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Centrica plc (CNA)

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Thursday 19 February, 2015

Centrica plc

Final Results

Final Results

Centrica plc

CENTRICA PLC

PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2014

Financial summary

               
Year ended 31 December   2014     2013   Change
Revenue   £29.4bn     £26.6bn   11%
Adjusted operating profit £1,746m £2,695m (35%)
Adjusted effective tax rate 30% 43% (13ppt)
Adjusted earnings £962m £1,370m (30%)
Adjusted basic earnings per share (EPS) 19.2p 26.6p (28%)
Full year dividend per share 13.5p 17.0p (21%)
Group net debt (i) £5,196m £4,942m 5%
Group net investment   £829m     £2,565m   (68%)
               
Statutory operating (loss)/profit (£1,137m) £1,892m nm
Statutory (loss)/profit for the year attributable to shareholders (£1,012m) £950m nm
Net exceptional items after tax included in statutory (loss)/profit (£1,161m) (£667m) nm
Basic earnings per share   (20.2p)     18.4p   nm
(i) The Group’s definition of net debt has been restated to include cash collateral posted or received, to support wholesale energy procurement.
Unless otherwise stated, all references to operating profit or loss, taxation, earnings and earnings per share throughout the announcement are adjusted figures, reconciled to their statutory equivalents in the Group Financial Review on pages 8 to 11.

2014 Group results

  • Group adjusted EPS down 28%, reflecting challenging trading conditions, including extreme weather patterns and falling oil and gas prices. Post-tax impairments of £1,385 million on E&P and power assets
    • British Gas operating profit down, primarily reflecting lower consumption in record warm year, with average dual fuel profit per household falling to £42. Average actual household energy bill around £100 lower than in 2013
    • Direct Energy operating profit down due to impact of polar vortex in Q1 and narrowing of energy supply margins in a competitive environment
    • Centrica Energy gas operating profit before tax down, reflecting lower market prices. Post-tax earnings largely protected by hedging, tax allowances on previous investments, and strong midstream performance. Power profit impacted by unplanned nuclear outages

2015 environment and response

  • Since the November IMS, our forecast 2015 adjusted EPS has been negatively impacted by about 2.5p, primarily due to changes in the external environment. 2015 adjusted earnings are expected to be down compared to 2014
  • Taking action in a low commodity price environment
    • 40% reduction in E&P capex to £650 million by 2016
    • Continued focus on competitiveness, service and efficiency downstream
    • Group-wide performance improvement plan, with a strong cost focus
    • Dividend rebased by 30%, commencing with the 2014 final dividend. 2014 full year dividend of 13.5p per share
  • Decision to retain UK CCGTs, with bids received significantly below our internal valuation
  • Strategic review launched, to be concluded by Interim Results in July 2015 covering; (i) outlook and sources of growth; (ii) portfolio mix and capital intensity; (iii) operating capability and efficiency; (iv) Group financial framework

Iain Conn, Centrica Chief Executive

“2014 was a very difficult year for Centrica and the recent fall in oil and gas prices creates further challenge. We are cutting investment and costs in response. However, it is with regret that, along with reducing capital expenditure and driving efficiency beyond planned levels, we have taken the difficult decision to rebase the dividend by 30%, commencing with the final distribution for 2014. In addition, given the changed external environment we are reviewing the longer term strategy, and will conclude this by the Interim Results in July. Despite the obvious current challenges, I am confident in the quality of Centrica’s team and the platform which has been established, and I believe the Group is well-placed to take advantage of the longer term trends in the global energy markets. Our priorities remain to serve our customers competitively and with integrity, to develop new offers and services, to provide secure and reliable energy supplies and to deliver long term value for shareholders.”

DIVISIONAL OPERATING PROFIT

Adjusted operating profit

               
Year ended 31 December   2014     2013   Change
British Gas        
Residential energy supply £439m £571m (23%)
Business energy supply and services £114m £141m (19%)
Residential services   £270m     £318m   (15%)
Total British Gas   £823m     £1,030m   (20%)
Direct Energy
Residential energy supply £90m £163m (45%)
Business energy supply £32m £77m (58%)
Residential and business services   £28m     £36m   (22%)
Total Direct Energy   £150m     £276m   (46%)
Bord Gáis Energy   £7m     -   nm
Centrica Energy
Gas £606m £1,155m (48%)
Power £131m £171m (23%)
Gas-fired (£120m) (£133m) nm
Renewables (operating assets) £27m £36m (25%)
Renewables (one-off write-offs, profit/loss on disposal) (£17m) (£11m) nm
Nuclear £210m £250m (16%)
Midstream   £31m     £29m   7%
Total Centrica Energy   £737m     £1,326m   (44%)
Gas – adjusted operating profit after tax   £302m     £325m   (7%)
Centrica Storage   £29m     £63m   (54%)
Total adjusted operating profit   £1,746m     £2,695m   (35%)

KEY PERFORMANCE INDICATORS

Key Operational Performance Indicators

               
Year ended 31 December   2014     2013   Change
Group        
Lost time injury frequency rate (per 100,000 hours worked)   0.14     0.11   27%
British Gas
Residential energy customer accounts (year end, ’000) (i) 14,778 15,146 (2%)
Residential services product holding (year end, ’000) 7,970 8,227 (3%)
Business energy supply points (year end, ’000) (ii) 854 916 (7%)
 
Total gas volumes (mmth) 4,085 5,126 (20%)
Total electricity volumes (TWh)   39.1     42.4   (8%)
Direct Energy
Residential energy customer accounts (year end, ’000) 3,256 3,360 (3%)
Residential services product holding (year end, ’000) (iii) 897 2,608 (66%)
Business energy supply gas volumes (mmth) 5,923 1,839 222%
Business energy supply electricity volumes (TWh) 96.9 63.9 52%
 
Total gas volumes (mmth) 8,163 3,883 110%
Total electricity volumes (TWh)   116.3     83.4   39%
Bord Gáis Energy
Residential energy customer accounts (year end, ’000) 608 nm
 
Total gas volumes (mmth) 106 nm
Total electricity volumes (TWh) 1.4 nm
Total power generated (TWh)   0.9       nm
Centrica Energy
Gas production (mmth) (iv) 3,772 3,557 6%
Liquids production (mmboe) (iv) 17.3 18.7 (7%)
Total gas and liquids production (mmth) (iv) 4,822 4,690 3%
Total gas and liquids production (mmboe) (iv) 79.5 77.3 3%
Upstream proven and probable reserves (mmboe) (v) 585 711 (18%)
Total UK power generated (TWh)   22.1     21.7   2%
(i) British Gas 2013 residential energy customer accounts have been restated to exclude 110,000 accounts subsequently reclassified as dormant
(ii) British Gas 2013 business energy supply points have been restated to include 4,000 supply points to align to industry reporting changes
(iii) Direct Energy 2014 residential services product holding reflects the disposal of the Ontario home services business, which had 1.9 million product holdings at the time of disposal
(iv) Includes 100% share of Canadian assets owned in partnership with QPI
(v) Centrica’s share of reserves, including a 60% share of Canadian assets owned in partnership with QPI, and excluding Rough cushion gas of 30mmboe. Includes the impact of QPI’s investment in 40% of our wholly-owned Canadian gas and liquids assets in the year

Enquiries

Investors and Analysts:   Martyn Espley   tel: 01753 494900  

email: [email protected]

Media: Sophie Fitton tel: 0800 107 7014

email: [email protected]

Interviews with Iain Conn (Chief Executive), Jeff Bell (Interim Chief Financial Officer), Mark Hanafin (Managing Director, Centrica Energy) and Ian Peters (Interim Managing Director, British Gas) are available on www.centrica.com

CHIEF EXECUTIVE’S STATEMENT

Overview

Centrica occupies a vital role in the energy affairs of the UK in particular, and also in the US and the Republic of Ireland. We are a customer facing business, and our principal role is to deliver excellence in the supply and reliability of energy and services to those customers. Although we are facing some significant challenges at present, it is clear to me that Centrica has built a solid set of positions, from which we will be able to continue to play an important role in the developing energy markets on both sides of the Atlantic.

The 2014 environment was very difficult for Centrica, with record mild weather in the UK, extreme cold weather in North America early in the year and a highly competitive market environment on both sides of the Atlantic. Upstream, the exploration and production (E&P) business faced falling oil and gas prices, while Centrica Storage was impacted by lower seasonal gas price spreads. Political uncertainty and the launch of the Competition and Markets Authority investigation provided further challenges in the UK.

Operationally, in British Gas these conditions translated into falls in gas and electricity sales volumes of 20% and 8% respectively, and a 2% fall in residential energy customer accounts, mostly in the first half of the year. Direct Energy also saw a 3% fall in residential energy customer accounts. In Centrica Energy, oil and gas production volumes of 79.5mmboe were up 3% compared to 2013, but realisations fell as a consequence of lower oil and gas price levels. The power business experienced unplanned outages on the nuclear fleet.

As a result, adjusted earnings per share fell by 28% compared to 2013. We also recognised pre-tax exceptional items of £1,597 million, £1,161 million post-tax, which included substantial impairments on E&P and power assets totalling £1,385 million post-tax, primarily as a result of the current low commodity price environment. These were partially offset by profits on disposal relating to the sale of the Texas gas-fired power stations and the Ontario home services business totalling £224 million.

The Group continues to face a number of challenges as we enter 2015, particularly the significant further reductions in wholesale oil and gas prices since the middle of December and continuing low spark spreads. While we plan for normal weather patterns in 2015, and relative to 2014 should see an associated improvement in earnings and cash flows in the customer-facing businesses, the current forward price curves for oil and gas are likely to more than offset this. It is not clear that the forward price curves for oil and gas will improve in the near term, and we therefore need to plan on the basis that lower wholesale prices will persist for all of 2015 and potentially through 2016 and into 2017. During this time we expect the E&P supply chain costs to respond to the lower price environment. Until that time, the Group’s cash flows from Centrica Energy will be materially impacted.

Centrica balances the significant energy commitments of our downstream obligations to customers with two sources of supply: upstream assets, whose cash flows have been materially impacted by current prices; and our procurement, hedging and optimisation activities which require strong investment grade credit ratings to ensure our supply of energy is delivered efficiently.

We are taking immediate actions to improve cash flows, focusing on reducing E&P capital expenditure relative to 2014 levels by around £250 million in 2015 and a further £150 million in 2016, and reducing cash production costs. In addition, we have initiated Group-wide performance improvement efforts, including a strong cost focus, and we will also pay close attention to working capital management.

Despite these actions, with 2014 adjusted earnings per share of 19.2p, and with 2015 adjusted earnings per share having been negatively impacted by around 2.5p since the Interim Management Statement in November and therefore expected to be down compared to 2014, the Group has taken the very difficult decision to re-base the dividend, commencing with the final payment for 2014. This reduction is driven by three things:

  • The need to operate with strong investment grade credit ratings
  • The desire to balance sources and uses of cash in 2015
  • Maintaining a healthy payout ratio

Going forward, the future level of dividend payments will be determined by the health and growth of the Group’s operating cash flow after tax.

To underpin future growth in cash flows, we have launched a strategic review to be concluded by the time of the Interim Results in July 2015. The review will focus on four key areas:

  • Outlook and sources of growth
  • Portfolio mix and capital intensity
  • Operating capability and efficiency
  • Group financial framework

Despite the challenging current environment, my initial assessment of the Group is that Centrica has an excellent and committed team, and has established a strong platform from which to play an important part in the evolution of energy supply and services in the UK, Republic of Ireland and North America.

2014 business performance summary

The top priorities for the Group are safety, compliance and market conduct. The lost time injury frequency rate (LTIFR) per 100,000 hours worked was 0.14, up compared to the 2013 level of 0.11. No significant process safety incidents were recorded during the year.

Downstream in the UK, British Gas faced continued political and regulatory scrutiny, competitive market conditions in each division and lower consumption due to the mild weather. Account numbers declined in both energy and services. In residential services we also experienced a shift in mix towards lower priced products, although we increased our sales of services products in the fourth quarter of the year and returned to account growth.

Overall we delivered improved service levels in British Gas, and we have now completed the implementation of a new combined residential energy and services customer relationship management (CRM) platform. We also completed the implementation of a new billing system in British Gas Business, although we have encountered some transitional issues following the migration of accounts, which we are now resolving. We continue to lead the industry in smart metering, innovation and connected homes, having installed around 1.3 million residential smart meters and we have now sold over 170,000 smart thermostats in the UK.

In North America, the business was impacted by extreme cold weather caused by the polar vortex in early 2014, resulting in additional network system charges. In addition, lower margin sales made in prior years impacted Direct Energy Business. However margins on new B2B sales materially increased in 2014 compared to 2013, reflecting a re-pricing of risk following the polar vortex, and this will benefit the business in 2015.

Market conditions remained highly competitive for Direct Energy Residential, particularly in the US North. Against this backdrop, we are differentiating our offering through innovative propositions that are attractive to the most valuable customer segments. During the year we delivered increased sales of protection plans, combined energy and services products and smart thermostats, while also adding residential solar capability through the acquisition of Astrum Solar. In Direct Energy Services, our focus is now on delivering growth in the US and Alberta following the disposal of our Ontario home services business in October 2014.

At the end of June 2014, Centrica completed the acquisition of Bord Gáis Energy, the incumbent gas supplier and largest dual fuel supplier in the Republic of Ireland. The transaction added some 600,000 residential energy accounts, giving us a leading position in an adjacent deregulated market and providing a platform for growth. We will look to use our experience from the UK and US to develop innovative propositions for our customers in the Republic of Ireland, in both energy and services.

In Centrica Energy, upstream gas post-tax earnings in the year were largely protected from falling wholesale prices by the impact of hedging, tax allowances, and strong midstream performance. We delivered increased E&P production, reflecting a full year of production from assets acquired in Canada in 2013 in partnership with Qatar Petroleum International (QPI). During the year we further strengthened our important relationship with the State of Qatar, selling a 40% share of our wholly owned gas assets in Western Canada to fully align our interests in the region.

In power generation, nuclear output was lower reflecting the temporary shut-down of four reactors following the discovery of a boiler spine issue at Heysham 1 nuclear power station. All four reactors are now back on-line, although at reduced power until modifications are made to the boilers during planned maintenance periods.

In Centrica Storage, our Rough gas storage asset reached its highest ever net reservoir volume in November 2014, reflecting mild UK weather and good asset reliability. However the low seasonal gas price spreads resulted in much reduced year-on-year profitability.

Disposal programme

We completed the disposal of our Texas gas-fired power stations for £411 million in January 2014, releasing capital from non-core assets. In addition, during the year we announced a £1 billion programme of further non-core asset disposals and we completed the sale of our Ontario home services business for £270 million in October. We also ran a process to dispose of our three larger UK CCGTs - Langage, Humber and Killingholme. However, the bids we received were significantly lower than our internal valuation and we have concluded that it is not in the best interest of shareholders to proceed with the disposal of these stations. In addition, the fall in oil and gas prices has made the proposed disposal of our Trinidad and Tobago gas assets more challenging, although we will continue to review our options to release capital from the assets.

Competition and Markets Authority Investigation

The Competition and Markets Authority investigation into the UK energy market commenced in June, and we continue to engage constructively and comprehensively with this full review by an independent body. The CMA published their updated statement of issues on 18 February 2015 and is expected to set out provisional findings in May or June 2015.

2015 environment and outlook

Against the low commodity price backdrop we are taking positive action to improve earnings and cash flows in 2015 and 2016. We are focused on reducing capital expenditure through driving efficiencies on in-flight projects and putting a hold on certain new projects. Absent a material change in commodity prices, we expect E&P capital expenditure to fall to approximately £800 million in 2015 and to approximately £650 million in 2016, around 40% lower than 2014 levels. We will also maintain a tight control on production costs, examining all internal and external supply costs for our operated fields and working with our partners to reduce costs where we are not the operator. Reflecting these actions, we are targeting a 10% or £100 million reduction in our 2016 lifting and other cash production costs compared to 2014 levels, including absorbing the incremental costs of the Valemon and Cygnus fields which will be on-stream.

In power, the Humber and Langage gas-fired stations are cash generative at the operating level in the current environment. We will retain these assets, however following a review we plan to close the Killingholme and Brigg power stations. We will also be taking action to make the management of our power portfolio more efficient.

Downstream, it is vital that we focus on competitive pricing, customer service and operational efficiency. Early in 2015, we were able to announce price reductions for both our British Gas and Bord Gáis Energy residential customers, improving our competitive positions. In North America, margins on new B2B sales improved during 2014, resulting in much improved second half profitability and leaving the business well placed for further profit growth in 2015. We also made good progress in improving our service levels. However, there are further improvements we can make, in part enabled by investment in our IT platforms on both sides of the Atlantic.

We will continue to develop our leading position in smart metering, innovation and connected homes in the UK, which will enable us to offer enhanced customer offerings and drive greater customer engagement, while also creating new skilled jobs. Smart meters are already providing significant benefits to over 600,000 British Gas customers, providing an end to estimated bills and a greater ability to monitor and reduce consumption, while also delivering higher levels of customer satisfaction.

We will also continue to drive sales of our Hive Active Heating smart thermostat, which has extremely positive customer reviews, and we have a strong development pipeline of further innovative products, including time of use tariffs and a ‘connected boiler’. In February 2015 we agreed to acquire AlertMe, the company that provides the technical platform that underpins British Gas’ existing connected homes activity, including Hive. The acquisition will enable further development of connected homes products and services across the Group. In North America, we have also focused on differentiating our offering to the more valuable customer segments, through joint energy and services products, solar and innovative partnership agreements.

Across the Group, we are reviewing our resource efficiency, with a focus on cost to serve, overhead levels and working capital consumption, and have initiated a Group-wide performance improvement plan, including a strong cost focus.

