which the country faces.

Centrica recognises the need to reaffirm and demonstrate its commitments to treating customers well, working constructively with policy makers and conducting its business in the most transparent manner possible. I have found such a response to be instinctive within the company and very much the focus of attention – as evidenced by the pace at which savings from recent UK Government policy changes were passed on to customers.

But this alone is unlikely to be sufficient to completely turn the tide. So, in parallel, I have been using my early independence to explore some of the issues to find a way to accelerate the restoration of trust and collaboration.

First, I have been looking into the various criticisms that have been directed towards the industry and am conducting my own independent fact finding review of some of the issues that are most important to our customers and seeing for myself whether we are truly living by the Business Principles we espouse.

Secondly, I have been meeting our customers to discuss what they need from their energy supplier, the trade-offs involved in fulfilling these needs and what it will take to re-establish a sense of mutual partnership. My early impression is that, while there are issues around customer trust and service levels, the reputation of British Gas in the eyes of our customers is vastly better than one would be led to believe from the media and political commentary, particularly when it comes to our service engineers helping customers in their homes.

At the same time, the growth and performance of the wider Centrica Group should not be forgotten. While our UK downstream businesses still contribute the largest proportion of the Group’s post-tax earnings, we have substantially increased the scale of our North American operations, and now serve over six million residential and business customers. We have also delivered good strategic progress upstream, despite some setbacks in the UK North Sea, adding reserves organically and through acquisition. And we continue to play a critical role in bringing supplies of gas to the UK as North Sea resources decline. Last year we signed new deals with both Qatari and US exporters, taking our supply commitments to over £60 billion.

In summary, our interests and those of customers are inextricably linked. Our financial future and corporate capability depend on forward momentum, both in and outside the UK. In an increasingly international gas market, Centrica has a clear strategic direction and strong management, positioning itself for long-term, sustainable growth.

RICK HAYTHORNTHWAITE
Chairman
20 February 2014

Chief Executive’s Review

STRATEGY AND FOCUS REAFFIRMED

In 2013, we saw unprecedented focus on the energy sector in the UK, with intense political and media scrutiny against a backdrop of declining real disposable income for many consumers. However much has been achieved during the year. We have simplified our energy offering and now have just four residential tariffs, and are leading the industry in the transparency of our reporting; the recently announced changes to the Government’s ECO energy efficiency programme will help more people at lower cost; and there is improved public understanding and recognition of the real costs of securing energy supplies, the impact of climate change objectives, and the global market in which we operate.

However investor confidence and public trust in the industry have been damaged, with proposals for price controls and the potential for further political intervention, at a time when substantial investment is required to secure supplies of energy for the UK for the long term. The consensus that existed between political parties over key questions of energy policy has broken down. We are engaging with all stakeholders, working towards a sustainable and affordable energy policy which recognises the need for strong underlying economics and investment certainty.

In February 2013, we announced new strategic priorities – Innovate to drive growth and service excellence; Integrate our natural gas business, linked to our core markets; and Increase our returns through efficiency and continued capital discipline. Developments over the past year have reaffirmed these priorities and validated our strategic direction. As existing sources of gas decline, and worldwide energy markets become more interrelated, the UK will need to look further afield to secure energy supplies for the future.

Downstream, we have completed strategic reviews in both British Gas and Direct Energy, and introduced new management structures. This will enable us to focus on improving our core operations in order to deliver better customer service, reduce costs where appropriate, and drive growth through innovative propositions.

Upstream, we entered into a number of key transactions which will not only benefit our customers but provide the business with sustainable growth over the longer term. We also added reserves organically, mainly in Norway. Moving forward, against a backdrop of challenging economics upstream, particularly in the UK North Sea, we will be increasingly selective in our investments, directing capital towards the projects offering the most attractive returns with the lowest political risk.

SOLID EARNINGS AND GOOD STRATEGIC PROGRESS IN CHALLENGING MARKET CONDITIONS

Centrica performed well in 2013, with good operational performance in gas and oil production, power generation and gas storage, and we are benefiting from improved scale from previous E&P and North American acquisitions. We delivered further improvements in our safety record, with the frequency of lost time incidents falling by 45% in 2013 compared to 2012 and no significant process safety incidents recorded during the year. I was also pleased to see another increase in employee engagement levels in 2013, and remain grateful to all my colleagues for their commitment and hard work during the year, particularly during times when the company was the subject of much political and media scrutiny.

We have made good strategic progress in 2013 in challenging market conditions - investing along the gas value chain to secure long term, affordable energy supplies, with customers at the core of our activities:

• we signed £14 billion worth of new gas supply agreements with Cheniere and Qatargas, helping secure supplies for the UK;
• we completed the C$1 billion acquisition of a portfolio of Canadian gas assets in partnership with Qatar Petroleum International (QPI), adding over 100mmboe of reserves to our international upstream portfolio at lower cost than for equivalent North Sea assets;
• we acquired a 25% stake in the Bowland shale exploration licence, bringing our expertise and resources to a potentially important long-term source of gas for our customers;
• we made over £1.5 billion of organic investments across the Group, predominantly in our North Sea E&P portfolio, including in major projects such as Cygnus;
• we added 56mmboe organically to our reserves base, mostly from upgrades to our Norwegian assets;
• we announced £650 million of disposals, of selected North Sea assets, our Texas CCGTs and non-core UK wind assets, underlining our commitment to capital discipline and value; and
• we acquired the Hess Energy Marketing business for $1.2 billion, transforming the capabilities of our North American B2B activities.

However, with economic and market headwinds impacting many areas of the business, adjusted earnings per share were flat year-on-year at 26.6p. We also recognised pre-tax impairments and provisions totalling £1,064 million, £667 million after tax.

Downstream in the UK, the post-tax margin for residential energy supply fell to 4.5%, in part reflecting the impact of mild weather on consumption towards the end of the year. This followed unusually cold weather in the first half, with the benefit from higher consumption used to absorb the increased external costs being faced by the business for as long as possible. However, in October we announced the decision to increase our residential energy tariffs, as a result of higher commodity and non-commodity costs. Following the announcement, the level of customer switching increased significantly and the number of residential customer accounts reduced by 2% over the year. However, although account losses have continued in early 2014, with around 100,000 in the year to date, the position is now stabilising, with British Gas the first to pass on savings in full to all our customers following the announcement of changes to the ECO programme and the introduction of new fixed price propositions.

British Gas Services once again recorded operating profit growth despite the challenging economic environment, benefiting from cost reduction initiatives implemented over the course of 2012 and 2013. Early signs of economic recovery are also benefiting our central heating installations business. Installations were 7% higher in 2013 compared to 2012, while weekly sales of our remote heating control product have more than doubled since its launch under the Hive brand in September. In British Gas Business, the trading environment remained difficult in a highly competitive market. We led the industry with our programme to end auto-rollover of contracts at renewal, although this has placed further pressure on margins.

Downstream in North America, we delivered profit growth in both residential energy and residential services, as we benefitted from previous acquisitions and services account growth. However total Direct Energy profitability fell as a result of lower margins in Direct Energy Business, with rising wholesale costs and a highly competitive power market resulting in difficult trading conditions.

Upstream, gas and liquids production performance was good, as recent acquisitions in the North Sea and Canada delivered production better than our investment cases. We also added 56 mmboe of 2P reserves organically, predominantly on our Norwegian assets. However, following reserve and resource downgrades and increases in expected costs on certain projects in the Southern North Sea, and a reduction in North American natural gas prices since previous asset acquisition and development, we recognised exceptional post-tax impairments of £318 million.

In UK power generation, the performance of the nuclear fleet was once again strong. However, our gas-fired fleet was loss-making, reflecting weak spark spreads and the end of free carbon allocations. In this environment we continued to minimise our cost base and run our plants as efficiently as possible. We also recognised a £125 million exceptional onerous contract charge on the Rijnmond tolling contract in the Netherlands as a result of decreases in expected future revenues.

Our Rough gas storage asset performed well, particularly during the prolonged cold weather at the start of the year, making an invaluable contribution to UK security of supply. However, forward seasonal gas spreads remain very low, leading to a significant reduction in profit in 2013. The low seasonal spreads, together with the UK Government’s decision to rule out incentivisation for new gas storage projects to be built, caused us not to proceed with the Baird storage project and to put our project at Caythorpe on hold. As a result, we have recognised exceptional impairments and provisions relating to storage projects of £224 million after tax.

We successfully completed our £500 million Group-wide cost reduction programme, announced at the start of 2012. We also completed our £500 million share repurchase programme launched in February, and in December announced a further £420 million share repurchase programme, following the sale of our Texas CCGTs, to be undertaken over the course of 2014.

WORKING TOWARDS A TRANSPARENT AND AFFORDABLE ENERGY POLICY

Over the past year, UK energy policy has seen unprecedented levels of debate and discussion amongst stakeholders. As a result, there is improved awareness of the costs of securing and supplying energy, the majority of which are external to the business. However, it is important that the facts are made public and that all stakeholders – energy companies, regulators, politicians, consumers and commentators - engage in full and open conversation.

We have simplified our UK residential energy product range to four tariffs, and led the way earlier in 2013 with our unique ‘Tariff Check’, making it easier for our customers to ensure they are on the most appropriate British Gas tariff for them. We continue to improve the transparency of our reporting, including publication of audited Ofgem segmental statements as part of our year end reporting and separating out our midstream power profits, and call on others to follow. We also protected over half a million of our most vulnerable customers from the November price rise, through a special discount to be applied to their bills. As a result, we currently expect this group of customers to have lower bills in 2014 than in 2013. And we welcome the proposed changes announced by Government to the ECO programme, enabling more customers to benefit, at lower cost.

However, the prospect of political intervention and a wide range of potential policy initiatives has damaged investor confidence. In particular, we believe that a price freeze is not a credible solution, when the large majority of costs are external to the business. Such proposals create both short term uncertainty for all energy suppliers and longer term additional costs for customers. With substantial investment required to secure energy supplies for the UK, these uncertainties increase the cost of capital and, in the eyes of major global producers, reduce the credit worthiness of prospective buyers of their gas, impairing rather than improving the UK’s energy security position.

Against this uncertain background, financial stewardship and discipline remain important to our business, for the benefit of customers and shareholders. Customers rely on us for our financial strength to enter into long term supply contracts and shareholders require an appropriate return, reflecting the risks inherent in managing commodity price and weather risk in the underlying business and in the investments we make. Whilst delivering good service and value for customers is paramount, with a significant proportion of our share capital held by UK pension funds and around 700,000 individual shareholders, making appropriate investments and delivering a fair level of return to investors also remains a core responsibility.

We firmly believe that any form of price control in a competitive market is not the answer and is not in the best interests of customers, and this has been clearly demonstrated by experience in other markets. The industry requires a stable policy environment, which recognises the need for strong underlying economics and investment certainty, to deliver secure supplies for our customers. We will continue to engage with all policymakers to present proposals for more affordable ways to decarbonise and reduce energy consumption, helping more people at lower cost.

INVESTING TO SECURE ENERGY SUPPLIES FOR OUR CUSTOMERS

We have made substantial progress in delivering our gas value chain strategy, positioning the business for future growth. In an increasingly global gas market, it is important that the UK is able to source gas at the most cost effective price. Centrica plays an important role, with existing relationships to secure pipeline gas from Norway and Continental Europe, and LNG from Qatar. During the year we extended our LNG supply contract with Qatargas until 2018. We also signed a contract with Cheniere to take gas export capacity at the Sabine Pass facility in Louisiana, which gives us destination rights over cargoes for the first time, and will allow us to benefit from any differential between North American gas prices and other worldwide markets.

With rising costs in the North Sea, we are targeting our investment towards opportunities that offer the best value, particularly in Norway and in North America. We have taken a stake in UK shale exploration, potentially a significant source of gas for the UK. And in power, our Lincs offshore wind farm, which is capable of providing electricity for up to 200,000 UK homes, is now fully operational.

POSITIONING THE BUSINESS FOR THE FUTURE

Market conditions are expected to remain challenging in 2014, with margin pressures in our energy supply businesses on both sides of the Atlantic, rising North Sea unit costs, and weak economics for both gas storage and gas-fired power generation. In British Gas Residential, the level of margin achieved in a competitive market is dependent on a number of factors, including retail and wholesale prices, service and the weather, which has been warmer than usual in the year to date. The wider external environment also currently provides a challenging operating backdrop. In North America, although the Hess Energy Marketing business is performing well, Direct Energy has had a difficult start to 2014. With a weaker US dollar, continued margin pressures, and exceptionally cold weather which resulted in additional short term system charges, we currently expect Direct Energy operating profit to be broadly flat year on year. Overall for the Group, 2014 trading is in line with recent market forecasts, other than the one-off impact from extreme weather conditions in Direct Energy, with adjusted earnings per share in 2014 expected to be lower than in 2013.

Recognising the challenges, we are maintaining our focus on operational and capital efficiency, with specific new targets appropriate for each area of the business.

We have now completed strategic reviews in both British Gas and Direct Energy, and our downstream strategic priority – Innovate to drive growth and service excellence – remains robust. New organisational structures are in place on both sides of the Atlantic to ensure delivery, as we target improvement in our core operations to enhance service and reduce costs, while driving growth through innovative propositions.

In our UK residential energy and services businesses, we are targeting industry leading service levels for our customers. We will aim to improve service and deliver further efficiencies by simplifying key customer interactions, in part enabled by our investment in a single residential Customer Relationship Management (CRM) system for energy and services, which is expected to be completed in 2014.

Our leadership in digital, smart and connected homes enables us to offer compelling, differentiated propositions.

By the end of 2014 we are targeting over 100,000 sales of our ‘Hive Active Heating’ smart thermostat and currently expect to have installed 1.3 million residential smart meters. We see the smart connected home as core to our customer proposition, materially improving the customer experience and providing an opportunity for growth.

We also see further opportunities in residential services, leveraging our insurance capabilities to offer new pricing structures and an expanded product choice, and from growing share in adjacent markets such as the landlord sector. Through enhanced price competitiveness, improved service quality and innovation we are targeting a return to account growth in both UK residential energy and services.

In British Gas Business, we are also targeting industry leading service levels, with a sustained programme of process simplification and the implementation of a new billing system expected to deliver improved service at lower cost.

A cost reduction programme is underway, which is expected to generate £100 million of annual savings by the end of 2015, helping to offset the impact of continuing difficult market conditions and the impact of our decision to lead the market in ending auto-rollover at contract renewal. Longer term, we expect to deliver growth from the development of new offerings tailored to the most valuable customer segments, and from business services, where the market opportunity is comparable in size to business energy.

In North America, with margin pressures persisting in 2014, improving cost competitiveness is a core priority. Against this backdrop we have launched a $100 million cost reduction programme, driving synergies from the enhanced scale of our business. We are already benefiting from call centre consolidation and back office integration, while we have started investment in a new residential energy billing system.

We are also positioning the business for growth, and building a range of innovative product offerings is core to our North American business model, enabling improved customer retention and delivering growth. Our ‘Power To Go’ prepayment offering and our innovative ‘Free Electricity Saturdays’ product have both proved popular with residential energy customers, while we are targeting further growth in our services protection plan offering in 2014, which we see as a unique differentiating factor in our business model. Over time, we see significant potential for bundling of energy and services propositions to our residential customer base.

In Commercial and Industrial energy supply, the integration of Hess Energy Marketing is proceeding well. Our priority for 2014 is to fully integrate the teams, retaining key personnel and systems, and in turn to deliver good service levels and high levels of customer retention. In the first three full months of our ownership, the business has delivered EBITDA in excess of our investment case. Over time, the enhanced scale, dual fuel capabilities, advantaged positions along the gas value chain and long-term customer relationships delivered by the Hess acquisition provide additional growth opportunities.

Our International E&P business has been re-organised with a substantially new leadership team, to help realise the full potential of the international resource base. We have added 155mmboe in total to our 2P reserves, organically and through acquisition. We also retain a number of attractive investment options, particularly in Norway and Canada, having increased our 2C resource base by 28% to 771mmboe over the year. However, with rising costs, in the UK in particular, we are targeting savings to keep unit lifting and other cash production costs flat over the next three years.

Against this backdrop, we are being increasingly selective in our investment, concentrating on the most attractive opportunities. An increasing proportion is expected to be directed towards North America, where we are well placed to benefit from any increase in gas prices. Taking account of forward UK gas prices and higher costs, we are targeting a reduction in our organic investment in gas and oil projects to approximately £900 million on average over the next three years. This is around 20% lower than previously expected levels, but will have limited impact on near-term production, which we expect to be in the range 80-85mmboe per annum. Our current level of committed capital expenditure in the short to medium term gives us flexibility to consider acquisition opportunities, if the economics are attractive and the assets provide a good fit with our existing portfolio, while potentially divesting non-core assets for value.

In UK power generation, reflecting the challenging market conditions that resulted in losses for our gas-fired power stations, we will continue to optimise the running of our existing fleet to capture the benefit from any improvement in market spark spreads. However, following our decision not to invest in new nuclear in the UK and to sell the Race Bank offshore wind project to Dong, we expect our near-term investment in the UK power sector to be limited. Any future investment in new build gas-fired generation capacity will depend on the economics of the projects and the successful introduction of a capacity market, including an assessment of the political risk.

Centrica is an important company, providing energy or services for over 11 million homes in the UK as well as serving some six million customer accounts in North America. We directly employ over 35,000 people worldwide, make a tax contribution of around £1 billion a year and make a valuable contribution to retirement savings through our dividend payments, as well as securing cost-effective sources of energy for the UK.

Centrica has a strong balance sheet, providing flexibility for targeted investments for value. However, maintaining tight capital discipline is a core priority, as evidenced by our share repurchase programmes. We are recommending 2013 full year dividend growth of 4%, in excess of the UK retail price index, and are maintaining our commitment to real dividend growth.

In a challenging external environment, we remain committed to our guiding principles of offering good service and value for customers and playing a vital role in the transition to a lower carbon economy. Whilst the outlook for the UK business has been impacted by short term political uncertainty, we are taking positive action across the Group to position the business for the long term, for the benefit of both customers and shareholders.

SAM LAIDLAW
Chief Executive
20 February 2014

Group Financial Review

Group revenue was up 11% to £26.6 billion (2012: £23.9 billion). Revenue increased in British Gas, primarily due to the impact on retail energy prices of higher UK wholesale gas and electricity prices and non-commodity costs. Revenue in Direct Energy increased, predominantly reflecting the impact of higher gas and power volumes, and the acquisition of the Hess Energy Marketing business which completed in November. Revenue increased in Centrica Energy, with higher gas and liquids production due to the full-year impact of the 2012 asset purchases and higher achieved gas and liquids prices in Europe. Centrica Storage revenue fell slightly, reflecting lower seasonal gas spreads and a higher proportion of storage capacity sold internally.

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:

Â

Â

Â

Â

2013

Â

Â

Â

2012

Year ended 31 December

Â

Notes

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Statutory result £m

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Statutory result £m

Adjusted operating profit

British Gas

1,030

1,093

Direct Energy

276

310

Centrica Energy

1,326

1,251

Centrica Storage

Â

Â

Â

63

Â

Â

Â

Â

Â

89

Â

Â

Â

Â

Total adjusted operating profit

5c

2,695

2,743

Depreciation of fair value uplifts from Strategic Investments, before tax

5c

(66)

(96)

Interest and taxation on joint ventures and associates

Â

5c

Â

(111)

Â

Â

Â

Â

Â

(85)

Â

Â

Â

Â

Group operating profit

5c, 6

2,518

(626)

1,892

2,562

63

2,625

Net finance cost

(243)

–

(243)

(209)

–

(209)

Taxation

Â

6, 8

Â

(942)

Â

243

Â

(699)

Â

(1,031)

Â

(140)

Â

(1,171)

Profit for the year

1,333

(383)

950

1,322

(77)

1,245

Depreciation of fair value uplifts from Strategic Investments, after taxation

Â

10

Â

37

Â

Â

Â

Â

Â

56

Â

Â

Â

Â

Adjusted earnings

Â

Â

Â

1,370

Â

Â

Â

Â

Â

1,378

Â

Â

Â

Â

The Group has applied IAS19 (revised) pensions accounting. As a result, 2012 net finance costs, taxation, earnings and earnings per share have been restated. To reflect a new organisational structure, the North American upstream gas business has been reallocated from Direct Energy to Centrica Energy.

In British Gas, total profitability decreased. Operating profit decreased in residential energy supply, with the impact of higher unit tariffs more than offset by increased wholesale commodity, transmission and metering, and environmental costs. Operating profit decreased in business energy supply and services, with lower margins as a result of challenging market conditions and our programme to end the auto-rollover of contracts. Operating profit increased in residential services, predominantly reflecting the impact of cost efficiencies.

In Direct Energy, overall profitability decreased, as increases in residential energy supply and residential and business services operating profit, resulting from previous acquisitions and services account growth, were more than offset by decreased profitability in the business energy supply segment, which experienced margin pressure on power sales in a competitive environment. In Centrica Energy, overall profitability increased, with higher operating profit in the gas segment more than offsetting lower power operating profit. In the gas segment, higher gas and liquids production and higher achieved prices in Europe more than offset the impact of increased unit costs. In the power segment, profitability decreased following the loss of free carbon allowances. In Centrica Storage, reduced seasonal gas price differentials led to lower profitability.

Net finance cost increased to £243 million (2012: £209 million), with higher average levels of debt in the year, as the Group raised $1.35 billion in the US bond market to fund North American acquisitions completed during the year. The taxation charge reduced to £942 million (2012: £1,031 million) and the adjusted tax charge was £1,022 million (2012: £1,112 million). The resultant adjusted effective tax rate for the Group was 43% (2012: 45%). An effective tax rate calculation, showing the UK and non-UK components, is shown in the table below:

	Â		Â		Â	2013	Â	Â	Â		Â		Â	2012
	Â	UK £m	Â	Non-UK £m	Â	Total £m	Â	Â	Â	UK £m	Â	Non-UK £m	Â	Total £m
Adjusted operating profit		1,903		792		2,695				2,079		664		2,743
Share of joint ventures / associates interest		(60)		-		(60)				(44)		–		(44)
Net finance cost	Â	(146)	Â	(97)	Â	(243)	Â	Â	Â	(105)	Â	(104)	Â	(209)
Adjusted profit before taxation	Â	1,697	Â	695	Â	2,392	Â	Â	Â	1,930	Â	560	Â	2,490
Taxation on profit		493		449		942				694		337		1,031
Tax impact of depreciation on Venture fair value uplift		29		-		29				40		–		40
Share of joint ventures / associates taxation	Â	51	Â	-	Â	51	Â	Â	Â	41	Â	–	Â	41
Adjusted tax charge	Â	573	Â	449	Â	1,022	Â	Â	Â	775	Â	337	Â	1,112
Adjusted effective tax rate	Â	34%	Â	65%	Â	43%	Â	Â	Â	40%	Â	60%	Â	45%
Reflecting all of the above, profit for the year was £1,333 million (2012: £1,322 million) and after adjusting for fair value uplifts adjusted earnings were broadly flat at £1,370 million (2012: £1,378 million). Adjusted basic earnings per share (EPS) were unchanged at 26.6 pence (2012: 26.6 pence).

The statutory profit for the year was £950 million (2012: £1,245 million). The reconciling items between Group profit for the year from business performance and statutory profit are related to exceptional items and certain re-measurements. The decrease compared with 2012 is principally due to an increased net exceptional charge of £667 million (2012: £481 million) and a reduced gain from certain re-measurements of £284 million (2012: £404 million). The Group reported a statutory basic EPS of 18.4 pence (2012: 24.0 pence).

In addition to the interim dividend of 4.92 pence per share, we propose a final dividend of 12.08 pence, giving a total ordinary dividend of 17.0 pence for the year (2012: 16.4 pence), an increase of 4%.

Group operating cash flow before movements in working capital was higher at £3,737 million (2012: £3,542 million), with the full year impact of the 2012 upstream asset purchases being the main contributing factor. After working capital adjustments, tax, and payments relating to exceptional charges, net cash flow from operating activities was £2,940 million (2012: £2,820 million).

The net cash outflow from investing activities was lower at £2,351 million (2012: £2,558 million), predominantly reflecting the receipt of a larger nuclear dividend and increased proceeds from the disposal of businesses.

The net cash outflow from financing activities was £791 million (2012: inflow of £190 million). The outflow mainly reflects the impact of the Group’s £500 million share repurchase programme, fully undertaken during the year, and a reduced net issuance of debt during the period of £809 million (2012: £1,196 million).

Reflecting all of the above, the Group’s net debt at 31 December 2013 was £5,049 million (2012: £4,047 million).

During the year net assets decreased to £5,257 million (2012: £5,927 million), reflecting the impact of the Group’s share repurchase programme, actuarial losses on the Group’s defined benefit pension schemes, and foreign currency movements on the retranslation of foreign subsidiaries.

EXCEPTIONAL ITEMS

Exceptional pre-tax charges of £1,064 million were incurred within Group operating profit during the year (2012: £534 million). Taxation on these charges generated a credit of £397 million (2012: £93 million), while there was a £40 million exceptional tax charge in 2012 related to the effect of a change in upstream UK tax rates. This resulted in exceptional post-tax charges of £667 million (2012: £481 million).

Following reserve and resources downgrades and increases in expected costs on the Seven Seas, York and Ensign fields in the Southern North Sea, and a weaker outlook for North American natural gas prices and an increase in the discount rate applicable to North American assets, the Group recognised pre-tax impairment charges of £699 million relating to UK and Canadian exploration and production assets. Taxation on these charges generated a credit of £381 million, resulting in exceptional post-tax charges of £318 million.

In September, in the light of weak economics for new storage projects and the UK Government’s announcement ruling out incentivisation for gas storage capacity to be built in the UK, Centrica announced its decision not to proceed with the Baird offshore gas storage project and to put the onshore project at Caythorpe on hold indefinitely. As a result, the Group has recorded £240 million of impairments and provision charges as exceptional operating costs. Taxation on these charges generated a credit of £16 million resulting in exceptional post-tax charges of £224 million.

The Group also recognised a further onerous contract charge of £125 million (no tax impact) for the Rijnmond power tolling contract in the Netherlands as a result of decreases in expected future revenues.

CERTAIN RE-MEASUREMENTS

As an integrated energy business the Group enters into a number of forward energy trades to protect and optimise the value of its underlying production, generation, storage and transportation assets (and similar capacity or off-take contracts), as well as 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 IAS39. The Group has shown the fair value adjustments on these commodity derivative trades separately as certain re-measurements, as they do not reflect the underlying performance of the business because they are economically related to our upstream assets, capacity/off-take contracts or downstream demand, which are typically not fair valued. The operating profit in the statutory results includes net gains of £438 million (2012: £597 million) relating to these re-measurements, of which there are a number of elements. The Group recognises the realised gains and losses on these contracts in business performance when the underlying transaction occurs. The profits 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. See note 2 for further details.