Despite these actions, since our Interim Management Statement in November 2014 the reductions in commodity prices and power margins, the associated impact on our ability to make asset disposals in the current environment and the impact of systems implementation delays in BGB are estimated to have had a negative impact of about 2.5p on 2015 adjusted EPS. As a result, we expect adjusted earnings to be down in 2015 compared to 2014. Earnings remain subject to the usual variables of commodity prices, weather and asset performance.

We have also taken the very difficult decision to rebase the dividend from the 2014 final payment. We are proposing a 2014 final dividend of 8.4 pence per share, 30% lower than the 2013 final dividend, which when added to the interim dividend of 5.1 pence, gives a 2014 full year dividend of 13.5 pence. We will also commence a scrip dividend programme as an alternative to the cash dividend, commencing with the final dividend, subject to shareholder approval.

Our primary role as a Group is to supply energy and services to our customers, and we provide security for that energy both by owning gas and electricity production and also in midstream by hedging, procurement and optimisation activities. To do this, the Group requires a strong investment grade credit rating.

The Group currently has an A3 credit rating with Moody’s and an A- credit rating with S&P, with both agencies having placed their rating on negative outlook in the summer. Since then, the fall in commodity prices has impacted the Group’s cashflows, with a corresponding reduction in its credit metrics. The actions we are taking to improve cashflow through the reduction of capital expenditure and operating costs, and the rebasing of the dividend, are therefore necessary both to balance sources and uses of cash in 2015 and to underpin the financial metrics necessary for strong investment grade credit ratings.

Summary

I joined Centrica at the start of the year and have spent my first weeks visiting our operations, meeting people and deepening my understanding of the Group. Despite the challenges we face, under Sam Laidlaw Centrica has built attractive positions and good capabilities in the UK, Republic of Ireland, Norway, Netherlands and North America. Given the current commodity price environment, we are taking a number of immediate actions and regrettably have had to take action to re-base the dividend. We are also conducting a review of our longer term strategy, including the financial framework for the Company. We will be in a position to share our conclusions by the time of the Interim Results in July 2015.

Despite the current challenges, I am convinced that the Group is well-placed to build on its existing strengths and be able to compete and contribute materially against the emerging long term trends in global energy markets.

Iain Conn

Chief Executive
19 February 2015

GROUP FINANCIAL REVIEW

Group revenue

Group revenue increased by 11% to £29.4 billion (2013: £26.6 billion). British Gas gross revenue decreased by 9%, reflecting the impact of record mild weather in the UK in 2014 compared to colder than normal temperatures in 2013. Residential energy supply gross revenue fell by 12%, with the warmer weather resulting in a 21% fall in total gas consumption and a 9% fall in total electricity consumption. Residential services gross revenue was broadly flat, with the impact of higher central heating installation volumes and inflationary price increases offset by lower product holdings and a shift towards lower priced offerings. Business energy supply and services gross revenue fell by 3%, with lower consumption due to the warm weather and lower average accounts only partially offset by higher retail tariffs.

Direct Energy gross revenue increased by 62%. This primarily reflects a full year of revenue from the Hess Energy Marketing acquisition, completed in November 2013, with business energy supply gross revenue more than doubling as a result. Residential energy supply gross revenue increased by 2%, reflecting additional gas volume as a result of extreme weather conditions across much of North America. Residential and business services gross revenue fell by 8%, reflecting the disposal of the Ontario home services business in October. Bord Gáis Energy reported gross revenue of £391 million in the six months of trading following completion of the acquisition at the end of June.

Centrica Energy gross revenue fell by 17%. Gas gross revenue fell by 21%, reflecting falling oil and gas prices and power gross revenue fell by 3% primarily reflecting lower nuclear output. Centrica Storage gross revenue fell by 21% reflecting lower seasonal gas price spreads.

Operating profit

Throughout the statement, reference is made to a number of different profit measures, which are shown below:

                             
        2014       2013
Year ended 31 December   Notes  

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 


Statutory
result
£m

 

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 


Statutory
result
£m

Adjusted operating profit
British Gas 823 1,030
Direct Energy 150 276
Bord Gáis Energy 7
Centrica Energy 737 1,326
Centrica Storage       29           63        
Total adjusted operating profit 5c 1,746 2,695
Depreciation of fair value uplifts from Strategic Investments (nuclear post-tax) 5c (78) (66)
Interest and taxation on joint ventures and associates   5c   (100)           (111)        
Group operating (loss)/profit 5c 1,568 (2,705) (1,137) 2,518 (626) 1,892
Net finance cost 7 (266) (266) (243) (243)
Taxation   6,8   (375)   773   398   (942)   243   (699)
(Loss)/profit for the year       927   (1,932)   (1,005)   1,333   (383)   950
Attributable to non-controlling interests (24)
Depreciation of fair value uplifts from Strategic Investments, after taxation   10   59           37        
Adjusted earnings       962           1,370        

British Gas operating profit fell by 20%. Residential energy supply operating profit fell by 23%, with lower revenue only partially offset by lower total wholesale commodity costs. Residential energy supply operating profit also included £46 million of costs from transportation and LNG capacity, previously reported in Centrica Energy, which enables the business to bring gas into the UK. Residential services profit fell by 15% reflecting lower margins in challenging trading conditions and a lower average number of contracts. Business energy supply and services operating profit fell 19% reflecting the lower revenue, competitive pressures resulting in lower margins, and a higher bad debt charge due to the impact of the transition to a new billing system.

Direct Energy operating profit fell by 46%. This predominantly reflects challenging competitive market conditions leading to a narrowing of margins in both residential and business energy supply, in particular in our legacy B2B power business, and additional ancillary and other charges incurred as a result of the polar vortex, estimated at approximately $110 million (£65 million). Residential energy supply profit fell by 45% and business energy supply profit fell by 58%. Residential and business services profitability fell by 22%, reflecting the sale of the Ontario home services business.

Bord Gáis Energy made an operating profit of £7 million in the six months post acquisition, including one-time acquisition-related costs.

Centrica Energy operating profit fell by 44%. In gas, despite increased production, the benefits of prior year hedging, and strong midstream performance, operating profit almost halved reflecting the impact of a lower wholesale price environment. Power profitability fell by 23%, reflecting lower output from the nuclear fleet, and higher net losses associated with asset impairments and disposals.

Centrica Storage operating profit more than halved, reflecting the impact of low seasonal gas price spreads.

Group finance charge and tax

Net finance cost increased to £266 million (2013: £243 million), reflecting higher notional interest. The taxation charge reduced to £375 million (2013: £942 million) and after taking account of tax on joint ventures and associates and the impact of fair value uplifts, the adjusted tax charge was £432 million (2013: £1,022 million). The resultant adjusted effective tax rate for the Group was 30% (2013: 43%), reflecting a shift in the mix of profit towards the lower taxed downstream businesses. In addition, a number of items acted to reduce the rate, specifically upstream small field tax allowances, deferred tax credits relating to the disposal of the Greater Kittiwake assets and a re-organisation of Power legal entities. Without these allowances and credits, the adjusted UK effective tax rate would have been 29%. An effective tax rate calculation, showing the UK and non-UK components, is shown below:

                         
      2014       2013

Year ended 31 December

 

UK
£m

 

Non-UK
£m

 

Total
£m

 

UK
£m

 

Non-UK
£m

 

Total
£m

Adjusted operating profit 1,285 461 1,746 1,903 792 2,695
Share of joint ventures/associates interest (62) (62) (60) (60)
Net finance cost   (152)   (114)   (266)   (146)   (97)   (243)
Adjusted profit before taxation   1,071   347   1,418   1,697   695   2,392
Taxation on profit 125 250 375 493 449 942
Tax impact of depreciation on Venture fair value uplift 19 19 29 29
Share of joint ventures’/associates’ taxation   38     38   51     51
Adjusted tax charge   182   250   432   573   449   1,022
Adjusted effective tax rate   17%   72%   30%   34%   65%   43%

Group earnings and dividend

Reflecting all of the above, profit for the year fell to £927 million (2013: £1,333 million) and after adjusting for profits attributable to non-controlling interests and fair value uplifts, adjusted earnings were £962 million (2013: £1,370 million). Adjusted basic earnings per share (EPS) was 19.2 pence (2013: 26.6 pence).

The statutory loss attributable to shareholders for the year was £1,012 million (2013: profit of £950 million). The reconciling items between Group profit for the year from business performance and statutory loss/profit are related to exceptional items and certain re-measurements. The change compared to 2013 is due to lower profit from business performance, a net loss from certain re-measurements of £771 million (2013: profit of £284 million) and higher net exceptional charges of £1,161 million (2013: £667 million). The Group reported a statutory basic EPS loss of 20.2 pence (2013: profit of 18.4 pence).

In addition to the interim dividend of 5.1 pence per share, we propose a final dividend of 8.4 pence, giving a total ordinary dividend of 13.5 pence for the year (2013: 17.0 pence).

Group cash flow, net debt and balance sheet

Group operating cash flow before movements in working capital was lower at £2,726 million (2013: £3,737 million), reflecting the reduced profit from business performance. After working capital adjustments, tax, and payments relating to exceptional charges, net cash flow from operating activities was £1,217 million (2013: £2,940 million), which includes the impact of a net outflow of £640 million (2013: £82 million inflow) of cash collateral due to falling commodity prices.

The net cash outflow from investing activities was lower at £651 million (2013: £2,351 million), reflecting the disposal of the Texas gas-fired power stations and Ontario home services business, and significant acquisition spend in 2013 primarily related to the Hess Energy Marketing acquisition.

The net cash outflow from financing activities was £663 million (2013: £791 million). The outflow was lower than in 2013 due to the investment by QPI in our Canadian upstream gas business and a lower cash outflow from the purchase of treasury shares under the share repurchase programme.

Reflecting all of the above, the Group’s net debt at 31 December 2014 was £5,196 million (2013: £4,942 million), which now includes within its definition cash collateral posted or received, to support wholesale energy procurement.

During the year net assets reduced to £3,071 million (2013: £5,257 million). This reflects the impact of dividend payments, the share repurchase programme and the statutory loss in the year.

Exceptional items

Net exceptional pre-tax charges of £1,597 million were incurred during the year (2013: £1,064 million). Taxation on these charges generated a credit of £436 million (2013: £397 million) which resulted in exceptional post-tax charges of £1,161 million (2013: £667 million).

Reflecting declining wholesale oil and gas prices, the Group recognised a total pre-tax impairment charge of £1,189 million (post-tax charge £712 million) on a number of E&P assets.

Reflecting declining clean spark spreads and capacity market auction prices, the Group recognised a pre-tax impairment charge of £371 million (post-tax charge £297 million) relating to Langage and Humber power stations, and a pre-tax impairment charge of £164 million (post-tax charge £162 million) on its other UK gas-fired power stations. The Group also recognised an impairment charge of £214 million (post-tax charge £214 million) on its nuclear investment, also due to declining power prices and the capacity market auction prices.

On 22 January 2014 the Group disposed of its Texas gas-fired power stations to Blackstone Group LP for consideration of $685 million (£411 million). As a result, an exceptional pre-tax gain of £219 million was recognised during the year. Taxation on this gain generated a charge of £77 million, resulting in an exceptional post-tax gain of £142 million.

On 20 October the Group disposed of the Ontario home services business for cash consideration of C$426 million (£235 million) as well as shares in the acquirer, Enercare Inc., of C$106 million (£59 million), which are listed on the Toronto Stock Exchange (TSX). As a result, an exceptional pre-tax gain of £122 million was recognised during the year. Taxation on this gain generated a charge of £40 million, resulting in an exceptional post-tax gain of £82 million.

Certain re-measurements

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 IAS 39. 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 loss in the statutory results includes net pre-tax losses of £1,108 million (2013: net gains of £438 million) relating to these re-measurements, largely as a result of falling forward prices, particularly in the second half of the year. 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 6 for further details.

Acquisitions and disposals

On 30 June 2014, the Group acquired Bord Gáis Energy’s gas and electricity supply business in the Republic of Ireland, including the Whitegate gas-fired power station, for total consideration of €214 million (£172 million).

On 29 July 2014, the Group acquired a 100% equity interest in Astrum Solar’s residential business for consideration of $53 million (£33 million).

On 27 June 2014, the Group acquired natural gas assets in the Foothills region of Alberta from Shell Canada Energy for C$42 million (£23 million). The assets were acquired by CQECP, the 60:40 partnership with QPI.

In addition to the disposals of the Ontario home services business and the Texas gas-fired power stations, referenced in ‘Exceptional items’, the Group disposed of the Barrow offshore wind farm to DONG Energy for a consideration of £50 million.

Further details on acquisitions, plus details of asset purchases, disposals and disposal groups are included in notes 5(f) and 15.

Events after the balance sheet date

On 13 February 2015, Centrica announced that British Gas will acquire AlertMe, a UK-based connected homes company that provides innovative energy management products and services. The net cost to British Gas will be £44 million, taking into account an existing 21% holding in AlertMe. It is anticipated that the transaction will close by the end of the first quarter of 2015.

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

Risks and capital management

The Group’s principal risks and uncertainties as disclosed in 2013 remain largely unchanged however the combination of a number of individual risks coming together in 2014 have impacted the results, as outlined above. 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 11a.

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 notes 1, 2 and 3.

BUSINESS REVIEW

British Gas

               
Year ended 31 December   2014     2013   Change
Residential energy supply operating profit (BGR)   £439m     £571m   (23%)
Residential services operating profit (BGS) £270m £318m (15%)
Business energy supply and services operating profit (BGB)   £114m     £141m   (19%)
Total British Gas operating profit   £823m     £1,030m   (20%)
BGR post-tax margin   4.1%     4.5%   (0.4ppts)
BGR customer accounts (year end, ’000) (i) 14,778 15,146 (2%)
BGS product holding (year end, ’000) 7,970 8,227 (3%)
BGB supply points (year end, ’000) (ii)   854     916   (7%)
BGR average gas consumption per customer (therms) 408 492 (17%)
BGR average electricity consumption per customer (kWh)   3,498     3,688   (5%)
British Gas total gas consumption (mmth) 4,085 5,126 (20%)
British Gas total electricity consumption (TWh)   39.1     42.4   (8%)
(i) 2013 residential energy customer accounts have been restated to exclude 110,000 accounts subsequently reclassified as dormant
(ii) 2013 business energy supply points have been restated to include 4,000 supply points to align to industry reporting changes

British Gas faced a challenging environment in 2014, with the warmest year on record in the UK, difficult trading conditions, major systems migrations, and continued political, regulatory and media focus. Against this backdrop, British Gas has a clear strategy focused on three priorities: deliver great service, transform to grow and engage our stakeholders.

British Gas Residential

British Gas Residential operating profit fell, reflecting lower average gas and electricity consumption predominantly due to the mild weather in the UK in 2014 compared to colder than normal temperatures in 2013. The average actual customer bill of £1,152 in 2014 was around £100 lower than in 2013, and the average profit per customer of £42 was nearly £10 lower than last year.

The number of residential accounts on supply reduced by 368,000 in 2014 and ended the year at 14.8 million. At the end of the year, we reviewed our definition of energy accounts on supply, which resulted in a downwards restatement of the number of opening accounts by 110,000. We experienced significant losses in the first quarter of the year, following an increase in residential prices in November 2013. However the rate of losses was reduced over the balance of the year, with British Gas being the first energy company to reduce prices following proposed changes to the Energy Company Obligation (ECO) programme announced in December 2013, improved service levels, and the launch of competitively priced offerings. The market remains highly competitive, with recent reductions in standard tariffs and most suppliers also offering a range of fixed price products.

Service levels in British Gas Residential improved with average call answering times lower than 2013, helping drive a significant improvement in our contact net promoter score (NPS). The British Gas brand NPS also recovered during the year, ending in positive territory for the first time since March 2012. In the fourth quarter we completed the migration of all our residential customers onto a new customer relationship management (CRM) platform, and the new system is helping deliver a more integrated customer experience.

Innovation and smart connected homes

In the UK, we continue to lead the industry in technology, innovation and smart connected homes. Around two thirds of our customer interactions are made through digital channels, with around half of those now initiated from a mobile or tablet device. Customer downloads of our top-rated app have now surpassed 1.5 million, and we were recently awarded ‘Most Popular Website’ in the utility category in the ‘Website of the Year’ 2014 awards.

We have installed around 1.3 million residential smart meters in the UK. Over 500,000 British Gas customers with smart meters now regularly receive our unique smart energy report, ‘my energy’, which provides a comprehensive analysis of their energy consumption including a breakdown by type of use, benchmarking against similar homes, personalised energy saving tips and access to an online tool. The report is helping to improve levels of customer satisfaction and the overall perception of British Gas.

We have taken the lead in the roll-out of smart meters to prepayment customers, and the ongoing trial of our SMETS1 capable prepayment meter will enable us to commence the full roll-out by the end of 2015. Additionally, leveraging our experience from Direct Energy, we have also successfully trialled our smart meter enabled ‘Free Saturdays or Sundays’ energy tariffs, with a full launch planned in the second half of 2015.

We have now sold over 170,000 smart thermostats, with sales of our Hive Active Heating product currently running at around 3,000 a week, and have established retail partnerships with Apple, John Lewis and Amazon. Hive has been received extremely positively with over 90% of customers recommending the product and 96% saying they feel more in control of their heating than before. In February 2015 we announced the acquisition of AlertMe, the provider of the technical platform that underpins our existing connected homes activity, including Hive, and will enable ownership and control over a scalable technology platform, software development capability, data analytics and a patent portfolio. We have a strong development pipeline of further innovative products with a ‘connected boiler’ and ‘virtual in home display’ both currently on commercial trial and with planned launch dates in the second half of 2015.