BUSINESS COMBINATIONS

On 15 April 2013, the Group announced that it had agreed to form a partnership with Qatar Petroleum International and jointly acquire a package of producing conventional natural gas and crude oil assets and associated infrastructure located in the Western Canadian Sedimentary Basin from Suncor Energy. The transaction completed on 26 September 2013 for consideration of C$987 million (£601 million). The Group owns a 60% share in the partnership and operates the assets. It has fully consolidated the partnership for accounting and reporting purposes.

On 30 July 2013, the Group announced that it had agreed to acquire the New Jersey-based energy marketing business of Hess Corporation. The transaction completed on 1 November 2013 for consideration of $1,194 million (£736 million) including a payment for the working capital of the business of approximately $416 million (£257 million).

Further details on business combinations, plus details of asset purchases, disposals and disposal groups held for sale are included in notes 5(f) and 15.

EVENTS AFTER THE BALANCE SHEET DATE

Details of events after the balance sheet are described in note 17.

RISKS AND CAPITAL MANAGEMENT

The Group’s risk management processes are largely unchanged from 31 December 2012. Details of how the Group has managed financial risks such as liquidity and credit risk are set out in note 4.

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

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.

Operating Review

INTERNATIONAL DOWNSTREAM

The operating environment for both our UK and North American downstream businesses was challenging during 2013. However we made good strategic progress on both sides of the Atlantic, positioning ourselves for the future, and our downstream strategic priority – Innovate to drive growth and service excellence – has been reaffirmed. Under the leadership of Chris Weston a new management structure is in place, designed to enable us to focus on improving our core operations to deliver better customer service and drive growth through innovative propositions.

BRITISH GAS

In the UK, the operating environment for our downstream energy supply businesses was unprecedented. Affordability has been a key concern for both residential and business customers, amplified by media and political debate ahead of the 2015 election. Against this backdrop we welcomed the Government’s proposed changes to the Energy Company Obligation (ECO), announced in December, which enabled us to be the first UK energy supplier to reduce retail tariffs. We have also made good progress in positioning the business for the future, with further development of our digital platforms, the launch of new propositions, continued industry leadership on smart metering, and an ongoing focus on service and cost efficiency.

Residential energy supply operating profit fell by 6%, reflecting warmer weather towards the end of the year and higher commodity and non-commodity costs, while business energy supply and services operating profit fell by 19% in challenging market conditions. A continued focus on cost reduction resulted in an increase in residential services profit, although delivering new sales of services contracts proved challenging. The health and safety of our employees and customers remains a core priority and the lost time injury frequency rate (LTIFR) over 2013 was 0.11 per 100,000 hours worked in British Gas (2012: 0.23).

Tough environment for residential energy supply

Having absorbed higher commodity and non-commodity costs for as long as possible, we took the decision in October to increase average household gas prices by 8.4% and average household electricity prices by 10.4%, an average of 9.2%. The price rise took effect in late November. However, the UK Government’s proposed changes to the ECO programme allowed British Gas to reduce average household gas and electricity prices by 3.2%, effective from 1 January 2014. Including the Government’s £12 rebate in relation to the Warm Home Discount, the average customer bill will reduce by £53, or 4.1%.

We strongly support the aims of the ECO programme, which is providing energy efficiency measures such as insulation to transform homes and communities across the UK, helping keep homes warm and reducing carbon emissions. Therefore we welcome the proposed changes to the ECO programme, which will extend the obligation period by two years to March 2017 and broaden eligibility measures, allowing us to help more customers and reduce the short term impact on bills. We expect our costs to be over £1.7 billion over the life of the programme, and in 2013 we incurred £420 million of costs. We also completed all work under the CERT and CESP programmes around the middle of 2013, later than the target date of December 2012. Overall, through these programmes, we installed 236,000 energy efficiency measures in customer homes in 2013, over half of which were for the elderly, disabled or those most in need.

We continue to lead the industry in helping the most vulnerable, having helped more than 1.8 million households suffering from fuel poverty. We maintain the widest eligibility criteria among all energy suppliers for the Warm Home Discount, which benefited over 500,000 of our customers during the year. We also protected these customers from our November price increase through an additional discount of up to £60 to be applied to their bills.

We now offer four distinct tariffs, all with a standing charge and single unit rate, and have consolidated our discount structures. We introduced our unique ‘Tariff Check’ in the first half of the year, which provides a personalised comparison of their energy costs under each British Gas tariff and enables customers to check that they are on the most appropriate tariff for them. In October, the Government announced a new annual competition review for the UK energy sector, and we expect the results to be published around the end of the first quarter of 2014.

Helping restore confidence in the energy industry is a top priority for British Gas. Our independent Customer Board is in its third year and has continued to challenge and advise on a range of service and product topics. And we are making good progress on implementing Ofgem’s Standards of Conduct and have established a Customer Fairness Committee, which includes two independent external members. We also continue to invest in jobs, with 1,200 apprentices currently in training, while we have committed that from January 2014 all UK-based employees will be paid at least the ‘living wage’ rate.

Focus on delivering great customer service

The number of residential accounts on supply as at the end of 2013 was 15.3 million, 2% lower than at the start of the year. This reflects a competitive market and higher levels of customer churn in the period immediately following our pricing announcement in October. Customer account losses have continued into 2014, with around 100,000 in the year to date, however the position is now stabilising, reflecting our January 2014 price reduction and the introduction of new fixed price propositions.

In a competitive market for energy supply it is important to focus on delivering high levels of customer service. The migration of our residential customers onto a new Customer Relationship Management (CRM) platform will be completed in 2014. We experienced some system outages during implementation, which was exacerbated by higher call volumes caused by the tariff increase announcement. Reflecting this, the total British Gas net promoter score decreased to +15 in 2013 (2012: +30). However we invested in additional customer service advisors to address the short term issues, and the new system is expected to deliver a more integrated customer experience.

We are leading the industry in the use of digital platforms, reducing our cost to serve and increasing customer engagement, and British Gas was awarded ‘best e-commerce utility supplier’ at the 2013 e-commerce awards for excellence. Customer downloads of our top-rated mobile ‘App’ were up 37% and over a million have been downloaded since its launch. The number of customers transacting through digital channels also increased. Total transactions increased 16%, while 1.2 million customers booked their annual service or boiler breakdown online, up 22% and nearly 40% of bills were sent electronically. In January 2014, we fully launched ‘Me’ (Mobile Energy), a new energy brand capable of being delivered entirely via mobile devices and aimed at the private tenant segment.

We are also developing smart and 'connected home' solutions to give customers greater visibility and control over their energy usage. We have now installed over 1.3 million smart meters for homes and businesses in the UK, with over 800,000 of these for residential customers, and in 2014 we expect to be the first company to install smart meters for residential prepayment customers. The industry-leading progress we have made leaves us well placed, as we move towards the mandated roll-out of smart meters in the UK from the end of 2015. Over 200,000 customers now receive our ‘Smart Energy Report’, which we launched in March 2013. This provides customers with comprehensive analysis of their energy usage, and has resulted in a positive impact on customers’ perception of British Gas. In September we launched Hive, our rebranded Remote Heating Control proposition, which allows customers to control their heating and hot water remotely via their smart phone or online. Initial brand recognition has been strong, and we have now sold over 50,000 smart thermostats, with weekly sales having doubled since the Hive launch.

Strong cost focus in residential services in tough sales environment

Market conditions remained challenging for British Gas Services, in part due to continued pressure on household disposable income. Retention of existing customers was strong, with customers recognising the value of our services products during sustained periods of cold weather in the first half. However sales of new products were lower, reflecting the overall economic environment. As a result, the number of services customer accounts fell by 2% during 2013, ending the year at 8.2 million. We are beginning to see some pick up in the market for new central heating installations, with the number increasing by 7% in 2013 compared to 2012, and by 10% in the second half of the year, in part reflecting our leadership position on the ‘Green Deal’. British Gas was the first energy supplier to market on the ‘Green Deal’ and we now have 300 Green Deal advisors trained, and have completed over 10,000 installation measures.

British Gas Services delivered strong levels of operational performance in the year. Overall we responded to 3.2 million boiler breakdowns, over 200,000 more than in 2012. Despite the higher workload, our net promoter score increased to +59 (2012: +55), while the average speed to answer calls improved.

Although we incurred additional costs as a result of the higher level of call-outs, residential services operating profit increased slightly compared to 2012, reflecting the benefit of cost savings delivered in 2012 and 2013. With the existing cost reduction programme now complete, we will maintain a keen focus on cost efficiency in the business. We will also look to develop new and innovative products and propositions. During 2013 we launched packages tailored specifically for landlords and tenants, while we also launched British Gas branded home insurance in partnership with AXA and entered into a new partnership agreement with Nationwide’s ‘buy-to-let’ mortgage arm.

Continued challenging market conditions for business energy supply and services

The number of business energy supply points fell by 12,000 over the year, and were flat in the second half of the year. The tough economic and competitive environment continued to put pressure on business energy supply margins, which were also impacted by our programme to end the auto-rollover of contracts at renewal, for the benefit of customers. This decision ensures our customers have a transparent choice of products, and should provide long-term benefits. As a result of the margin pressures, operating profit in 2013 was significantly lower than in 2012.

During the year we started the implementation of a new business energy billing system, which is proceeding to plan and is expected to be fully operational by the end of 2014. The system leverages previous investment in residential platforms and will result in improved customer service at lower cost, helping to offset margin pressures. We continue to develop our business services propositions, and we have now mobilised two major new contracts with Cornwall Council and a consortium of eight local authorities in the North East of England. We have also signed and commenced work on thirteen energy performance contracts. Business services revenue increased by 11% in 2013 compared to 2012, while our secured pipeline of future work increased by 25% to over £200 million.

Reduced year-on-year operating profit

Total British Gas gross revenue increased to £14,226 million (2012: £13,857 million) while total British Gas operating profit fell to £1,030 million (2012: £1,093 million) with a slight increase in residential services profitability more than offset by declines in residential energy supply and business energy supply and services. British Gas has delivered its £300 million share of the Group’s cost reduction programme, with the full year impact of 2012 initiatives coming through and further savings delivered in 2013 through procurement, IT and operational efficiencies. Reflecting the impact of inflation and investment in growth areas, British Gas operating costs were up slightly in 2013 compared to 2012, while previous investment in systems and a more proactive approach to helping customers resulted in the bad debt charge as a proportion of revenue holding broadly flat.

Residential energy supply gross revenue increased to £9,487 million (2012: £9,121 million), predominantly reflecting the impact of higher commodity and non-commodity costs on retail gas and electricity tariffs. Average gas consumption was broadly flat compared to a cold 2012, with a decline in underlying consumption and warmer than usual weather in the fourth quarter offsetting the impact of unusually cold weather in the first half. Average electricity consumption fell by 3%. Second half operating profit fell by 18% compared to 2012, while full year operating profit fell by 6% to £571 million (2012: £606 million), as increased revenue was more than offset by higher external costs, with commodity, transmission, metering, and environmental costs all rising. The full year post-tax margin decreased to 4.5% (2012: 5.0%).

Residential services gross revenue decreased slightly to £1,655 million (2012: £1,674 million). Operating profit, including the receipt of an ECO management fee from residential energy supply, increased to £318 million (2012: £312 million), while the post-tax margin increased to 14.6% (2012: 14.1%), primarily reflecting the impact of operational efficiencies. Business energy and services gross revenue increased to £3,084 million (2012: £3,062 million), while operating profit, including credits arising from improved revenue and billing processes, fell by 19% to £141 million (2012: £175 million), reflecting the margin pressures. The post-tax margin fell to 3.7% (2012: 4.2%).

Positioning the business for the future in a tough external environment

Having completed a comprehensive review of the business, our focus is on improving our core operations to enhance service and reduce costs, while driving growth through innovative propositions.

In British Gas Residential and British Gas Services, we are targeting industry leading service levels for our customers. We will aim to improve service and deliver efficiencies by simplifying key customer interactions, such as moving home and paying by direct debit, to provide an effortless, consistent experience through all channels. Our project to move to a single residential billing platform for energy and services, which is expected to be completed this year, will improve service and cost efficiency as well as facilitating the integrated propositions needed to deliver increased energy and services cross-selling.

In addition, our leadership in digital, smart and connected homes enables us to offer compelling, differentiated propositions, such as our ‘Hive Active Heating’ smart thermostat. We currently expect to have installed 1.3 million residential smart meters and to have sold over 100,000 smart thermostats by the end of 2014. We continue to see the smart connected home as core to our customer proposition, materially improving the customer experience and providing an opportunity for growth.

We see further growth opportunities in residential services, from new pricing structures and expanded product choice, leveraging our insurance capabilities. We also see opportunities to grow share in adjacent, under-served markets such as the landlord sector and from improved conversion of boiler installation enquiries into sales. Overall, through enhanced price competitiveness and innovation, we are targeting a return to account growth in both residential energy and services.

In British Gas Business, a sustained programme of process simplification and the implementation of a new billing system, which started in 2013, is expected to deliver improved service at lower cost. We expect to deliver £100 million of annual operating cost and bad debt reductions by the end of 2015, and have already delivered around £20 million of this in 2013. This will help to offset the impact of transitioning our commercial model, including our decision to lead the market in ending auto-rollover at contract renewal.

As in the residential business, we will drive growth in business energy supply by developing new offerings tailored to valuable customer segments and utilising a more targeted channel strategy. In business services, where the market opportunity is comparable in size to business energy, we expect to grow a material position over time, through a combination of organic and inorganic growth.

Total British Gas

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

For the year ended 31 December

Â

FY 2013

Â

FY 2012

Â

Δ%

Â

H2 2013

Â

H2 2012

Â

Δ%

Total customer accounts (period end) (’000)

Â

24,395

Â

24,944

Â

(2)

Â

24,395

Â

24,944

Â

(2)

Total customer households (period end) (’000)

Â

11,120

Â

11,379

Â

(2)

Â

11,120

Â

11,379

Â

(2)

Joint product households (period end) (’000)

Â

2,257

Â

2,393

Â

(6)

Â

2,257

Â

2,393

Â

(6)

Gross Revenue (£m)

Â

14,226

Â

13,857

Â

3

Â

6,314

Â

6,650

Â

(5)

Operating cost (excluding bad debt) (£m)

Â

1,392

Â

1,353

Â

3

Â

706

Â

672

Â

5

Operating profit (£m)

Â

1,030

Â

1,093

Â

(6)

Â

461

Â

530

Â

(13)

Operating profit after taxation (£m)

Â

777

Â

823

Â

(6)

Â

nm

Â

nm

Â

nm

FY 2012 residential energy customer accounts have been restated to exclude 38,000 accounts subsequently reclassified as dormant. FY 2012 total customer households and joint product households have been restated to reflect a revised alignment of products to households following the implementation of a new customer database. FY 2012 operating costs have been restated to reflect the reallocation of certain costs from operating costs to cost of sales.

Â

Residential energy supply

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

For the year ended 31 December

Â

FY 2013

Â

FY 2012

Â

Δ%

Â

H2 2013

Â

H2 2012

Â

Δ%

Customer accounts (period end):

Â

Â

Â

Â

Â

Â

Â

Gas (’000)

8,603

8,872

(3)

8,603

8,872

(3)

Â

Electricity (’000)

Â

6,653

Â

6,746

Â

(1)

Â

6,653

Â

6,746

Â

(1)

Â

Total (’000)

Â

15,256

Â

15,618

Â

(2)

Â

15,256

Â

15,618

Â

(2)

Estimated market share (%):

Gas

38.2

39.9

(1.7) ppts

38.2

39.9

(1.7) ppts

Â

Electricity

Â

24.5

Â

25.1

Â

(0.6) ppts

Â

24.5

Â

25.1

Â

(0.6) ppts

Average consumption:

Gas (therms)

492

494

(0)

181

218

(17)

Â

Electricity (kWh)

Â

3,688

Â

3,794

Â

(3)

Â

1,752

Â

1,875

Â

(7)

Total consumption:

Gas (mmth)

4,342

4,460

(3)

1,579

1,945

(19)

Â

Electricity (GWh)

Â

25,078

Â

25,683

Â

(2)

Â

11,932

Â

12,696

Â

(6)

Gross Revenue (£m):

Gas

6,033

5,884

3

2,307

2,668

(14)

Â

Electricity

Â

3,454

Â

3,237

Â

7

Â

1,694

Â

1,646

Â

3

Â

Total

Â

9,487

Â

9,121

Â

4

Â

4,001

Â

4,314

Â

(7)

Operating profit (£m)

Â

571

Â

606

Â

(6)

Â

215

Â

261

Â

(18)

Operating profit after taxation (£m)

Â

423

Â

457

Â

(7)

Â

nm

Â

nm

Â

nm

Post-tax margin (%)

Â

4.5

Â

5.0

Â

(0.5) ppts

Â

nm

Â

nm

Â

nm

FY 2012 residential energy customer accounts have been restated to exclude 38,000 accounts subsequently reclassified as dormant. Further detail on costs can be found in the Ofgem Consolidated Segmental statement on page 74 of the Preliminary Results announcement and on the Centrica website

Residential services		Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â
For the year ended 31 December		Â	FY 2013	Â	FY 2012	Â	Δ%	Â	H2 2013	Â	H2 2012	Â	Δ%
Customer product holdings (period end):		Â		Â		Â		Â		Â		Â
Â	Central heating service contracts (’000)		4,575		4,663		(2)		4,575		4,663		(2)
	Kitchen appliances care (no. of customers) (’000)		453		465		(3)		453		465		(3)
	Plumbing and drains care (’000)		1,683		1,714		(2)		1,683		1,714		(2)
	Home electrical care (’000)		1,420		1,444		(2)		1,420		1,444		(2)
Â	Other contracts (’000)	Â	96	Â	116	Â	(17)	Â	96	Â	116	Â	(17)
Â	Total holdings (’000)	Â	8,227	Â	8,402	Â	(2)	Â	8,227	Â	8,402	Â	(2)
Domestic central heating installations (’000)		Â	101	Â	94	Â	7	Â	55	Â	50	Â	10
Gross Revenue (£m):
	Central heating service contracts		841		839		0		430		435		(1)
	Central heating installations		263		258		2		142		137		4
Â	Other	Â	551	Â	577	Â	(5)	Â	278	Â	291	Â	(4)
Â	Total	Â	1,655	Â	1,674	Â	(1)	Â	850	Â	863	Â	(2)
Operating profit (£m)		Â	318	Â	312	Â	2	Â	183	Â	187	Â	(2)
Operating profit after taxation (£m)		Â	241	Â	236	Â	2	Â	nm	Â	nm	Â	nm
Post-tax margin (%)		Â	14.6	Â	14.1	Â	0.5 ppts	Â	nm	Â	nm	Â	nm
														Â
Business energy supply and services		Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â
For the year ended 31 December		Â	FY 2013	Â	FY 2012	Â	Δ%	Â	H2 2013	Â	H2 2012	Â	Δ%
Customer supply points (period end):
	Gas (’000)		310		322		(4)		310		322		(4)
Â	Electricity (’000)	Â	602	Â	602	Â	0	Â	602	Â	602	Â	0
Â	Total (’000)	Â	912	Â	924	Â	(1)	Â	912	Â	924	Â	(1)
Average consumption:
	Gas (therms)		2,476		2,737		(10)		996		1,156		(14)
Â	Electricity (kWh)	Â	28,852	Â	27,521	Â	5	Â	14,201	Â	14,014	Â	1
Total consumption:
	Gas (mmth)		784		940		(17)		312		399		(22)
Â	Electricity (GWh)	Â	17,260	Â	17,110	Â	1	Â	8,504	Â	8,581	Â	(1)
Gross Revenue (£m):
	Gas		904		1,014		(11)		373		443		(16)
	Electricity		1,951		1,841		6		968		929		4
Â	Business Services	Â	229	Â	207	Â	11	Â	122	Â	101	Â	21
Â	Total	Â	3,084	Â	3,062	Â	1	Â	1,463	Â	1,473	Â	(1)
Operating profit (£m)		Â	141	Â	175	Â	(19)	Â	63	Â	82	Â	(23)
Operating profit after taxation (£m)		Â	113	Â	130	Â	(13)	Â	nm	Â	nm	Â	nm
Post-tax margin (%)		Â	3.7	Â	4.2	Â	(0.5) ppts	Â	nm	Â	nm	Â	nm
Further detail on costs can be found in the Ofgem Consolidated Segmental statement on page 74 of the Preliminary Results announcement and on the Centrica website

DIRECT ENERGY

Market conditions for our North American downstream energy supply businesses proved challenging in 2013, as rising gas and power prices, declining barriers to entry and an increasingly competitive environment among both competitive energy suppliers and default utility providers led to a narrowing of margins. However we made good strategic progress during the year, with the acquisition of the Hess Energy Marketing business significantly enhancing our scale and capability in Commercial and Industrial (C&I) gas supply, the acquisition of Bounce Energy providing a leading internet-based digital platform and further organic growth in our services protection plan product. We also continued our strong focus on health and safety, with the LTIFR remaining low at 0.12 per 100,000 hours worked in Direct Energy (2012: 0.11).

Direct Energy’s scale in deregulated markets leaves us uniquely positioned in North America to respond to these challenging market dynamics. In the fourth quarter of the year the business was reorganised, and the role of Chief Operations Officer was created to lead the drive for operational synergies across our businesses. In 2014 the business will be focused on delivering further cost reductions and building our range of innovative new products and services, with an increased focus on digital channels. We are positioning the business for growth, through innovation and attractive products and propositions, while the Hess acquisition provides us with the ability to optimise positions along the gas value chain.

The combination of organic growth and the effect of acquisitions has increased the scale of the business, resulting in an increase in Direct Energy gross revenue to £7,325 million (2012: £5,684 million). However operating profit fell to £276 million (2012: £310 million), principally reflecting lower margins in business power energy supply. The operating profit in 2013 includes £14 million of integration costs and £22 million of additional amortisation of acquired intangibles relating to the Hess acquisition.

Competitive pressures offsetting the impact of acquisitions in residential energy supply

Operating profit for Direct Energy residential energy supply was up slightly in 2013, as the positive impact of previous acquisitions and reduced operating costs were largely offset by some narrowing of margins in Texas and the continued decline of our customer base in Ontario as a result of our decision to forgo renewals and new customer sales, due to the Energy Consumer Protection Act (ECPA). Gross revenue increased to £2,517 million (2012: £2,357 million) reflecting higher gas and power prices, while operating profit was £163 million (2012: £156 million) and the post-tax margin was unchanged at 4.4%.

The number of residential energy accounts at the end of 2013 was 3.4 million, a slight decline since the start of 2013, in part reflecting the expected decline in Ontario, a highly competitive sales environment in both Texas and the US North East and the expected loss of aggregation customers in the US North East.

In Canada, we now have less than 200,000 customer accounts in Ontario. The business is no longer core to our operations, with the region delivering only 11% of our residential energy supply operating profit in 2013 compared to 20% in 2012 and 29% at its peak in 2010. We also experienced a small drop in our regulated customer base in Alberta, although this was partially offset by growth in the competitive customer base in the region. This resulted in an increase in profitability in Alberta.

In the US North East, the number of accounts fell by 72,000, to 1.3 million, with the loss of 53,000 aggregation customers and the impact of a competitive sales environment being only partly offset by improved retention rates. However profitability increased in the region, reflecting cost efficiencies and the successful integration of customers acquired in 2012 in the Energetix and NYSEG Solutions transactions onto our systems.

In Texas, retention rates also improved, with churn improving by 2ppt. However a highly competitive sales environment, with around 50 retail energy suppliers and 200 competitive offers, resulted in reduced renewal margins. To help offset this margin decline, we focused on lowering our operating cost base, with our cost to serve per customer in Texas falling by 24%. We also continued to develop innovative products, and during the second half of the year we launched our ‘Free Electricity Saturdays’ product, while we increased sales of our prepayment product, ‘Power To Go’ by 30% in 2013. In the second half of the year we also completed the acquisition of the independent electricity retailer, Bounce Energy, for $42 million (£27 million), adding 80,000 accounts to our Texas business and further consolidating our position as a top three retail energy provider in Texas. The acquisition provides a leading internet-based digital and e-commerce platform, for marketing innovative products and online account management and over time we expect this platform to aid residential energy and services account growth in all our core regions.

Volume growth in business energy supply not fully offsetting margin pressures

On 1 November 2013 we completed the acquisition of the New Jersey-based energy marketing business of Hess Corporation for $1,194 million (£736 million), including a payment for working capital of $416 million (£257 million). The acquisition makes Direct Energy the largest C&I gas supplier on the East Coast of the US and the second largest C&I power supplier in the competitive US retail markets, and gives us a more balanced gas and power customer portfolio. It also builds on our existing capabilities and further integrates our activities along the gas value chain, linking gas supply from producers and other market participants, through secured transport and storage capacity, to both our C&I and residential customer bases. The initial performance of the acquired business has been strong.

Direct Energy business energy supply gross revenue increased by 52% to £4,238 million (2012: £2,795 million), reflecting the impact of higher wholesale commodity prices and increased sales volumes. Electricity volumes increased by 24% to 63.9TWh (2012: 51.4TWh) and gas volumes more than doubled to 1,839mmth (2012: 793mmth) reflecting two months of contribution from the Hess Energy Marketing business and good sales performance. However the power market has been increasingly competitive with, up until January 2014, potential competitors finding it easier to access credit and reduced market volatility providing lower barriers to entry. This led to a 36% decline in profitability to £77 million (2012: £121 million). The underlying post-tax margin, excluding the impact of integration costs and additional amortisation associated with the Hess acquisition, fell to 1.8% (2012: 2.8%).

The business energy supply division now includes power generation and midstream activities. In December we announced the sale of our three Texas-based power stations, with a combined capacity of 1,295MW, to Blackstone for $685 million (£420 million). The disposal completed in January 2014 and we expect to recognise a profit on disposal of approximately £220 million as an exceptional item in the 2014 financial results. As part of the transaction we also entered into a three year heat rate call option arrangement with Blackstone for an equivalent amount of capacity. We believe that in the near term this arrangement, together with a liquid physical and financial power market in Texas, can ably support our downstream operations through contractual arrangements rather than asset ownership.

Contract and profit growth in residential and business services

Direct Energy residential and business services gross revenue increased by 7% to £570 million (2012: £532 million), predominantly reflecting an increase in sales from our owned operations and those of our franchises. Operating profit increased to £36 million (2012: £33 million) and the post-tax margin improved slightly to 4.4% (2012: 4.1%) reflecting cost control.