Helping people today

Helping customers to reduce and control their energy consumption is the most sustainable way to keep bills down. We have made good progress in delivering our commitments under the ECO programme and we completed our March 2015 targets in December 2014, subject to Ofgem confirmation. To date, we have delivered energy efficiency measures to over 350,000 households under the programme.

We continue to lead the industry in helping customers most in need and in 2014 we helped nearly 1.8 million households. There are also fewer residential energy customers in debt than a year ago, and on average these customers have lower levels of debt. We have one of the widest eligibility criteria among all energy suppliers for the Warm Home Discount, which benefited over 500,000 customers during the year by up to £140. The bills of our customers most in need were on average 13% lower in 2014 than in 2013.

British Gas Services

British Gas Services operating profit reduced reflecting the decline in the number of contract holdings, lower on-demand volumes due to warmer weather, higher pension costs, and the change in product mix towards flexible, cheaper product offerings.

While retention levels for contract customers remained high, the sales environment has been challenging. As a result, the number of product holdings fell by 257,000 in the year, to slightly under 8 million. However we returned to growth in the final quarter of the year. This follows the migration of all accounts onto the new billing and CRM platform and the completion of comprehensive sales and conduct training for our front line staff, as well as the development of an enhanced digital offering and innovative customer propositions. The market for central heating installations showed signs of recovery in the year and the number of boilers installed increased by 3% in the year compared to 2013.

British Gas Services delivered very high levels of customer service in 2014, both in our contact centres and in customers’ homes. Customer complaints fell by 14% compared to last year, while the NPS for our engineers increased to a record high of +68 in December 2014. New terms and conditions, aimed at delivering greater operational flexibility to meet customer needs, were agreed with our engineers and their union in 2014 and are now in place.

British Gas Business

British Gas Business operating profit fell, primarily due to lower average consumption as a result of the mild weather, competitive pressures leading to lower margins and accounts, and a higher bad debt charge due to the impact of the transition to a new billing system.

The number of business supply points fell by 62,000 in 2014 reflecting the highly competitive conditions in the business energy market and our decision to lead the industry in ending the auto-rollover of contracts at renewal. Towards the end of the year, cleansing of data following the implementation of the new billing system resulted in the removal of 49,000 supply points.

As a result of some transitional issues following the implementation of a new billing system, which we are now resolving, we now expect to deliver £100 million of targeted reductions in operating costs and bad debt by the end of 2016, a year later than originally planned. These savings will help to offset the margin pressures from a competitive market.

To drive growth in BGB we are focusing our proposition development on dual fuel, energy efficiency and joint energy and services offers. We continue to develop our business services capabilities and revenues from these activities grew by 10% in the year. In July we announced our participation in the Generation Community scheme to deliver up to £60 million in solar photovoltaic solutions for Local Authority and Housing Association properties. The ability to offer energy management services, products and technologies is a key differentiator and will help us retain existing customers and acquire new ones.

Direct Energy

               
Year ended 31 December   2014     2013   Change
Residential energy supply operating profit (DER)   £90m     £163m   (45%)
Business energy supply operating profit (DEB) £32m £77m (58%)
Residential and business services operating profit (DES)   £28m     £36m   (22%)
Total Direct Energy operating profit £150m £276m (46%)
Total Direct Energy operating profit (excluding polar vortex impact)   £215m     £276m   (22%)
DER customer accounts (year end, ’000) 3,256 3,360 (3%)
DES product holding (year end, ’000) (i)   897     2,608   (66%)
DER average gas consumption per customer (therms) 1,403 1,296 8%
DER average electricity consumption per customer (kWh)   10,888     10,862   0%
DEB total gas volumes (mmth) 5,923 1,839 222%
DEB total electricity volumes (TWh)   96.9     63.9   52%
Direct Energy total gas volumes (mmth) 8,163 3,883 110%
Direct Energy total electricity volumes (TWh)   116.3     83.4   39%

(i) DES 2014 product holding reflects the disposal of the Ontario home services business, which had 1.9 million product holdings at the time of disposal

Direct Energy faced challenging conditions in 2014, with extreme weather conditions caused by the polar vortex in the first quarter of the year, estimated at approximately $110 million (£65 million), and margin pressures across most of our markets in energy supply. Overall operating profit fell by 46% compared to 2013, and on a constant currency basis fell by 43%. However during the year we added significant value through the completion of disposals of non-core assets, recognising a £219 million profit on disposal on the sale of our Texas gas-fired power stations, and a £122 million profit on disposal from the sale of our Ontario home services business.

A $100 million cost reduction programme was launched at the start of the year, to help improve Direct Energy’s competitive position. The programme was successfully completed towards the end of 2014.

The outlook for 2015 is more positive and we are positioned for growth, with the effect of increased sold B2B unit margins in 2014 following the polar vortex starting to positively impact profitability. We also continue to develop a broad range of innovative energy and services product offerings to improve customer retention and attract the highest value customers in our residential energy business, to build innovative partnership offerings in our B2B business in compressed natural gas (CNG) and solar, and have additional growth opportunities in residential services following our acquisition of Astrum Solar.

Direct Energy Residential

Direct Energy Residential operating profit fell due to additional costs relating to the extreme weather conditions in early 2014, and a competitive sales environment in both Texas and the US North East, which led to a reduction in unit margins. The number of residential energy accounts decreased by 104,000 over 2014, predominantly reflecting the expected decline in Ontario, with the Energy Consumer Protection Act (ECPA) making retention of customers difficult, and impact of the competitive market in Texas. Against this challenging backdrop, we remain focused on delivering high levels of customer service and higher levels of customer retention, and we have now successfully implemented a new residential billing platform in Alberta.

Sales through digital channels doubled in 2014 compared to 2013, with the acquisition of Bounce Energy in 2013 having provided a leading internet-based platform and digital marketing capabilities. We are also focused on differentiating our offering to the more valuable customer segments through the development of innovative products and bundled energy and services offerings, which we started selling in the first half of the year and now have over 189,000 joint residential and services customers with sales averaging around 6,000 per week during the fourth quarter. We have also sold over 39,000 smart thermostats through our partnerships with Nest and Honeywell.

Direct Energy Business

The integration of the Hess Energy Marketing acquisition is now fully completed and the business is performing ahead of our investment case. Direct Energy is now the largest commercial and industrial (C&I) gas supplier and the second largest C&I power supplier in the competitive US retail market, as well as a top 10 wholesale gas marketer in North America in the Platts third quarter rankings. In addition to enhanced scale, the business is also set up to benefit from portfolio diversification and expansion along the gas value chain.

Despite increased volumes resulting from the Hess Energy Marketing acquisition, Direct Energy Business operating profit fell, reflecting the one off impact of the polar vortex, lower margins on power sales made in prior periods, and mild weather late in the year resulting in low levels of commodity price volatility and leading to fewer optimisation opportunities. However, average C&I sold unit margins in the second half of 2014 were 35% higher for gas and 50% higher for power compared to the second half of 2013, reflecting a re-pricing of risk following the polar vortex, with second half profit being significantly higher than in 2013. Combined with a lower amortisation charge relating to the Hess acquisition, this leaves the business well placed for strong underlying growth in 2015.

We continue to develop innovative propositions for our C&I customers. We have a partnership agreement with Panoramic Power to offer wireless energy sensors to help customers better understand their power consumption. We are also helping our customers implement energy efficiency projects through a network of partners across the US. In the fourth quarter, we agreed a joint venture with Xpress Natural Gas on a CNG station in New York State, that will enable us to transport CNG to customers with no access to distributed natural gas. In solar, to date we have deployed around 60% of our $125 million fund with SolarCity and are expanding our offering, both in funds and the types of projects we support.

In January 2014 we completed the sale of our three Texas gas-fired power stations for £411 million. Following the sale we are supporting our downstream demand needs in Texas through a combination of the liquid physical and financial power markets and a three-year heat rate call option for an equivalent amount of capacity.

Direct Energy Services

In Direct Energy Services we completed the sale of the Ontario home services business for C$532 million (£294 million) in October. This was an attractive opportunity to realise value from the business in a region where joint energy and services opportunities are more limited, and focus our attention on opportunities in the US and Alberta, where we see good prospects for growth.

Total Direct Energy Services operating profit reduced by 22%, although profit from the non-Ontario business remained flat. Excluding the Ontario home services business, which had 1.9 million customer accounts, the number of services accounts was up 23%. We now have over 312,000 protection plan customers across the US, while our HVAC (heating, ventilation and air conditioning) leasing proposition continues to perform well as customers are willing to undertake a higher value of work when purchased through rental payments as opposed to upfront payment. In addition, the future pipeline of work for our residential new construction, commercial and solar business was $79 million, a record for the business. The business continued to deliver high levels of customer service, with NPS closing the year at +62.

In July, we entered the rapidly growing US residential solar market through the acquisition of Astrum Solar. This transaction enables Direct Energy to sell solar alongside its existing range of energy and services products, as we look to develop further attractive propositions to attract the highest value customers. We completed around 600 residential solar installations in 2014 following the acquisition, 50% more than Astrum Solar installed over the same period in 2013.

Bord Gáis Energy

               
Year ended 31 December   2014     2013   Change
Total Bord Gáis Energy operating profit   £7m       nm
Residential energy customer accounts (year end, ’000)   608       nm
Residential average gas consumption per customer (therms)   127       nm
Residential average electricity consumption per customer (kWh)   2,373       nm
Total gas volumes (mmth) 106 nm
Total electricity volumes (TWh) 1.4 nm
Total power generated (TWh)   0.9       nm

On 30 June 2014, Centrica completed the acquisition of Bord Gáis Energy in the Republic of Ireland, a supply business with power generation capacity in an adjacent deregulated market, providing a good platform for growth. Bord Gáis Energy is the incumbent gas supplier and largest dual fuel supplier in the Republic of Ireland with over 600,000 residential accounts and 30,000 business supply points.

The business made an operating profit of £7 million in the first six months of Centrica’s ownership, including one-time integration and acquisition costs and some unplanned outages at the Whitegate gas-fired power station. In 2015 we expect the business to contribute around €40 million (£31 million) EBITDA, in line with the investment case.

Centrica Energy

               
Year ended 31 December   2014     2013   Change
Gas operating profit   £606m     £1,155m   (48%)
Power operating profit/(loss) £131m £171m (23%)
Gas-fired (£120m) (£133m) nm
Renewables (operating assets) £27m £36m (25%)
Renewables (one off write-offs, profit/loss on disposal) (£17m) (£11m) nm
Nuclear £210m £250m (16%)
Midstream   £31m     £29m   7%
Total Centrica Energy operating profit   £737m     £1,326m   (44%)
Gas operating profit after tax   £302m     £325m   (7%)
Gas production (mmth) (i) 3,772 3,557 6%
Liquids production (mmboe) (i) 17.3 18.7 (7%)
Total gas and liquids production (mmth) (i) 4,822 4,690 3%
Total gas and liquids production (mmboe) (i) 79.5 77.3 3%
Upstream proven and probable reserves (mmboe) (ii) 585 711 (18%)
Total UK power generated (TWh)   22.1     21.7   2%
(i) Includes 100% share of Canadian assets owned in partnership with QPI
(ii) Centrica’s share of reserves, including a 60% share of Canadian assets owned in partnership with QPI, and excluding Rough cushion gas of 30mmboe. Includes the impact of QPI’s investment in 40% of our wholly-owned Canadian gas and liquids assets in the year

Centrica Energy’s diversified upstream and midstream portfolio and hedging helped to mitigate against the impact of a falling wholesale oil and gas price environment in 2014. However the lower wholesale price environment creates a challenging backdrop, and we are enforcing strict financial discipline, with the management team taking action to reduce capital expenditure and costs and progressing asset disposals to release capital.

Gas

Our E&P business continued to see good production from previous investments in Norway and Canada, however production from the UK and Netherlands was disappointing. Total gas and liquids production increased by 3% to 79.5mmboe, with gas volumes up 6% and liquids volumes down 7%.

Production in the Americas increased by 68% reflecting a full year of production from the assets acquired from Suncor in September 2013, in partnership with Qatar Petroleum International (QPI). During 2014, we strengthened our relationship with QPI, who invested in 40% of our wholly-owned Canadian gas and liquids assets in October for C$215 million (£119 million), fully aligning our interests in the region. The partnership also acquired a package of natural gas assets in Alberta from Shell Canada Energy for C$42 million (£23 million) and production from these assets, combined with new production wells, helped the Canadian business end the year at record high production volumes.

Production in Europe decreased by 16%, partly as a result of the disposals of three packages of North Sea assets, all announced in late 2013. We experienced some production issues in the UK and Netherlands, with gas export constraints in the Greater Markham Area (GMA) and lower than expected flows from York. However production rates in the GMA increased towards the end of the year, and a fourth well was brought online at York in the second half. Our assets in Norway performed well, with strong production from the Kvitebjorn asset, ahead of our original investment case.

The large scale Valemon project in the Norwegian North Sea was brought on-stream in January 2015, with further wells being drilled over 2015 and into 2016 to maximise the recoverable reserves from the field. The Cygnus project in the Southern North Sea remains on schedule to produce first gas around the end of 2015. We also produced first gas from the Kew field at the start of 2014 and from an additional well drilled at Grove in the second half of the year. Two wells drilled adjacent to the Butch discovery, Butch East and Butch South West, did not find further commercial hydrocarbons, however the results contributed valuable information that will enable us to optimise the development of the main Butch field.

On exploration, six out of seven wells drilled in Europe were successful in finding hydrocarbons and three, Valemon North, Cepheus and Pegasus were classified as commercial discoveries. We also wrote down exploration costs in respect of [Solberg, Ivory and Novus drilled in 2014 and] Fulham and Olympus, which were drilled in previous years and face significant development challenges to be commercial in the current price environment. In addition we wrote off exploration licenses originally acquired as part of the Venture acquisition, and impaired the Bains asset and a recent failed well drilled on Buckland.

In the year we recognised exceptional post-tax impairments of £712 million relating to our E&P assets, predominantly as a result of declining oil and gas prices, including £265 million on our assets in Trinidad and Tobago. We will continue to review our options to release capital from these assets.

Centrica Energy’s proven and probable (2P) reserves reduced by 18% to 585mmboe, reflecting production in the year and the sale of a 40% share of our wholly-owned gas assets in Western Canada to QPI. This also reflects a reduction in reserve expectations from some UK fields, with updated production flow data as well as the lower price environment making a number of future developments uneconomic and leading to an earlier forecast cessation of production on some assets.

In view of the current oil and gas price levels, we have taken action to scale back exploration and development expenditure across the portfolio, particularly in Canada where we have flexibility to manage drilling programmes in line with the sharp price drop. In 2014, total E&P capital expenditure was above £1 billion and we expect this to reduce to approximately £800 million in 2015. We have taken further steps to reduce expenditure in 2016 to approximately £650 million, which is substantially below previous guidance. Reflecting lower capital expenditure, we expect total production in 2015 to be around 75mmboe.

Our midstream business performed well as we managed periods of wholesale market volatility and falling commodity prices. We also optimised our flexible gas contracts during the fall in summer gas prices to realise additional value, resulting in a significant increase in the midstream gas profit in 2014, partially offset by a consequential reduction in expected results for 2015. In LNG, Federal Energy Regulatory Commission (FERC) approval for the fifth train at Cheniere’s Sabine Pass export facility is anticipated around the end of the first quarter of 2015, and the project remains on course to enable the first commercial delivery through our contract by the end of 2018. We also took delivery of our first ‘Free on Board’ cargoes in the fourth quarter, as we look to increase our presence and capability in LNG.

Gas operating profit fell by 48% despite increased production, reflecting lower wholesale oil and gas prices. However profit after tax was only down 7%, reflecting the benefits from forward hedging, a strong midstream performance, production mix weighted towards lower taxed assets, non-recurring small field tax allowances and a tax credit relating to the disposal of the Greater Kittiwake assets. Unit lifting and other cash production costs increased by 6%, principally reflecting lower production from European fields.

In the low wholesale price environment, we have acted to manage our cost base, examining all our internal and external supply costs for our operated fields. We are also working with our partners to reduce costs where we are not the operator. Reflecting these actions, we are targeting our 2016 lifting and other cash production costs to be around 2013 levels. This requires a 10% reduction on 2014 as well as absorbing the incremental costs of Valemon and Cygnus which will be on-stream.

Power

In December 2014, the UK’s first power capacity auction took place for capacity in 2018/19. The auction clearing price was £19.40/kw/year, significantly below market expectations. Our Humber and Langage gas-fired power stations were both successful in the auction, as were all the nuclear reactors in which we have a 20% equity interest. However our remaining four operational gas-fired stations at Barry, Brigg, Killingholme and Peterborough were unsuccessful, as was King’s Lynn which is currently mothballed.

During the year, we commenced a process to dispose of our three larger UK gas-fired power stations. However the low capacity auction price resulted in an expected consequential decline in bidder confidence, and we decided that a disposal was no longer highly probable. As a result, the assets were reclassified out of assets held for sale as at 31 December. In 2015 we received bids that were lower than our internal valuation, and we have concluded that it is not in the best interest of shareholders to proceed with the disposal of these stations. Humber and Langage are cash generative at the operating level in the current environment. We will retain these assets, however following a review we plan to close the Killingholme and Brigg power stations. We will also be taking action to make the management of our power portfolio more efficient.

Reflecting the result of the capacity auction and declining power prices, we recognised a post-tax impairment of £459 million on our UK gas-fired power generation assets and a post-tax impairment of £214 million on our investment in the UK nuclear fleet.