Direct Energy Services gained market share during 2013, with the number of accounts increasing by 207,000. This partly reflects the acquisition of the US-based home services business, America’s Water Heater Rentals (AWHR) for $30 million (£18 million), which added over 80,000 residential customers located primarily in the US Midwest, Florida and the US Northeast. The acquisition was completed in October and provides Direct Energy with an expanded services product range and the opportunity to grow its customer base further in the US, offering rentals alongside heating, air conditioning, plumbing and electrical services across its growing franchise business. In the year we increased our number of franchise territories by 11% to 633.

The increase in accounts also reflects organic growth from developing our protection plan offering in the US, in part leveraging the acquisition of Home Warranty of America in 2012, and we now have over 100,000 whole-home warranty plans, up from 70,000 at the time of acquisition. Direct Energy Services also benefited from improved optimism in the economy, with a revival in new housing starts helping drive a 25% increase in sales in our residential new construction business.

Positioning the business for the future in a challenging external environment

Direct Energy has had a difficult start to 2014, and market conditions for our residential and business energy supply divisions look set to remain challenging. Although the Hess Energy Marketing business is performing well, Direct Energy has been impacted by a weaker US dollar, continued margin pressures and exceptionally cold weather, which had a significant impact across all suppliers in the US North East and resulted in additional system charges. As a result, we currently expect total Direct Energy operating profit to be broadly flat year-on-year.

Against this backdrop, improving cost competitiveness is a core priority and a cost reduction programme of $100 million is underway, as we deliver synergies from Direct Energy’s enhanced scale. We are already benefiting from the creation of an integrated residential energy operations centre in Tulsa and a consolidated energy and services call centre in Phoenix. We are also investing in a new residential energy billing platform for the Alberta market. And in Services, we are transitioning from eight separate operating systems to one, to help deliver simplified processes and operating efficiencies as well as to facilitate a more robust franchising platform.

In C&I, the integration of Hess Energy Marketing is proceeding well and on schedule. Our priority for 2014 is to fully integrate the teams, retaining key personnel and systems, and in turn deliver exceptional service levels and high levels of customer retention. In the first three full months of ownership, the business has delivered EBITDA in excess of our investment case, with the acquisition expected to be earnings accretive in 2014. Over time, the enhanced scale, dual fuel capabilities, advantaged positions along the gas value chain and long-term customer relationships delivered by the Hess acquisition will provide additional growth opportunities across the enlarged business.

Building a range of innovative product offerings is also core to our business model, improving customer retention and delivering growth. Our ‘Power To Go’ prepayment product and our innovative ‘Free Electricity Saturdays’ product have both proved popular with residential energy customers. The Bounce Energy acquisition is already delivering increased sales through digital channels, while we see scope for further growth through connected home propositions. We have a relationship with Nest in Canada and launched a bundled thermostat and energy offering in the first quarter of 2014. Additionally, we plan to launch a Direct Energy branded smart thermostat in 2014.

In services, our franchise model enables expansion for limited capital outlay, while we expect to see further growth in our protection plan offering in the United States. We also recently launched a small scale pilot of a new HVAC leasing proposition. Initial sales have been considerably ahead of our expectations, with customers willing to undertake a higher value of work when purchased through rental payments as opposed to upfront payment. Over time, we see significant potential for bundling of energy and services propositions to our residential customer base.

Total Direct Energy

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

For the year ended 31 December

Â

FY 2013

Â

FY 2012

Â

Δ%

Â

H2 2013

Â

H2 2012

Â

Δ%

Total residential energy and services accounts (period end) (’000)

Â

5,967

Â

5,856

Â

2

Â

5,967

Â

5,856

Â

2

Gross revenue (£m)

Â

7,325

Â

5,684

Â

29

Â

4,134

Â

2,921

Â

42

Operating profit (£m)

Â

276

Â

310

Â

(11)

Â

111

Â

155

Â

(28)

Operating profit after taxation (£m)

Â

189

Â

203

Â

(7)

Â

nm

Â

nm

Â

nm

Â

Residential energy supply

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

For the year ended 31 December

Â

FY 2013

Â

FY 2012

Â

Δ%

Â

H2 2013

Â

H2 2012

Â

Δ%

Customer accounts (period end) (’000)

3,360

3,455

(3)

3,360

3,455

(3)

Gross revenue (£m)

Â

2,517

Â

2,357

Â

7

Â

1,209

Â

1,147

Â

5

Operating profit (£m)

Â

163

Â

156

Â

4

Â

64

Â

55

Â

16

Operating profit after taxation (£m)

Â

111

Â

103

Â

8

Â

nm

Â

nm

Â

nm

Post-tax margin (%)

Â

4.4

Â

4.4

Â

0.0 ppts

Â

nm

Â

nm

Â

nm

Â

Business energy supply

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

For the year ended 31 December

Â

FY 2013

Â

FY 2012

Â

Δ%

Â

H2 2013

Â

H2 2012

Â

Δ%

Gas sales (mmth)

1,839

793

132

1,345

372

262

Electricity sales (GWh)

63,919

51,378

24

35,920

27,443

31

Gross revenue (£m)

Â

4,238

Â

2,795

Â

52

Â

2,629

Â

1,495

Â

76

Operating profit (£m)

Â

77

Â

121

Â

(36)

Â

24

Â

78

Â

(69)

Operating profit after taxation (£m)

Â

53

Â

78

Â

(32)

Â

nm

Â

nm

Â

nm

Post-tax margin (%)

Â

1.3

Â

2.8

Â

(1.5) ppts

Â

nm

Â

nm

Â

nm

Post-tax underlying margin (%)

Â

1.8

Â

2.8

Â

(1.0) ppts

Â

nm

Â

nm

Â

nm

FY 2013 post-tax underlying margin (%) excludes £25million (£36m pre-tax) relating to amortisation of customer intangibles and integration costs associated with the Hess Energy Marketing acquisition.

Residential and business services

For the year ended 31 December

Â

Â

Â

Â

Â

Â

Â

Â

FY 2013

Â

Â

Â

Â

Â

FY 2012

Â

Â

Â

Â

Â

Δ%

Â

Â

Â

Â

Â

H2 2013

Â

Â

Â

Â

Â

H2 2012

Â

Â

Â

Â

Â

Δ%

Contract relationships (period end) (’000)

Â

Â

Â

Â

Â

Â

Â

Â

2,608

Â

Â

Â

Â

Â

2,401

Â

Â

Â

Â

Â

9

Â

Â

Â

Â

Â

2,608

Â

Â

Â

Â

Â

2,401

Â

Â

Â

Â

Â

9

On demand and installation jobs (’000)

748

670

12

398

360

11

Gross revenue (£m)

Â

Â

Â

Â

Â

Â

Â

Â

570

Â

Â

Â

Â

Â

532

Â

Â

Â

Â

Â

7

Â

Â

Â

Â

Â

296

Â

Â

Â

Â

Â

279

Â

Â

Â

Â

Â

6

Operating profit (£m)

Â

Â

Â

Â

Â

Â

Â

Â

36

Â

Â

Â

Â

Â

33

Â

Â

Â

Â

Â

9

Â

Â

Â

Â

Â

23

Â

Â

Â

Â

Â

22

Â

Â

Â

Â

Â

5

Operating profit after taxation (£m)

Â

Â

Â

Â

Â

Â

Â

Â

25

Â

Â

Â

Â

Â

22

Â

Â

Â

Â

Â

14

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Post-tax margin (%)

Â

Â

Â

Â

Â

Â

Â

Â

4.4

Â

Â

Â

Â

Â

4.1

Â

Â

Â

Â

Â

0.3 ppts

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Direct Energy (with comparator year of 2012 restated to remove effect of foreign exchange movements)

For the year ended 31 December

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

FY 2013

Â

Â

Â

Â

Â

FY 2012

Â

Â

Â

Â

Â

Δ%

Â

Â

Â

Â

Â

H2 2013

Â

Â

Â

Â

Â

H2 2012

Â

Â

Â

Â

Â

Δ%

Revenue (£m)

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Residential energy supply

2,517

2,360

7

1,209

1,132

7

Business energy supply

4,238

2,989

42

2,629

1,594

65

Residential and business services

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

570

Â

Â

Â

Â

Â

534

Â

Â

Â

Â

Â

7

Â

Â

Â

Â

Â

296

Â

Â

Â

Â

Â

276

Â

Â

Â

Â

Â

7

Direct Energy revenue

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

7,325

Â

Â

Â

Â

Â

5,883

Â

Â

Â

Â

Â

25

Â

Â

Â

Â

Â

4,134

Â

Â

Â

Â

Â

3,002

Â

Â

Â

Â

Â

38

Operating profit (£m)

Residential energy supply

163

157

4

64

55

16

Business energy supply

77

121

(36)

24

77

(69)

Residential and business services

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

36

Â

Â

Â

Â

Â

33

Â

Â

Â

Â

Â

9

Â

Â

Â

Â

Â

23

Â

Â

Â

Â

Â

22

Â

Â

Â

Â

Â

5

Direct Energy operating profit

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

276

Â

Â

Â

Â

Â

311

Â

Â

Â

Â

Â

(11)

Â

Â

Â

Â

Â

111

Â

Â

Â

Â

Â

154

Â

Â

Â

Â

Â

(28)

2012 figures restated at 2013 weighted average exchange rate.

INTERNATIONAL UPSTREAM

CENTRICA ENERGY

Significant progress towards our refreshed strategic priorities

International Upstream performed well in 2013, with strong gas and oil production, the highest UK nuclear generation volumes for eight years and consistent operational performance from our gas-fired generation fleet. Under the leadership of Mark Hanafin we also made significant progress towards our refreshed strategic priority – to integrate our natural gas business, linked to our core markets – with a new international structure enabling us to maximise the potential of our core E&P regions of UK and Netherlands, Norway and Canada.

We have completed three key transactions: the North American LNG export agreement with Cheniere; the acquisition of a package of producing conventional gas and oil assets in the Western Canadian Sedimentary Basin from Suncor; and the acquisition of a 25% interest in the Bowland shale exploration license from Cuadrilla Resources and AJ Lucas. Overall we added 155 million barrels of oil equivalent (mmboe) of net proven and probable (2P) reserves in 2013, both organically – principally in Norway - and through acquisition, and we increased our 2C resource base by 28% to 771mmboe. However, we recognised £318 million of post-tax impairments, reflecting reserve and resource downgrades and increases in expected costs on certain Southern North Sea projects and a reduction in North American natural gas prices since previous asset acquisitions and developments. We also announced the divestments of selected North Sea E&P assets and of non-core UK wind assets for value, evidence of our commitment to maintaining capital discipline.

International Upstream operating profit increased by 6% to £1,326 million (2012: £1,251 million). Gas operating profit increased, reflecting higher production volumes following recent acquisitions and higher achieved prices, partially offset by a decrease in Power operating profit following the loss of free carbon allowances, and continued difficult trading conditions for gas-fired generation. Health and safety remains a core priority and we continued our focus on the effective management of major accident hazards through improved process safety training and reporting. We had no significant safety events in 2013, while the LTIFR fell to 0.10 (2012: 0.22).

Increased and more diverse gas and oil production

Total production of gas and liquids increased by 16% to 77.3mmboe (2012: 66.8mmboe). Total gas production volumes increased by 19% to 3,557 million therms (mmth) (2012: 2,990mmth) and total liquids volumes increased by 7% to 18.7mmboe (2012: 17.4mmboe). This predominantly reflects the benefit of a full year of production from the three acquisitions completed during 2012, and a part year of production from the package of Canadian conventional gas and crude oil assets acquired from Suncor in partnership with QPI, with production from new fields broadly offsetting the natural decline in our existing portfolio.

As a result of the recent acquisitions, we now have a more diverse geographical portfolio, with less reliance on Morecambe, and larger scale businesses in Norway and Canada. Norwegian production increased by 36% in 2013 and production from Canada increased by 28%, while production from the East Irish Sea contributed only 17% of total 2013 production, compared to 20% in 2012.

The assets acquired in 2012 have overall been producing better than our investment cases and initial production from the Canadian assets acquired from Suncor was ahead of our expectations in the fourth quarter of 2013, following completion of the transaction in late September. This C$987 million (£601 million) acquisition was made through a newly formed partnership owned by Centrica (60%) and QPI (40%), and was the first transaction made under the Memorandum of Understanding signed between the two parties in 2011. 100% of production and financial performance from the assets have been consolidated into the 2013 results. Centrica’s 60% share of 2P reserves from the assets as at the end of 2013 was 101 mmboe, which was higher than original expectations, and we are well placed to benefit from any upside in North American gas prices through the accelerated development of resources in the portfolio.

In 2013 we had a full year of production from our Ensign and Seven Seas fields, which came on-stream in 2012, and delivered first gas from our York and Rhyl fields in the first quarter of 2013. However, lower than expected production flow rates at Ensign, Seven Seas and York, combined with lower forward gas prices and updated information on resource potential and development costs, have caused significant reductions in the value of these assets, leading to post-tax impairments totalling £252 million.

In the case of Ensign, the lower flow rates have led to adverse revisions of the future reserves potential of producing wells and of additional wells to exploit the potential of the field. In the case of Seven Seas, lower flow rates have led to a downward revision in 2P reserves from the production well. In the case of York, production flow rates from a second well were below expectations and we also suspended drilling on a third well. This has led to an increase in expected capital expenditure, and adverse revisions to the future reserves potential of the two producing wells and of additional wells yet to be drilled.

In the second half of the year we announced the disposals of three packages of North Sea assets – a 13% non-operated stake in the Babbage field, a 50% operated interest in the Greater Kittiwake Area and a portfolio of assets in the Heimdal area in Norway – disposing of 2P reserves totalling 12mmboe for a combined consideration of £125 million, including contingent consideration. The Babbage and Heimdal disposals, totalling 8mmboe of reserves, were completed in late 2013, with the Greater Kittiwake disposal expected to complete in late February 2014. This is in line with our strategy to optimise the North Sea portfolio, investing selectively in assets around our existing hubs while managing costs, and looking to divest non-core assets for value. Taking into account these North Sea divestments and the full year impact of the Canadian acquisition, total gas and liquids production volumes are expected to increase to around 85mmboe in 2014, in line with previous guidance.

Adding value through reserve additions in our E&P portfolio

Centrica Energy added 155mmboe of 2P reserves in 2013, a net 99mmboe from acquisitions and disposals and 56mmboe from existing fields. This represents a total production replacement ratio of 201%, and 73% from organic sources.

In Norway, we recognised an additional 23mmboe of 2P reserves across our Kvitebjorn and Statfjord fields, reflecting strong performance from these assets and demonstrating the quality of our acquisitions in Norway. In Canada, incremental reserves of 7mmboe were recognised in the year from our existing portfolio, in addition to the reserves added following the Suncor acquisition. We have now undertaken a review of our larger Canadian portfolio and expect to increase our capital allocation to a number of attractive liquids-rich opportunities in the region, which we believe will drive longer term profit growth. However we recognised a post-tax impairment of £66 million on our existing gas assets in Canada, reflecting a weaker outlook for North American natural gas prices and an increase in the discount rate applicable to these assets.

We continued to make progress across our development portfolio. In addition to producing first gas from York and Rhyl in the first quarter of 2013, first production from Kew was delivered in January 2014, while we are currently drilling a fourth production well at York. We have now sanctioned a sidetrack well at Grove, which is expected to produce first gas later in 2014. The Statoil-operated Valemon project continues to proceed as planned, with first production expected towards the end of 2014, while the GDF-operated Cygnus project is progressing well and remains on track to bring 53mmboe of reserves into production around the end of 2015.

In the year, we recognised 21mmboe of 2P reserves at Butch in the Norwegian North Sea, which was discovered in 2011, and continue to work on a development plan for the project. We have now also commenced appraisal drilling on the adjacent Butch East well, which has the potential to add further to reserves. On our Block 22 project in Trinidad and Tobago we had drilling successes on two wells, helping to firm up our resource base in the region. We continue to review our development and partnership options for gas export.

In exploration, drilling at the Rodriguez well in Norway in January confirmed the presence of gas condensate, while drilling at Whitehaven in the East Irish Sea in February confirmed a satellite field adjacent to the Rhyl reservoir. In January 2014 we were awarded 10 further Norwegian licences through the ‘Awards in Predefined Areas’ (APA) process. In the UK, we were awarded 16 licences in the second tranche of the 27^th UK offshore oil and gas licencing round, in addition to the 6 licences awarded in 2012. Since the start of 2013, in line with our commitment to capital discipline, we have relinquished our interests in Bligh, Christian, Selkirk and Peik. Overall we have an attractive portfolio of exploration prospects and will focus our expenditure on the best prospects.

In June, we announced that we had acquired a 25% interest in the Bowland shale exploration license in Lancashire from Cuadrilla Resources and AJ Lucas for £44 million. This provides an attractive opportunity to explore the potential for natural gas from shale in the UK, while utilising our expertise as a responsible operator and developer of UK gas resources. We welcomed the Government’s announcements in July and December concerning tax allowances relating to shale gas, although much remains to be done to determine its commercial viability in the UK.

Develop our midstream business to integrate along the gas value chain

In March, we announced a 20 year agreement with Cheniere to purchase 91,250,000 million British thermal units (mmbtu) (89 billion cubic feet) per annum of liquefied natural gas (LNG) volumes for export from the Sabine Pass liquefaction plant in Louisiana in the United States. The project remains subject to regulatory approvals being achieved for the fifth train, including Federal Energy Regulatory Commission clearance. In early April the export licence application was filed with the US Department of Energy and the full Federal Energy Regulatory Commission application was filed in September 2013. The contract marks an important step in delivering our strategy, as we look to link our positions across the gas value chain and invest in new sources of gas on both sides of the Atlantic, where we see attractive opportunities.

In November, we announced that we had entered into a further supply agreement with Qatargas to purchase up to 3 million tonnes per annum of LNG for the UK from June 2014. This deal follows on from our existing agreement with Qatargas, and highlights Centrica’s status as an attractive counterparty, underpinning the UK’s access to the global LNG market amidst fierce demand from Asia and Latin America.

Higher gas and oil volumes and achieved prices more than offsetting higher costs

International gas operating profit increased by 23% to £1,155 million (2012: £940 million), reflecting higher production volumes and higher achieved prices. The average achieved gas sales price, including production from North America, increased by 10% to 53.7 pence per therm (p/th) (2012: 49.0p/th). This primarily reflects an increased achieved gas price in Europe of 65.0p/th (2012: 57.6p/th) due to a higher prevailing UK NBP gas price, only partially offset by a change in the production mix towards North America. The achieved gas price for North America and Trinidad and Tobago fell slightly to 20.9 p/th (2012: 23.2p/th). The average achieved oil and condensate price was broadly flat at £61.6 per boe (2012: £61.7/boe).

On a per unit of production basis, depletion, depreciation and amortisation (DDA) costs increased by 23% in the year to £11.4/boe (2012: £9.3/boe) with a shift in production mix towards more recently acquired and developed higher cost fields in Europe, partly offset by additional production from lower cost North American fields. Unit lifting and other cash production costs increased by 2% to £12.6/boe (2012: £12.4/boe), with the impact of industry-wide cost inflation being mostly offset by the impact of an increased proportion of lower cost North American production. Exploration and appraisal costs were £154 million (2012: £143 million), in part reflecting costs written down following licence relinquishments.

International gas operating profit after tax was £325 million (2012: £198 million) and the return on total capital employed was 8.3% (2012: 5.6%). The business generated free cash flow of £180 million, net of total capital expenditure and acquisitions of £1,449 million.

Strong performance from existing nuclear fleet; challenging market conditions for gas-fired generation

Output from the nuclear fleet was once again strong, with our 20 per cent equity share of the output increasing to 12.1 terawatt hours (TWh) (2012: 12.0TWh), the highest annual output since 2005. This reflects continued investment in the fleet, with no large unplanned outages occurring during the year, underlining the quality of our original investment in the British Energy fleet. The average achieved price for the year was £51.9 per megawatt hour (MWh) (2012: £49.6/MWh), reflecting the increase in the baseload power market price and the impact of hedging. An increase in revenue was only partly offset by additional depreciation and inflationary cost pressures, resulting in a 5% increase in nuclear operating profit, to £250 million (£237 million). In February we announced that we would not be exercising our option to participate in UK nuclear new build, taking into account increased costs and the lengthening time frame for a return on capital invested in a project of this scale.

The market environment remains challenging for gas-fired power generation, with continued low market clean spark spreads. The average gas-fired load factor increased to 27% (2012: 26%), although slightly lower capacity meant that generation volumes reduced to 8.9TWh (2012: 9.0TWh). Against this challenging environment, we continued to minimise costs, running the plants as efficiently as possible and thermal fleet reliability remained high at 97% (2012: 97%), enabling running at peak times. The gas-fired operating loss increased to £133 million (2012: £4 million loss), primarily reflecting the end of free carbon allowances.

Our gas-fired power stations at Barry, Brigg and Peterborough were all awarded contracts by the National Grid in March, as part of its Short Term Operating Reserve (STOR) market. All the contracts run until the end of the first quarter of 2015, with Brigg awarded a two-year contract, Peterborough awarded a ‘follow-on’ contract when its current arrangement finishes in 2014 and Barry awarded a one-year contract starting in April 2014.

Availability of our wind assets was 88% (2012: 88%), with generated volumes up 41% to 753 gigawatt hours (GWh) (2012: 533 GWh) and a load factor of 36% (2012: 32%), reflecting output from the Lincs wind farm, with all 75 turbines having been fully commissioned by September. In June, we sold our 50% interest in the Braes of Doune onshore wind farm to Hermes GPE Infrastructure fund for £59 million. In December, we were disappointed not to receive a letter of eligibility for transitional Feed in Tariffs for our Race Bank offshore wind project, and we sold our 100% interest in the project to DONG Energy Power (UK) Limited, for £50 million. The net impact of these two transactions was a £23 million profit on disposal. We retain a 50% interest in 4.2GW of potential capacity in Celtic Array, the Round 3 Irish Sea Zone, however we have impaired the carrying value of this project by £25 million in the year. Overall, renewables operating profit reduced to £25 million (2012: £56 million), predominantly reflecting lower net profit on disposal during the year and the Round 3 impairment.

Total Power profitability decreased by 45% to £171 million (2012: £311 million), with increased losses from our gas-fired fleet and lower renewables profit only partially offset by improved nuclear and Midstream profits. UK power operating profit after tax was £143 million (2012: £243 million) and the return on total capital employed was 3.8% (2012: 6.7%).

Positioning the business for the future

We made good strategic progress during 2013 and we will benefit in 2014 from a full year’s worth of production from the Canadian assets acquired from Suncor. However the E&P business is facing rising costs in the UK North Sea, while gas and oil prices have reduced from their peaks. As a result, we expect operating profit to reduce in 2014 compared to 2013, although with the move in production mix towards Canada, we expect post-tax profit to be broadly unchanged.

In this environment, while existing projects such as Cygnus and Valemon remain attractive opportunities and we have a number of potentially attractive future development options in Norway, we are likely to concentrate on only the very best North Sea investments, with North America potentially a more attractive region for investment. We have also established new processes for project stage-gate review and have reduced our rig commitments, to provide additional assurance and maximise project returns. Overall we expect to invest around £900 million per annum of capital expenditure in E&P projects over the next three years, with an increasing proportion of capital spend in North America. This is around 20% lower than previously expected levels, but will have limited impact on near-term production, which we expect to be in the range 80-85mmboe per annum. Our profile of committed investment gives us flexibility to consider acquisitions, if the economics are attractive and they are a good fit with our existing portfolio, while potentially divesting further non-core assets for value.

Market conditions look set to remain challenging for our gas-fired power stations with no sign of material recovery in 2014. We have sanctioned a further turbine blade upgrade at our 1.3GW South Humber CCGT power station, which will improve the efficiency of the plant and work is scheduled to commence on the project in the first half of 2014. In addition, we have consent for 1GW of new build CCGT on our existing site at Kings Lynn and are exploring the option to repower the existing plant. However continued political uncertainty is putting investment at risk, and any future investment decisions remain dependent on the economics of the projects and the successful introduction of the capacity market. On renewables, we retain interests in our joint venture portfolio of operating wind assets, with purchase agreements for both the power and the ROCs. Our focus will be on maximising value through operating our assets efficiently.

International gas		Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â
For the year ended 31 December		Â	FY 2013	Â	FY 2012	Â	Δ%	Â	H2 2013	Â	H2 2012	Â	Δ%
Gas production volumes (mmth)		Â		Â		Â		Â		Â		Â
Â	East Irish Sea		718		740		(3)		374		378		(1)
	Other UK and Netherlands		1,071		883		21		530		403		32
	Norway		828		557		49		392		381		3
	North America		701		549		28		449		270		66
Â	Trinidad & Tobago	Â	239	Â	261	Â	(8)	Â	116	Â	131	Â	(11)
Â	Total	Â	3,557	Â	2,990	Â	19	Â	1,861	Â	1,563	Â	19
Liquids production volumes (mmboe)
	UK and Netherlands		6.3		7.4		(15)		2.8		3.5		(20)
	Norway		11.0		8.9		24		5.2		5.9		(12)
Â	North America	Â	1.4	Â	1.1	Â	27	Â	0.9	Â	0.5	Â	80
Â	Total	Â	18.7	Â	17.4	Â	7	Â	8.9	Â	9.9	Â	(10)
Total production volumes (mmboe)		Â	77.3	Â	66.8	Â	16	Â	39.7	Â	35.9	Â	11
Average achieved gas price (p/therm)
	Europe		65.0		57.6		13		64.2		59.3		8
Â	North America and Trinidad & Tobago	Â	20.9	Â	23.2	Â	(10)	Â	21.2	Â	22.4	Â	(5)
Â	Total	Â	53.7	Â	49.0	Â	10	Â	51.8	Â	50.9	Â	2
Average oil and condensate sales price (£/boe)
	Europe		62.9		62.8		0		60.6		63.4		(4)
Â	North America and Trinidad & Tobago	Â	43.3	Â	45.5	Â	(5)	Â	41.3	Â	46.9	Â	(12)
Â	Total	Â	61.6	Â	61.7	Â	0	Â	58.8	Â	62.5	Â	(6)
DDA costs (£/boe)
	Europe		12.9		10.2		26		13.0		10.5		24
Â	North America and Trinidad & Tobago	Â	6.1	Â	6.2	Â	(2)	Â	5.5	Â	5.8	Â	(5)
Â	Total	Â	11.4	Â	9.3	Â	23	Â	11.0	Â	9.6	Â	15
Lifting and other cash production costs (£/boe)
	Europe		13.5		13.8		(2)		14.0		15.0		(7)
Â	North America and Trinidad & Tobago	Â	9.7	Â	7.4	Â	31	Â	10.4	Â	8.0	Â	30
Â	Total	Â	12.6	Â	12.4	Â	2	Â	13.0	Â	13.6	Â	(4)
Exploration & appraisal costs (£m)		Â	154	Â	143	Â	8	Â	107	Â	110	Â	(3)
Operating profit (£m)		Â	1,155	Â	940	Â	23	Â	472	Â	421	Â	12
Operating profit after taxation (£m)		Â	325	Â	198	Â	64	Â	nm	Â	nm	Â	nm
Return on total capital employed (%)		Â	8.3	Â	5.6	Â	2.7 ppts	Â	nm	Â	nm	Â	nm
Total net proven and probable reserves (mmboe)		Â	711	Â	633	Â	12	Â	nm	Â	nm	Â	nm
To align with a new organisational structure, the North American Upstream gas business is now reported in Centrica Energy. Prior year comparatives have been restated accordingly. Lifting and other cash production costs include all cash costs except exploration and appraisal costs and the impact of underlift / overlift. Prior year comparatives have been restated. Centrica's share of proven and probable reserves excludes Rough cushion gas of 30mmboe, and includes the 60% share of Canadian assets acquired from Suncor.