In 2014, output from our interest in the UK nuclear fleet was down 7% compared to 2013, reflecting the temporary shut-down of four reactors at the Heysham 1 and Hartlepool power stations following discovery of a boiler spine issue at Heysham 1 in August. All reactors have now returned to service following inspections of all boiler spines at the affected reactors which found no further defects, however the four affected reactors will operate at 75-80% power until modifications are made to the boilers during standard maintenance periods in 2015 and 2016. Reflecting the lower output, nuclear operating profit fell 16%.

Gas-fired generation volumes were 12% higher than in 2013, although market spark spreads remained low throughout the year, and the forward market currently shows little sign of recovery in 2015. Our gas-fired business reported a reduced operating loss of £120 million, which includes a £39m depreciation saving as a result of the three larger power stations being classified as held for sale assets for eight months in 2014.

Our wind assets delivered generation volumes up 20%, reflecting a full contribution from the Lincs offshore wind farm. Reflecting our focus on capital discipline, at the half year we reviewed the economic viability of the Round 3 Irish Sea Zone project, Celtic Array, following discussions with The Crown Estate and our partners in the project, DONG Energy, and have now handed the license back to the Crown Estate. As a result we recognised a charge of £40 million, principally in respect of writing off the total book value of the project. In November, the sale of the Lincs transmission assets under the offshore transmission owner (OFTO) regime was completed in line with book value, while in December we sold our 50% non-operated interest in the Barrow offshore wind farm to DONG Energy for £50 million, with Centrica recognising a £26 million pre-tax profit from the disposal.

Renewables operating profit fell by 60% compared to 2013, reflecting a reduced contribution from the disposal of assets and increased costs associated with writing down developments.

Centrica Storage

               
Year ended 31 December   2014     2013   Change
Total Centrica Storage operating profit   £29m     £63m   (54%)

The Rough gas storage asset reached its highest ever net reservoir volume (NRV) in November 2014, reflecting the lower level of withdrawal in the first quarter due to the warmer than normal weather combined with continued good asset reliability.

Seasonal gas price spreads fell to historic lows towards the end of 2013 due to the abundance of flexible supply across North West Europe and warm weather. As a result the average Standard Bundled Unit (SBU) price for the 2014/15 storage year fell to 20.0p, lower than the 23.3p achieved in 2013/14 and the 33.9p achieved in 2012/13. This resulted in a 21% reduction in SBU revenue in 2014 compared to 2013, and operating profit fell by 54%.

At the start of 2014 we commenced a three year programme to deliver £15 million of cost reductions through operational improvements and capital discipline. We are on track to deliver this with significant progress in the year on business restructuring, reductions in capital expenditure and improved maintenance planning.

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 confirms 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

Iain Conn
Chief Executive

GROUP INCOME STATEMENT

                             
        2014       2013
Year ended 31 December   Notes  

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 

Results for
the year
£m

 

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 

Results for
the year
£m

Group revenue 5(b) 29,408     29,408 26,571     26,571

Cost of sales before exceptional items and certain re-measurements

(25,043) (25,043) (21,464) (21,464)
Exceptional items – onerous provision 6 (125) (125)
Re-measurement of energy contracts 6   (1,134)   (1,134)   413   413
Cost of sales       (25,043)   (1,134)   (26,177)   (21,464)   288   (21,176)
Gross profit 4,365   (1,134)   3,231 5,107   288   5,395
Operating costs before exceptional items (2,903) (2,903) (2,735) (2,735)
Exceptional items – impairments 6 (1,938) (1,938) (939) (939)
Exceptional items – gains on disposals 6   341   341    
Operating costs (2,903) (1,597) (4,500) (2,735) (939) (3,674)
Share of profits of joint ventures and associates, net of interest and taxation   12(a)   106   26   132   146   25   171
Group operating (loss)/profit 5(c) 1,568   (2,705)   (1,137) 2,518   (626)   1,892
Financing costs 7 (318) (318) (297) (297)
Investment income 7 52     52 54     54
Net finance cost       (266)     (266)   (243)     (243)
(Loss)/profit before taxation 1,302 (2,705) (1,403) 2,275 (626) 1,649
Taxation on (loss)/profit   6, 8   (375)   773   398   (942)   243   (699)
(Loss)/profit for the year       927   (1,932)   (1,005)   1,333   (383)   950
Attributable to:
Owners of the parent 903 (1,915) (1,012) 1,333 (383) 950
Non-controlling interests       24   (17)   7      
 
Earnings per ordinary share               Pence           Pence
Basic 10     (20.2) 18.4
Diluted 10 (20.2) 18.3
Interim dividend paid per ordinary share 9 5.10 4.92
Final dividend proposed per ordinary share   9       8.40           12.08

The notes on pages 25 to 63 form part of these Financial Statements.

GROUP STATEMENT OF COMPREHENSIVE INCOME

             

Year ended 31 December

  Notes  

2014
£m

 

2013
£m

(Loss)/profit for the year     (1,005)   950
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 4 3
   
Net losses on cash flow hedges (44) (25)
Transferred to income and expense on cash flow hedges 46 34
Transferred to assets and liabilities on cash flow hedges 6
Taxation on cash flow hedges (1) (1)
7 8
Exchange differences on translation of foreign operations (165) (217)

Share of other comprehensive (loss)/income of joint ventures and associates,
net of taxation

(15) 18
(169) (188)
Items that will not be recycled to the Group Income Statement:    
Net actuarial losses on defined benefit pension schemes (83) (179)
Taxation on net actuarial losses on defined benefit pension schemes 18 31
(65) (148)
Reversal of revaluation reserve, net of taxation and exchange differences (10) (17)

Share of other comprehensive income/(loss) of joint ventures and associates,
net of taxation

      21   (15)
Other comprehensive loss net of taxation       (223)   (368)
Total comprehensive (loss)/income for the year       (1,228)   582
Attributable to:
Owners of the parent (1,234) 590
Non-controlling interests       6   (8)

GROUP STATEMENT OF CHANGES IN EQUITY

                             
   

Share
capital
£m

 

Share
premium
£m

 

Retained
earnings
£m

 

Other
equity
£m

 

Total
£m

 

Non-controlling
interests
£m

 

Total
equity
£m

1 January 2013   321   929   4,186   491   5,927     5,927
Total comprehensive income/(loss) 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 81 81
Distribution paid to non-controlling interests (8) (8)
Dividends paid to equity holders (note 9) (864) (864) (864)
Taxation on share based payments         (16)   (16)     (16)
31 December 2013   321   931   4,255   (315)   5,192   65   5,257
Total comprehensive (loss)/income (1,012) (222) (1,234) 6 (1,228)
Employee share schemes 71 71 71
Purchase of treasury shares (2) (420) (422) (422)
Cancellations of shares held in treasury (10) (549) 559
Investment by non-controlling interests 283 283
Distribution paid to non-controlling interests (18) (18)
Dividends paid to equity holders (note 9) (867) (867) (867)
Taxation on share based payments         (5)   (5)     (5)
31 December 2014   311   931   1,825   (332)   2,735   336   3,071

The notes on pages 25 to 63 form part of these Financial Statements.

GROUP BALANCE SHEET

             

31 December

  Notes   2014
£m
  2013
£m
Non-current assets      
Property, plant and equipment 6,377 7,446
Interests in joint ventures and associates 12(d) 2,395 2,658
Other intangible assets 1,991 1,905
Goodwill 2,609 2,819
Deferred tax assets 354 105
Trade and other receivables 87 150
Derivative financial instruments 13 313 227
Retirement benefit assets 14 185 205
Securities   11(b)   263   202
        14,574   15,717
Current assets
Trade and other receivables 6,226 5,446
Inventories 555 530
Derivative financial instruments 13 617 573
Current tax assets 88 151
Securities 11(b) 11 9
Cash and cash equivalents   11(b)   621   719
        8,118   7,428
Assets of disposal groups classified as held for sale         301
        8,118   7,729
Total assets       22,692   23,446
Current liabilities
Derivative financial instruments 13 (1,565) (506)
Trade and other payables (5,667) (5,630)
Current tax liabilities (348) (645)
Provisions for other liabilities and charges (395) (258)
Bank overdrafts, loans and other borrowings   11(c)   (1,635)   (859)
        (9,610)   (7,898)
Liabilities of disposal groups classified as held for sale         (99)
        (9,610)   (7,997)
Non-current liabilities
Deferred tax liabilities (663) (1,426)
Derivative financial instruments 13 (588) (431)
Trade and other payables (83) (64)
Provisions for other liabilities and charges (3,203) (2,934)
Retirement benefit obligations 14 (123) (165)
Bank overdrafts, loans and other borrowings   11(c)   (5,351)   (5,172)
        (10,011)   (10,192)
Total liabilities       (19,621)   (18,189)
Net assets       3,071   5,257
Share capital 311 321
Share premium 931 931
Retained earnings 1,825 4,255
Other equity       (332)   (315)
Total shareholders’ equity       2,735   5,192
Non-controlling interests       336   65
Total shareholders’ equity and non-controlling interests       3,071   5,257

The Financial Statements on pages 21 to 63, of which the notes on pages 25 to 63 form part, were approved and authorised for issue by the Board of Directors on 19 February 2015 and were signed below on its behalf by:

Iain Conn
Chief Executive

GROUP CASH FLOW STATEMENT

             

Year ended 31 December

  Notes  

2014
£m

 

2013
£m

Group operating (loss)/profit including share of results of joint ventures and associates     (1,137)   1,892
Less share of profit of joint ventures and associates, net of interest and taxation   12(a)   (132)   (171)
Group operating (loss)/profit before share of results of joint ventures and associates (1,269) 1,721
Add back/(deduct):
Depreciation, amortisation, write-downs and impairments 3,288 2,319
Profit on disposals (372) (21)
(Decrease)/increase in provisions (37) 162
Defined benefit pension service cost and contributions (83) (87)
Employee share scheme costs 39 43
Unrealised losses/(gains) arising from re-measurement of energy contracts       1,160   (400)
Operating cash flows before movements in working capital 2,726 3,737
Decrease in inventories 4 78
Increase in trade and other receivables (i) (631) (456)
(Decrease)/increase in trade and other payables (i)       (50)   697
Operating cash flows before payments relating to taxes, interest and exceptional charges 2,049 4,056
Taxes paid (707) (892)
Payments relating to exceptional charges       (125)   (224)
Net cash flow from operating activities       1,217   2,940
Purchase of businesses (131) (1,115)
Sale of businesses 658 140
Purchase of property, plant and equipment and intangible assets 5(f) (1,456) (1,615)
Sale of property, plant and equipment and intangible assets 17 17
Investments in joint ventures and associates (26) (51)
Dividends received from joint ventures and associates 12(c) 138 193
Repayments of loans to, and disposal of investments in, joint ventures and associates 109 59
Interest received 35 29
Sale/(purchase) of securities   11(b)   5   (8)
Net cash flow from investing activities       (651)   (2,351)
Issue and surrender of ordinary share capital for share awards, net of payments
for own shares
25 20
Purchase of treasury shares under share repurchase programme (422) (502)
Investment by non-controlling interests 119
Distribution to non-controlling interests (18) (8)
Financing interest paid (296) (248)
Repayment of borrowings 11(b) (518) (400)
Cash received from borrowings, net of linked deposit 11(b) 1,311 1,209
Equity dividends paid       (864)   (862)
Net cash flow from financing activities       (663)   (791)
Net decrease in cash and cash equivalents (97) (202)
Cash and cash equivalents at 1 January 719 931
Effect of foreign exchange rate changes       (1)   (10)
Cash and cash equivalents at 31 December       621   719
Included in the following line of the Group Balance Sheet:
Cash and cash equivalents   11(b)   621   719

(i) Includes net outflow of £640 million of cash collateral in 2014 (2013: £82 million inflow). See note 11(b).

The notes on pages 25 to 63 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 2014 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 2014 included in this announcement were authorised for issue in accordance with a resolution of the Board of Directors on 19 February 2015.

The preliminary results for the year ended 31 December 2014 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 2014 or 31 December 2013. The financial information for the year ended 31 December 2013 is derived from the statutory accounts for that year. The report of the auditors on the statutory accounts for the year ended 31 December 2014 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 2014 are consistent with those of the annual Financial Statements for the year ended 31 December 2013, as described in those Financial Statements, with the exception of standards, amendments and interpretations effective in 2014 and other presentational changes.

(a) Standards, amendments, and interpretations effective or adopted in 2014

(i) IFRIC 21

IFRIC 21: ‘Levies’ has been applied by the Group for the first time in the current period. This interpretation clarifies the point at which an entity should recognise a liability to pay a levy. The interpretation provides a definition of a levy and states that an obligating event must occur for a liability to be recognised – the obligating event being the activity that triggers the payment of the levy. Economic compulsion and/or preparation of the financial statements on the going concern basis do not imply that the Group has a present obligation to pay a levy.

In 2014, this interpretation is applicable to a number of government schemes including the Energy Company Obligation (ECO) and the Renewables Obligation in the UK. However, IFRIC 21 has not materially changed the accounting for these schemes in the Group’s consolidated Financial Statements.

This interpretation will also apply to the funding of Contracts for Difference (CfDs) which are being put in place as part of the Electricity Market Reform (EMR) introduced by the UK Government. Payments made by the CfD counterparty to qualifying generators will be funded by all licensed electricity suppliers. The supplier payments will be in the scope of IFRIC 21 when they commence from 1 April 2015.

(ii) Other amendments

In the current year, the Group has applied the following amendments to IFRSs as issued by the International Accounting Standards Board (IASB) as they are mandatorily effective for accounting periods beginning on or after 1 January 2014:

  • Amendments to IAS 32: ‘Financial instruments: Presentation’ related to offsetting financial assets and financial liabilities
  • Amendments to IAS 36: ‘Impairment’ related to recoverable amount disclosures for non-financial assets
  • Amendments to IAS 39: ‘Financial instruments: Recognition and measurement’ related to the novation of derivatives and continuation of hedge accounting.

None of the above amendments have had a material impact on the Group consolidated Financial Statements.

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

The Group has not yet applied the following standards and amendments as these are not yet effective and remain subject to endorsement by the European Union (EU):

  • IFRS 9: ‘Financial instruments’
  • IFRS 15: ‘Revenue from contracts with customers’
  • Amendments to IFRS 11: ‘Joint arrangements’ related to the acquisition of interests in joint operations and the sale or contribution of assets between an investor and its associate or joint venture
  • Amendment to IAS 16: ‘Property, plant and equipment’ and IAS 38: ‘Intangible assets’ related to the clarification of acceptable methods of depreciation and amortisation
  • Annual Improvement Project 2012-2014
  • IAS 1: ‘Presentation of financial statements’.

The following standards and amendments are not yet effective but have been endorsed by the EU:

  • Annual Improvement Project 2010-2012
  • Annual Improvement Project 2011-2013
  • Amendment to IAS 19: ‘Employee benefits’ related to employee contributions to defined benefit plans.

The Directors do not anticipate that the application of the Annual Improvement Projects and the Amendments to IAS 1, IAS 16, IAS 19, IAS 38 and IFRS 11 (in relation to the sale or contribution of assets between an investor and its associate or joint venture) will have a material impact on the amounts reported and disclosed.

The amendment to IFRS 11 in relation to acquisitions of interests in joint operations, which will be effective in the 2016 Group consolidated Financial Statements, clarifies that an acquisition of a joint operation that meets the definition of a business is accounted for in accordance with IFRS 3: ‘Business combinations’. This will lead to a change to the Group’s current accounting policy for this type of acquisition. However, the amendment is only applicable prospectively for acquisitions on or after 1 January 2016 and therefore the accounting of acquisitions prior to this date will not be restated.

The Group is currently in the process of assessing the impact of IFRS 9 and IFRS 15. The preliminary view for IFRS 9 is that it will not have a material impact on the Group’s consolidated Financial Statements. In respect of IFRS 15, it is too early to conclude what impact this standard will have as a detailed impact assessment is required. Particular focus will need to be given to customer contracts in the Group’s International Downstream business.

At this stage, it is not practicable to provide a quantified estimate of the effects of IFRS 9 and IFRS 15. This will be provided once the Group has completed the detailed reviews.

2. Centrica specific accounting measures

 

This section sets out the Group’s specific accounting measures applied in the preparation of the consolidated 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 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 the statutory result 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 (Nuclear), which owns the former British Energy Group nuclear power station fleet now operated by EDF; 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) Nuclear

The 20% interest in Nuclear 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 Nuclear relate to the fair value uplifts made to the nuclear power stations to report the PP&E at their acquisition-date fair values and fair value uplifts made to 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 the overall reported Group result 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 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 (they are prohibited from being designated as ‘own use’), the rules within IAS 39 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 (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 Group consolidated 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 consolidated 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 and Lincs Wind Farm Limited.

Associated with some 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 off-take 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 and IAS 28 (Revised (2011)): ‘Investments in joint ventures and associates’.

The Directors have also judged that the 15-year off-take 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 equity interests in wind farms are recognised within the ‘business performance’ column of the Group Income Statement as part of the ‘Centrica Energy – Power’ segment. These divestments are 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 the 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 one material acquisition – Bord Gáis Energy Limited. This acquisition has been accounted for as a business combination as set out in note 15.

The key areas of judgement were the value of customer relationships, the favourable and unfavourable pricing terms of gas and power purchase contracts and the value of the gas-fired power station. Customer relationship valuations 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 value of the gas and power purchase contracts as well as the valuation of the power station are based on forward market curves derived from both liquid market data and internal predictions of future prices. Any significant changes to these assumptions may have a material impact on the valuation of the business acquired.

Consolidation of the CQ Energy Canada Partnership

The Suncor upstream acquisition in 2013 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: ‘Consolidated financial statements’ and the conclusion has been reached that the Group has power over the relevant activities of CQECP. This entity has been fully consolidated into the Group’s Financial Statements and QPI’s ownership share is represented as a non-controlling interest.

Energy Company Obligation

The Energy Company Obligation (ECO) order requires UK-licenced 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 (for ECO phase 1) and by 31 March 2017 (for ECO phase 2). The Group continues to judge that it is not legally obligated by this order until 31 March 2015 and 31 March 2017 respectively. Accordingly, the costs of delivery are recognised as incurred, when cash is spent or unilateral commitments made resulting in obligations that cannot be avoided.

In prior periods, the Group had 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 included the costs of these contractual arrangements and commitment obligations. The Group has now delivered in excess of those commitments.

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 roll-out, 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.

Disposal groups classified as held for sale

On 8 May 2014, the Group announced that it had undertaken a strategic review of its UK power station fleet and that it intended to focus its UK gas-fired power generation on small flexible ‘peaking’ plants. The Group sought to release capital from its three larger operating plants (Langage, Humber and Killingholme) in order to focus on other investment opportunities. These three power stations were classified as a disposal group held for sale as at 8 May 2014 and at the half year as the Group considered it highly probable that their value would be principally recovered through a divestment and that this disposal would occur within 12 months. The Group ran a disposal process throughout the second half of 2014 and continued to expect the value of the assets to be recovered through a divestment. In December, the first capacity market auction prices cleared at a level significantly below market expectations with an expected consequential decline in bidder confidence. These events led the Group to reassess the asset held for sale classification and decide the disposal was no longer ‘highly probable’. Consequently, the assets were reclassified out of assets held for sale as at 31 December. The culmination of the bid process in February 2015 provided further evidence of the conditions existing at 31 December, as the bid levels were below the Group’s hold value. An impairment of £384 million was recorded on reclassification to measure the assets at their recoverable amounts at the date of transfer. See note 6 for further details.

(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 2055, 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 nuclear power stations and the costs of waste management and spent fuel. These estimates impact the carrying value of our Nuclear 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 64.

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 in accordance with the Group’s accounting policy as described in note 6. 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 assumptions used in determining the recoverable amounts and 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. Further details of the impairments booked during the year are provided in note 6.

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 and the value from extracting cushion gas at the end of the field life less any related capital and operating expenditure.

Nuclear investment

The recoverable amount of the Nuclear investment is based on the value of the existing UK nuclear fleet operated by EDF. 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. Further details of the impairments booked during the year are provided in note 6.

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 detail on impairments arising and the assumptions used in determining the recoverable amounts is provided in note 6.

Credit provisions for trade and other receivables

The methodology for determining provisions for credit losses on trade and other receivables is based on an incurred loss model and is determined by application of expected default and loss factors, informed by historical loss experience and current sampling to the various balances receivable from residential and business customers on a portfolio basis, in addition to provisions taken against individual accounts. Balances are written off when recoverability is assessed as being remote. Although the provisions recognised are considered appropriate, the use of different assumptions or changes in economic conditions could lead to movements in the provisions and therefore impact the Group Income Statement.

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

  • development of a combined risk and controls universe designed to ensure a more consistent and comprehensive approach to risk identification;
  • improved and more explicit consideration of business risk as part of our capital allocation framework process;
  • refresh of our processes, to identify and assess ‘Black Swan’ and high impact, low likelihood risks;
  • greater interaction with specialist risk areas, such as Information Security and Health, Safety, Environment and Security, allowing for a more consistent and granular approach to risk identification and reporting;
  • greater engagement with the Executive through changes to the Group risk report with inclusion of more diverse analysis; and,
  • increased resourcing in a number of second line of defence functions.

Financial risk management is overseen by the 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 from the Board. Treasury risk management, including management of currency risk, interest rate risk and liquidity risk is carried out by a central Group Treasury function in accordance with the Group’s financing and treasury policy, as approved by the Board.

The wholesale credit risks associated with commodity trading and treasury positions are managed in accordance with the Group’s credit risk policy and collateral 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 2014 there have been fewer credit rating downgrades of financial institutions and European energy majors, than in 2013. The Group continually reviews its rating thresholds for counterparty credit limits, and updates these as necessary based on a consistent set of principles. It continues to operate within its limits. In the US and Europe, ongoing regulatory changes are increasing trading over exchanges or via zero threshold margined contracts. This helps to reduce counterparty credit risk, but carries increased liquidity requirements. The fall in oil prices towards the end of 2014, if sustained, may add financial pressure to certain counterparties which may in turn have a detrimental impact on their financial strength and resulting credit risk profile. These pressures will be taken into account in counterparty credit reviews.

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 2014, the Group had undrawn committed credit facilities of £3,751 million (2013: £3,780 million) and £374 million (2013: £484 million) of unrestricted cash and cash equivalents. 112% (2013 (restated): 115%) 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 12.8 years (2013: 13.8 years).

The Group’s liquidity is impacted by the cash posted 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. Refer to note 11(b) for movement in cash posted or received as collateral.

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 30 June 2014, the Group acquired 100% of Bord Gáis Energy’s gas and electricity supply business in the Republic of Ireland, including the Whitegate gas-fired power station. Bord Gáis Energy is reported as a separate segment within International Downstream.

The types of products and services from which each reportable segment derived its revenues during the year are detailed below.

     

Segment

  Description
International Downstream    
British Gas:  
Residential energy supply   The supply of gas and electricity to residential customers in the UK
Residential services   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
  The supply of gas and electricity and provision of energy-related services to business customers in the UK
Direct Energy:
Residential energy supply   The supply of gas and electricity to residential customers in North America
Business energy supply   (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   Installation and maintenance of heating, ventilation and air conditioning (HVAC) equipment, water heaters, solar power generating equipment and the provision of breakdown services, including the provision of fixed-fee maintenance/breakdown service and insurance contracts in North America
Bord Gáis Energy:   (i) The supply of gas, electricity and energy management solutions to residential, commercial and industrial customers, and (ii) power generation in the Republic of Ireland
International Upstream    
Centrica Energy:
Gas  

Production, processing, trading and optimisation of gas and oil and the development of new fields to grow reserves

Power   Generation, trading and optimisation of power from thermal, nuclear and wind sources
Centrica Storage   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.
                         
      2014       2013
Year ended 31 December  

Gross segment
revenue
£m

 

Less inter-
segment
revenue
£m

 

Group
revenue
£m

 

Gross segment
revenue
£m

 

Less inter-
segment
revenue
£m

 

Group
revenue
£m

International Downstream                    
Residential energy supply 8,328 (3) 8,325 9,487 9,487
Residential services 1,658 (156) 1,502 1,655 (149) 1,506
Business energy supply and services 2,981   (47)   2,934 3,084   (38)   3,046
British Gas 12,967 (206) 12,761 14,226 (187) 14,039
                   
Residential energy supply 2,571 2,571 2,517 2,517
Business energy supply 8,744 (6) 8,738 4,238 (55) 4,183
Residential and business services 523     523 570     570
Direct Energy 11,838 (6) 11,832 7,325 (55) 7,270
 
Bord Gáis Energy 391 391
 
International Upstream                    
Gas 3,644 (326) 3,318 4,596 (455) 4,141
Power 1,347   (343)   1,004 1,386   (402)   984
Centrica Energy 4,991 (669) 4,322 5,982 (857) 5,125
 
Centrica Storage   149   (47)   102   188   (51)   137
    30,336   (928)   29,408   27,721   (1,150)   26,571
 
The Group does not monitor and manage performance by geographic territory, but we provide below an analysis of revenue
and certain non-current assets by geography.
         
 

Revenue
(based on location of customer)

 

Non-current assets
(based on location of assets) (i)

Year ended 31 December   2014
£m
  2013
£m
  2014
£m
  2013
£m
UK 15,880   17,463 8,132   8,985
North America 11,996 7,530 3,421 3,534
Norway 478 695 1,564 1,813
Rest of the world   1,054   883   255   496
    29,408   26,571   13,372   14,828

(i) Non-current assets include goodwill, other intangible assets, PP&E and interests in joint ventures and associates.

(c) Operating profit and operating profit before 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 and 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.

         
  Adjusted operating profit (i)   Adjusted operating profit after taxation (ii)
Year ended 31 December                 2014
£m
  2013
£m
  2014
£m
  2013
£m
International Downstream                        
Residential energy supply 439 571 344 423
Residential services 270 318 212 241
Business energy supply and services 114 141 91 113
British Gas 823 1,030 647 777
       
Residential energy supply 90 163 62 111
Business energy supply 32 77 17 53
Residential and business services 28 36 20 25
Direct Energy 150 276 99 189
 
Bord Gáis Energy 7 3
 
International Upstream        
Gas (iii) 606 1,155 302 325
Power (iii) (iv) 131 171 158 143
Centrica Energy 737 1,326 460 468
 
Centrica Storage                 29   63   21   48
    1,746   2,695   1,230   1,482
Share of joint ventures’/associates’ interest and taxation (100) (111)
Depreciation of fair value uplifts to property, plant and equipment – Venture (iii) (31) (48)

Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – Nuclear (iii)

  (47)   (18)
1,568 2,518
Exceptional items (note 6) (1,597) (1,064)
Certain re-measurements included within gross profit (note 6) (1,134) 413
Certain re-measurements of associates’ energy contracts (net of taxation) (note 6)   26   25

Operating (loss)/profit after exceptional items
and certain re-measurements

  (1,137)   1,892
                 
            2014
£m
  2013
£m
Adjusted operating profit after taxation (ii)           1,230   1,482

Depreciation of fair value uplifts to property, plant and equipment (net of taxation) (iii)

(59) (37)
Impact of changes to UK corporation tax rates (note 8) (v) (2) 64
Corporate and other taxation, and interest (net of taxation) (vi)           (242)   (176)
Business performance profit for the year           927   1,333

Exceptional items and certain re-measurements (net of taxation) (note 6)

          (1,932)   (383)
Statutory (loss)/profit for the year           (1,005)   950
(i) 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.
(ii) 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. Segment operating profit after tax includes £28 million (2013: £1 million) attributable to non-controlling interests.
(iii) 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.
(iv) Power adjusted operating profit after taxation includes a one-off deferred tax benefit of £44 million (2013: nil) following a legal entity reorganisation.
(v) In 2014 there is no impact of equity accounted interests (2013: £29 million credit).
(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.
             
  Share of results of joint
ventures and associates
before interest and taxation (i)
 

Depreciation and impairments of
property, plant and equipment

 

Amortisation, write-downs and
impairments of intangibles

Year ended 31 December   2014
£m
  2013
£m
  2014
£m
  2013
£m
  2014
£m
  2013
£m
International Downstream                  
Residential energy supply (1) (7) (17) (16) (57) (48)
Residential services (27) (23) (7) (8)
Business energy supply and services (2) (2) (8) (7)
British Gas (1) (7) (46) (41) (72) (63)
           
Residential energy supply (1) (1) (23) (24)
Business energy supply (1) (16) (77) (36)
Residential and business services (3) (2) (7) (7)
Direct Energy (5) (19) (107) (67)
 
Bord Gáis Energy (1) (3)
 
International Upstream            
Gas (ii) (809) (886) (154) (111)
Power (ii) 254 282 (55) (93) (2) (4)
Centrica Energy 254 282 (864) (979) (156) (115)
 
Centrica Storage (34) (30)
Other (iii)       (12)   (15)   (15)   (20)
    253   275   (962)   (1,084)   (353)   (265)

(i) 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.

(ii) Depreciation of PP&E is stated before depreciation of fair value uplifts for the Strategic Investments acquired in 2009.
(iii) The Other segment includes corporate functions.

Impairment of property, plant and equipment

During 2014, a £34 million (2013: nil) impairment charge was recognised in the ‘Centrica Energy – Gas’ segment within business performance.

Write-downs of intangible assets

During 2014, £135 million (2013: £95 million) of write-downs relating to exploration and evaluation assets were recognised in the ‘Centrica Energy – Gas’ segment within operating costs before exceptional items.

(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.

                         
      2014       2013
Year ended 31 December  

Total average
capital
employed
£m

 

Pre-productive
capital
employed
£m

 

Productive
capital
employed
£m

 

Total average
capital
employed
£m

 

Pre-productive
capital
employed
£m

 

Productive
capital
employed
£m

International Downstream                    
Residential energy supply (7) (7) 101 101
Residential services 173 173 218 218
Business energy supply and services 428     428 539     539
British Gas 594 594 858 858
                   
Residential energy supply 982 982 820 820
Business energy supply 1,268 1,268 783 783
Residential and business services 333     333 384     384
Direct Energy 2,583 2,583 1,987 1,987
 
Bord Gáis Energy 54 54
 
International Upstream                    
Gas (i) 3,761 (1,326) 2,435 3,932 (1,292) 2,640
Power 3,490   (24)   3,466 3,717   (282)   3,435
Centrica Energy 7,251 (1,350) 5,901 7,649 (1,574) 6,075
 
Centrica Storage   256     256   435   (130)   305
Total average segmental capital employed   10,738   (1,350)   9,388   10,929   (1,704)   9,225

(i) Capital employed includes £133 million (2013: £35 million) attributable to non-controlling interests.

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

           
Year ended 31 December     2014
£m
  2013
£m
Total average segmental capital employed     10,738   10,929
Add back/(deduct):
Average intra-group, margin cash and cash balances 668 281
Effect of averaging     (336)   (81)
Total segmental net operating assets at 31 December 11,070 11,129
(Deduct)/add back:
Bank overdrafts and loans, securities and treasury derivatives (6,641) (5,785)
Certain derivative financial instruments including balances held by joint ventures/associates (1,302) (257)
Corporate (liabilities)/assets (118) 130
Net retirement benefit asset     62   40
Net assets in Group Balance Sheet     3,071   5,257

(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.

         
  Capital expenditure on
property, plant and
equipment
  Capital expenditure on
intangible assets other
than goodwill
Year ended 31 December                 2014
£m
  2013
£m
  2014
£m
  2013
£m
International Downstream                        
Residential energy supply 28 27 348 287
Residential services 33 59 13 12
Business energy supply and services 1 1 166 121
British Gas 62 87 527 420
       
Residential energy supply 24 9 24 33
Business energy supply 3 19 84 64
Residential and business services 4 3 1
Direct Energy 31 31 108 98
 
Bord Gáis Energy 2 3
 
International Upstream        
Gas 923 982 217 147
Power 62 32 67 74
Centrica Energy 985 1,014 284 221
 
Centrica Storage 21 37 2 3
Other (i)   11   15   15   39
Capital expenditure       1,112 1,184 939 781
Capitalised borrowing costs (45) (43) (5) (8)
Movements in payables and prepayments related to capital expenditure 3 123 (1) 9
Purchases of emissions allowances and renewable obligations certificates       (547)   (431)
Net cash outflow (ii)                 1,070   1,264   386   351
(i) The Other segment relates to corporate assets.
(ii) The £386 million (2013: £351 million) purchase of intangible assets includes £201 million (2013: £121 million) relating to exploration and evaluation of oil and gas assets.

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   2014
£m
  2013
£m
Provision for onerous power procurement contract     (125)
Exceptional items included within gross profit     (125)
Impairment of Centrica Energy exploration and production assets (i)   (1,189)   (699)
Impairment of UK power generation assets (ii) (535)
Impairment of Nuclear investment (iii) (214)
Impairment of UK gas storage assets and associated provision for onerous capacity contracts (240)
Gain on disposal of Texas gas-fired power stations (note 15(c)) 219
Gain on disposal of Ontario home services business (note 15(c))   122  
    (1,597)   (939)
Exceptional items included within Group operating profit (1,597) (1,064)
Taxation on exceptional items (note 8)   436   397
Net exceptional items after taxation   (1,161)   (667)
(i) Impairment of Centrica Energy exploration and production assets has been recognised predominantly due to declining gas and oil prices. The Group recognised a pre-tax impairment charge of £1,189 million (post-tax charge £712 million) in the ‘Centrica Energy – Gas’ segment, which included a pre-tax impairment charge of £309 million (post-tax charge £265 million) on the Trinidad and Tobago gas assets (including £70 million of goodwill), a pre-tax impairment charge of £837 million (post-tax charge £410 million) on UK and Norwegian gas and oil assets and a pre-tax impairment charge of £43 million (post-tax charge £37 million) on Canadian upstream assets. Further details on how the recoverable amounts of fields are calculated on a fair value less cost of disposal (FVLCD) basis are provided below.
(ii) The Group’s larger UK gas-fired power stations, Langage, Humber and Killingholme were classified as held for sale on 8 May 2014. The Group reassessed the likelihood of the value of these assets being recovered principally through a divestment at 31 December 2014 and, since the disposal was no longer considered to be ‘highly probable’; the assets have been reclassified out of held for sale, see note 3 for further details. A pre-tax impairment charge of £371 million (post-tax charge of £297 million) has been recognised in the ‘Centrica Energy – Power’ segment (including £17 million of goodwill), predominantly due to declining forecast capacity market auction prices and clean spark spread prices together with other changes in assumptions following information gained during the disposal process. A further £13 million charge (£10 million net of taxation) was recognised in other comprehensive income to reverse previous upwards valuations of the impaired assets. The Group also recognised a pre-tax impairment charge of £164 million (post-tax £162 million) on its other UK gas-fired power stations based on the same assumptions. Further details on how the recoverable amount of the assets is calculated on a VIU basis are provided below.
(iii) The Group recognised an impairment charge of £214 million (post-tax charge of £214 million) on its Nuclear investment within the ‘Centrica Energy – Power’ segment due to declining forecast power prices and capacity market auction prices. Further details on how the recoverable amount of the investment is calculated on a FVLCD basis are provided below.
 