UK power
For the year ended 31 December	Â	FY 2013	Â	FY 2012	Â	Δ%	Â	H2 2013	Â	H2 2012	Â	Δ%
Power generated (GWh)	Â		Â		Â		Â		Â		Â
Gas-fired		8,897		8,952		(1)		4,366		4,046		8
Renewables		753		533		41		463		287		61
Nuclear	Â	12,097	Â	12,004	Â	1	Â	6,334	Â	6,050	Â	5
Total	Â	21,747	Â	21,489	Â	1	Â	11,163	Â	10,383	Â	8
Achieved Clean Spark Spread (£/MWh)		11.7		10.7		9		13.4		11.2		20
Achieved power price (including ROCs) (£/MWh) - renewables		114.5		105.7		8		120.9		111.3		9
Achieved power price (£/MWh) - nuclear	Â	51.9	Â	49.6	Â	5	Â	51.7	Â	49.8	Â	4
Operating profit / (loss) (£m)
Gas-fired		(133)		(4)		nm		(69)		0		nm
Renewables		25		56		(55)		(10)		11		nm
Nuclear		250		237		5		128		119		8
Midstream	Â	29	Â	22	Â	32	Â	3	Â	7	Â	(57)
Operating profit (£m)	Â	171	Â	311	Â	(45)	Â	52	Â	137	Â	(62)
Operating profit after taxation (£m)	Â	143	Â	243	Â	(41)	Â	nm	Â	nm	Â	nm
Return on total capital employed (%)	Â	3.8	Â	6.7	Â	(2.9) ppts	Â	nm	Â	nm	Â	nm
Midstream includes results from trading and from bilateral arrangements with third party owners of power generation assets in the UK and Europe.

CENTRICA STORAGE

Good operational performance in challenging market conditions

Centrica Storage performed well operationally in 2013, with strong reliability of 96% (2012: 92%) helping Rough make an important contribution to the UK’s security of supply during periods of sustained cold weather in the first four months of the year. However operating profit fell by 29%, reflecting narrowing summer/winter gas price differentials.

The Net Reservoir Volume (NRV) reached record low levels in April, as we experienced sustained customer withdrawals during the prolonged cold weather. As temperatures returned to more normal levels from mid-April, customers switched to injection, and the business delivered a record year in terms of gas volume injected. With warmer weather in November and December resulting in less withdrawal than usual towards the end of the year, the NRV ended the year above the five year average.

Health and safety remains a core priority and Centrica Storage continues to progress its process safety programme. We experienced no further lost time incidents (LTIs) in the year, after recording our first LTI in over three years in March.

Narrow forward seasonal spreads creating commercial headwinds

In April, Centrica Storage announced that it had sold all SBUs for the 2013/14 storage year at an average price of 23.3p (2012/13: 33.9p), reflecting low summer/winter gas price differentials over the course of 2012 and 2013. Forward 2014/15 market spreads remain narrower still.

The narrow summer/winter spreads also provide a challenging background for new projects. In light of the weak economics for storage projects, and the UK Government’s decision to rule out incentivisation for additional gas storage capacity to be built, Centrica decided not to proceed with its offshore Baird project and put its project at Caythorpe on hold indefinitely. As a result, a post-tax exceptional charge of £224 million was recognised in the year, relating to impairments and provisions for these projects.

Reduced year-on-year operating profit

Gross revenue fell 7% to £188 million (2012: £202 million). This reflected a lower calendar year SBU price of 26.7p (2012: 31.0p) and lower optimisation revenue, only partially offset by revenue generated from the York gas processing terminal, which was commissioned early in the year. Operating profit decreased by 29% to £63 million (2012: £89 million), primarily reflecting the decrease in revenue, additional fuel costs from the high levels of injection during the year and costs associated with the York terminal.

With forward spreads even lower, Centrica Storage profitability is likely to be only around break-even in 2014. Against this backdrop we will continue our focus on safety, and further capital investment will be limited. We have also now launched a three year programme to deliver £15 million of cost reductions through operational improvements.

Centrica Storage

For the year ended 31 December

Â

Â

Â

Â

Â

FY 2013

Â

Â

Â

Â

Â

FY 2012

Â

Â

Â

Â

Â

Δ%

Â

Â

Â

Â

Â

H2 2013

Â

Â

Â

Â

Â

H2 2012

Â

Â

Â

Â

Â

Δ%

Average SBU price (in period) (pence)

Â

Â

Â

Â

Â

26.7

Â

Â

Â

Â

Â

31.0

Â

Â

Â

Â

Â

(14)

Â

Â

Â

Â

Â

23.3

Â

Â

Â

Â

Â

33.9

Â

Â

Â

Â

Â

(31)

Gross Revenue (£m)

Â

Standard SBUs

121

141

(14)

52

77

(32)

Â

Optimisation / other

Â

Â

Â

Â

Â

67

Â

Â

Â

Â

Â

61

Â

Â

Â

Â

Â

10

Â

Â

Â

Â

Â

29

Â

Â

Â

Â

Â

34

Â

Â

Â

Â

Â

(15)

Â

Total

Â

Â

Â

Â

Â

188

Â

Â

Â

Â

Â

202

Â

Â

Â

Â

Â

(7)

Â

Â

Â

Â

Â

81

Â

Â

Â

Â

Â

111

Â

Â

Â

Â

Â

(27)

Operating profit (£m)

Â

Â

Â

Â

Â

63

Â

Â

Â

Â

Â

89

Â

Â

Â

Â

Â

(29)

Â

Â

Â

Â

Â

16

Â

Â

Â

Â

Â

53

Â

Â

Â

Â

Â

(70)

Operating profit after taxation (£m)

Â

Â

Â

Â

Â

48

Â

Â

Â

Â

Â

67

Â

Â

Â

Â

Â

(28)

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Return on total capital employed (%)

Â

Â

Â

Â

Â

11.0

Â

Â

Â

Â

Â

13.0

Â

Â

Â

Â

Â

(2.0) ppts

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

Â

Â

Â

Â

Â

nm

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 Strategic Report 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	Â	NICK LUFF
Chief Executive		Group Finance Director

Group Income Statement

Â

Â

Â

Â

2013

Â

Â

Â

2012 (restated) (i)

Year ended 31 December

Â

Notes

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Results for the year £m

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Results for the year £m

Â

Group revenue

5(b)

26,571

Â

–

Â

26,571

Â

23,942

Â

–

Â

23,942

Cost of sales before exceptional items and certain re-measurements (i)

(21,464)

–

(21,464)

(18,840)

–

(18,840)

Exceptional items

6

–

(125)

(125)

–

(89)

(89)

Re-measurement of energy contracts

6

–

Â

413

Â

413

–

Â

603

Â

603

Cost of sales

Â

Â

Â

(21,464)

Â

288

Â

(21,176)

Â

(18,840)

Â

514

Â

(18,326)

Gross profit

5,107

Â

288

Â

5,395

Â

5,102

Â

514

Â

5,616

Operating costs before exceptional items (i)

(2,735)

–

(2,735)

(2,680)

–

(2,680)

Exceptional items

6

–

Â

(939)

Â

(939)

–

Â

(445)

Â

(445)

Operating costs

(2,735)

(939)

(3,674)

(2,680)

(445)

(3,125)

Share of profits/(losses) in joint ventures and associates, net of interest and taxation

Â

6, 12

Â

146

Â

25

Â

171

Â

140

Â

(6)

Â

134

Group operating profit

5(c)

2,518

Â

(626)

Â

1,892

2,562

Â

63

Â

2,625

Financing costs (i)

7

(297)

–

(297)

(271)

–

(271)

Investment income (i)

7

54

Â

–

Â

54

62

Â

–

Â

62

Net finance cost

Â

Â

Â

(243)

Â

–

Â

(243)

Â

(209)

Â

–

Â

(209)

Profit before taxation

2,275

(626)

1,649

2,353

63

2,416

Taxation on profit (i)

Â

6, 8

Â

(942)

Â

243

Â

(699)

Â

(1,031)

Â

(140)

Â

(1,171)

Profit for the year

Â

Â

Â

1,333

Â

(383)

Â

950

Â

1,322

Â

(77)

Â

1,245

Attributable to:

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Owners of the parent

Â

Â

Â

1,333

Â

(383)

Â

950

Â

1,322

Â

(77)

Â

1,245

Â

Earnings per ordinary share

Â

Â

Â

Pence

Pence

Basic (i)

10

18.4

24.0

Diluted (i)

10

18.3

23.9

Interim dividend paid per ordinary share

9

4.92

4.62

Final dividend proposed per ordinary share

Â

9

Â

Â

Â

Â

Â

12.08

11.78

(i) See note 1(a).

The notes on pages 36 to 72 form part of these Financial Statements.

Group Statement of Comprehensive Income

Year ended 31 December	Â	Notes	Â	2013 £m	Â	2012 (restated) (i) £m
Profit for the year (i)	Â		Â	950	Â	1,245
Other comprehensive income/(loss):
Items that will be or have been recycled to the Group Income Statement:
Gains on revaluation of available-for-sale securities, net of taxation				3		5
				Â	Â	Â
Net losses on cash flow hedges				(25)		(27)
Transferred to income and expense on cash flow hedges				34		108
Taxation on cash flow hedges				(1)	Â	(20)
				8		61
Exchange differences on translation of foreign operations				(217)		(44)
Share of other comprehensive income/(loss) of joint ventures and associates, net of taxation				18	Â	(12)
				(188)		10
Items that will not be recycled to the Group Income Statement:				Â	Â	Â
Net actuarial losses on defined benefit pension schemes (i)				(179)		(293)
Taxation on net actuarial losses on defined benefit pension schemes (i)				31	Â	71
				(148)		(222)
Reversal of revaluation reserve, net of taxation and exchange differences				(17)		–
Share of other comprehensive (loss)/income of joint ventures and associates, net of taxation	Â	Â	Â	(15)	Â	44
Other comprehensive loss net of taxation	Â	Â	Â	(368)	Â	(168)
Total comprehensive income for the year	Â	Â	Â	582	Â	1,077
Attributable to:
Owners of the parent				590		1,077
Non-controlling interests	Â	Â	Â	(8)	Â	–
(i) See note 1(a).

Group Statement of Changes in Equity

Â

Â

Share capital £m

Â

Share premium £m

Â

Retained earnings £m

Â

Other equity £m

Â

Total £m

Â

Non-controlling interests £m

Â

Total equity £m

Â

1 January 2012 (as previously reported)

Â

319

Â

874

Â

4,043

Â

364

Â

5,600

Â

–

Â

5,600

Effect of adoption of IAS 19 (revised 2011) (i)

Â

–

Â

–

Â

(297)

Â

297

Â

–

Â

–

Â

–

1 January 2012 (restated)

319

874

3,746

661

5,600

–

5,600

Total comprehensive income (i)

–

–

1,245

(168)

1,077

–

1,077

Employee share schemes

2

55

11

(2)

66

–

66

Dividends

–

–

(816)

–

(816)

–

(816)

Taxation

–

–

–

(1)

(1)

–

(1)

Exchange adjustments

Â

–

Â

–

Â

–

Â

1

Â

1

Â

–

Â

1

31 December 2012 (restated)

Â

321

Â

929

Â

4,186

Â

491

Â

5,927

Â

–

Â

5,927

Total comprehensive income

–

–

950

(360)

590

(8)

582

Employee share schemes

–

2

(15)

70

57

–

57

Purchase of treasury shares

–

–

(2)

(500)

(502)

–

(502)

Amounts arising on acquisition (see note 15)

–

–

–

–

–

81

81

Distribution paid to non-controlling interests

–

–

–

–

–

(8)

(8)

Dividends paid to equity holders

–

–

(864)

–

(864)

–

(864)

Taxation on share based payments

Â

–

Â

–

Â

–

Â

(16)

Â

(16)

Â

–

Â

(16)

31 December 2013

Â

321

Â

931

Â

4,255

Â

(315)

Â

5,192

Â

65

Â

5,257

(i) See note 1(a).

The notes on pages 36 to 72 form part of these Financial Statements.

Group Balance Sheet

31 December	Â	Notes	Â	2013 £m	Â	2012 (restated) (i) £m
Non-current assets	Â		Â		Â
Property, plant and equipment				7,446		7,965
Interests in joint ventures and associates		12		2,658		2,721
Other intangible assets				1,905		1,579
Goodwill				2,819		2,543
Deferred tax assets				105		183
Trade and other receivables				150		55
Derivative financial instruments		13		227		313
Retirement benefit assets		14		205		254
Securities	Â	11(b)	Â	202	Â	199
Â	Â	Â	Â	15,717	Â	15,812
Current assets
Trade and other receivables				5,446		4,335
Inventories				530		545
Derivative financial instruments		13		573		268
Current tax assets				151		54
Securities		11(b)		9		7
Cash and cash equivalents	Â	11(b)	Â	719	Â	931
Â	Â	Â	Â	7,428	Â	6,140
Assets of disposal groups classified as held for sale	Â	15	Â	301	Â	–
Total assets	Â	Â	Â	23,446	Â	21,952
Current liabilities
Derivative financial instruments		13		(506)		(615)
Trade and other payables				(5,630)		(4,545)
Current tax liabilities				(645)		(594)
Provisions for other liabilities and charges				(258)		(266)
Bank overdrafts, loans and other borrowings (i)	Â	11(c)	Â	(859)	Â	(566)
Â	Â	Â	Â	(7,898)	Â	(6,586)
Net current liabilities	Â	Â	Â	(470)	Â	(446)
Non-current liabilities
Deferred tax liabilities				(1,426)		(1,678)
Derivative financial instruments		13		(431)		(327)
Trade and other payables				(64)		(26)
Provisions for other liabilities and charges				(2,934)		(2,480)
Retirement benefit obligations		14		(165)		(166)
Bank overdrafts, loans and other borrowings (i)	Â	11(c)	Â	(5,172)	Â	(4,762)
Â	Â	Â	Â	(10,192)	Â	(9,439)
Liabilities of disposal groups classified as held for sale	Â	15	Â	(99)	Â	–
Net assets	Â	Â	Â	5,257	Â	5,927
Share capital				321		321
Share premium				931		929
Retained earnings (i)				4,255		4,186
Other equity (i)	Â	Â	Â	(315)	Â	491
Total shareholders’ equity	Â	Â	Â	5,192	Â	5,927
Non-controlling interests	Â	Â	Â	65	Â	–
Total non-controlling interests and shareholders’ equity	Â	Â	Â	5,257	Â	5,927
(i) See note 1(a).

The Financial Statements on pages 32 to 72, of which the notes on pages 36 to 72 form part, were approved and authorised for issue by the Board of Directors on 20 February 2014 and were signed below on its behalf by:

SAM LAIDLAW	Â	NICK LUFF
Chief Executive		Group Finance Director

Group Cash Flow Statement

Year ended 31 December	Â	Notes	Â	2013 £m	Â	2012 £m
Group operating profit including share of results of joint ventures and associates	Â		Â	1,892	Â	2,625
Less share of profit of joint ventures and associates	Â	Â	Â	(171)	Â	(134)
Group operating profit before share of results of joint ventures and associates				1,721		2,491
Add back/(deduct):
Depreciation, amortisation, write-down and impairments				2,319		1,507
Profit on disposals				(21)		(38)
Increase in provisions				162		201
Defined benefit pension service cost and contributions				(87)		(52)
Employee share scheme costs				43		43
Unrealised gains arising from re-measurement of energy contracts	Â	Â	Â	(400)	Â	(610)
Operating cash flows before movements in working capital				3,737		3,542
Decrease/(increase) in inventories				78		(88)
Increase in trade and other receivables (i)				(456)		(205)
Increase in trade and other payables (i)	Â	Â	Â	697	Â	361
Operating cash flows before payments relating to taxes, interest and exceptional charges				4,056		3,610
Taxes paid				(892)		(524)
Payments relating to exceptional charges	Â	Â	Â	(224)	Â	(266)
Net cash flow from operating activities	Â	Â	Â	2,940	Â	2,820
Purchase of businesses				(1,115)		(155)
Sale of businesses				140		30
Purchase of intangible assets and property, plant and equipment		5(f)		(1,615)		(2,367)
Sale of property, plant and equipment and intangible assets		Â		17		14
Investments in joint ventures and associates				(51)		(291)
Dividends received from joint ventures and associates		12(c)		193		110
Repayments of loans to, and disposal of investments in, joint ventures and associates				59		42
Interest received				29		33
(Purchase)/sale of securities	Â	11(b)	Â	(8)	Â	26
Net cash flow from investing activities	Â	Â	Â	(2,351)	Â	(2,558)
Issue and surrender of ordinary share capital for share awards				20		24
Purchase of treasury shares under share repurchase programme				(502)		–
Distribution paid to non-controlling interests				(8)		–
Financing interest paid				(248)		(215)
Repayment of borrowings		11(b)		(400)		(516)
Cash received from borrowings		11(b)		1,209		1,712
Equity dividends paid	Â	Â	Â	(862)	Â	(815)
Net cash flow from financing activities		Â		(791)		190
Net (decrease)/increase in cash and cash equivalents				(202)		452
Cash and cash equivalents at 1 January				931		479
Effect of foreign exchange rate changes	Â	Â	Â	(10)	Â	–
Cash and cash equivalents at 31 December	Â	Â	Â	719	Â	931
Included in the following line of the Group Balance Sheet:
Cash and cash equivalents	Â	11(b)	Â	719	Â	931
(i) Includes net inflow of £82 million of cash collateral in 2013 (2012: £114 million).

The notes on pages 36 to 72 form part of these Financial Statements.

Notes to the Financial Statements

1. GENERAL INFORMATION, BASIS OF PREPARATION AND SUMMARY OF SIGNIFICANT NEW ACCOUNTING POLICIES AND REPORTING CHANGES

This section details new accounting standards, amendments and interpretations, whether these are effective in 2013 or later years, and if and how these are expected to impact the financial position and performance of the Group.

General Information

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 2013 included in this announcement were authorised for issue in accordance with a resolution of the Board of Directors on 20 February 2014.

The preliminary results of the year ended 31 December 2013 have been extracted from audited accounts (with the exception of notes 19 to 23 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 2013 or 31 December 2012. The financial information for the year ended 31 December 2012 is derived from the statutory accounts for that year. The report of the auditors on the statutory accounts for the year ended 31 December 2013 was unqualified and did not contain a statement under Section 498 of the Companies Act 2006.

Basis of preparation

The accounting policies applied in these condensed Financial Statements for the year ended 31 December 2013 are consistent with those of the annual Financial Statements for the year ended 31 December 2012, as described in those Financial Statements, with the exception of standards, amendments and interpretations effective in 2013 and other presentational changes.

(a) Standards, amendments, and interpretations effective or adopted in 2013 and other reporting changes

(i) IAS 19 (revised)

IAS 19 (revised): ‘Employee benefits’ amends the accounting for employee benefits. The Group has applied the standard retrospectively in accordance with the transition provisions and the comparatives have been restated accordingly.

The impact on the Group’s financial statements has been as follows:

• The standard replaces the interest cost on the defined benefit obligation and the expected return on plan assets with a net interest cost, based on the net defined benefit asset or liability and the discount rate, measured at the beginning of the year. This has increased the Income Statement charge with an equal and offsetting movement in other comprehensive income (actuarial gains and losses).
• Investment income has been reduced by £46 million for the year ended 31 December 2013, and reduced by £26 million for the year ended 31 December 2012.
• Profit after tax has been reduced by £51 million for year ended 31 December 2013, and reduced by £28 million for the year ended 31 December 2012.
• As at 1 January 2012 and 1 January 2013, retained earnings have been reduced by £297 million and £325 million respectively. The actuarial gains and losses reserve increased by the same amounts to reflect the retrospective application.
• Basic and diluted earnings per share (EPS) have been reduced by 1.0 pence for the year ended 31 December 2013. For the year ended 31 December 2012 the effect was a reduction of 0.6 pence on basic EPS and 0.5 pence on diluted EPS. The effect on adjusted basic EPS and adjusted diluted EPS was to reduce EPS by 1.0 pence for the year ended 31 December 2013. For the year ended 31 December 2012 the effect was a reduction of 0.5 pence on adjusted basic EPS and 0.6 pence on adjusted diluted EPS.

(ii) Amendment to IAS 1

Amendment to IAS 1: ‘Presentation of financial statements – Presentation of items of other comprehensive income’. The Group has applied this amendment retrospectively and the comparatives have been re-presented accordingly. Within the Group Statement of Comprehensive Income, items are now separated into ‘Items that will be or have been recycled to the Group Income Statement’ and ‘Items that will not be recycled to the Group Income Statement’.

(iii) IFRS 10

IFRS 10: ‘Consolidated financial statements’, builds on the existing principle of control as the determining factor in whether an entity should be included within the consolidated financial statements. The enhanced concept of control requires the identification of the relevant activities of the investee, and provides guidance to assist in the determination of these activities. If an investor has power over the relevant activities and the ability to use its power to affect returns, it is deemed to control, and therefore must consolidate, the investee. The standard is not mandatory for adoption by the Group until 1 January 2014, however it has been early adopted as of 1 January 2013. The change in accounting policy has had no material impact on the Group Balance Sheet, Group Income Statement, Group Statement of Comprehensive Income, Group Cash Flow Statement and Earnings Per Share for investments owned by the Group at the date of initial application of the standard or for the comparative period. However, the Suncor Upstream acquisition, as described in note 15 was conducted through a legal partnership (CQ Energy Canada Partnership) with Qatar Petroleum International. This partnership has been fully consolidated in accordance with IFRS 10 and is described in more detail in the critical accounting judgements in note 3.

(iv) IFRS 11

IFRS 11: ‘Joint arrangements’, focuses on the rights and obligations of the parties to the arrangement rather than its legal form. Under the new standard, there are two types of joint arrangement: joint operations and joint ventures. A joint operation arises where the investors have rights to the assets and obligations for the liabilities of an arrangement. A joint operator recognises its share of the assets, liabilities, revenue and expenses for the operation. A joint venture arises where the investors have rights to the net assets of the arrangement. A joint venture partner equity accounts for its share of net assets. The application of the standard is not mandatory for the Group until 1 January 2014, however it has decided to early adopt it as of 1 January 2013. The change in accounting policy has had no material impact on the Group Balance sheet, Group Income Statement, Group Statement of Comprehensive Income, Group Cash Flow Statement and Earnings per Share for existing investments held by the Group at the date of initial application of the standard, or for the comparative period.

(v) IFRS 12

IFRS 12: ‘Disclosures of interests in other entities’ includes the disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, structured entities and other off Balance Sheet vehicles. The standard is not mandatory for the Group until 1 January 2014, however it has decided to early adopt as of 1 January 2013. The change in accounting policy has had no material impact on the Group Balance Sheet, Group Income Statement, Group Statement of Comprehensive Income, Group Cash Flow Statement and Earnings Per Share as it relates to disclosures matters only.

(vi) IFRS 13

IFRS 13: ‘Fair value measurement’, aims to provide a single source of fair value measurement and disclosure requirements for use across the IFRS framework. The requirements do not extend the use of fair value accounting but provide guidance on application where use is required or permitted by other IFRSs. The change in accounting policy has had no material impact on the Group Balance Sheet, Group Income Statement, Group Statement of Comprehensive Income, Group Cash Flow Statement and Earnings Per Share.

(vii) Other presentational changes

Presentation of sales commissions and prepayment customer vending fees

Where there is a specific link to revenue generation, the Group has reclassified sales commissions paid to brokers or agents (or similar arrangements) and prepayment customer vending fees, from operating costs to cost of sales. The effect of this change has been to reduce operating costs and increase cost of sales by £171 million for the year ended 31 December 2013, and by £164 million for the year ended 31 December 2012. The prior period comparatives have been restated accordingly.

Current/non-current classification of interest accruals

The Group has reclassified the interest accruals on bank overdrafts, loans and other borrowings from non-current liabilities to current liabilities because the amounts are due for payment within 12 months. The effect of this change has been to increase current liabilities and reduce non-current liabilities by £102 million as at 31 December 2013, by £94 million as at 31 December 2012 and by £65 million as at 31 December 2011. The prior period comparatives have been restated accordingly.

Presentation of gains and losses on revaluations in financing costs

The Group has re-presented fair value gains and losses on its derivatives and hedges on a net basis within financing costs because it aids comparability with prior periods. Historically, such gains and losses were recognised gross within financing costs and investment income. The effect has been to reduce financing costs and reduce investment income by £346 million for the year ended 31 December 2013, and by £166 million for the year ended 31 December 2012. The prior period comparatives have been restated accordingly.

(b) Standards, amendments and interpretations that are issued but not yet applied by the Group

The only issued standard not yet applied by the Group which could have an effect on future Financial Statements is IFRS 9: ‘Financial Instruments’. The mandatory effective date of this standard has not yet been determined by the IASB, however the Group are continuing to assess the impact that it may have.

There are no issued amendments or interpretations that have not yet been applied by the group.

2. CENTRICA SPECIFIC ACCOUNTING MEASURES

This section sets out the Group’s specific accounting measures applied in the preparation of the Financial Statements. These measures enable the users of the accounts to understand the Group’s underlying and statutory business performance separately.

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 the Strategic Investments acquired in 2009;

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. Note 5 also details an analysis of adjusted operating profit after taxation by segment and a reconciliation to statutory profit for the year. Adjusted operating profit after taxation is defined as segment operating profit after tax, before exceptional items, certain re-measurements and impact of fair value uplifts from the Strategic Investments acquired in 2009. This includes the operating results of equity-accounted interests, net of associated taxation, before interest and associated taxation.

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 acquired in 2009, 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 Centrica Energy – Gas segment and the acquisition of the 20% interest in Lake Acquisitions Limited (British Energy), which owns the former British Energy Group nuclear power station fleet, the results of which are included within the Centrica Energy – 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 after taxation.

(ii) British Energy

The 20% interest in British Energy is accounted for as an investment in an associate using the equity method. 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 for the year. The impact of unwinding the acquisition-date fair values attributable to the acquired energy procurement and energy 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 Group Income Statement.

The Group is an integrated energy business. This means that it utilises its knowledge and experience across the gas and power (and related commodity) value chains to make profits across the core markets in which it operates. As part of this strategy, the Group enters into a number of forward energy trades to protect and optimise the value of its underlying production, generation, storage and transportation assets (and similar capacity or off-take contracts), as well as to meet the future needs of our customers (downstream demand). These trades are designed to reduce the risk of holding such assets, contracts or downstream demand and are subject to strict risk limits and controls.

Primarily because some of these trades include terms that permit net settlement (ie they are prohibited from being designated as ‘own use’), the rules within IAS 39: ‘Financial instruments’ require them to be individually fair valued. Fair value movements on these commodity derivative trades do not reflect the underlying performance of the business because they are economically related to our upstream assets, capacity/off-take contracts or downstream demand, which are typically not fair valued. Therefore, these certain re-measurements are reported separately and are subsequently reflected in business performance when the underlying transaction or asset impacts profit or loss.

The arrangements discussed above and reflected as certain re-measurements are all managed separately from proprietary energy trading activities where trades are entered into speculatively for the purpose of making profits in their own right. These proprietary trades are included in the business performance column (ie in the results before certain re-measurements).

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/impairments.

3. CRITICAL ACCOUNTING JUDGEMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

This section sets out the key areas of judgement and estimation that have the most significant effect on the amounts recognised in the Financial Statements.

(a) Critical judgements in applying the Group’s accounting policies

Such key judgements include the following:

• the presentation of selected items as exceptional, see notes 2 and 6;
• the use of adjusted profit and adjusted earnings per share measures, see notes 2, 5 and 10; and
• the classification of energy procurement contracts as derivative financial instruments and presentation as certain re-measurements, see notes 2, 6 and 13.

In addition, management has made the following key judgements in applying the Group’s accounting policies that have the most significant effect on the Group’s Financial Statements:

Wind farm disposals

In recent years, the Group has partially disposed of some of its wind farm companies by selling 50% of the equity voting capital (and 50% of the shareholder loans where relevant) in, for example, GLID Wind Farms TopCo Limited, Lincs Wind Farm Limited and Celtic Array Limited (Round 3).

Associated with certain of these disposals, the Group contracted to purchase a large percentage of the output produced by the wind farms under arm’s length, 15-year offtake agreements. The Group also contracted to provide management, operational and transitional support services to these companies as directed by their boards (and shareholders). Shareholders’ agreements were put in place which include a number of reserved matters and provide for joint management of the major decisions of the companies. Accordingly, the Directors have judged that the partial disposals of equity interests constituted a loss of control as the Group was no longer able to exercise control over the relevant activities or operating and financial policies of these companies. Therefore, the remaining investments are equity accounted as investments in joint ventures (see note 12) in accordance with IFRS 11: ‘Joint arrangements’ and IAS 28 (Revised (2011)): ‘Investments in joint ventures and associates’.

The Directors have also judged that the 15-year offtake agreements are not leasing arrangements. This is because the Group is not purchasing substantially all of the economic output of the wind farms. These contracts are considered to be outside the scope of IAS 39 apart from the embedded derivatives arising from the pricing terms which are marked to market separately.

The profits and losses arising on the disposal of the equity interests in Braes of Doune Wind farm (Scotland) Limited and Centrica (RBW) Limited respectively are recognised within this year’s ‘business performance’ column of the Income Statement as part of the ‘Centrica Energy – Power’ segment. See note 15 for further details of the disposals. In the prior period the profit on the partial disposal of the Celtic Array Limited (Round 3) was also recognised in the ‘business performance’ column. This is in line with the Group’s established wind farm strategy to realise value, share risk and reduce our capital requirements as individual projects develop, which may involve bringing in partners at an appropriate stage or full disposal.

Leases – third-party power station tolling arrangements

The Group has two long-term power station tolling contracts considered to be leases: (i) Spalding in the UK and (ii) Rijnmond in the Netherlands. The arrangements provide Centrica with the right to nominate 100% of the plant capacity for the duration of the contracts in return for a mix of capacity payments and operating payments based on plant availability.

The Spalding contract runs until 2021 and Centrica holds an option to extend the tolling arrangement for a further eight years, exercisable by 30 September 2020. If extended, Centrica is granted an option to purchase the station at the end of this further period. The Directors have determined that the arrangement should be accounted for as a finance lease as the lease term is judged to be substantially all of the economic life of the power station and the present value of the minimum lease payments at inception date of the arrangement amounted to substantially all of the fair value of the power station at that time.

The Rijnmond contract runs until 2030 and Centrica does not have the right to extend the agreement or any option to purchase the plant. The Directors have determined that the arrangement should be accounted for as an operating lease as the lease term is not judged to be substantially all of the economic life of the power station and the present value of the minimum lease payments at the inception date of the arrangement did not amount to substantially all of the fair value of the power station at that time. Details of the operating lease disclosures are included in note 16.

Business combinations and asset acquisitions

Business combinations and acquisitions of associates and joint ventures require a fair value exercise to be undertaken to allocate the purchase price (cost) to the fair value of the acquired identifiable assets, liabilities, contingent liabilities and goodwill.

As a result of the nature of fair value assessments in the energy industry this purchase price allocation exercise requires subjective judgements based on a wide range of complex variables at a point in time. Management uses all available information to make the fair value determinations.

During the year the Group has made two major acquisitions – Suncor Upstream and Hess Energy Marketing LLC. Both of these acquisitions have been accounted for as business combinations as set out in note 15.

For Suncor Upstream, the key areas of judgement revolved around the value of the oil and gas assets classified as property, plant and equipment and the decommissioning provisions. A large proportion of the consideration is allocated to this property, plant and equipment and a discounted projected cash flow exercise was undertaken based on forecast future commodity prices, expected production profiles, assessed levels of reserves/resources, expected costs and appropriate discount rates to determine fair value. Similarly, the decommissioning provision required an estimation of the costs of site rehabilitation based on known technology at the date of acquisition and an appropriate discount rate.

For Hess Energy Marketing LLC, the key areas of judgement were the value of customer relationships and derivatives. Customer relationships are based on anticipated retention rates as well as expected margins for the customer extensions based on unit margins for gas and power (these variables being key inputs for modelling purposes). Customer relationship valuations have inherent risks as they are based on estimates in respect of (i) customer performance, (ii) future margin rates and (iii) future renewal rates (customer churn). The purchase accounting valuation exercise was also materially impacted by exchange traded and over-the-counter (OTC) derivative fair values (ie swaps, futures, options, etc.) as these represent a fairly significant element of the identifiable net assets acquired. The value of these instruments is based on forward market curves derived from both liquid market data and internal predictions of future prices.

In the prior year the Group acquired interests in a number of Norwegian producing and development oil and gas assets. The Group determined that these acquisitions took the form of asset purchases rather than business combinations as they constituted the purchase of jointly controlled assets (referred to as ‘joint operations’ under IFRS 11) governed by joint operating agreements and as such do not give the Group control of the businesses.

Consolidation of the CQ Energy Canada Partnership

The Suncor Upstream acquisition involved the formation of the CQ Energy Canada Partnership (CQECP) to acquire Suncor Energy’s North American oil and gas assets. CQECP is owned and funded by the Group and Qatar Petroleum International (QPI) on a 60:40 basis. The partnership provides the Group with the ability to control the business plan and budgets and consequently the general operation of the assets. Accordingly, this arrangement has been assessed under IFRS 10 and the conclusion has been reached that the Group has power over the relevant activities of CQECP. Consequently this entity has been fully consolidated into the Group’s financial statements and QPI’s ownership share is represented as a non-controlling interest. Further details of the acquisition are provided in note 15.

Energy Company Obligation

The Energy Company Obligation (ECO) order requires UK-licensed energy suppliers to improve the energy efficiency of domestic households from 1 January 2013. Targets are set in proportion to the size of historic customer bases and must be delivered by 31 March 2015. The Group continues to judge that it is not legally obligated by this order until 31 March 2015. Accordingly, the costs of delivery are recognised as incurred, when cash is spent or unilateral commitments made resulting in obligations that cannot be avoided.

During the year, the Group has entered into a number of contractual arrangements and commitments, and issued a public statement to underline its commitment to deliver a specific proportion of the ECO requirements. Consequently, the Group’s result includes the costs of these contractual arrangements and commitment obligations.

The Government has recently announced a likely extension to the ECO delivery period up to 2017 with other potential changes to the obligations. Further legislation is expected in 2014 and the Group will judge the impact when more details become available.

Metering contracts

The Department of Energy and Climate Change (DECC) has modified the UK gas and electricity supply licences requiring all domestic premises to be fitted with compliant smart meters for measuring energy consumption by 31 December 2020. The Group has a number of existing rental contracts for non-compliant meters that include penalty charges if these meters are removed from use before the end of their deemed useful lives. The Group considers that these contracts are not onerous until the meters have been physically removed from use and therefore only recognises a provision for penalty charges at this point.

As part of the smart meter rollout, the Group has entered into new meter rental arrangements with third parties. The Group judges these are not leases because it does not have the right to physically or operationally control the smart meters and other parties also take a significant amount of the output from the assets.

(b) Key sources of estimation uncertainty

Revenue recognition – unread gas and electricity meters

Revenue for energy supply activities includes an assessment of energy supplied to customers between the date of the last meter reading and the year end (unread). Unread gas and electricity comprises both billed and unbilled revenue. It is estimated through the billing systems, using historical consumption patterns, on a customer by customer basis, taking into account weather patterns, load forecasts and the differences between actual meter reads being returned and system estimates. Actual meter reads continue to be compared to system estimates between the balance sheet date and the finalisation of the accounts. An assessment is also made of any factors that are likely to materially affect the ultimate economic benefits which will flow to the Group, including bill cancellation and re-bill rates. To the extent that the economic benefits are not expected to flow to the Group, the value of that revenue is not recognised. The judgements applied, and the assumptions underpinning these judgements, are considered to be appropriate. However, a change in these assumptions would have an impact on the amount of revenue recognised.

Industry reconciliation process – cost of sales

Industry reconciliation procedures are required as differences arise between the estimated quantity of gas and electricity the Group deems to have supplied and billed customers, and the estimated quantity industry system operators deem the individual suppliers, including the Group, to have supplied to customers. The difference in deemed supply is referred to as imbalance. The reconciliation procedures can result in either a higher or lower value of industry deemed supply than has been estimated as being supplied to customers by the Group, but in practice tends to result in a higher value of industry deemed supply. The Group reviews the difference to ascertain whether there is evidence that its estimate of amounts supplied to customers is inaccurate or whether the difference arises from other causes. The Group’s share of the resulting imbalance is included within commodity costs charged to cost of sales. Management estimates the level of recovery of imbalance which will be achieved either through subsequent customer billing or through developing industry settlement procedures.

Decommissioning costs

The estimated cost of decommissioning at the end of the producing lives of fields (including storage facility assets) is reviewed periodically and is based on reserves, price levels and technology at the balance sheet date. Provision is made for the estimated cost of decommissioning at the balance sheet date. The payment dates of total expected future decommissioning costs are uncertain and dependent on the lives of the facilities, but are currently anticipated to be incurred until 2067, with the majority of the costs expected to be paid between 2020 and 2030.

Significant judgements and estimates are also made about the costs of decommissioning British Energy’s nuclear power stations and the costs of waste management and spent fuel. These estimates impact the carrying value of our investment. Various arrangements and indemnities are in place with the Secretary of State with respect to these costs.

Gas and liquids reserves

The volume of proven and probable (2P) gas and liquids reserves is an estimate that affects the unit of production method of depreciating producing gas and liquids PP&E as well as being a significant estimate affecting decommissioning and impairment calculations. The factors impacting gas and liquids estimates, the process for estimating reserve quantities and reserve recognition are described on page 73.

The impact of a change in estimated 2P reserves is dealt with prospectively by depreciating the remaining book value of producing assets over the expected future production. If 2P reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down (impairment) of the asset’s book value.

Determination of fair values – energy derivatives

Fair values of energy derivatives are estimated by reference in part to published price quotations in active markets and in part by using valuation techniques. Quoted market prices considered for valuation purposes are the bid price for assets held and/or liabilities to be issued, or the offer price for assets to be acquired and/or liabilities held, although the mid-market price or another pricing convention may be used as a practical expedient (where typically used by other market participants).

Impairment of long-lived assets

The Group has several material long-lived assets that are assessed or tested for impairment at each reporting date. The Group makes 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 taking into account those assumptions that market participants would take into account when assessing fair value. 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.

Further details of the impairments booked during the year are provided in note 6.

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 and forecast power, gas, carbon and capacity 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.

Storage facility assets

The recoverable amount of our operational and 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. Further details of the impairments booked during the year are provided in note 6.

Nuclear investment

The recoverable amount of the nuclear investment is based on the value of the existing British Energy nuclear fleet. 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.

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) and hence the goodwill impairment tests are also subject to these key estimates. The results of these tests may then be verified by reference to external market valuation data.

Further details on impairments arising are provided in note 6.

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, on which further detail is provided in note 14.

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 benefits, 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 by taking the unavoidable costs that will be incurred under the contract and deducting any estimated revenues.

European gas transportation capacity contracts

The onerous provision is calculated using capacity costs incurred under the contracts, less any predicted income. The provision assumes that contracts for capacity in Continental Europe are onerous but those that enable gas to be transported directly back into the UK may be necessary to achieve security of supply in the future. Therefore no provision has been recognised relating to these latter contracts.

Direct Energy 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.

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 2012 Annual Report and Accounts. Throughout 2013 we continued to develop the integrated approach to our risk and assurance activities. Specifically the following improvements were implemented:

• refresh of our risk management policy, guidelines and assessment matrices and the introduction of a separate risk standards document;
• the Group Control Standards have been embedded in our self-certification process, which underpins our overall review of the system of internal control;
• development of software to support both risk and controls processes;
• development of risk training materials to drive consistency and knowledge sharing;
• improved interaction with specialist risk committees, such as Legal & Regulatory Compliance and Health & Safety, which improves visibility and enables a more consistent approach to risk identification; and
• a review of and improved resourcing in a number of second line of defence functions.

During 2013 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 is 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 is the risk of loss associated with a counterparty’s inability or failure to discharge its obligations under a contract. The Group continues to be vigilant in managing counterparty risks in accordance with its financial risk management policies. In 2013 there have been relatively few credit rating downgrades of financial institutions and European energy majors, compared with 2012. The Group has not altered its rating thresholds for counterparty credit limits and continues to operate within its limits. In the US and Europe, ongoing regulatory changes are resulting in increased trading over exchanges or via zero threshold margined contracts. This helps to reduce counterparty credit risk, but carries increased liquidity requirements.

Liquidity risk management and going concern

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 2013, the Group had undrawn committed credit facilities of £3,780 million (2012: £3,029 million) and £484 million (2012: £690 million) of unrestricted cash and cash equivalents. 113% (2012: 130%) 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 13.8 years (2012: 12.6 years).

The Group’s liquidity is impacted by the cash pledged or received under margin and collateral agreements. The terms and conditions of these depend on the counterparty and the specific details of the transaction. Cash is generally returned to the Group or by the Group within two days of trade settlement.

5. SEGMENTAL ANALYSIS

The Group’s operating segments are those used internally by management to run the business and make decisions. The Group’s operating segments are based on products and services. The operating segments are also the Group’s reportable segments.

(a) Segmental structure

On 27 February 2013 the Group announced a new organisational structure. To reflect this structure and to align with management reporting, the North American Upstream Gas business has been reallocated from the ‘Direct Energy – Upstream and wholesale energy’ segment to the ‘Centrica Energy – Gas’ segment and the North American Power and Midstream & Trading businesses have been reallocated from the ‘Direct Energy – Upstream and wholesale energy’ segment to the ‘Direct Energy – Business energy supply’ segment. Prior period comparatives have been restated accordingly throughout note 5.

The types of products and services from which each reportable segment derived its revenues during the year:

Segment	Â	Description
International Downstream
British Gas:	Â
Residential energy supply	Â	The supply of gas and electricity to residential customers in the UK
Residential services	Â	Installation, repair and maintenance of domestic central heating, plumbing and drains, gas appliances and kitchen appliances, including the provision of fixed-fee maintenance/breakdown service and insurance contracts in the UK
Business energy supply and services	Â	The supply of gas and electricity and provision of energy-related services to business customers in the UK
Direct Energy:
Residential energy supply	Â	The supply of gas and electricity to residential customers in North America
Business energy supply	Â	i) The supply of gas, electricity and energy management solutions to commercial and industrial customers in North America, ii) power generation, and iii) procurement and trading activities in the North American wholesale energy markets
Residential and business services	Â	Installation and maintenance of heating, ventilation and air conditioning (HVAC) equipment, water heaters and the provision of breakdown services, including the provision of fixed-fee maintenance/breakdown service and insurance contracts in North America
International Upstream
Centrica Energy:
Gas	Â	Production, processing, trading and optimisation of gas and oil and the development of new fields to grow reserves
Power	Â	Generation, trading and optimisation of power from thermal, nuclear and wind sources
Centrica Storage	Â	Gas storage in the UK

(b) Revenue

Gross segment revenue represents revenue generated from the sale of products and services to both third parties and to other reportable segments of the Group. Group revenue reflects only the sale of products and services to third parties.

	Â	2013					Â	2012 (restated) (i)
Year ended 31 December	Â	Gross segment revenue £m	Â	Less inter- segment revenue £m	Â	Group revenue £m	Â	Gross segment revenue £m	Â	Less inter- segment revenue £m	Â	Group revenue £m
International Downstream		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Residential energy supply		9,487	Â	–	Â	9,487		9,121	Â	–	Â	9,121
Residential services		1,655		(149)		1,506		1,674		(131)		1,543
Business energy supply and services		3,084	Â	(38)	Â	3,046		3,062	Â	(10)	Â	3,052
British Gas		14,226		(187)		14,039		13,857		(141)		13,716
		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Residential energy supply		2,517		–		2,517		2,357		–		2,357
Business energy supply (i)		4,238		(55)		4,183		2,795		(45)		2,750
Residential and business services		570	Â	–	Â	570		532	Â	–	Â	532
Direct Energy		7,325		(55)		7,270		5,684		(45)		5,639
													Â
International Upstream		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Gas (i)		4,596		(455)		4,141		3,893		(432)		3,461
Power		1,386	Â	(402)	Â	984		1,237	Â	(275)	Â	962
Centrica Energy		5,982		(857)		5,125		5,130		(707)		4,423
													Â
Centrica Storage	Â	188	Â	(51)	Â	137	Â	202	Â	(38)	Â	164
Â	Â	27,721	Â	(1,150)	Â	26,571	Â	24,873	Â	(931)	Â	23,942
(i) Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).

(c) Operating profit before and after taxation

The measure of profit used by the Group is adjusted operating profit. Adjusted operating profit is operating profit before exceptional items and certain re-measurements, before depreciation on fair value uplifts on the Strategic Investments acquired in 2009. This includes results of equity-accounted interests before interest and taxation. This note also details adjusted operating profit after taxation. Both measures are reconciled to their statutory equivalents.

	Â	Adjusted operating profit (iii)			Â	Adjusted operating profit after taxation (iv)
Year ended 31 December	Â	2013 £m	Â	2012 (restated) (i) £m	Â	2013 £m	Â	2012 £m
International Downstream		Â	Â	Â		Â	Â	Â
Residential energy supply		571		606		423		457
 Residential services		318		312		241		236
 Business energy supply and services		141		175		113		130
British Gas		1,030		1,093		777		823
		Â		Â		Â		Â
 Residential energy supply		163		156		111		103
 Business energy supply (i)		77		121		53		78
 Residential and business services		36		33		25		22
Direct Energy		276		310		189		203
								Â
International Upstream		Â		Â		Â		Â
 Gas (i) (ii)		1,155		940		325		198
 Power (ii)		171		311		143		243
 Centrica Energy Â		1,326		1,251		468		441
								Â
Centrica Storage	Â	63	Â	89	Â	48	Â	67
Â	Â	2,695	Â	2,743	Â	1,482	Â	1,534
Share of joint ventures’/associates’ interest and taxation		(111)		(85)
Depreciation of fair value uplifts to property, plant and equipment – Venture (ii)		(48)		(67)
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – British Energy (ii)	Â	(18)	Â	(29)
		2,518		2,562
Exceptional items (note 6)		(1,064)		(534)
Certain re-measurements included within gross profit (note 6)		413		603
Certain re-measurements of associates’ energy contracts (net of taxation) (note 6)	Â	25	Â	(6)
Operating profit after exceptional items and certain re-measurements	Â	1,892	Â	2,625
Â	Â	Â	Â	Â	Â	Â	Â	Â
Â	Â	Â	Â	Â	Â	2013 £m	Â	2012 £m
Adjusted operating profit after taxation (iv)	Â	Â	Â	Â	Â	1,482	Â	1,534
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) (ii)						(37)		(56)
Impact of changes to UK corporation tax rates (note 8) (v)						64		32
Corporate and other taxation, and interest (net of taxation) (vi)	Â	Â	Â	Â	Â	(176)	Â	(188)
Business performance profit for the year	Â	Â	Â	Â	Â	1,333	Â	1,322
Exceptional items and certain re-measurements (net of taxation) (note 6)	Â	Â	Â	Â	Â	(383)	Â	(77)
Statutory profit for the year	Â	Â	Â	Â	Â	950	Â	1,245
Â

(i)	Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).
(ii)	See notes 2 and 10 for an explanation of the depreciation on fair value uplifts to PP&E on the Strategic Investments acquired in 2009.
(iii)	Segment operating profit before exceptional items, certain re-measurements and impact of fair value uplifts from the Strategic Investments acquired in 2009. This includes results of equity-accounted interests before interest and taxation.
(iv)	Segment operating profit after tax, before exceptional items, certain re-measurements and impact of fair value uplifts from the Strategic Investments acquired in 2009. This includes operating results of equity-accounted interests, net of associated taxation, before interest and associated taxation.
(v)	Excludes £29 million credit (2012: £21 million) relating to equity-accounted interests.
(vi)	Includes joint ventures’/associates’ interest, net of associated taxation.

(d) Included within adjusted operating profit

Presented below are certain items included within adjusted operating profit, including further details of impairments of property, plant and equipment and write downs relating to exploration and evaluation assets.

	Â	Share of results of joint ventures and associates before interest and taxation			Â	Depreciation and impairments of property, plant and equipment			Â	Amortisation, write-downs and impairments of intangibles
Year ended 31 December	Â	2013 £m	Â	2012 £m	Â	2013 £m	Â	2012 (restated) (i) £m	Â	2013 £m	Â	2012 (restated) (i) £m
International Downstream		Â	Â	Â		Â	Â	Â		Â	Â	Â
Residential energy supply		(7)		–		16		8		48		34
Residential services		–		–		23		20		8		8
Business energy supply and services		–		–		2		2		7		6
British Gas		(7)		–		41		30		63		48
		Â		Â		Â		Â		Â		Â
Residential energy supply		–		–		1		2		24		22
Business energy supply (i)		–		–		16		18		36		9
Residential and business services		–		–		2		3		7		7
Direct Energy		–		–		19		23		67		38
													Â
International Upstream		Â		Â		Â		Â		Â		Â
Gas (i) (ii) (iii)		–		–		886		705		111		135
Power (ii) (iii)		282		254		93		106		4		5
Centrica Energy		282		254		979		811		115		140
													Â
Centrica Storage		–		–		30		30		–		–
Other	Â	–	Â	–	Â	15	Â	22	Â	20	Â	19
Â	Â	275	Â	254	Â	1,084	Â	916	Â	265	Â	245

(i)	Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).
(ii)	The share of results of joint ventures and associates is before interest, taxation, certain re-measurements and depreciation of fair value uplifts to PP&E on the Strategic Investments acquired in 2009.
(iii)	Depreciation of PP&E is stated before depreciation of fair value uplifts for the Strategic Investments acquired in 2009.

Impairment of property, plant and equipment

During 2012, a £73 million impairment charge was recognised in the ‘Centrica Energy – Gas’ segment, in relation to the Ensign development well in the Southern North Sea.

Write-downs of intangible assets

During 2013, £95 million of write-downs relating to exploration and evaluation assets were recognised in the ‘Centrica Energy – Gas’ segment (2012: £122 million), within ‘operating costs before exceptional items’ within the Group Income Statement.

(e) Average capital employed

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.

Â

Â

Â

2013

Â

Â

Â

2012 (restated) (i)

Year ended 31 December

Â

Total capital employed £m

Â

Pre-productive capital employed £m

Â

Productive capital employed £m

Â

Total capital employed £m

Â

Pre-productive capital employed £m

Â

Productive capital employed £m

International Downstream

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Residential energy supply

101

–

101

212

–

212

Residential services

218

–

218

289

–

289

Business energy supply and services

539

Â

–

Â

539

714

Â

–

Â

714

British Gas

858

–

858

1,215

–

1,215

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Residential energy supply

820

–

820

840

–

840

Business energy supply (i)

783

–

783

628

–

628

Residential and business services

384

Â

–

Â

384

371

Â

–

Â

371

Direct Energy

1,987

–

1,987

1,839

–

1,839

Â

International Upstream

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Gas (i)

3,932

(1,292)

2,640

3,557

(1,161)

2,396

Power

3,717

Â

(282)

Â

3,435

3,605

Â

(610)

Â

2,995

Centrica Energy

7,649

(1,574)

6,075

7,162

(1,771)

5,391

Â

Centrica Storage

Â

435

Â

(130)

Â

305

Â

517

Â

(216)

Â

301

Total average segmental capital employed

Â

10,929

Â

(1,704)

Â

9,225

Â

10,733

Â

(1,987)

Â

8,746

(i) Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).

Reconciliation of total average segmental capital employed to net assets in the Group Balance Sheet

Year ended 31 December	Â	Â	2013 £m	Â	2012 £m
Total average segmental capital employed	Â	Â	10,929	Â	10,733
Add back/(deduct):
Average intra-group, margin cash and cash balances			281		395
Effect of averaging	Â	Â	(81)	Â	(177)
Total segmental net operating assets at 31 December			11,129		10,951
(Deduct)/add back:
Bank overdrafts and loans, securities and treasury derivatives			(5,785)		(5,054)
Certain derivative financial instruments including balances held by joint ventures/associates			(257)		(553)
Corporate assets			130		495
Net retirement benefit asset	Â	Â	40	Â	88
Net assets in Group Balance Sheet	Â	Â	5,257	Â	5,927

(f) Capital expenditure

Capital expenditure represents additions, other than assets acquired as part of business combinations, to property, plant and equipment, and intangible assets. Capital expenditure has been reconciled to the related cash outflow.