Certain re-measurements are the fair value movements on energy contracts entered into to meet the future needs of our customers or to sell the energy produced from our upstream assets. 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   2014
£m
  2013
£m
Certain re-measurements recognised in relation to energy contracts (note 2):    
Net (losses)/gains arising on delivery of contracts (63) 317
Net (losses)/gains arising on market price movements and new contracts   (1,071)   96
Net re-measurements included within gross profit (1,134) 413
Net gains arising on re-measurement of associates’ energy contracts (net of taxation)   26   25
Net re-measurements included within Group operating profit   (1,108)   438
Taxation on certain re-measurements (note 8)   337   (154)
Net re-measurements after taxation   (771)   284

The Group is generally a net buyer of commodity, procuring gas and power for our customers. Following significant decreases in commodity prices, net losses arising on market price movements and new contracts of £1,071 million have been recorded.

(c) Impairment accounting policy, process and sensitivities

The Group reviews the carrying amounts of goodwill, PP&E and intangible assets (with the exception of exploration assets) annually, or more frequently if events or changes in circumstances indicate that the recoverable amounts may be lower than their carrying amounts. Exploration assets and interests in joint ventures and associates are reviewed annually for indicators of impairment and tested for impairment where such an indicator arises. Where an asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the CGU to which the asset belongs. The recoverable amount is the higher of VIU and FVLCD. At inception, goodwill is allocated to each of the Group’s CGUs or groups of CGUs that expect to benefit from the business combination in which the goodwill arose. If the recoverable amount of an asset (or CGU) is estimated to be less than its carrying amount, the carrying amount of the asset (or CGU) is reduced to its recoverable amount. Any impairment is expensed immediately in the Group Income Statement. Any CGU impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to the other assets of the unit pro rata on the basis of the carrying amount of each asset in the unit.

VIU calculations have been used to determine recoverable amounts for all CGUs that include goodwill and indefinite-lived intangible asset balances with the exception of the impairment tests for the Centrica Energy – Upstream gas and oil CGUs, where FVLCD has been used. This methodology is deemed to be more appropriate for this CGU as it is based on the post-tax cash flows arising from the underlying assets and is consistent with the approach taken by management to evaluate the economic value of the underlying assets. Subsequently, the specific, underlying Upstream gas and oil PP&E assets and, in addition, the Group’s associate investment in Nuclear and the Storage PP&E assets have also used the FVLCD impairment methodology. UK power generation assets have used the VIU impairment methodology.

FVLCD discount rate and cash-flow assumptions

Centrica Energy – Gas – Upstream gas and oil production

An impairment charge of £1,189 million has been recorded within exceptional items for Centrica Energy exploration and production assets. The associated recoverable amounts (net of decommissioning costs) of £552 million are categorised within Level 3 of the fair value hierarchy. FVLCD is determined by discounting the post-tax cash flows expected to be generated by the gas and oil production and development assets, net of associated selling costs, taking into account those assumptions that market participants would use in estimating fair value. Post-tax cash flows are derived from projected production profiles of each field, taking into account forward prices for gas and liquids over the relevant period. Where forward market prices are not available, prices are determined based on internal model inputs. The date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, production costs, the contractual duration of the licence area and the selling price of the gas and liquids produced. As each field has specific reservoir characteristics and economic circumstances, the post-tax cash flows for each field are computed using individual economic models. Post-tax cash flows used in the FVLCD calculation for the first three years are based on the Group’s Board-approved three-year business plans and, thereafter, are based on long-term production and cash flow forecasts.

The future post-tax cash flows are discounted using a post-tax nominal discount rate of 9% (2013: 9%) to determine the FVLCD. The discount rate and inflation rate used in the FVLCD calculation are determined in the same manner as the rates used in the VIU calculations, with the exception of the adjustment required to determine an equivalent pre-tax discount rate.

The valuation of Centrica Energy – Gas goodwill is particularly sensitive to the price assumptions made in the impairment calculations. To illustrate this, the price assumptions for gas and oil have been varied by +/–10%. Changes in price generate different production profiles and in some cases the date that an asset ceases production and this has been considered in the sensitivity analysis. Otherwise, all other operating costs, life of field capital expenditure and abandonment expenditure assumptions remain unchanged. For exploration and production assets, an increase in gas and oil prices of 10% would reverse £142 million of post-tax impairment charges recorded at the year end. A reduction of 10% would give rise to further post-tax impairments of the underlying exploration and production assets of £254 million and an impairment of goodwill of £251 million in the UK/Norway/Netherlands CGU.

Centrica Energy – Power – Nuclear

An impairment charge of £214 million has been recorded within exceptional items for the Group’s associate investment in Nuclear. FVLCD is determined by discounting the post-tax cash flows expected to be generated by the investment, net of associated selling costs, taking into account those assumptions that market participants would use in estimating fair value. Post-tax cash flows are derived from projected production profiles of the underlying nuclear power stations, planned and unplanned outage assumptions and forward prices for power and forecast capacity market auction prices. Where forward market prices are not available, prices are determined based on internal model inputs. Post-tax cash flows used in the FVLCD calculations for the first three years are based on the Group’s Board-approved three-year business plans and, thereafter, are based on long-term production and cash flow forecasts.

The future post-tax cash flows are discounted using a post-tax nominal discount rate of 8% (2013: 8%) to determine the FVLCD. The discount rate and inflation rate used in the FVLCD calculation are determined in the same manner as the rates used in the VIU calculations, with the exception of the adjustment required to determine an equivalent pre-tax discount rate.

The valuation of the Group’s investment in Nuclear, which is categorised within Level 3 of the fair value hierarchy, is particularly sensitive to assumptions/variations in the power price. To illustrate this, sensitivities were performed at the year end to vary the power price assumptions in the Group’s internal valuation model by +/–10%. An increase in power prices of 10%, assuming all other assumptions remain constant, would result in the reversal of the impairment of £214 million recorded at the year end and would provide headroom of £310 million. A reduction of 10% would give rise to a further impairment charge of £522 million.

VIU discount rate and cash-flow assumptions

Centrica Energy – Power – Upstream Power

An impairment charge of £535 million has been recorded within exceptional items for the UK gas-fired power stations. The recoverable amounts have been determined using value in use calculations, with future cash flows discounted using a pre-tax nominal discount rate of 7.4% (2013: 7.4%). Cash inflows are based on forecast production profiles, forward prices for power, gas and carbon and forecast capacity market auction prices. Where forward market prices are not available, prices are determined based on internal model inputs. Cash outflows for operating and capital expenditure are based, for the first three years, on the Group’s Board-approved three-year business plans and, thereafter, are based on long-term production and cash flow forecasts.

7. Net finance cost

 
Financing costs mainly comprise 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.

                         
      2014         2013
Year ended 31 December   Financing costs
£m
  Investment
income
£m
 

Total
£m

 

Financing
costs
£m

 

Investment
income
£m

 

Total
£m

Cost of servicing net debt            
Interest income 46 46 43 43
Interest cost on bonds, bank loans and overdrafts (i) (257) (257) (252) (252)
Interest cost on finance leases (16) (16) (17) (17)
(273) 46 (227) (269) 43 (226)
Net losses on revaluation (ii) (14) (14) (6) (6)
Notional interest arising from discounting and other interest   (81)   6   (75)   (73)   11   (62)
(368) 52 (316) (348) 54 (294)
Capitalised borrowing costs (iii)   50     50   51     51
(Cost)/income   (318)   52   (266)   (297)   54   (243)
(i) During 2014 the Group increased its outstanding bond debt principal by $200 million, ¥30 billion, €100 million and £51 million, and decreased it by $100 million and £315 million. See note 11(c).
(ii) 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.
(iii) Borrowing costs have been capitalised using an average rate of 4.0% (2013: 4.6%). Capitalised interest has attracted tax deductions totalling £13 million (2013: £14 million), with deferred tax liabilities being set up for the same amounts.

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 temporary and are expected to unwind in the future.

Analysis of tax charge

                         
      2014       2013

Year ended 31 December

  Business
performance
£m
 

Exceptional items
and certain
re-measurements
£m

  Results for
the year
£m
  Business
performance
£m
  Exceptional items
and certain
re-measurements
£m
  Results for
the year
£m
Current tax
UK corporation tax (186) (186) (346) (1) (347)
UK petroleum revenue tax (53) (53) (210) (210)
Non-UK tax (i) (234) (130) (364) (504) (504)
Adjustments in respect of prior years – UK 86 86 140 140
Adjustments in respect of prior years – non-UK   2     2   28     28
Total current tax   (385)   (130)   (515)   (892)   (1)   (893)
Deferred tax
Origination and reversal of temporary differences – UK 109 538 647 (85) 370 285
UK petroleum revenue tax (7) 8 1 37 37

Origination and reversal of temporary differences – non-UK

(6) 374 368 55 (121) (66)
Change in tax rates (2) (17) (19) 64 (5) 59
Adjustments in respect of prior years – UK (72) (72) (94) (94)
Adjustments in respect of prior years – non-UK   (12)     (12)   (27)     (27)
Total deferred tax   10   903   913   (50)   244   194
Total tax on (loss)/profit (ii)   (375)   773   398   (942)   243   (699)
(i) Non-UK tax on exceptional items and certain re-measurements arose on the gains on disposal of the Texas gas-fired power stations and Ontario home services business in 2014.
(ii) Total tax on (loss)/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 2014 was 21% (2013: 23%). Upstream oil and gas production activities are taxed at a UK corporation tax rate of 30% (2013: 30%) plus a supplementary charge of 32% (2013: 32%) to give an overall rate of 62% (2013: 62%). In addition, certain upstream assets in the UK attract petroleum revenue tax (PRT) at 50% (2013: 50%) which is deductible against corporation tax, giving an overall effective rate of 81% (2013: 81%). Norwegian upstream profits are taxed at the standard rate of 27% (2013: 28%) plus a special tax of 51% (2013: 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 a reduction in the main UK corporation tax rate to 20% from 1 April 2015. At 31 December 2014, the relevant UK deferred tax assets and liabilities included in these Financial Statements were based on the reduced rate.

On 3 December 2014, the UK Government announced a 2% reduction to the rate of supplementary charge from 32% to 30% effective 1 January 2015. This reduction had not been substantively enacted at 31 December 2014 and so these financial statements have not applied the reduced rate. The effect of the announced reduction would be to decrease net deferred tax liabilities by £19 million.

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. The Group retains part of the profits generated to meet future investment plans or to fund share repurchase programmes.

                         
      2014       2013
    £m   Pence per
share
  Date of
payment
  £m   Pence per
share
  Date of
payment
Prior year final dividend 610 12.08 11 Jun 2014 611 11.78 12 Jun 2013
Interim dividend   257   5.10   12 Nov 2014   253   4.92   13 Nov 2013
    867           864        

The Directors propose a final dividend of 8.4 pence per ordinary share (totalling £417 million) for the year ended 31 December 2014. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 27 April 2015 and, subject to approval, will be paid on 25 June 2015 to those shareholders registered on 1 May 2015.

10. Earnings per ordinary share

 
Earnings per share (EPS) is the amount of loss or profit attributable to each share. Basic EPS is the amount of loss or profit for the year divided by the weighted average 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 loss attributable to equity holders of the Company for the year of £1,012 million (2013: £950 million profit) by the weighted average number of ordinary shares in issue during the year of 5,022 million (2013: 5,150 million). The number of shares excludes 82 million ordinary shares (2013: 50 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 132.1 million (2013: 137.3 million) ordinary shares of 614/81 pence each, representing 2.6% of the called up share capital as at 31 December 2014 (2013: 2.7%) at an average price of £3.18 (2013: £3.64) per share for a total consideration including expenses of £422 million (2013: £502 million). The current year shares were purchased as part of the £420 million share repurchase programme announced on 18 December 2013. The prior year 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, unless they are cancelled.

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 loss or profit for either 2014 or 2013, however, the weighted average number of shares used as the denominator is adjusted for potentially dilutive ordinary shares.

Weighted average number of shares

         
Year ended 31 December   2014
Million
shares
  2013
Million
shares
Weighted average number of shares – basic   5,022   5,150
Dilutive impact of share-based payment schemes (i)   27   33
Weighted average number of shares – diluted   5,049   5,183

(i) The dilutive impact of share based payment schemes is included in the calculation of diluted EPS, unless it has the effect of increasing the profit or decreasing the loss attributable to each share. Therefore, these shares are excluded from the calculation of basic diluted EPS in 2014.

Basic to adjusted basic earnings per share reconciliation

                 
    2014     2013
Year ended 31 December   £m   Pence per
ordinary
share
  £m   Pence per
ordinary
share
(Loss)/earnings – basic (1,012) (20.2) 950 18.4
Net exceptional items after taxation (notes 2 and 6(i)) 1,144 22.8 667 13.0
Certain re-measurement gains after taxation (notes 2 and 6) 771 15.4 (284) (5.5)
Depreciation of fair value uplifts to property, plant and equipment from
the Strategic Investments acquired in 2009, net of taxation
  59   1.2   37   0.7
Earnings – adjusted basic   962   19.2   1,370   26.6
                 
(Loss)/earnings – diluted   (1,012)   (20.2)   950   18.3
                 
Earnings – adjusted diluted   962   19.1   1,370   26.4

(i) Net exceptional items after taxation of £1,161 million are reduced by £17 million for the purpose of calculating adjusted basic and adjusted diluted EPS. The adjustment reflects the share of net exceptional items attributable to non-controlling interests.

Strategic Investments

During 2009, the Group acquired a 20% interest in Lake Acquisitions Limited (Nuclear) 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 £31 million (2013: £48 million) depreciation and a taxation credit of £19 million (2013: £29 million) in the period. Additionally, the impact of depreciation arising on fair value uplifts attributed to the 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 £47 million (2013: £18 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   2014
£m
  2013
(restated) (i)
£m
Net debt   5,196   4,942
Equity   2,735   5,192
Capital   7,931   10,134

(i) Net debt has been restated to include cash posted or received as collateral under margin and collateral agreements to more accurately reflect management’s view of net debt.

Debt levels are restricted to limit the risk of financial distress and, in particular, to maintain a strong credit profile. The Group’s credit standing is important for several reasons: to maintain a low cost of debt, limit collateral requirements in energy trading, hedging and decommissioning security arrangements; and to ensure the Group is an attractive counterparty to energy producers and long-term customers.

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 2014, the ratio of the Group’s net debt to adjusted EBITDA was 1.8 (2013: 1.3). Adjusted EBITDA to gross interest expense for the year ended 31 December 2014 was 8.8 (2013: 12.8).

British Gas Insurance Limited (BGIL) is required under PRA regulations to hold a minimum capital amount and has complied with this requirement in 2014 (and 2013). 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 2014 of £3.1 billion, the limit for net debt was £9.3 billion. The Group funds its long term debt requirements through issuing bonds in the capital markets and taking bank debt. Short term debt requirements are met primarily through issuance of commercial paper. The Group maintains substantial committed facilities and uses these to provide liquidity for general corporate purposes, including short term business requirements and back-up for commercial paper.

(b) Net debt summary

 
Net debt predominantly includes capital market borrowings offset by cash, cash posted or received as collateral, securities and certain hedging financial instruments used to manage interest rate and foreign exchange movements on borrowings.
                         
   

Cash and
cash
equivalents (i)
£m

 

Cash
posted/(received)
as collateral (ii)
£m

 

Current and
non-current
securities (iii)
£m

 

Current and non-current
borrowings, net
of related deposits (iv)
£m

 

Derivatives
£m

 

Net debt
£m

1 January 2013 (restated) (v)   931   102   206   (5,328)   144   (3,945)
Cash outflow from purchase of securities (8) 8
Cash inflow from additional borrowings 1,209 (1,209)
Cash outflow from payment of capital element
of finance leases
(30) 30
Cash outflow from repayment of borrowings (370) 370
Net cash outflow increasing net debt (1,085) (1,085)
Cash inflow from collateral received 82 (82)
Revaluation (2) 87 (96) (11)

(Increase)/decrease in interest payable and amortisation of borrowings

(11) 4 (7)
Acquisition of businesses 93 93
Exchange adjustments   (10)   (6)   (1)   30     13
31 December 2013 (restated) (v)   719   107   211   (6,031)   52   (4,942)
Cash inflow from sale of securities 5 (5)
Cash inflow from additional borrowings (iv) 1,311 (1,311)
Cash outflow from payment of capital element
of finance leases
(32)

32
Cash outflow from repayment of borrowings (486) 486
Net cash outflow increasing net debt (255) (255)
Cash outflow from collateral posted (ii) (640) 640
Revaluation 8 (61) 21 (32)

(Increase)/decrease in interest payable and amortisation of borrowings

(9) 16 7
Exchange adjustments (1) 29 1 (62) (33)
Other non-cash movements (vi)       59       59
31 December 2014   621   776   274   (6,956)   89   (5,196)
(i) Cash and cash equivalents includes £247 million (2013: £235 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) Collateral is posted or received to support energy trading and procurement activities. It is posted when contracts with marginable counterparties are out of the money and is received when contracts are in the money. These positions reverse when contracts are settled and the collateral is returned. As a net procurer of energy, the fall in commodity prices at the end of 2014 resulted in significant out of the money energy contracts which required £640 million of collateral to be posted during the year. Of the net cash collateral posted at the year end, £185 million (2013: £53 million) is included within trade payables and £961 million (2013: £160 million) within trade receivables.
(iii) Securities balances include £129 million (2013: £126 million) of index-linked gilts which the Group uses for short-term liquidity management purposes and £86 million of available-for-sale financial assets (2013: £85 million). The Group has posted £29 million (2013: £28 million) of non-current securities as collateral against an index-linked swap maturing on 16 April 2020.
(iv) A £30 million deposit with Societe Generale in relation to a rolling credit facility is included within this category. The deposit is classified as an other receivable but the matching loan is included in borrowings.
(v) Net debt has been restated to include cash posted or received as collateral under margin and collateral agreements, to more accurately reflect management’s view of net debt. The items to which the cash posted as collateral relate are not included within net debt.
(vi) Shares in Enercare Inc. with a value of C$106 million (£59 million), were received as part consideration for the disposal of Ontario home services. See note 15(c) for further details.