		Â	Capital expenditure on property, plant and equipment			Â	Capital expenditure on intangible assets other than goodwill
Year ended 31 December	Â		2013 £m	Â	2012 (restated) (i) £m		2013 £m	Â	2012 (restated) (i) £m
International Downstream			Â		Â		Â		Â
Residential energy supply			27		7		287		230
Residential services			59		44		12		9
Business energy supply and services			1		9		121		91
British Gas			87		60		420		330
			Â		Â		Â		Â
Residential energy supply			9		–		33		3
Business energy supply (i)			19		17		64		29
Residential and business services			3		3		1		2
Direct Energy			31		20		98		34
										Â
International Upstream			Â		Â		Â		Â
Gas (i) (ii)			982		1,795		147		392
Power			32		76		74		8
Centrica Energy			1,014		1,871		221		400
										Â
Centrica Storage			37		42		3		1
Other		Â	15	Â	17	Â	39	Â	64
Capital expenditure			1,184		2,010		781		829
Capitalised borrowing costs			(43)		(53)		(8)		(7)
Movements in payables and prepayments related to capital expenditure			123		(162)		9		–
Purchases of emissions allowances and renewable obligations certificates		Â	–	Â	–	Â	(431)	Â	(250)
Net cash outflow (iii)	Â	Â	1,264	Â	1,795	Â	351	Â	572

(i)	Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).
(ii)	During 2012, £1,175 million of assets were acquired from Statoil, ConocoPhillips and Total.
(iii)	The £351 million (2012: £572 million) purchase of intangible assets includes £121 million (2012: £370 million) relating to exploration and evaluation of oil and gas assets.

The Group does not monitor and manage performance by geographic territory, but we provide below an analysis of certain non-current assets and revenue by geography.

	Â	Non-current assets (based on location of assets)(i)			Â	Revenue (based on location of customer)
Year ended 31 December	Â	2013 £m	Â	2012 £m	Â	2013 £m	Â	2012 £m
UK		8,985	Â	9,788		17,463	Â	16,991
North America		3,534		2,458		7,530		5,741
Norway		1,813		2,113		695		184
Rest of the world	Â	496	Â	449	Â	883	Â	1,026
Â	Â	14,828	Â	14,808	Â	26,571	Â	23,942
(i) Non-current assets include goodwill, other intangible assets, PP&E and interests in joint ventures and associates.

6. EXCEPTIONAL ITEMS AND CERTAIN RE-MEASUREMENTS

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. Items which may be considered exceptional in nature include disposals of businesses, business restructurings, significant onerous contract charges and asset write-downs.

(a) Exceptional items

Year ended 31 December	Â	2013 £m	Â	2012 £m
Provision for onerous power procurement contract (i)	Â	(125)	Â	–
Provision for Direct Energy wind power purchase agreements	Â	–	Â	(89)
Exceptional items included within gross profit	Â	(125)	Â	(89)
Impairment of UK and North American exploration and production assets (ii)		(699)		–
Impairment of UK gas storage assets and associated provision for onerous capacity contracts (iii)		(240)		–
Restructuring charges		–		(214)
Impairment of investment in nuclear new build (note 12)	Â	–	Â	(231)
Â	Â	(939)	Â	(445)
Exceptional items included within Group operating profit		(1,064)		(534)
Taxation on exceptional items (note 8)		397		93
Effect of change in upstream UK tax rates (note 8)	Â	–	Â	(40)
Total exceptional items after taxation	Â	(667)	Â	(481)

Certain re-measurements are the fair value movements on energy contracts entered into to meet the future needs of our customers. These contracts are economically related to our upstream assets, capacity/off-take contracts or downstream demand, which are typically not fair valued, and are therefore separately identified in the current period and reflected in business performance in future periods when the underlying transaction or asset impacts the Group Income Statement.

(b) Certain re-measurements

Year ended 31 December	Â	2013 £m	Â	2012 £m
Certain re-measurements recognised in relation to energy contracts (note 2):	Â		Â
Net gains arising on delivery of contracts		317		745
Net gains/(losses) arising on market price movements and new contracts	Â	96	Â	(142)
Net re-measurements included within gross profit		413		603
Net gains/(losses) arising on re-measurement of associates’ energy contracts (net of taxation)	Â	25	Â	(6)
Net re-measurements included within Group operating profit	Â	438	Â	597
Taxation on certain re-measurements (note 8)	Â	(154)	Â	(193)
Net re-measurements after taxation	Â	284	Â	404

(i)	The Group has recognised a further £125 million onerous contract charge in the ‘Centrica Energy – Power’ segment for the Rijnmond tolling contract as a result of decreases in expected future revenues.
(ii)	Following reserve and resources downgrades, and increases in expected costs on the Seven Seas, York and Ensign fields in the Southern North Sea, the Group recognised pre-tax impairment charges of £166 million (post-tax charge £63 million) on the Seven Seas field, £221million (post-tax charge £97 million) on the York field, and £225 million (post-tax charge £92 million) on the Ensign field in the ‘Centrica Energy – Gas’ segment. As a result of the weaker outlook for North American natural gas prices, and an increase in the discount rate applicable to these assets, the Group recognised a pre-tax Income Statement impairment charge of £87 million (post-tax charge £66 million) in relation to the Canadian Upstream assets held prior to the Suncor Upstream acquisition, in the ‘Centrica Energy – Gas’ segment. A further £20 million charge (£15 million net of taxation) was recognised in other comprehensive income to reverse previous upwards revaluations of the impaired assets, giving a total impairment of the Canadian Upstream assets held prior to the Suncor Upstream acquisition, of £107 million.
(iii)	In light of weak economics for storage projects, and following announcements regarding future government support for gas storage in the UK, the Group announced its decision not to proceed with the Baird offshore gas storage project and to put the onshore project at Caythorpe on hold indefinitely. As a result, the Group has recorded pre-tax impairments and provision charges totalling £240 million (post-tax charge £224 million) in the ‘Centrica Storage’ segment. Goodwill (£33 million), property, plant and equipment (£105 million) and investments in joint ventures and associates (£55 million) have been written off during the year, and an onerous capacity contract provision of £47 million was recognised.

7. NET FINANCE COST

Financing costs mainly comprises interest on bonds, bank debt and commercial paper, the results of hedging activities used to manage foreign exchange and interest rate movements on the Group’s borrowings, and notional interest arising on discounting of decommissioning provisions. An element of financing cost is capitalised on qualifying projects. Investment income predominantly includes interest received on short term investments in money market funds, bank deposits, government bonds and notional interest on pensions.

	Â		Â		Â	2013	Â		Â	2012 (restated) (i)
Year ended 31 December	Â	Financing costs £m	Â	Investment income £m	Â	Total £m	Â	Financing costs £m	Â	Investment income £m	Â	Total £m
Cost of servicing net debt		Â		Â		Â		Â		Â	Â	Â
Interest income		–		43		43		–		39		39
Interest cost on bonds, bank loans and overdrafts (ii)		(252)		–		(252)		(232)		–		(232)
Interest cost on finance leases		(17)		–		(17)		(18)		–		(18)
		(269)		43		(226)		(250)		39		(211)
Net losses on revaluation (iii)		(6)		–		(6)		(21)		–		(21)
Notional interest arising from discounting and other interest	Â	(73)	Â	11	Â	(62)	Â	(60)	Â	23	Â	(37)
		(348)		54		(294)		(331)		62		(269)
Capitalised borrowing costs (iv)	Â	51	Â	–	Â	51	Â	60	Â	–	Â	60
(Cost)/income	Â	(297)	Â	54	Â	(243)	Â	(271)	Â	62	Â	(209)

(i)	See note 1(a).
(ii)	During 2013 the Group increased its outstanding bond debt principal by £50 million and $1,480 million, and decreased it by ¥3,000 million and €367 million. See note 11 (c).
(iii)	Includes gains and losses on fair value hedges, movements in fair value of other derivatives primarily used to hedge foreign exchange exposure associated with inter-company loans, and foreign currency gains and losses on the translation of inter-company loans.
(iv)	Borrowing costs have been capitalised using an average rate of 4.55% (2012: 4.70%). See note 5(f).

8. TAXATION

The taxation note details the different tax charges and rates, including current and deferred tax arising in the Group. The current tax charge is the tax payable on this year’s taxable profits. This tax charge excludes taxation on the Group’s share of results of joint ventures and associates. Deferred tax represents the tax on differences between the accounting carrying values of assets and liabilities and their tax bases. These differences are generally temporary and are expected to unwind in the future.

Analysis of tax charge

	Â		Â		Â	2013	Â		Â		Â	2012
Year ended 31 December	Â	Business performance £m	Â	Exceptional items and certain re-measurements £m Â	Â	Results for the year £m	Â	Business performance (restated) (i) £m	Â	Exceptional items and certain re-measurements £m	Â	Results for the year (restated) (i) £m
Current tax
UK corporation tax		(346)		(1)		(347)		(376)		14		(362)
UK petroleum revenue tax		(210)		–		(210)		(208)		–		(208)
Non-UK tax		(504)		–		(504)		(285)		(7)		(292)
Adjustments in respect of prior years – UK		140		–		140		(71)		–		(71)
Adjustments in respect of prior years – Non-UK	Â	28	Â	–	Â	28	Â	18	Â	–	Â	18
Total current tax	Â	(892)	Â	(1)	Â	(893)	Â	(922)	Â	7	Â	(915)
Deferred tax
Origination and reversal of temporary differences – UK (i)		(85)		370		285		(137)		(86)		(223)
UK petroleum revenue tax		37		–		37		13		–		13
Origination and reversal of temporary differences – Non-UK tax		55		(121)		(66)		(70)		(11)		(81)
Change in tax rates (i)		64		(5)		59		32		(50)		(18)
Adjustments in respect of prior years – UK		(94)		–		(94)		52		–		52
Adjustments in respect of prior years – Non-UK	Â	(27)	Â	–	Â	(27)	Â	1	Â	–	Â	1
Total deferred tax	Â	(50)	Â	244	Â	194	Â	(109)	Â	(147)	Â	(256)
Total tax on profit (ii)	Â	(942)	Â	243	Â	(699)	Â	(1,031)	Â	(140)	Â	(1,171)

(i)	See note 1(a).
(ii)	Total tax on profit excludes taxation on the Group’s share of profits of joint ventures and associates.

The Group earns the majority of its profits in the UK. Most activities in the UK are subject to the standard rate for UK corporation tax, which from 1 April 2013 was 23% (2012: 24%). Upstream oil and gas production activities are taxed at a UK corporation tax rate of 30% (2012: 30%) plus a supplementary charge of 32% (2012: 32%) to give an overall rate of 62% (2012: 62%). In addition, certain upstream assets in the UK bear petroleum revenue tax (PRT) at 50% (2012: 50%) which is deductible against corporation tax, giving an overall effective rate of 81% (2012: 81%). Norwegian upstream profits are taxed at the standard rate of 28% (2012: 28%) plus a special tax of 50% (2012: 50%) resulting in an aggregate tax rate of 78%. Taxation for other jurisdictions is calculated at the rates prevailing in those respective jurisdictions.

On 2 July 2013, the UK Government substantively enacted Finance Act 2013 which included reductions in the main UK corporation tax rate to 20% by 1 April 2015. At 31 December 2013, the relevant UK deferred tax assets and liabilities included in these Financial Statements have been based on the reduced rates. The deferred tax revaluation benefit recognised from the adoption of the reduced rates is not expected to recur in future periods.

9. DIVIDENDS

Dividends represent the cash return of profits to shareholders and are paid twice a year, in June and November. Dividends are paid as an amount per ordinary share held. We retain part of the profits generated in the year to meet future investment plans or to fund share repurchase programmes.

Â

Â

Â

2013

Â

Â

Â

2012

Â

Â

£m

Â

Pence per share

Â

Date of payment

Â

£m

Â

Pence per share

Â

Date of payment

Prior year final dividend

611

11.78

12 Jun 2013

576

11.11

13 Jun 2012

Interim dividend

Â

253

Â

4.92

Â

13 Nov 2013

Â

240

Â

4.62

Â

14 Nov 2012

Â

Â

864

Â

Â

Â

Â

Â

816

Â

Â

Â

Â

The Directors propose a final dividend of 12.08 pence per ordinary share (totalling £614 million) for the year ended 31 December 2013. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 12 May 2014 and, subject to approval, will be paid on 11 June 2014 to those shareholders registered on 25 April 2014.

10. EARNINGS PER ORDINARY SHARE

Earnings per share (EPS) is the amount of profit attributable to each share. Basic EPS is the amount of profit for the year divided by the number of shares in issue during the year. Diluted EPS includes the impact of outstanding share options as if they were exercised at the year end.

Basic earnings per ordinary share has been calculated by dividing the earnings attributable to equity holders of the Company for the year of £950 million (2012: £1,245 million) by the weighted average number of ordinary shares in issue during the year of 5,150 million (2012: 5,183 million). The number of shares excludes 50 million ordinary shares (2012: six million), being the weighted average number of the Company’s own shares held in the employee share trust and treasury shares purchased by the Group as part of the share repurchase programme.

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 the Strategic Investments acquired in 2009, assists with understanding the underlying performance of the Group, as explained in note 2.

During the year, the Group purchased 137.3 million ordinary shares of 6¹⁴/₈₁ pence each, representing 2.7% of the called up share capital as at 31 December 2013 at an average price of £3.64 per share for a total consideration including expenses of £502 million. The shares were purchased as part of the £500 million share repurchase programme announced on 4 February 2013. These shares are held as treasury shares once purchased and are deducted from equity.

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 2013 or 2012, however the weighted average number of shares used as the denominator is adjusted for potentially dilutive ordinary shares.

Weighted average number of shares

Â	Â	2013 Million shares	Â	2012 Million shares
Weighted average number of shares – basic	Â	5,150	Â	5,183
Dilutive impact of share-based payment schemes	Â	33	Â	33
Weighted average number of shares – diluted	Â	5,183	Â	5,216

Basic to adjusted basic earnings per share reconciliation

	Â		Â	2013	Â		Â	2012 (restated) (i)
Year ended 31 December	Â	£m	Â	Pence per ordinary share	Â	£m	Â	Pence per ordinary share
Earnings – basic (i)		950		18.4		1,245		24.0
Net exceptional items after taxation (notes 2 and 6)		667		13.0		481		9.3
Certain re-measurement gains after taxation (notes 2 and 6)		(284)		(5.5)		(404)		(7.8)
Depreciation of fair value uplifts to property, plant and equipment from the Strategic Investments acquired in 2009, net of taxation	Â	37	Â	0.7	Â	56	Â	1.1
Earnings – adjusted basic (i)	Â	1,370	Â	26.6	Â	1,378	Â	26.6
Â	Â	Â	Â	Â	Â	Â	Â	Â
Earnings – diluted (i)	Â	950	Â	18.3	Â	1,245	Â	23.9
Â	Â	Â	Â	Â	Â	Â	Â	Â
Earnings – adjusted diluted (i)	Â	1,370	Â	26.4	Â	1,378	Â	26.4

(i) See note 1(a).

Strategic Investments

During 2009, the Group acquired a 20% interest in British Energy and the entire share capital of Venture. As explained in note 2, 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 £48 million (2012: £67 million) depreciation and a taxation credit of £29 million (2012: £40 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 £18 million (2012: £29 million) net of taxation.

11. SOURCES OF FINANCE

(a) Capital structure

The Group seeks to maintain an efficient capital structure with a balance of debt and equity as shown in the below table.

31 December	Â	2013 £m	Â	2012 £m
Net debt	Â	5,049	Â	4,047
Equity	Â	5,192	Â	5,927
Capital	Â	10,241	Â	9,974

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 for several reasons, to maintain a low cost of debt; limit collateral requirements in energy trading, hedging and decommissioning security arrangements; and ensure the Group is an attractive counterparty to energy producers and long term customers. At 31 December 2013, the Group’s long-term credit rating was A3 stable outlook for Moody’s Investors Service Limited and A- stable outlook for Standard & Poor’s Credit Market Services Europe Limited. These ratings did not change during 2013.

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 adjusted EBITDA to gross interest expense. At 31 December 2013, the ratio of the Group’s net debt to adjusted EBITDA was 1.3 (2012: 1.1). Adjusted EBITDA to gross interest expense for the year ended 31 December 2013 was 12.8 (2012: 13.5). The Group now has a new financial covenant in some of its debt facilities, which restricts adjusted net borrowings to less than 3.5 times adjusted EBITDA. At 31 December 2013 the ratio was 1.4 times.

British Gas Insurance Limited (BGIL) is required under PRA regulations to hold a minimum capital amount and has complied with this requirement in 2013 (and 2012). 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 2013 of £5.2 billion, the limit for net debt was £15.6 billion. The Group funds its debt principally through issuing bonds, supplemented by some bank debt. In addition the Group also maintains substantial committed facilities from banks but generally uses these to provide backup liquidity and does not typically draw on them.

(b) Net debt summary

Net debt includes predominately capital market borrowings offset by cash, securities and certain hedging financial instruments used to manage interest rate and foreign exchange movements on borrowings.

Â	Â	Cash and cash equivalents (i) £m	Â	Current and non-current securities (ii) £m	Â	Current and non-current borrowings £m	Â	Derivatives £m	Â	Net debt £m
1 January 2012	Â	518	Â	218	Â	(4,171)	Â	143	Â	(3,292)
Cash inflow from sale of securities		26		(26)		–		–		–
Cash inflow from issued bonds and bank loans		1,712		–		(1,712)		–		–
Cash outflow from payment of capital element of finance leases		(31)		–		31		–		–
Cash outflow from repayment of other borrowings		(471)		–		471		–		–
Cash outflow from derivatives		(14)		–		–		14		–
Net cash outflow increasing net debt		(809)		–		39		–		(770)
Revaluation		–		10		2		(12)		–
Increase in interest payable and amortisation of borrowings		–		–		(41)		–		(41)
Acquisitions		–		5		–		–		5
Exchange adjustments		–		(1)		48		(1)		46
Other non-cash movements	Â	–	Â	–	Â	5	Â	–	Â	5
31 December 2012	Â	931	Â	206	Â	(5,328)	Â	144	Â	(4,047)
Cash outflow from purchase of securities		(8)		8		–		–		–
Cash inflow from issued bonds and commercial paper		1,209		–		(1,209)		–		–
Cash outflow from payment of capital element of finance leases		(30)		–		30		–		–
Cash outflow from repayment of other borrowings		(370)		–		370		–		–
Net cash outflow increasing net debt		(1,003)		–		–		–		(1,003)
Revaluation		–		(2)		87		(96)		(11)
(Increase)/decrease in interest payable and amortisation of borrowings		–		–		(11)		4		(7)
Exchange adjustments	Â	(10)	Â	(1)	Â	30	Â	–	Â	19
31 December 2013	Â	719	Â	211	Â	(6,031)	Â	52	Â	(5,049)

(i)	Cash and cash equivalents includes £235 million (2012: £241 million) of restricted cash mostly held by the Group’s insurance undertakings that is not readily available to be used for other purposes within the Group.
(ii)	Securities balances include £126 million (2012: £130 million) of index-linked gilts which the Group uses for short term liquidity management purposes and £85 million of available-for-sale financial assets (2012: £76 million). During the year the Group pledged £28 million of non-current securities as collateral against an index-linked swap maturing on 16 April 2020.

(c) Borrowings summary

			Â		Â		Â		Â	2013	Â		Â		Â	2012
										Â						(restated) (i)
								Non-						Non-		Â
		Coupon rate		Principal		Current		current		Total		Current		current		Total
31 December		%		m		£m		£m		£m		£m		£m		£m
Bank overdrafts and loans (i)						(16)		(305)		(321)		(31)		(336)		(367)
Bonds (by maturity date): (i)						Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
27 February 2013		1.045		¥3,000		–		–		–		(22)		–		(22)
9 December 2013		7.125		€367		–		–		–		(304)		–		(304)
4 November 2014		Floating		$100		(60)		–		(60)		–		(61)		(61)
10 December 2014		5.125		£315		(323)		–		(323)		–		(331)		(331)
31 March 2015		Floating		$70		–		(42)		(42)		–		(43)		(43)
24 October 2016		5.500		£300		–		(321)		(321)		–		(334)		(334)
19 September 2018		7.000		£400		–		(443)		(443)		–		(471)		(471)
1 February 2019		3.213		€100		–		(83)		(83)		–		(81)		(81)
25 September 2020		Floating		$80		–		(48)		(48)		–		–		–
22 February 2022		3.680		HK$450		–		(35)		(35)		–		(36)		(36)
10 March 2022		6.375		£500		–		(490)		(490)		–		(501)		(501)
16 October 2023		4.000		$750		–		(444)		(444)		–		–		–
4 September 2026		6.400		£200		–		(212)		(212)		–		(224)		(224)
16 April 2027		5.900		$70		–		(42)		(42)		–		(43)		(43)
13 March 2029		4.375		£750		–		(740)		(740)		–		(740)		(740)
5 January 2032 (ii)		Zero		€50		–		(46)		(46)		–		(41)		(41)
19 September 2033		7.000		£770		–		(762)		(762)		–		(762)		(762)
16 October 2043		5.375		$600		–		(356)		(356)		–		–		–
12 September 2044		4.250		£500		–		(489)		(489)		–		(489)		(489)
12 September 2044		4.250		£50		–		(47)		(47)		–		–		–
25 September 2045		5.250		$50		–	Â	(30)	Â	(30)		–	Â	–	Â	–
						(383)		(4,630)		(5,013)		(326)		(4,157)		(4,483)
Commercial paper						(325)		–		(325)		(82)		–		(82)
Obligations under finance leases						(32)		(237)		(269)		(30)		(269)		(299)
Interest accruals (i)		Â	Â	Â	Â	(103)	Â	–	Â	(103)	Â	(97)	Â	–	Â	(97)
Â	Â	Â	Â	Â	Â	(859)	Â	(5,172)	Â	(6,031)	Â	(566)	Â	(4,762)	Â	(5,328)

(i)	See note 1(a).
(ii)	€50 million of zero coupon notes have an accrual yield of 4.200%, which will result in a €114 million repayment on maturity.

Maturity analysis for non-current bank loans at 31 December	Â	2013 £m	Â	2012 £m
1-2 years	Â	–	Â	(15)
2-5 years		(90)		–
>5 years	Â	(215)	Â	(321)
Â	Â	(305)	Â	(336)

12. JOINT VENTURES AND ASSOCIATES

Joint ventures and associates are businesses where we exercise joint control or significant influence and generally have an equity holding of up to 50%.

(a) Share of results of joint ventures and associates

The Group’s share of results of joint ventures and associates for the year ended 31 December 2013 principally arises from its interests in the following entities (predominantly reported in the Centrica Energy – Power segment):

• Wind farms – Braes of Doune Wind Farm (Scotland) Limited, Barrow Offshore Wind Limited, GLID Wind Farms TopCo Limited, Lincs Wind Farm Limited and Celtic Array Limited (Round 3) ⁽ⁱⁱ⁾; and
• Nuclear – Lake Acquisitions Limited (British Energy).

	Â		Â		Â		Â	2013	Â	2012
		Joint ventures		Associates
		Wind farms		Nuclear		Other		Total		Total
Year ended 31 December	Â	£m	Â	£m	Â	£m	Â	£m	Â	£m
Income		82		645		8		735		641
Expenses excluding certain re-measurements (i)		(59)		(447)		(15)		(521)		(453)
Certain re-measurements	Â	–	Â	23	Â	–	Â	23	Â	(8)
		23		221		(7)		237		180
Interest paid		(34)		(25)		(1)		(60)		(44)
Taxation excluding certain re-measurements (i)		–		(8)		–		(8)		(4)
Taxation on certain re-measurements	Â	–	Â	2	Â	–	Â	2	Â	2
Share of post-taxation results of joint ventures and associates (i)	Â	(11)	Â	190	Â	(8)	Â	171	Â	134

(i)	Â	Includes £61 million (2012: £66 million) relating to depreciation of fair value uplifts to PP&E on acquiring British Energy. The associated tax impact is £43 million credit (2012: £37 million credit).
(ii)		As part of the finance arrangements entered into by GLID Wind Farms TopCo Limited and Lincs Wind Farm Limited, the Group’s shares in GLID Wind Farms TopCo Limited and Lincs Wind Farm Limited are secured in favour of third parties. The securities would only be enforced in the event that GLID Wind Farms TopCo Limited or Lincs Wind Farm Limited default on any of their obligations under their respective finance arrangements.

British Energy

During November 2009 the Group acquired a 20% interest in British Energy. The Group’s share of profit arising from its investment in British Energy for the year to 31 December 2013, as set out in the above table, includes the effect of unwinding the fair value uplifts recognised at acquisition.

As explained in note 2 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 notes 5(c) and 10.

(b) Reconciliation of share of results of joint ventures and associates to share of adjusted results of joint ventures and associates

	Â		Â		Â		Â	2013	Â	2012
		Joint ventures		Associates
		Wind farms		Nuclear		Other		Total		Total
Year ended 31 December	Â	£m	Â	£m	Â	£m	Â	£m	Â	£m
Share of post-taxation results of joint ventures and associates		(11)		190		(8)		171		134
Certain re-measurements (net of taxation)		–		(25)		–		(25)		6
Depreciation – British Energy (net of taxation) (i)		–		18		–		18		29
Interest paid		34		25		1		60		44
Taxation (excluding certain re-measurements and British Energy depreciation)	Â	–	Â	51	Â	–	Â	51	Â	41
Share of adjusted results of joint ventures and associates	Â	23	Â	259	Â	(7)	Â	275	Â	254

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

(c) Interests in joint ventures and associates

	Â		Â		Â	2013	Â		Â		Â	2012
		Investments in joint ventures and associates		Shareholder loans		  Total		Investments in joint ventures and associates		Shareholder loans		  Total
Â	Â	£m	Â	£m	Â	£m	Â	£m	Â	£m	Â	£m
1 January		2,316		405		2,721		2,351		269		2,620
Additions		55		20		75		140		178		318
Disposals		(29)		(5)		(34)		–		–		–
Decrease in shareholder loans		–		–		–		–		(42)		(42)
Share of profits for the year		171		–		171		134		–		134
Share of other comprehensive income		3		–		3		32		–		32
Impairment (i)		(64)		(21)		(85)		(231)		–		(231)
Dividends	Â	(193)	Â	–	Â	(193)	Â	(110)	Â	–	Â	(110)
31 December	Â	2,259	Â	399	Â	2,658	Â	2,316	Â	405	Â	2,721

(i) Includes £55 million in relation to the Baird offshore gas storage project. See note 6.

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

	Â		Â		Â		Â	2013	Â	2012
		Joint ventures		Associates
		Wind farms		Nuclear		Other		Total		Total
31 December	Â	£m	Â	£m	Â	£m	Â	£m	Â	£m
Share of non-current assets		850		3,529		11		4,390		4,319
Share of current assets	Â	69	Â	618	Â	2	Â	689	Â	765
Â		919		4,147		13		5,079		5,084
Share of current liabilities		(244)		(205)		(1)		(450)		(473)
Share of non-current liabilities	Â	(534)	Â	(1,828)	Â	–	Â	(2,362)	Â	(2,283)
Â	Â	(778)	Â	(2,033)	Â	(1)	Â	(2,812)	Â	(2,756)
Restricted interest on shareholder loan (i)	Â	(8)	Â	–	Â	–	Â	(8)	Â	(12)
Share of net assets of joint ventures and associates		133		2,114		12		2,259		2,316
Shareholder loans	Â	399	Â	–	Â	–	Â	399	Â	405
Interests in joint ventures and associates	Â	532	Â	2,114	Â	12	Â	2,658	Â	2,721
Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â
Net (debt)/cash included in share of net assets	Â	(620)	Â	86	Â	–	Â	(534)	Â	(279)

(i) The Group restricts an element of interest received on the shareholder loan to Lincs Wind Farm Limited.

13. DERIVATIVE FINANCIAL INSTRUMENTS

The Group uses derivative financial instruments to manage the risk arising from fluctuations in the value of certain assets or liabilities, associated with treasury management, energy sales and procurement. These derivatives are held at fair value, and are predominantly unrealised positions, expected to unwind in future periods. The Group also uses derivatives for proprietary energy trading purposes.

Purpose	Â	Accounting treatment
Proprietary energy trading and treasury management	Â	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	Â	Carried at fair value, with changes in 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 or loss include certain energy contracts that the Group has, at its option, designated at fair value through profit or loss under IAS 39 because the energy contract contains one or more embedded derivatives that significantly modify the cash flows under the contract.

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

	Â		Â	2013	Â		Â	2012
31 December	Â	Assets £m	Â	Liabilities £m	Â	Assets £m	Â	Liabilities £m
Derivative financial instruments – held for trading under IAS 39:
Energy derivatives – for procurement		512		(750)		229		(772)
Energy derivatives – for proprietary trading		56		–		69		–
Interest rate derivatives (i)		–		(26)		13		(86)
Foreign exchange derivatives (i)		106		(96)		33		(42)
Energy derivative contracts designated at fair value through profit or loss		24		(1)		65		–
Derivative financial instruments in hedge accounting relationships:
Energy derivatives		–		(2)		–		(14)
Interest rate derivatives (i)		95		(22)		172		(2)
Foreign exchange derivatives (i)	Â	7	Â	(40)	Â	–	Â	(26)
Total derivative financial instruments	Â	800	Â	(937)	Â	581	Â	(942)
Included within:
Derivative financial instruments – current		573		(506)		268		(615)
Derivative financial instruments – non-current	Â	227	Â	(431)	Â	313	Â	(327)

(i) Included within these categories are £52 million (2012: £144 million) of derivatives used to hedge movements in net debt. See note 11(b).

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:

31 December	Â	2013 £m	Â	2012 £m
Short-term forward market purchases and sales of gas and electricity:	Â		Â
UK and Europe		(30)		(163)
North America		22		(209)
Structured gas purchase contracts		(54)		(36)
Structured gas sales contracts		(54)		(78)
Structured power purchase contracts		(41)		54
Other	Â	(4)	Â	9
Net total	Â	(161)	Â	(423)

14. POST RETIREMENT BENEFITS

The Group manages a number of final salary and career average defined benefit pension schemes. It also has defined contribution schemes. The majority of these schemes are in the UK.

(a) Summary of main post retirement benefit schemes

Name of scheme	Â	Type of benefit	Â	Status	Â	Country	Â	Number of active members as at 31 December 2013 (i)	Â	Total membership as at 31 December 2013 (i)
Centrica Engineers Pension Scheme	Â	Defined benefit final salary pension	Â	Closed to new members in 2006	Â	UK	Â	4,614	Â	8,730
	Â	Defined benefit career average pension	Â	Open to service engineers only	Â	UK	Â	3,672	Â	4,375
Centrica Pension Plan	Â	Defined benefit final salary pension	Â	Closed to new members in 2003	Â	UK	Â	4,302	Â	8,785
Centrica Pension Scheme		Defined benefit final salary pension		Closed to new members in 2003		UK		34		10,828
		Defined benefit career average pension		Closed to new members in 2008		UK		2,166		4,055
	Â	Defined contribution pension	Â	Open to new members	Â	UK	Â	13,462	Â	14,903
Direct Energy Marketing Limited Pension Plan	Â	Defined benefit final salary pension	Â	Closed to new members in 2004	Â	Canada	Â	383	Â	749
Direct Energy Marketing Ltd	Â	Post-retirement benefits	Â	Closed to new members in 2012	Â	Canada	Â	655	Â	857

(i) For Direct Energy schemes, membership information is as at 31 December 2012.

The Centrica Engineers Pension Scheme (CEPS), Centrica Pension Plan (CPP) and Centrica Pension Scheme (CPS) form the significant majority of the Group’s defined benefit obligation and are referred to below as the ‘Registered Pension Schemes’. The other schemes are individually, and in aggregate, immaterial.

Independent valuations

The Registered Pensions Schemes are subject to independent valuations at least every three years, on the basis of which the qualified actuary certifies the rate of employer contributions which, together with the specified contributions payable by the employees and proceeds from the schemes’ assets, are expected to be sufficient to fund the benefits payable under the schemes.

The latest full actuarial valuations were carried out at the following dates: the Registered Pensions Schemes at 31 March 2012 and the Direct Energy Marketing Limited Pension Plan at 31 December 2012. These have been updated to 31 December 2013 for the purposes of meeting the requirements of IAS 19. Investments have been valued for this purpose at market value.

Governance

The Registered Pension Schemes are managed by trustee companies whose boards consist of both company-nominated and member-nominated Directors. Each scheme holds units in the Centrica Combined Common Investment Fund (CCCIF), which holds the majority of the combined assets of the participating schemes. The board of the CCCIF is currently comprised of nine Directors; three independent Directors, three Directors appointed by Centrica plc (including the Chairman) and one Director appointed by each of the three participating schemes.

Under the terms of the Pensions Act 2004, Centrica plc and each trustee board must agree the funding rate for its defined benefit pension scheme and a recovery plan to fund any deficit against the scheme-specific statutory funding objective. This approach was first adopted for the triennial valuations completed at 31 March 2006, and has been reflected in subsequent valuations, including the 31 March 2012 valuations.

(b) Risks

The Registered Pension Schemes expose the Group to the following risks:

Asset volatility

The pension liabilities are calculated using a discount rate set with reference to AA corporate bond yields; if the growth in plan assets is lower than this, this will create an actuarial loss within other equity. The CCCIF is responsible for managing the assets of each scheme in line with the liability related investment objectives that have been set by the trustees of the schemes, and invests in a diversified portfolio of assets. The schemes are relatively young in nature (the schemes opened in 1997 on the formation of Centrica plc on demerger from BG plc (formerly British Gas plc), and only took on liabilities in respect of active employees). Therefore, the CCCIF holds a significant proportion of return seeking assets; such assets are generally expected to provide a higher return than corporate bonds, but result in greater exposure to volatility and risk in the short-term. The investment objectives are to achieve a target return above a return based on a portfolio of gilts, subject to a maximum volatility ceiling. If there have been advantageous asset movements relative to liabilities above a set threshold, then de-risking is undertaken, and as a consequence the return target and maximum volatility ceiling are reduced. Whilst there is no explicit target for the level or rate of de-risking, the pace of de-risking is regularly monitored and is typically restricted to once a quarter.

Interest rate

A decrease in the bond interest rate will increase the net present value of the pension liabilities. The relative immaturity of the schemes means that the duration of the liabilities is longer than average for typical UK pension schemes, resulting in a relatively higher exposure to interest rate risk.

Inflation

Pensions in deferment, pensions in payment and pensions accrued under the career average schemes increase in line with the Retail Price Index and the Consumer Price Index. Therefore scheme liabilities will increase if inflation is higher than assumed, although in some cases caps are in place to limit the impact of significant movements in inflation.

Longevity

The majority of the schemes’ obligations are to provide benefits for the life of scheme members and their surviving spouses; therefore increases in expected life expectancy will result in an increase in the pension liabilities. The relative immaturity of the schemes means that there is comparatively little observable mortality data to assess the rates of mortality experienced by the schemes, and means that the schemes’ liabilities will be paid over a long period of time, making it particularly difficult to predict the life expectancy of the current membership. Furthermore, pension payments are subject to inflationary increases, resulting in a higher sensitivity to changes in life expectancy.

Salary

For final salary schemes, the pension liabilities are calculated by reference to the future salaries of active members, and hence salary rises in excess of assumed increases will increase scheme liabilities. During 2011 changes were introduced to the final salary sections of CEPS and CPP such that annual increases in pensionable pay are capped to 2%, resulting in a reduction in salary risk.

Foreign exchange

Certain of the assets held by the CCCIF are denominated in foreign currencies, and hence their values are subject to exchange rate risk.

The CCCIF has long-term hedging programmes in place to manage interest rate, inflation and foreign exchange risks.

The table below analyses the total liabilities of the Registered Pension Schemes, calculated in accordance with accounting principles, by type of liability, as at 31 December 2013.

Total liabilities of the Registered Pension Schemes	Â	2013
31 December	Â	%
Actives - final salary – capped		29
Actives - final salary – uncapped and crystallised benefits		4
Actives - career average		5
Deferred pensioners		30
Pensioners	Â	32
Â	Â	100

(c) Accounting assumptions

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

Major assumptions used for the actuarial valuation	Â	2013	Â	2012
31 December	Â	%	Â	%
Rate of increase in employee earnings:
Subject to cap		1.7		1.7
Other		3.3		3.2
Rate of increase in pensions in payment		3.3		3.2
Rate of increase in deferred pensions:
In line with CPI capped at 2.5%		2.3		2.5
In line with RPI		3.3		3.2
Discount rate	Â	4.6	Â	4.8

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 an allowance for future improvements in mortality. The longevity assumptions for members in normal health are as follows:

	Â	2013			Â	2012
Life expectancy at age 65 for a member	Â	Male Years	Â	Female Years	Â	Male Years	Â	Female Years
Currently aged 65		22.9	Â	25.3		22.8	Â	25.2
Currently aged 45	Â	24.7	Â	27.3	Â	24.6	Â	27.2

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 valuations of the pension schemes.

Reasonably possible changes as at 31 December to one of the actuarial assumptions would have affected the scheme liabilities as set out below:

	Â	2013			Â	2012
Impact of changing material assumptions	Â	Increase/ decrease in assumption	Â	Indicative effect on scheme liabilities %	Â	Increase/ decrease in assumption	Â	Indicative effect on scheme liabilities %
Rate of increase in employee earnings subject to cap		0.25%	Â	+/–1		0.25%	Â	+/–1
Rate of increase in pensions in payment and deferred pensions		0.25%		+/–5		0.25%		+/–4
Discount rate		0.25%		–/+6		0.25%		–/+5
Inflation assumption		0.25%		+/–5		0.25%		+/–4
Longevity assumption	Â	1 year	Â	+/–3	Â	1 year	Â	+/–2

The indicative effects on scheme liabilities have been calculated by changing each assumption in isolation and assessing the impact on the liabilities. For the reasonably possible change in the inflation assumption, it has been assumed that a change to the inflation assumption would lead to corresponding changes in the assumed rates of increase in uncapped pensionable pay, pensions in payment and deferred pensions.

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

(d) Amounts included in the Group Balance Sheet

31 December	Â	2013 £m	Â	2012 £m
Fair value of plan assets	Â	5,683	Â	5,133
Present value of defined benefit obligation	Â	(5,643)	Â	(5,045)
Net asset recognised in the Group Balance Sheet	Â	40	Â	88
Pension asset presented in the Group Balance Sheet as:
Retirement benefit assets		205		254
Retirement benefit liabilities	Â	(165)	Â	(166)
Net pension asset	Â	40	Â	88

(e) Movement in the year

Â

Â

2013

Â

Â

2012 (restated) (i)

Â

Â

Pension liabilities £m

Â

Pension assets £m

Â

Pension liabilities £m

Â

Pension assets £m

1 January

(5,045)

5,133

(4,340)

4,670

Items included in the Group Income Statement:

Â

Â

Â

Â

Current service cost

(103)

–

(84)

–

Contributions by employer in respect of employee salary sacrifice arrangements (ii)

(19)

–

–

–

Total current service cost

(122)

–

(84)

–

Interest (expense)/income (i)

(242)

249

(235)

254

Items included in the Group Statement of Comprehensive Income:

Returns on plan assets, excluding interest income (i)

–

187

–

156

Actuarial loss from changes to demographic assumptions

(64)

–

(56)

–

Actuarial loss from changes in financial assumptions

(311)

–

(480)

–

Actuarial gain from experience adjustments

9

–

87

–

Exchange adjustments

12

(6)

2

(2)

Items included in the Group Cash Flow Statement:

Employer contributions

–

232

–

187

Contributions by employer in respect of employee salary sacrifice arrangements (ii)

–

19

–

–

Other movements:

Plan participants’ contributions

(7)

7

(27)

27

Benefits paid from schemes

138

(138)

159

(159)

Transfers from provisions for other liabilities and charges

Â

(11)

Â

–

Â

(71)

Â

–

31 December

Â

Â

Â

Â

(5,643)

Â

5,683

Â

(5,045)

Â

5,133

(i)	See note 1(a).
(ii)	A salary sacrifice arrangement was introduced on 1 April 2013 for pension scheme members. The contributions paid via the salary sacrifice arrangement have been treated as employer contributions, and included within current service cost, with a corresponding reduction in salary costs.

In addition to current service cost on the Group’s defined benefit pension schemes, the Group also charged £32 million (2012: £13 million) to operating profit in respect of defined contribution pension schemes. This included £8 million (2012: nil) contributions paid via a salary sacrifice arrangement.

(f) Pension scheme assets

The market value of plan assets were:

	Â		Â		Â	2013	Â		Â		Â	2012
31 December	Â	Quoted £m	Â	Unquoted £m	Â	Total £m	Â	Quoted £m	Â	Unquoted £m	Â	Total £m
Equities		1,636		163		1,799		1,756		146		1,902
Diversified asset funds		305		98		403		246		–		246
Corporate bonds		1,571		–		1,571		1,412		–		1,412
High-yield debt		155		207		362		173		151		324
Liability matching assets		1,012		258		1,270		1,005		22		1,027
Property		–		271		271		–		210		210
Cash pending investment	Â	7	Â	–	Â	7	Â	12	Â	–	Â	12
Â	Â	4,686	Â	997	Â	5,683	Â	4,604	Â	529	Â	5,133

Included within equities are £2 million (2012: £3 million) of ordinary shares of Centrica plc via pooled funds that include a benchmark allocation to UK equities. Included within corporate bonds are £4 million (2012: £3 million) of bonds issued by Centrica plc held within pooled funds over which the CCCIF has no ability to direct investment decisions. Apart from the investment in the Scottish Limited Partnerships described in note 14(g), no direct investments are made in securities issued by Centrica plc or any of its subsidiaries or property leased to or owned by Centrica plc or any of its subsidiaries.

Included within the Group Balance Sheet within non-current securities are £67 million (2012: £61 million) of investments, held in trust on behalf of the Group, as security in respect of the Centrica Unfunded Pension Scheme. Of the pension scheme liabilities above, £42 million (2012: £37 million) relate to this scheme.

(g) Pension scheme contributions

Based on the latest triennial valuations at 31 March 2012, the Group and the trustees of the Registered Pension Schemes agreed to fund the scheduled deficit payments using asset-backed contribution arrangements. Under the arrangements, certain loans to UK Group companies were transferred to Scottish Limited Partnerships established by the Group. During the year the Group made special contributions to the Registered Pension Schemes of £360 million (31 December 2012: £84 million); the schemes immediately used these contributions to acquire interests in the partnerships for their fair value of £360 million (31 December 2012: £84 million). The schemes’ total partnership interests now entitle them to distributions from the income of the partnerships over a period of between 4 and 15 years. £77 million was distributed in the year to 31 December 2013, £77 million per annum will be distributed from 2014 to 2016, and further reduced distributions will be made thereafter. The partnerships are controlled by and consolidated by the Group. As the trustees’ interests in the partnerships do not meet the definition of a plan asset under IAS 19, they are not reflected in the Group Balance Sheet. Distributions from the partnerships to the schemes will be recognised as scheme assets in the future as they occur. A continuing £590 million charge over the Humber power station provides additional security for the trustees.

Deficit payments are also being made in respect of the Direct Energy Marketing Limited Pension Plan in Canada. £7 million was paid in the year to 31 December 2013 and £7 million per annum is to be paid until 2018.

The Group estimates that it will pay £100 million of ordinary employer contributions during 2014 at an average rate of 21% of pensionable pay, together with £25 million of contributions paid via the salary sacrifice arrangement. At 31 March 2012 (the date of the latest full actuarial valuations) the weighted average duration of the liabilities of the Registered Pensions Schemes was 24 years.

15. ACQUISITIONS AND DISPOSALS

Business combinations

The Group has acquired a number of businesses during the year, including Hess Energy Marketing LLC (HEM) in the US and a package of gas and oil assets from Suncor Energy in Canada in partnership with Qatar Petroleum International (QPI). The business combinations section details the consideration paid, net assets acquired and the goodwill arising on these acquisitions.

The fair values are provisional unless stated otherwise. Note 3(a) sets out the assumptions used to derive the fair values. Goodwill recognised on the following acquisitions is attributable to enhanced geographical presence, cost savings, synergies, growth opportunities and technical goodwill from items such as deferred tax.

Suncor Upstream

The Group formed a 60:40 partnership (CQ Energy Canada Partnership, CQECP) with QPI and, on 26 September 2013, jointly acquired a package of producing conventional natural gas and crude oil assets and associated infrastructure located in the Western Canadian Sedimentary Basin from Suncor Energy for consideration of C$987 million (£601 million). The Group and QPI funded this acquisition using a mixture of equity and debt in CQECP. As described in note 3(a), the Group has judged that it has power over the relevant activities of CQECP and hence it will fully consolidate this entity. Accordingly, the Suncor acquisition is treated as a business combination of the Group and a purchase price allocation was performed.

The 40% equity interest owned by QPI is shown as a non-controlling interest and is recognised at the acquisition date fair value calculated using the income approach (which equals the equity cash injected by QPI into CQECP). The 40% financial liability due to QPI is included within other payables. Goodwill arising on the transaction is not deductible for tax purposes. This business forms part of the ‘Centrica Energy – Gas’ segment.

Hess Energy Marketing

The Group acquired 100% of the New Jersey-based energy marketing business, HEM, from Hess Corporation on 1 November 2013, for consideration of $1,194 million (£736 million). This included a payment for the working capital of the business of approximately $416 million (£257 million). A purchase price allocation was performed and goodwill arising is deductible for tax purposes. Included in the opening balance sheet is $586 million (£361 million) related to the fair value of the trade receivables, with a gross contractual amount of $613 million (£378 million). This business forms part of the ‘Direct Energy – Business energy supply’ segment.

Bounce Energy

On 13 August 2013 the Group acquired a 100% equity interest in the privately-owned Texas-based electricity retailer Bounce Energy (Bounce) for $42 million (£27 million) in cash. Goodwill of $47 million (£30 million) was recognised and is not tax deductible. This business forms part of the ‘Direct Energy – Residential energy supply’ segment.

America’s Water Heater Rentals

On 11 October 2013 the Group acquired a 100% equity interest in the privately owned America’s Water Heater Rentals (AWHR) for consideration of $30 million (£18 million). The business rents water heaters to approximately 89,000 residential customers. A tax deductible goodwill of $7 million (£4 million) arose on acquisition. This business forms part of the ‘Direct Energy – Residential and business services’ segment.

Provisional fair value of the identifiable acquired assets and liabilities

Â	Â	Suncor Upstream £m	Â	Hess Energy Marketing £m	Â	Other £m	Â	Total £m
Balance sheet items	Â		Â		Â		Â
Intangible assets		105		210		23		338
Property, plant and equipment		762		–		10		772
Other non-current assets		–		146		5		151
Current assets including £25 million of cash and cash equivalents		47		749		16		812
Current liabilities		(20)		(487)		(25)		(532)
Non-current liabilities	Â	(443)	Â	(93)	Â	(19)	Â	(555)
Net identifiable assets		451		525		10		986
Goodwill	Â	150	Â	211	Â	39	Â	400
Net assets acquired	Â	601	Â	736	Â	49	Â	1,386
Non-controlling interests – equity (i)		(81)		–		–		(81)
Financial liability due to non-controlling interest – other payables (i)	Â	(156)	Â	–	Â	–	Â	(156)
Total	Â	364	Â	736	Â	49	Â	1,149
Consideration comprises:
Cash consideration injected from Centrica (i)		355		736		49		1,140
Cash consideration injected from non-controlling interest upon acquisition (i)		237		–		–		237
Deferred consideration (i)	Â	9	Â	–	Â	–	Â	9
Total consideration transferred	Â	601	Â	736	Â	49	Â	1,386
Â	Â	Â	Â	Â	Â	Â	Â	Â
Income Statement items (ii)
Revenue recognised since the acquisition date in the Group Income Statement		62		906		27		995
(Loss)/profit since the acquisition date in the Group Income Statement	Â	(2)	Â	(2)	Â	2	Â	(2)

Acquisition-related costs have been charged to ‘operating costs before exceptional items’ in the Group Income Statement for the year ended 31 December 2013 for an aggregated amount of £4 million.

(i)

QPI injected £237 million of cash into CQECP, of which £81 million was equity, upon acquisition of Suncor Upstream. This equated to 40% of the initial purchase consideration of £592 million. At the same time, Centrica injected £355 million of cash into CQECP, of which £121 million was equity. The deferred consideration of £9 million will be funded directly by the operations of CQECP rather than further contributions from its owners.

(ii)

Revenue and (losses)/profits from business performance between the acquisition date and the balance sheet date, excluding exceptional items and certain re-measurements.

Pro forma information

The pro forma consolidated results of the Group, as if the acquisitions had been made at the beginning of the year, would show revenue of £30,584 million (compared to reported revenue of £26,571 million) and profit after taxation of £1,019 million (compared to reported profit after taxation of £950 million). This pro forma information includes the revenue and profits/losses made by the acquired businesses between the beginning of the financial year and the date of acquisition, not restated for accounting policy alignments and/or the impact of the fair value uplifts resulting from purchase accounting considerations. This pro forma aggregated information is not necessarily indicative of the results of the combined Group that would have occurred had the acquisitions actually been made at the beginning of the year presented, or indicative of the future results of the combined Group.

Note that despite the fact that the Group controls the relevant activities of CQECP, dividends are subject to unanimous consent of the partnership owners. This means that dividends are restricted as they require QPI approval. At the balance sheet date, cash and cash equivalents held by CQECP amounted to £66 million. If these funds were to be distributed as a dividend to owners, on a 60:40 basis, the non-controlling interests would be entitled to £26 million of the cash paid from the partnership.

2012 Business Combinations – fair value updates

There have been no significant updates in 2013 to the fair values recognised for businesses acquired in 2012.

Asset purchases

UK shale gas

On 13 June 2013, the Group acquired a 25% interest in the Bowland exploration licence in Lancashire from Cuadrilla Resources Ltd and AJ Lucas Group Ltd for £44 million in cash. The Group is committed to pay exploration and appraisal costs of up to £6 million (included in ‘Other intangible assets’ in note 16) and may pay up to £45 million additional costs under a carry arrangement which is contingent on consents being received. Following the exploration and appraisal phase, if the Group elects to continue into the development phase, a further contingent consideration of £60 million will become payable.

Disposals

The Group has disposed of a number of businesses and assets during the year. This note details the cash consideration received and the profit or loss arising.

Date of disposal	Â	Business/assets disposed of by the Group	Â	Sold to	Â	Cash consideration £m	Â	Profit/(loss) on disposal before tax £m
7 June 2013	Â	50% interest in the Braes of Doune Wind Farm (Scotland) Limited	Â	Hermes GPE Infrastructure fund	Â	59	Â	29
23 October 2013		Babbage upstream production licence		Bayerngas Europe Limited		19		(17)
12 December 2013		Centrica (RBW) Limited - Race Bank offshore Wind Farm project (i)		DONG Energy Power (UK) Limited		50		(6)
30 December 2013	Â	Various interests in upstream assets in the Heimdal area	Â	Lotos Exploration & Production Norge	Â	64	Â	9

(i) £31 million of contingent consideration has not been recognised.

On 18 March 2013, the Group legally disposed of its 20% investment in NNB Holding Company Limited (Nuclear New Build). A related exceptional impairment charge of £231 million was recorded in 2012.

Assets and liabilities of disposal groups classified as held for sale

Assets, and associated liabilities, that are expected to be recovered principally through a sale have been classified as held for sale on the face of the Balance Sheet, and include the Group’s gas-fired power stations in the US.

In October 2013, the Group agreed to sell its Greater Kittiwake upstream gas assets to Enquest Heather Limited, for cash consideration of $40 million (£24 million) plus contingent consideration. This transaction is expected to complete in February 2014.

On 18 December 2013, the Group announced that it had agreed to sell its Texas gas-fired power stations to Blackstone for $685 million (£420 million) in cash. This transaction completed on 22 January 2014.

Â	Â	Texas Power stations £m	Â	Greater Kittiwake Upstream gas assets £m	Â	Total £m
Property, plant and equipment	Â	186	Â	89	Â	275
Other assets	Â	9	Â	17	Â	26
Assets of disposal groups classified as held for sale	Â	195	Â	106	Â	301
Other liabilities		–		(50)		(50)
Non-current provisions for other liabilities and charges	Â	(3)	Â	(46)	Â	(49)
Liabilities of disposal groups classified as held for sale	Â	(3)	Â	(96)	Â	(99)
Net assets of disposal groups classified as held for sale and total shareholders’ equity	Â	192	Â	10	Â	202

16. COMMITMENTS AND CONTINGENCIES

(a) Commitments

Commitments are not held on the Group’s Balance Sheet as these are executory arrangements, and relate to amounts that we are contractually required to pay in the future as long as the other party meets its contractual obligations.