(c) Borrowings summary

                                 
31 December   Coupon rate
%
  Principal
m
  Current
£m
  Non-current
£m
  2014
Total
£m
  Current
£m
  Non-current
£m
  2013
Total
£m
Bank overdrafts and loans (i)       (427)   (312)   (739)   (16)   (305)   (321)
Bonds (by maturity date):                    
4 November 2014 Floating $100 (60) (60)
10 December 2014 5.125 £315 (323) (323)
31 March 2015 Floating $70 (45) (45) (42) (42)
10 September 2015 0.320 ¥30,000 (161) (161)
11 September 2015 Floating £51 (51) (51)
12 September 2015 Floating €100 (78) (78)
24 October 2016 5.500 £300 (316) (316) (321) (321)
14 April 2017 Floating $200 (128) (128)
19 September 2018 7.000 £400 (444) (444) (443) (443)
1 February 2019 3.213 €100 (78) (78) (83) (83)
25 September 2020 Floating $80 (51) (51) (48) (48)
22 February 2022 3.680 HK$450 (37) (37) (35) (35)
10 March 2022 6.375 £500 (528) (528) (490) (490)
16 October 2023 4.000 $750 (494) (494) (444) (444)
4 September 2026 6.400 £200 (225) (225) (212) (212)
16 April 2027 5.900 $70 (45) (45) (42) (42)
13 March 2029 4.375 £750 (741) (741) (740) (740)
5 January 2032 (ii) Zero €50 (41) (41) (46) (46)
19 September 2033 7.000 £770 (762) (762) (762) (762)
16 October 2043 5.375 $600 (379) (379) (356) (356)
12 September 2044 4.250 £550 (536) (536) (536) (536)
25 September 2045 5.250 $50   (32)   (32)   (30)   (30)
(335) (4,837) (5,172) (383) (4,630) (5,013)
Commercial paper (735) (735) (325) (325)
Obligations under finance leases (35) (202) (237) (32) (237) (269)
Interest accruals       (103)     (103)   (103)     (103)
            (1,635)   (5,351)   (6,986)   (859)   (5,172)   (6,031)
(i) Current bank overdrafts and loans include £300 million (2013: nil) of short term borrowings drawn under committed facilities with maturities of 1 April 2019.
(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   2014
£m
  2013
£m
1–2 years    
2–5 years (96) (90)
>5 years   (216)   (215)
    (312)   (305)

12. Joint ventures and associates

 

Share of results of joint ventures and associates represents the results of businesses where we exercise joint control or significant influence and generally have an equity holding of up to 50%.

(a) Share of results in joint ventures and associates

The Group’s share of results of joint ventures and associates for the year ended 31 December 2014 principally arises from its interests in the following entities (predominantly reported in the Centrica Energy – Power segment):

  • Wind farms – Barrow Offshore Wind Limited, Celtic Array Limited (Round 3), GLID Wind Farms TopCo Limited and Lincs Wind Farm Limited (i).
  • Nuclear – Lake Acquisitions Limited.
                     
Year ended 31 December   Joint ventures
Wind farms
£m
  Associates
Nuclear
£m
  Other
£m
  2014
Total
£m
  2013
Total
£m
Income   96   620   6   722   735
Expenses excluding certain re-measurements (ii) (104) (416) (7) (527) (521)
Certain re-measurements     25     25   23
(8) 229 (1) 220 237
Interest paid (47) (15) (62) (60)
Taxation excluding certain re-measurements (ii) 8 (35) (27) (8)
Taxation on certain re-measurements     1     1   2
Share of post-taxation results of joint ventures and associates   (47)   180   (1)   132   171
(i) As part of the finance arrangements entered into by GLID Wind Farms TopCo Limited and Lincs Wind Farm Limited, the Group’s shares in these companies 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.
(ii) Includes £58 million (2013: £61 million) relating to depreciation of fair value uplifts to PP&E on investment in Nuclear. The associated tax impact is £11 million credit (2013: £43 million credit).

Nuclear

In November 2009 the Group acquired a 20% interest in Lake Acquisitions Limited (Nuclear). The Group’s share of profit arising from its investment in Nuclear for the year to 31 December 2014, 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

                     
Year ended 31 December   Joint ventures
Wind farms
£m
  Associates
Nuclear
£m
  Other
£m
  2014
Total
£m
  2013
Total
£m
Share of post-taxation results of joint ventures and associates   (47)   180   (1)   132   171
Certain re-measurements (net of taxation) (26) (26) (25)
Depreciation – Nuclear (net of taxation) (i) 47 47 18
Interest paid 47 15 62 60
Taxation (excluding taxation on certain re-measurements
and Nuclear depreciation)
  (8)   46     38   51
Share of adjusted results of joint ventures and associates   (8)   262   (1)   253   275

(i) Relates to depreciation of fair value uplifts to PP&E on investment in Nuclear.

(c) Interests in joint ventures and associates

                         
      2014       2013
   

Investments in
joint ventures and
associates
£m

  Shareholder
loans
£m
  Total
£m
 

Investments in
joint ventures
and associates
£m

  Shareholder
loans
£m
  Total
£m
1 January 2,259 399 2,658 2,316 405 2,721
Additions 24 24 48 55 20 75
Disposals (24) (24) (29) (5) (34)
Decrease in shareholder loans (73) (73)
Share of profits for the year 132 132 171 171
Share of other comprehensive income 6 6 3 3
Impairment (note 6) (214) (214) (64) (21) (85)
Dividends   (138)     (138)   (193)     (193)
31 December   2,045   350   2,395   2,259   399   2,658

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

                     
        2014   2013
31 December   Joint ventures
Wind farms
£m
  Associates
Nuclear
£m
  Other
£m
  Total
£m
  Total
£m
Share of non-current assets 603 3,491 23 4,117 4,390
Share of current assets   58   639   2   699   689
    661   4,130   25   4,816   5,079
Share of current liabilities (130) (189) (2) (321) (450)
Share of non-current liabilities   (472)   (1,755)   (1)   (2,228)   (2,362)
    (602)   (1,944)   (3)   (2,549)   (2,812)
Impairment (note 6) (214) (214)
Restricted interest on shareholder loan (i)   (8)       (8)   (8)
Share of net assets of joint ventures and associates 51 1,972 22 2,045 2,259
Shareholder loans   348     2   350   399
Interests in joint ventures and associates   399   1,972   24   2,395   2,658
                     
Net (debt)/cash included in share of net assets   (453)   73     (380)   (534)

(i) The Group restricted 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

 

Accounting treatment

Proprietary energy trading and treasury management  

Carried at fair value, with changes in fair value recognised in the Group’s results for the year before exceptional items and certain re-measurements (i)

Energy procurement/ optimisaton   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.

In cases where a derivative qualifies for hedge accounting, derivatives are classified as fair value hedges, or cash flow hedges. The carrying values of derivative financial instruments by product type for accounting purposes are as follows:

                 
    2014     2013
31 December   Assets
£m
  Liabilities
£m
  Assets
£m
  Liabilities
£m
Derivative financial instruments – held for trading under IAS 39:
Energy derivatives – for procurement/optimisation 644 (1,878) 512 (750)
Energy derivatives – for proprietary trading 44 (17) 56
Interest rate derivatives (i) (30) (26)
Foreign exchange derivatives (i) 58 (125) 106 (96)
Energy derivative contracts designated at fair value through profit or loss 16 (14) 24 (1)
Derivative financial instruments in hedge accounting relationships:
Energy derivatives (2)
Interest rate derivatives (i) 158 (2) 95 (22)
Foreign exchange derivatives (i)   10   (87)   7   (40)
Total derivative financial instruments   930   (2,153)   800   (937)
Included within:
Derivative financial instruments – current 617 (1,565) 573 (506)
Derivative financial instruments – non-current   313   (588)   227   (431)

(i) Included within these categories are £89 million (2013: £52 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   2014
£m
  2013
£m
Short-term forward market purchases and sales of gas and electricity:    
UK and Europe (302) (30)
North America (721) 22
Structured gas purchase contracts (105) (54)
Structured gas sales contracts (14) (54)
Structured power purchase contracts (67) (41)
Other   4   (4)
Net total   (1,205)   (161)

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   Type of benefit   Status   Country  

Number of active
members as at
31 December 2014

 

Total membership as
at 31 December
2014

Centrica Engineers Pension Scheme   Defined benefit final
salary pension
  Closed to new members in 2006   UK   4,358   8,695
  Defined benefit career
average pension
  Open to service engineers only   UK   3,783   4,716
Centrica Pension Plan   Defined benefit final
salary pension
  Closed to new members in 2003   UK   4,119   8,770
Centrica Pension Scheme Defined benefit final
salary pension
Closed to new members in 2003 UK 25 10,785
Defined benefit career
average pension
Closed to new members in 2008 UK 2,000 4,151
  Defined contribution pension   Open to new members   UK   14,211   17,580
Bord Gáis Energy Company Defined Benefit Pension Scheme   Defined benefit final salary pension   Closed to new members in 2014   Republic of Ireland   171   175
Bord Gáis Energy Company Defined Contribution Pension Plan   Defined contribution pension   Open to new members   Republic of Ireland   117   124
Direct Energy Marketing Limited Pension Plan   Defined benefit final
salary pension
  Closed to new members in 2004   Canada   48   413

Direct Energy Marketing Limited

  Post retirement benefits   Closed to new members in 2012   Canada   162   366

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 1 August 2014. These have been updated to 31 December 2014 for the purposes of meeting the requirements of IAS 19: ‘Employee Benefits’ (2011). 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 (RPI) and the Consumer Price Index (CPI). 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. During the year the Group initiated a pension increase exchange (PIE). This PIE offered retired pensioners the option to receive a higher current pension in return for giving up certain future increases linked to RPI. A past service credit of £10 million arose in the year in relation to those pensioners that accepted the PIE.

Longevity

The majority of the schemes’ obligations are to provide benefits for the life of scheme members and their surviving spouses; therefore increases in 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 2014.

     
Total liabilities of the Registered Pension Schemes   2014
31 December   %
Actives – final salary – capped 30
Actives – final salary – uncapped and crystallised benefits 5
Actives – career average 4
Deferred pensioners 32
Pensioners   29
    100

(c) Accounting assumptions

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

         
Major assumptions used for the actuarial valuation   2014   2013
31 December   %   %
Rate of increase in employee earnings:
Subject to cap 1.7 1.7
Other 3.0 3.3
Rate of increase in pensions in payment 3.0 3.3
Rate of increase in deferred pensions:
In line with CPI capped at 2.5% 1.9 2.3
In line with RPI 3.0 3.3
Discount rate   3.9   4.6

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:

         
Life expectancy at age 65 for a member
31 December
  2014   2013
  Male
Years
  Female
Years
  Male
Years
  Female
Years
Currently aged 65 22.7   25.1 22.9   25.3
Currently aged 45   24.4   27.0   24.7   27.3

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:

         
Impact of changing material assumptions


31 December

  2014   2013
 

Increase/
decrease in
assumption

 

Indicative effect
on scheme
liabilities
%

 

Increase/
decrease in
assumption

 

Indicative effect
on scheme
liabilities
%

Rate of increase in employee earnings subject to cap 0.25%   +/–1 0.25%   +/–1
Rate of increase in pensions in payment and deferred pensions 0.25% +/–5 0.25% +/–5
Discount rate 0.25% –/+6 0.25% –/+6
Inflation assumption 0.25% +/–5 0.25% +/–5
Longevity assumption   1 year   +/–3   1 year   +/–3

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   2014
£m
  2013
£m
Fair value of plan assets   6,444   5,683
Present value of defined benefit obligation   (6,382)   (5,643)
Net asset recognised in the Group Balance Sheet   62   40
Pension asset presented in the Group Balance Sheet as:
Retirement benefit assets 185 205
Retirement benefit liabilities   (123)   (165)
Net pension asset   62   40

(e) Movement in the year

         
    2014   2013
                 

Pension
liabilities
£m

 

Pension
assets
£m

 

Pension
liabilities
£m

 

Pension
assets
£m

1 January             (5,643)   5,683 (5,045)   5,133
Items included in the Group Income Statement:        
Current service cost (115) (103)
Contributions by employer in respect of employee salary sacrifice arrangements (i) (25) (19)
Total current service cost (140) (122)
Past service credit 10
Interest (expense)/income (260) 266 (242) 249
Items included in the Group Statement of Comprehensive Income:
Returns on plan assets, excluding interest income 467 187
Actuarial gain/(loss) from changes to demographic assumptions 67 (64)
Actuarial loss from changes in financial assumptions (609) (311)
Actuarial (loss)/gain from experience adjustments (8) 9
Exchange adjustments 1 (2) 12 (6)
Items included in the Group Cash Flow Statement:
Employer contributions 191 232
Contributions by employer in respect of employee salary sacrifice arrangements (i) 25 19
Other movements:
Plan participants’ contributions (1) 1 (7) 7
Benefits paid from schemes 153 (153) 138 (138)
Acquisition/disposal of businesses 50 (34)
Transfers from provisions for other liabilities and charges                 (2)     (11)  
31 December                 (6,382)   6,444   (5,643)   5,683

(i) 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 £37 million (2013: £32 million) to operating profit in respect of defined contribution pension schemes. This included contributions of £12 million (2013: £8 million) paid via a salary sacrifice arrangement.

(f) Pension scheme assets

The market value of plan assets were:

                         
      2014       2013
31 December   Quoted
£m
  Unquoted
£m
  Total
£m
  Quoted
£m
  Unquoted
£m
  Total
£m
Equities 1,950 211 2,161 1,636 163 1,799
Diversified asset funds 42 113 155 305 98 403
Corporate bonds 1,813 1,813 1,571 1,571
High-yield debt 182 275 457 155 207 362
Liability matching assets 1,052 415 1,467 1,012 258 1,270
Property 328 328 271 271
Cash pending investment   63     63   7     7
    5,102   1,342   6,444   4,686   997   5,683

Included within equities are £2 million (2013: £2 million) of ordinary shares of Centrica plc via pooled funds that include a benchmark allocation to UK equities. Included within corporate bonds are £3 million (2013: £4 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 £75 million (2013: £67 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, £49 million (2013: £42 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 2012 and 2013 the Group made special contributions to the Registered Pension Schemes of £444 million, which the schemes immediately used to acquire interests in the partnerships for their fair value of £444 million. The schemes’ total partnership interests entitle them to distributions from the income of the partnerships over a period of between 4 and 15 years. Between 2014 and 2016 this income will amount to £77 million per annum but will reduce thereafter. The partnerships are controlled by Centrica and their results are 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.

Deficit payments are also being made in respect of the Direct Energy Marketing Limited Pension Plan in Canada. £4 million was paid in the year to 31 December 2014. £1 million is to be paid in 2015, £2 million is to be paid in 2016 and £1 million is to be paid in 2017, 2018, and 2019.

The Group estimates that it will pay £100 million of ordinary employer contributions during 2015 at an average rate of 20.5% 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

(a) Business combinations

 
During the period, the Group acquired Bord Gáis Energy’s gas and electricity supply and generation business, Astrum Solar’s residential solar installation business and certain upstream Canadian natural gas assets. The business combinations section details the consideration paid and/or payable, as well as the provisional fair values of the net assets acquired.

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

Bord Gáis Energy

On 30 June 2014, the Group acquired 100% of Bord Gáis Energy’s gas and electricity supply business in the Republic of Ireland, including the Whitegate gas-fired power station, for consideration of €214 million (£172 million). The transaction provides a platform for growth in an adjacent downstream market to the UK. This business is a separate reportable segment of International Downstream. Goodwill of €20 million (£16 million) was recognised and is not tax deductible. The opening balance sheet includes an amount of €153 million (£123 million) related to the fair value of receivables with a gross contractual value of €183 million (£147 million).

Provisional fair value of the identifiable acquired assets and liabilities

     
    Bord Gáis Energy
£m
Balance Sheet items  
Non-current assets 89
Current assets (including £62 million of cash and cash equivalents) 244
Current liabilities (159)
Non-current liabilities   (18)
Net identifiable assets (i)   156
Goodwill (i)   16
Net assets acquired (i)   172
Consideration comprises:
Cash consideration paid 158
Contingent consideration (ii)   14
Total consideration (i)   172
     
Income Statement items (iii)
Revenue recognised since the acquisition date in the Group Income Statement (iii) 391
Profit since the acquisition date in the Group Income Statement (iii)   3
(i) Net identifiable assets were disclosed in the interim accounts as at 30 June 2014 totalling £160 million. Cash consideration paid at the acquisition date was £150 million. Post-completion, a true-up of working capital amounts resulted in an additional payment of £8 million. Together with updated valuations, predominantly of certain commodity contracts, this gave rise to a goodwill balance of £16 million.
(ii) Contingent consideration is stated at fair value at the reporting date and is classified as an other financial liability (level 3 in terms of fair value hierarchy). Fair value is based on a set of key assumptions which take into consideration the probability of meeting underlying EBITDA targets between 2014 and 2016, as well as the impact of the discount rate. Future developments may require further revisions to the estimate. The maximum consideration to be paid to the vendor amounts to €21 million (£17 million).
(iii) Revenue and profits from business performance between the acquisition date and the balance sheet date exclude exceptional items and certain re-measurements.

Acquisition-related costs of £12 million have been charged to operating costs before exceptional items in the Group Income Statement for the year ended 31 December 2014.