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.

On 25 March 2013, the Group and Company announced that it had entered into a 20 year agreement with Cheniere to purchase 89bcf per annum of LNG volumes for export from the Sabine Pass liquefaction plant in the US, subject to a number of project milestones and regulatory approvals being achieved. Under the terms of the agreement the Group is committed to make capacity payments of up to £3.7 billion (included in ‘LNG capacity’ below) between 2018 and 2038. The Group may also make up to £6 billion of commodity purchases based on market gas prices and foreign exchange rates as at the balance sheet date. The target date for first commercial delivery is September 2018.

31 December	Â	2013 £m	Â	2012 £m
Commitments in relation to the acquisition of property, plant and equipment:	Â		Â
Development of Norwegian oil and gas assets		159		283
Development of Cygnus gas field		146		88
Other capital expenditure	Â	51	Â	21
Commitments in relation to the acquisition of intangible assets:
Renewable obligation certificates to be purchased from joint ventures (i)		1,169		1,376
Renewable obligation certificates to be purchased from other parties		1,516		784
Other intangible assets	Â	205	Â	147
Other commitments:
Commodity purchase contracts		49,831		51,933
LNG capacity		4,452		844
Transportation capacity		939		936
Outsourcing of services		226		277
Commitments to invest in joint ventures		130		174
Energy Company Obligation		255		–
Power station tolling fees		125		–
Smart meters		62		6
Power station operating and maintenance		138		150
Other long term commitments	Â	333	Â	406
Operating lease commitments:
Future minimum lease payments under non-cancellable operating leases	Â	975	Â	974

(i) 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.

At 31 December the maturity analyses for commodity purchase contract commitments and the total minimum lease payments under non-cancellable operating leases were:

Â	Â	Commodity purchase contracts commitments			Â	Total minimum lease payments under non-cancellable operating leases
31 December	Â	2013 £billion	Â	2012 £billion	Â	2013 £m	Â	2012 £m
<1 year	Â	11.1	Â	9.2	Â	217	Â	222
1-2 years		8.1		7.2		138		98
2-3 years		5.8		5.9		89		82
3-4 years		3.8		5.1		64		64
4-5 years		3.7		3.0		54		54
>5 years	Â	17.3	Â	21.5	Â	413	Â	454
Â	Â	49.8	Â	51.9	Â	975	Â	974

Operating lease payments recognised as an expense in the year were as follows:

Year ended 31 December	Â	2013 £m	Â	2012 £m
Minimum lease payments (net of sub-lease receipts)	Â	112	Â	125
Contingent rents – renewables (i)	Â	109	Â	130

(i) The Group has entered into long-term arrangements with renewable providers to purchase physical power, renewable obligation certificates and levy exemption certificates from renewable sources. Payments made under these contracts are contingent upon actual production and so there is no commitment to a minimum lease payment (2012: nil). Payments made for physical power are charged to the Income Statement as incurred and disclosed as contingent rents.

(b) Guarantees and indemnities

This section discloses any guarantees and indemnities that the Group has given, where we may have to provide security in the future against existing and future obligations that will remain for a specific period.

In connection with the Group’s energy trading, transportation and upstream activities, certain Group companies have entered into contracts under which they may be required to prepay, provide credit support or provide other collateral in the event of a significant deterioration in creditworthiness. The extent of credit support is contingent upon the balance owing to the third party at the point of deterioration.

The Group has provided a number of guarantees and indemnities in respect of decommissioning costs; the two most significant indemnities relate to the decommissioning costs associated with the Morecambe and Statfjord fields. These indemnities are to the previous owners of these fields. Under the licence conditions of the fields, the previous owners will have exposure to the decommissioning costs should these liabilities not be fully discharged by the Group.

Security is to be provided when the estimated future net revenue stream from the associated gas field falls below a predetermined proportion of the estimated decommissioning cost. The nature of the security may take a number of different forms and will remain in force until the costs of such decommissioning have been irrevocably discharged and the relevant legal decommissioning notices in respect of the relevant fields have been revoked.

(c) Contingent liabilities

There are no material contingent liabilities other than those disclosed in note 15.

17. EVENTS AFTER THE BALANCE SHEET DATE

The Group updates disclosures in light of new information being received, or a significant event occurring, in the period between 31 December 2013 and the date of this report.

Disposals

In October 2013, the Group agreed to sell its Greater Kittiwake upstream gas assets to Enquest Heather Limited, for cash consideration of $40 million (£24 million) plus contingent consideration. This transaction is expected to complete in February 2014.

On 18 December 2013, the Group announced that it had agreed to sell its Texas gas-fired power stations to Blackstone for $685 million (£420 million) in cash. This transaction completed on 22 January 2014.

Share repurchase programme

On 18 December 2013, the Group announced that it will return the proceeds from the sale of the Texas gas-fired power stations to shareholders through a £420 million extension of its share repurchase programme, which will be conducted during 2014.

Dividends

The Directors propose a final dividend of 12.08 pence per ordinary share (totalling £614 million) for the year ended 31 December 2013. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 12 May 2014 and, subject to approval, will be paid on 11 June 2014 to those shareholders registered on 25 April 2014.

18. 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 2013 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 to 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 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 at their 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)

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

Â

Â

Â

Â

2013

Â

Â

Â

2012 (restated) (i)

Six months ended 31 December

Â

Notes

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Results for the period £m

Â

Business performance £m

Â

Exceptional items and certain re-measurements £m

Â

Results for the period £m

Â

Group revenue

21(a)

12,920

Â

–

Â

12,920

11,965

Â

–

Â

11,965

Cost of sales before exceptional items and certain re-measurements (i)

(10,578)

–

(10,578)

(9,395)

–

(9,395)

Exceptional items

22(a)

–

(125)

(125)

–

(89)

(89)

Re-measurement of energy contracts

22(b)

–

Â

309

Â

309

–

Â

90

Â

90

Cost of sales

Â

Â

Â

(10,578)

Â

184

Â

(10,394)

Â

(9,395)

Â

1

Â

(9,394)

Gross profit

2,342

Â

184

Â

2,526

2,570

Â

1

Â

2,571

Operating costs before exceptional items (i)

(1,403)

–

(1,403)

(1,436)

–

(1,436)

Exceptional items

22(a)

–

Â

(939)

Â

(939)

–

Â

(355)

Â

(355)

Operating costs

(1,403)

(939)

(2,342)

(1,436)

(355)

(1,791)

Share of profits/(losses) in joint ventures and associates, net of interest and taxation

Â

Â

Â

94

Â

24

Â

118

Â

82

Â

(4)

Â

78

Group operating profit

21(b)

1,033

Â

(731)

Â

302

1,216

Â

(358)

Â

858

Financing costs (i)

(168)

–

(168)

(138)

–

(138)

Investment income (i)

28

Â

–

Â

28

31

Â

–

Â

31

Net finance cost

Â

Â

Â

(140)

Â

–

Â

(140)

Â

(107)

Â

–

Â

(107)

Profit before taxation

893

(731)

162

1,109

(358)

751

Taxation on profit (i)

Â

Â

Â

(293)

Â

262

Â

(31)

Â

(510)

Â

28

Â

(482)

Profit for the period

Â

Â

Â

600

Â

(469)

Â

131

Â

599

Â

(330)

Â

269

Attributable to:

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Owners of the parent

Â

Â

Â

600

Â

(469)

Â

131

Â

599

Â

(330)

Â

269

Â

Earnings per ordinary share

Â

Â

Â

Â

Â

Â

Â

Pence

Â

Â

Â

Â

Â

Pence

Basic (i)

23

Â

2.5

Â

5.2

Diluted (i)

Â

23

Â

Â

Â

Â

Â

2.5

Â

Â

Â

Â

Â

5.2

(i) See note 1(a).

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

	Â	2013 £m	Â	2012 £m
Group operating profit including share of results of joint ventures and associates	Â	302	Â	858
Less share of profit of joint ventures and associates	Â	(118)	Â	(78)
Group operating profit before share of results of joint ventures and associates		184		780
Add back/(deduct):
Depreciation, amortisation, write-down and impairments		1,640		1,020
Loss on disposals		9		5
Increase in provisions		189		153
Defined benefit pension service cost and contributions		(84)		(45)
Employee share scheme costs		20		20
Unrealised gains arising from re-measurement of energy contracts	Â	(279)	Â	(72)
Operating cash flows before movements in working capital		1,679		1,861
Increase in inventories		(71)		(31)
Increase in trade and other receivables (i)		(420)		(334)
Increase in trade and other payables (i)	Â	924	Â	632
Operating cash flows before payments relating to taxes, interest and exceptional charges		2,112		2,128
Taxes paid		(491)		(241)
Payments relating to exceptional charges	Â	(92)	Â	(99)
Net cash flow from operating activities	Â	1,529	Â	1,788
Purchase of businesses		(1,113)		(81)
Sale of businesses		135		3
Purchase of intangible assets and property, plant and equipment		(826)		(967)
Sale of property, plant and equipment and intangible assets		11		9
Investments in joint ventures and associates		(17)		(171)
Dividends received from joint ventures and associates		90		74
Repayments of loans to, and disposal of investments in, joint ventures and associates		–		5
Interest received		18		12
(Purchase)/sale of securities	Â	(2)	Â	1
Net cash flow from investing activities	Â	(1,704)	Â	(1,115)
Issue and surrender of ordinary share capital for share awards		11		10
Purchase of treasury shares under share repurchase programme		(299)		(2)
Distribution paid to non-controlling interests		(8)		–
Financing interest paid		(132)		(154)
Repayment of borrowings		(348)		(487)
Cash received from borrowings		1,137		179
Equity dividends paid	Â	(255)	Â	(244)
Net cash flow from financing activities	Â	106	Â	(698)
Net (decrease)/increase in cash and cash equivalents		(69)		(25)
Cash and cash equivalents at beginning of period		800		954
Effect of foreign exchange rate changes	Â	(12)	Â	2
Cash and cash equivalents at 31 December	Â	719	Â	931
Included in the following line of the Balance Sheet:
Cash and cash equivalents	Â	719	Â	931

(i) Includes net inflow of £84 million of cash collateral in 2013 (2012: net outflow of £18 million).

21. SEGMENTAL ANALYSIS FOR THE SIX MONTHS ENDED 31 DECEMBER

(a) Revenue

	Â		Â		Â	2013	Â		Â		Â	2012 (restated) (i)
Six months ended 31 December	Â	Gross segment revenue £m	Â	Less inter- segment revenue £m	Â	Group revenue £m	Â	Gross segment revenue £m	Â	Less inter- segment revenue £m	Â	Group revenue £m
International Downstream		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Residential energy supply		4,001		–		4,001		4,314		–		4,314
Residential services		850		(81)		769		863		(75)		788
Business energy supply and services		1,463	Â	(36)	Â	1,427		1,473	Â	(5)	Â	1,468
British Gas		6,314		(117)		6,197		6,650		(80)		6,570
		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Residential energy supply		1,209		–		1,209		1,147		–		1,147
Business energy supply (i)		2,629		(33)		2,596		1,495		(29)		1,466
Residential and business services		296	Â	–	Â	296		279	Â	–	Â	279
Direct Energy		4,134		(33)		4,101		2,921		(29)		2,892
													Â
International Upstream		Â	Â	Â	Â	Â		Â	Â	Â	Â	Â
Gas (i)		2,148		(44)		2,104		2,068		(146)		1,922
Power		720	Â	(251)	Â	469		597	Â	(104)	Â	493
Centrica Energy		2,868		(295)		2,573		2,665		(250)		2,415
													Â
Centrica Storage	Â	81	Â	(32)	Â	49	Â	111	Â	(23)	Â	88
Â	Â	13,397	Â	(477)	Â	12,920	Â	12,347	Â	(382)	Â	11,965

(i) Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).

(b) Operating profit

Six months ended 31 December	Â	2013 £m	Â	2012 (restated) (i) £m
International Downstream	Â	Â	Â	Â
Residential energy supply		215		261
Residential services		183		187
Business energy supply and services		63		82
British Gas		461		530
		Â		Â
Residential energy supply		64		55
Business energy supply (i)		24		78
Residential and business services		23		22
Direct Energy		111		155
				Â
International Upstream		Â		Â
Gas (i)		472		421
Power		52		137
Centrica Energy		524		558
				Â
Centrica Storage	Â	16	Â	53
Adjusted operating profit – segment operating profit before exceptional items, certain re-measurements and impact of fair value uplifts from Strategic Investments (iii)		1,112		1,296
Share of joint ventures/associates’ interest and taxation		(64)		(36)
Depreciation of fair value uplifts to property, plant and equipment – Venture (ii)		(21)		(30)
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – British Energy (ii)	Â	6	Â	(14)
		1,033		1,216
Exceptional items (note 22)		(1,064)		(444)
Certain re-measurements included within gross profit (note 22)		309		90
Certain re-measurements of associates’ energy contracts (net of taxation) (note 22)	Â	24	Â	(4)
Operating profit after exceptional items and certain re-measurements	Â	302	Â	858

(i)	Prior period comparatives have been restated to reflect the new organisational structure announced by the Group on 27 February 2013. See note 5(a).
(ii)	See note 2 and note 10 for an explanation of the depreciation on fair value uplifts to PP&E on the Strategic Investments acquired in 2009.
(iii)	Includes results of equity-accounted interests before interest and taxation.

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

(a) Exceptional items	Â		Â
Six months ended 31 December	Â	2013 £m	Â	2012 £m
Provision for onerous power procurement contract (i)		(125)		–
Provision for Direct Energy wind power purchase agreements	Â	–	Â	(89)
Exceptional items included within gross profit	Â	(125)	Â	(89)
Impairment of UK and North American exploration and production assets (ii)		(699)		–
Impairment of UK gas storage assets and associated provision for onerous capacity contracts (iii)		(240)		–
Restructuring charges		–		(124)
Impairment of investment in nuclear new build	Â	–	Â	(231)
Â	Â	(939)	Â	(355)
Exceptional items included within Group operating profit		(1,064)		(444)
Taxation on exceptional items		397		69
Effect of change in upstream UK tax rates	Â	–	Â	(40)
Total exceptional items after taxation	Â	(667)	Â	(415)
Â
(b) Certain re-measurements		Â		Â
Â
		2013		2012
Six months ended 31 December	Â	£m	Â	£m
Certain re-measurements recognised in relation to energy contracts:
Net gains arising on delivery of contracts		26		254
Net gains/(losses) arising on market price movements and new contracts	Â	283	Â	(164)
Net re-measurements included within gross profit		309		90
Net gains/(losses) arising on re-measurement of associates’ energy contracts (net of taxation)	Â	24	Â	(4)
Net re-measurements included within Group operating profit	Â	333	Â	86
Taxation on certain re-measurements	Â	(135)	Â	(1)
Net re-measurements after taxation	Â	198	Â	85

(i)	The Group has recognised a further £125 million onerous contract charge in the ‘Centrica Energy – Power’ segment for the Rijnmond tolling contract as a result of decreases in expected future revenues.
(ii)	Following reserve and resources downgrades, and increases in expected costs on the Seven Seas, York and Ensign fields in the Southern North Sea, the Group recognised pre-tax impairment charges of £166 million (post-tax charge £63 million) on the Seven Seas field, £221million (post-tax charge £97 million) on the York field, and £225 million (post-tax charge £92 million) on the Ensign field in the ‘Centrica Energy – Gas’ segment. As a result of the weaker outlook for North American natural gas prices, and an increase in the discount rate applicable to these assets, the Group recognised a pre-tax Income Statement impairment charge of £87 million (post-tax charge £66 million) in relation to the Canadian Upstream assets held prior to the Suncor Upstream acquisition, in the ‘Centrica Energy – Gas’ segment. A further £20 million charge (£15 million net of taxation) was recognised in other comprehensive income to reverse previous upwards revaluations of the impaired assets, giving a total impairment of the Canadian Upstream assets held prior to the Suncor Upstream acquisition, of £107 million.
(iii)	In light of weak economics for storage projects, and following announcements regarding future government support for gas storage in the UK, the Group announced its decision not to proceed with the Baird offshore gas storage project and to put the onshore project at Caythorpe on hold indefinitely. As a result, the Group has recorded pre-tax impairments and provision charges totalling £240 million (post-tax charge £224 million) in the ‘Centrica Storage’ segment. Goodwill (£33 million), property, plant and equipment (£105 million) and investments in joint ventures and associates (£55 million) have been written off during the year, and an onerous capacity contract provision of £47 million was recognised.

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

	Â		Â	2013	Â		Â	2012 (restated) (i)
Six months ended 31 December	Â	£m	Â	Pence per ordinary share	Â	£m	Â	Pence per ordinary share
Earnings – basic (i)		131		2.5		269		5.2
Net exceptional items after taxation (notes 2 and 22)		667		12.9		415		8.0
Certain re-measurement gains after taxation (notes 2 and 22)		(198)		(3.8)		(85)		(1.6)
Depreciation of fair value uplifts to property, plant and equipment from Strategic Investments, after taxation	Â	3	Â	0.1	Â	26	Â	0.5
Earnings – adjusted basic (i)	Â	603	Â	11.7	Â	625	Â	12.1
Â	Â	Â	Â	Â	Â	Â	Â	Â
Earnings – diluted (i)	Â	131	Â	2.5	Â	269	Â	5.2
Â	Â	Â	Â	Â	Â	Â	Â	Â
Earnings – adjusted diluted (i)	Â	603	Â	11.6	Â	625	Â	12.0

(i) See note 1(a).

Gas and Liquid 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 Europe are Kvitebjorn, Statfjord, Cygnus, South Morecambe, Maria, Chiswick, Valemon, Butch, Rhyl, Grove and York. The principal field in Trinidad and Tobago is NCMA-1. The principal field in Centrica Storage is the Rough field. 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, Hanlan and Medicine Hat in the province of Alberta, Canada. The Canadian field 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)	Â	Europe	Â	Canada	Â	Trinidad and Tobago (v)	Â	Centrica Energy	Â	Centrica Storage	Â	Total
1 January 2013 (i)	Â	2,236	Â	581	Â	140	Â	2,957	Â	182	Â	3,139
Revisions of previous estimates (ii)		(32)		10		7		(15)		–		(15)
(Disposals)/purchases of reserves in place (iii)		(43)		567		–		524		–		524
Extensions, discoveries and other additions (iv)		107		33		–		140		–		140
Production (vi)	Â	(257)	Â	(61)	Â	(19)	Â	(337)	Â	–-	Â	(337)
31 December 2013	Â	2,011	Â	1,130	Â	128	Â	3,269	Â	182	Â	3,451

Estimated net 2P reserves of liquids (million barrels)

Â

Europe

Â

Canada

Â

Trinidad and Tobago (v)

Â

Centrica Energy

Â

Centrica Storage

Â

Total

1 January 2013 (i)

Â

129

Â

11

Â

–

Â

140

Â

–

Â

140

Revisions of previous estimates

(1)

(1)

–

(2)

–

(2)

(Disposals)/purchases of reserves in place

(2)

11

–

9

–

9

Extensions, discoveries and other additions (iv)

38

2

–

40

–

40

Production (vi)

Â

(19)

Â

(1)

Â

–

Â

(20)

Â

–

Â

(20)

31 December 2013

Â

145

Â

22

Â

–

Â

167

Â

–

Â

167

Estimated net 2P reserves (million barrels of oil equivalent)

Â

Europe

Â

Canada

Â

Trinidad and Tobago (v)

Â

Centrica Energy

Â

Centrica Storage

Â

Total

31 December 2013 (vii)

Â

480

Â

210

Â

21

Â

711

Â

30

Â

741

(i)	See note 5(a).
(ii)	Revision of previous estimates including those associated with Seven Seas and Ensign.
(iii)	Reflects our share of the acquisition of producing assets in Canada from Suncor Energy, and the disposals of Babbage and assets in the Heimdal area.
(iv)	Recognition of reserves including the Kvitebjorn, Statfjord and Whitehaven fields in Centrica Energy.
(v)	The Trinidad and Tobago reserves are subject to a production sharing contract and accordingly have been stated on an entitlement basis (including tax barrels).
(vi)	Represents total sales volumes of gas and oil produced from the Group’s reserves.
(vii)	Includes the total of estimated gas and liquid reserves at 31 December 2013 in million barrels of oil equivalent.

Liquids reserves include oil, condensate and natural gas liquids.

Ofgem Consolidated Segmental Statement

The Ofgem Consolidated Segmental Statement (CSS) segments our Supply and Generation activities and provides a measure of profitability, weighted average cost of fuel, and volumes, in order to increase energy market transparency for consumers and other stakeholders.

The following is an extract of the audited CSS and is prepared in accordance with Standard Condition 19A of the Electricity and Gas Supply Licences and Standard Condition 16B of Electricity Generation Licences. This extract should be read in conjunction with the full CSS which includes the Statement, the audit opinion and the basis of preparation. These are available on www.centrica.com/prelims2013.

Year ended 31 December 2013																			Â	Â
																			Â
Â	Â	Unit	Â	Generation					Â	Aggregate Generation (i)	Â	Electricity Supply			Â	Gas Supply			Â	Aggregate Supply Business
	Â		Â	Nuclear	Â	Thermal	Â	Renewables			Â	Domestic	Â	Non-Domestic	Â	Domestic	Â	Non-Domestic	Â			Midstream (ii)
Total revenue		£m		628	Â	590	Â	157	Â	1,375		3,497	Â	1,951		6,091	Â	904		12,443		111
Sales of electricity & gas		£m		622		576		51		1,249		3,458		1,941		6,052		904		12,355		71
Other revenue	Â	£m	Â	6	Â	14	Â	106	Â	126	Â	39	Â	10	Â	39	Â	–	Â	88		40
Total operating costs	Â	£m	Â	(324)	Â	(630)	Â	(105)	Â	(1,059)	Â	(3,441)	Â	(1,897)	Â	(5,512)	Â	(804)	Â	(11,654)		(79)
Direct fuel costs		£m		(99)		(475)		–		(574)		(1,554)		(1,010)		(3,282)		(538)		(6,384)		-
Direct costs	Â	£m	Â	(202)	Â	(99)	Â	(54)	Â	(355)	Â	(1,382)	Â	(681)	Â	(1,500)	Â	(157)	Â	(3,720)		(69)
Network costs		£m		(32)		(36)		(3)		(71)		(903)		(442)		(1,159)		(140)		(2,644)		-
Environmental and social obligation costs		£m		–		–		–		–		(479)		(211)		(341)		–		(1,031)		-
Other direct costs	Â	£m	Â	(170)	Â	(63)	Â	(51)	Â	(284)	Â	–	Â	(28)	Â	–	Â	(17)	Â	(45)		(69)
Indirect costs	Â	£m	Â	(23)	Â	(56)	Â	(51)	Â	(130)	Â	(505)	Â	(206)	Â	(730)	Â	(109)	Â	(1,550)		(10)
WACOF/E/G	Â	£/MWh, P/th	Â	(8.18)	Â	(53.37)	Â	N/A	Â	N/A	Â	(61.91)	Â	(58.38)	Â	(75.6)	Â	(68.6)	Â	N/A		N/A
EBITDA	Â	£m	Â	304	Â	(40)	Â	52	Â	316	Â	56	Â	54	Â	579	Â	100	Â	789		32
DA	Â	£m	Â	(54)	Â	(93)	Â	(27)	Â	(174)	Â	(28)	Â	(5)	Â	(36)	Â	(3)	Â	(72)		(3)
EBIT	Â	£m	Â	250	Â	(133)	Â	25	Â	142	Â	28	Â	49	Â	543	Â	97	Â	717		29
Volume	Â	TWh, MThms	Â	12.1	Â	8.9	Â	0.7	Â	21.7	Â	25.1	Â	17.3	Â	4,342	Â	784	Â	N/A
								Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â	Â
								Supply EBIT margin	Â		Â	0.8%	Â	2.5%	Â	8.9%	Â	10.7%	Â	5.8%
								Supply PAT £m	Â		Â	21	Â	39	Â	402	Â	78	Â	540
								Supply PAT margin	Â		Â	0.6%	Â	2.0%	Â	6.6%	Â	8.6%	Â	4.3%

2012 Summarised CSS – Unaudited

Year ended 31 December 2012

Â

Â

Unit

Â

Generation

Â

Aggregate Generation re-presented (iii)

Â

Electricity Supply

Â

Gas Supply

Â

Aggregate Supply Business

Â

Â

Â

Â

Nuclear

Â

Thermal

Â

Renewables

Â

Â

Domestic

Â

Non-Domestic

Â

Domestic

Â

Non-Domestic

Â

Midstream (ii) (iii)

Total revenue

Â

£m

Â

603

Â

598

Â

96

Â

1,297

Â

3,237

Â

1,841

Â

5,884

Â

1,014

Â

11,976

142

EBIT

Â

£m

Â

237

Â

(4)

Â

56

Â

289

Â

(53)

Â

65

Â

659

Â

119

Â

790

22

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Â

Supply EBIT margin

Â

(1.6)%

Â

3.5%

Â

11.2%

Â

11.7%

Â

6.6%

Supply PAT £m

Â

(40)

Â

48

Â

497

Â

88

Â

593

Supply PAT margin

Â

(1.2)%

Â

2.6%

Â

8.4%

Â

8.7%

Â

5.0%

(i)	The Generation Segment was granted no free carbon allowances in 2013.
(ii)	Midstream includes results from non-licenced activities related to power trading and bilateral arrangements with third party owners of power generation assets in the UK and Europe (included in the ‘Centrica Energy – Power’ segment as defined in the Centrica plc Preliminary Results of the year ended 31 December 2013 (Note 5)).
(iii)	The Aggregate Generation segment has been re-presented to separately disclose the certain non-licenced Midstream activities previously included in the Generation segment in the 2012 CSS (Total revenue £34 million, EBIT £2 million). These results are now presented within the Midstream segment.

Disclaimer

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 2013 Preliminary Results presentation for analysts and institutional investors at 9.30am (UK) on Thursday 20 February 2014. There will be a live audio webcast of the presentation and slides 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 2013 Preliminary Results Announcement”.

An archived webcast and full transcript of the presentation and the question and answer session will be available on the website on Monday 24 February 2014.

ENQUIRIES

Investors and Analysts:	Â	Andrew Page	Â	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 2013 final dividend	Â	23 April 2014
Record date for 2013 final dividend		25 April 2014
2013 final dividend payment date		11 June 2014
Interim Management Statement		12 May 2014
Annual General Meeting		12 May 2014
2014 Interim results announcement		31 July 2014

REGISTERED OFFICE

Millstream, Maidenhead Road, Windsor, Berkshire SL4 5GD