Astrum Solar

On 29 July 2014, the Group acquired a 100% equity interest in the privately owned Astrum Solar’s residential business for consideration of $53 million (£33 million). The business designs, installs and maintains solar power generating equipment for use in the home. Goodwill of $50 million (£31 million) arose on acquisition, which is not tax deductible. This business forms part of the ‘Direct Energy – Residential and business services’ segment.

Canadian natural gas assets

On 27 June 2014, the Group acquired natural gas assets in the Foothills region of Alberta from Shell Canada Energy for C$42 million (£23 million). The assets were acquired by CQECP, the 60:40 partnership with QPI. As part of the transaction, the Group disposed of its interests in the Burnt Timber gas processing plant and the Waterton undeveloped lands in south-west Alberta. The Group has judged that the assets acquired meet the definition of a business and that the Group has power over the relevant activities; therefore the acquisition is treated as a business combination of the Group. No goodwill arose on this transaction.

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 £29,898 million (compared to reported revenue of £29,408 million) and profit after taxation before exceptional items and certain re-measurements of £936 million (compared to reported profit after taxation of £927 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.

2013 Business Combinations – fair value updates

The Group acquired Hess Energy Marketing (HEM) on 1 November 2013. During the measurement period a true up of working capital was agreed with the vendor, Hess Corporation, resulting in a repayment of $31 million (£21 million) cash consideration.

There have been no other significant updates during the measurement period to the fair values recognised for businesses acquired in 2013, although changes to the opening balance sheets of these previously acquired businesses have offset the goodwill recognised on Astrum Solar and Bord Gáis Energy by £31 million.

(b) 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 and are presented separately on the face of the Group Balance Sheet.

UK power stations

On 8 May 2014, the Group announced that it had undertaken a strategic review of its UK power station fleet and that it intended to focus its UK gas-fired power generation on small flexible ‘peaking’ plants. Consequently, the Group sought to release capital from its larger operating plants, Langage, Humber and Killingholme in order to focus on other investment opportunities. These assets and liabilities were classified as a disposal group held for sale at the half year.

The Group ran a disposal process throughout the second half of 2014 and continued to expect the value to be recovered through a divestment. In December, the first capacity market auction prices cleared at a level significantly below market expectations with an expected consequential decline in bidder confidence. These events led the Group to reassess the asset classification and decide the disposal was no longer ‘highly probable’. Consequently, the assets were reclassified out of assets held for sale as at 31 December. The culmination of the bid process in February 2015 provided further evidence of the conditions existing at 31 December, as the bid levels were below the Group’s hold value. An impairment of £384 million was recorded on reclassification to measure the assets at their recoverable amounts at the date of transfer. See note 6 for further details.

Other

The Ontario home services and Amethyst/Ravenspurn assets were classified as held for sale in the second half of the year and subsequently disposed of before year end.

(c) Disposals

 

The Group’s Texas gas-fired power stations and Greater Kittiwake upstream gas assets classified as disposal groups held for sale at 31 December 2013 have now been disposed. This note details the consideration received, the assets and liabilities disposed of and the profit before and after tax arising on disposal. The Ontario home services, Amethyst/Ravenspurn upstream gas assets and Barrow Offshore Wind Farm businesses were also disposed of during the year.

                     
Date of disposal   22 January 2014   1 March 2014   30 September 2014   20 October 2014   19 December 2014
Business/assets disposed of by the Group

Texas gas-fired
power stations(i)

Greater Kittiwake
upstream gas assets(ii)

Amethyst/Ravenspurn
upstream gas assets

Ontario
home services(iii)

Barrow offshore
wind farm(iv)

Sold to Blackstone Group LP Enquest Heather Limited Perenco UK Limited Enercare Inc. DONG Energy
    £m   £m   £m   £m   £m
Goodwill 150
Property, plant and equipment 186 89 10
Interest in joint ventures 24
Other assets 9 8
Other liabilities (15) (2)
Non-current provisions for other liabilities and charges   (3)   (46)   (35)    

Net assets/(liabilities)
disposed of

  192   36   (25)   148   24
Cash consideration received 411 18 1 235 50
Other forms of consideration 2 59
Disposal costs         (24)  

Profit/(loss) on disposal
before tax

  219   (18)   28   122   26
Taxation   (77)   31   (14)   (40)   (4)
Profit on disposal after tax   142   13   14   82   22
(i) The profit on disposal of the Texas gas-fired power stations has been treated as an exceptional item. See note 6.
(ii) Further consideration of up to $130 million (£83 million) is receivable from the vendor, contingent on approval of certain field development plans by the Secretary of State. No amounts have been recorded at the balance sheet date as the likelihood of receipt is not yet considered probable.
(iii) The profit on disposal of the Ontario home services has been treated as an exceptional item, as shown in note 6. The consideration received comprises cash of C$426 million (£235 million) as well as shares in the acquirer, Enercare Inc., of C$106 million (£59 million), which are listed on the Toronto Stock Exchange (TSX). The shares transferred as consideration upon disposal of the Ontario home services business were valued at fair value, which is their quoted market price discounted to reflect the application of a lock-up period of 18 months to these financial assets. The assets are classified as level 2 within the fair value hierarchy. An amount of £15 million of disposal costs remained unpaid as at the balance sheet date.
(iv) Consideration for the disposal of Barrow offshore wind farm includes £19 million for the termination of the power purchase agreement the Group had with Barrow offshore wind farm which is shown in ‘Net cash flow from operating activities’ in the Group Cash Flow Statement, with the remaining consideration included in ‘Repayments of loans to, and disposal of investments in, joint ventures and associates’. Of the profit on disposal after tax, £2 million was allocated to the ‘British Gas – Residential energy supply’ segment.

All other disposals undertaken by the Group were immaterial, both individually and in aggregate, with net cash consideration of £2 million.

None of these disposals are shown as discontinued operations on the face of the Group Income Statement as they do not represent a separate major line of business or geographical area of operation.

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 offset 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 and other commodities that the Group is contracted to buy at estimated future prices.

On 25 March 2013, the Group 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 £3.6 billion (included in ‘LNG capacity’ below) between 2018 and 2038. The Group may also make up to £7 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   2014
£m
  2013
£m
Commitments in relation to the acquisition of property, plant and equipment:    
Development of Norwegian oil and gas assets 76 159
Development of Cygnus gas field 182 146
Other capital expenditure   23   51
Commitments in relation to the acquisition of intangible assets:
Renewable obligation certificates to be purchased from joint ventures (i) 1,063 1,169
Renewable obligation certificates to be purchased from other parties 2,024 1,516
Other intangible assets   247   205
Other commitments:
Commodity purchase contracts 39,563 49,831
LNG capacity 4,388 4,452
Transportation capacity 942 939
Outsourcing of services 148 226
Commitments to invest in joint ventures 5 130
Energy Company Obligation 39 255
Power station tolling fees 110 125
Smart meters 67 62
Power station operating and maintenance 162 138
Heat rate call options 146
Other long-term commitments   396   333
Operating lease commitments:
Future minimum lease payments under non-cancellable operating leases   810   975

(i) Renewable obligation certificates are purchased from several joint ventures which produce power from wind energy under long-term off-take 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:

         
   

Commodity
purchase contracts
commitments

 

Total minimum lease
payments under
non-cancellable
operating leases

31 December   2014
£billion
  2013
£billion
  2014
£m
  2013
£m
<1 year   10.4   11.1   154   217
1–2 years 6.4 8.1 117 138
2–3 years 3.3 5.8 79 89
3–4 years 3.0 3.8 60 64
4–5 years 2.2 3.7 50 54
>5 years   14.3   17.3   350   413
    39.6   49.8   810   975

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

         
Year ended 31 December   2014
£m
  2013
£m
Minimum lease payments (net of sub-lease receipts)   113   112
Contingent rents – renewables (i)   98   109

(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 (2013: nil). Payments made for physical power are charged to the Group 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 most significant indemnities relate to the decommissioning costs associated with the Morecambe, Statfjord and Kvitebjorn 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.

With regards to Morecombe the 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.

Following legislation being executed, the UK Government is now signing contracts (Decommissioning Relief Deeds – DRDs) with industry, providing certainty on decommissioning tax relief via the tax code or DRD. These deeds should permit industry to move to “post tax” Decommissioning Security Agreements (DSAs), cutting the cost of these and freeing capital for investment. Centrica now has a signed DRD, discussions are ongoing on moving to a post-tax DSA, whilst we continue to analyse options to update the South Morecambe DSA.

Security for Statfjord and Kvitebjorn is slightly different in this respect as it was provided to the previous owners as part of the acquisition of these fields.

(c) Contingent liabilities

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 may pay up to £36 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.

There are no other material contingent liabilities.

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 2014 and the date of this report.

Acquisition

On 13 February 2015, Centrica announced that British Gas will acquire AlertMe, a UK-based connected homes company that provides innovative energy management products and services. The net cost to British Gas will be £44 million, taking into account an existing 21% holding in AlertMe. It is anticipated that the transaction will close by the end of the first quarter of 2015.

Dividends

The Directors propose a final dividend of 8.4 pence per ordinary share (totalling £417 million) for the year ended 31 December 2014. The dividend will be submitted for formal approval at the Annual General Meeting to be held on 27 April 2015 and, subject to approval, will be paid on 25 June 2015 to those shareholders registered on 1 May 2015.

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 month period ended 31 December 2014 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, Republic of Ireland 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 and the Republic of Ireland 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.

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

19. Group Income Statement for the six months ended 31 December (unaudited)

                             
        2014     2013
Six months ended 31 December   Notes  

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 

Results for
the period
£m

 

Business
performance
£m

 

Exceptional
items and certain
re-measurements
£m

 

Results for
the period
£m

 
Group revenue 21(a) 13,660     13,660 12,920     12,920

Cost of sales before exceptional items and certain re-measurements

(11,571) (11,571) (10,578) (10,578)
Exceptional items – onerous provision 22(a) (125) (125)
Re-measurement of energy contracts 22(b)   (988)   (988)   309   309
Cost of sales       (11,571)   (988)   (12,559)   (10,578)   184   (10,394)
Gross profit 2,089   (988)   1,101 2,342   184   2,526
Operating costs before exceptional items (1,505) (1,505) (1,403) (1,403)
Exceptional items – impairments 22(a) (1,938) (1,938) (939) (939)
Exceptional items – gains on disposals 22(a)   122   122    
Operating costs (1,505) (1,816) (3,321) (1,403) (939) (2,342)
Share of profits in joint ventures and associates, net of interest and taxation   22(b)   55   7   62   94   24   118
Group operating (loss)/profit 21(b) 639   (2,797)   (2,158) 1,033   (731)   302
Financing costs (163) (163) (168) (168)
Investment income 28     28 28     28
Net finance cost       (135)     (135)   (140)     (140)
(Loss)/profit before taxation 504 (2,797) (2,293) 893 (731) 162
Taxation on (loss)/profit       (94)   832   738   (293)   262   (31)
(Loss)/profit for the period       410   (1,965)   (1,555)   600   (469)   131
Attributable to:                            
Owners of the parent 403 (1,948) (1,545) 600 (469) 131
Non-controlling interests       7   (17)   (10)      
Earnings per ordinary share               Pence           Pence
Basic 23     (30.9)       2.5
Diluted   23       (30.9)       2.5

20. Group Cash Flow Statement for the six months ended 31 December (unaudited)

         

Six months ended 31 December

  2014
£m
  2013
£m
Group operating (loss)/profit including share of results of joint ventures and associates   (2,158)   302
Less share of profit of joint ventures and associates, net of interest and taxation   (62)   (118)
Group operating (loss)/profit before share of results of joint ventures and associates (2,220) 184
Add back/(deduct):
Depreciation, amortisation, write-down and impairments 2,665 1,640
(Profit)/loss on disposals (176) 9
(Decrease)/increase in provisions (14) 189
Defined benefit pension service cost and contributions (86) (84)
Employee share scheme costs 13 20
Unrealised losses/(gains) arising from re-measurement of energy contracts   1,049   (279)
Operating cash flows before movements in working capital 1,231 1,679
Increase in inventories (55) (71)
Increase in trade and other receivables (i) (1,335) (420)
Increase in trade and other payables (i)   679   924
Operating cash flows before payments relating to taxes, interest and exceptional charges 520 2,112
Taxes paid (294) (491)
Payments relating to exceptional charges   (63)   (92)
Net cash flow from operating activities   163   1,529
Purchase of businesses (18) (1,113)
Sale of businesses 225 135
Purchase of property, plant and equipment and intangible assets (715) (826)
Sale of property, plant and equipment and intangible assets 8 11
Investments in joint ventures and associates (16) (17)
Dividends received from joint ventures and associates 95 90
Repayments of loans to, and disposal of investments in, joint ventures and associates 96
Interest received 22 18
Sale/(purchase) of securities   7   (2)
Net cash flow from investing activities   (296)   (1,704)
Issue and surrender of ordinary share capital for share awards, net of payments for own shares 5 11
Purchase of treasury shares under share repurchase programme (215) (299)
Investment by non-controlling interests 119
Distribution to non-controlling interests (18) (8)
Financing interest paid (201) (132)
Repayment of borrowings (491) (348)
Cash received from borrowings, net of linked deposit 984 1,137
Equity dividends paid   (259)   (255)
Net cash flow from financing activities   (76)   106
Net decrease in cash and cash equivalents (209) (69)
Cash and cash equivalents at beginning of period 815 800
Effect of foreign exchange rate changes   15   (12)
Cash and cash equivalents at 31 December   621   719
Included in the following line of the Group Balance Sheet:
Cash and cash equivalents   621   719

(i) Includes net outflow of £513 million of cash collateral in 2014 (2013: net inflow of £84 million).

21. Segmental analysis for the six months ended 31 December (unaudited)

(a) Revenue

                         
      2014       2013
Six months ended 31 December  

Gross
segment
revenue
£m

 

Less inter-
segment
revenue
£m

 

Group
revenue
£m

 

Gross
segment
revenue
£m

 

Less inter-
segment
revenue
£m

 

Group
revenue
£m

International Downstream                    
Residential energy supply 3,777 (3) 3,774 4,001 4,001
Residential services 854 (82) 772 850 (81) 769
Business energy supply and services 1,408   (9)   1,399 1,463   (36)   1,427
British Gas 6,039 (94) 5,945 6,314 (117) 6,197
                   
Residential energy supply 1,172 1,172 1,209 1,209
Business energy supply 3,930 3,930 2,629 (33) 2,596
Residential and business services 267     267 296     296
Direct Energy 5,369 5,369 4,134 (33) 4,101
 
Bord Gáis Energy 391 391
 
International Upstream                    
Gas 1,521 (143) 1,378 2,148 (44) 2,104
Power 686   (161)   525 720   (251)   469
Centrica Energy 2,207 (304) 1,903 2,868 (295) 2,573
 
Centrica Storage   79   (27)   52   81   (32)   49
    14,085   (425)   13,660   13,397   (477)   12,920

(b) Operating profit before and after tax

           
 

 

Adjusted operating profit (i)

 

Adjusted operating profit after taxation (ii)

Six months ended 31 December                 2014
£m
  2013
£m
  2014
£m
  2013
£m
International Downstream                        
Residential energy supply 174 215 137 150
Residential services 141 183 111 138
Business energy supply and services 53 63 44 53
British Gas 368 461 292 341
       
Residential energy supply 42 64 32 49
Business energy supply 53 24 31 20
Residential and business services 14 23 10 17
Direct Energy 109 111 73 86
 
Bord Gáis Energy 7 3
 
International Upstream        
Gas (iii) 141 472 67 143
Power (iii) (iv) 70 52 116 43
Centrica Energy 211 524 183 186
 
Centrica Storage                 19   16   14   12
    714   1,112   565   625
Share of joint ventures’/associates’ interest and taxation (37) (64)
Depreciation of fair value uplifts to property, plant and equipment – Venture (iii) (14) (21)
Depreciation of fair value uplifts to property, plant and equipment
(net of taxation) – associates – Nuclear (iii)
  (24)   6
639 1,033
Exceptional items (note 22) (1,816) (1,064)
Certain re-measurements included within gross profit (note 22) (988) 309
Certain re-measurements of associates’ energy contracts (net of taxation) (note 22)   7   24
Operating (loss)/profit after exceptional items
and certain re-measurements
  (2,158)   302
                 
            2014
£m
  2013
£m
Adjusted operating profit after taxation (ii)           565   625
Depreciation of fair value uplifts to property, plant and equipment (net of taxation) (iv) (29) (3)
Impact of changes to UK corporation tax rates (v) (2) 64
Corporate and other taxation, and interest (net of taxation) (vi)           (124)   (86)
Business performance profit for the period           410   600
Exceptional items and certain re-measurements (net of taxation) (note 22)           (1,965)   (469)
Statutory (loss)/profit for the period           (1,555)   131
(i) 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.
(ii) 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.
(iii) 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.
(iv) Power adjusted operating profit after taxation includes a one-off deferred tax benefit of £44 million (2013: nil) following a legal entity reorganisation.
(v) In 2014 there is no impact relating to equity accounted interests (2013: £29 million credit).
(vi) Includes joint ventures’/associates’ interest, net of associated taxation.

22. Exceptional items and certain re-measurements for the six months ended 31 December (unaudited)

(a) Exceptional items

         
Six months ended 31 December   2014
£m
  2013
£m
Provision for onerous power procurement contract     (125)
Exceptional items included within gross profit     (125)
Impairment of Centrica Energy exploration and production assets (note 6)   (1,189)   (699)
Impairment of UK power generation assets (note 6) (535)
Impairment on Nuclear investment (note 6) (214)
Impairment of UK gas storage assets and associated provision for onerous capacity contracts (240)
Gain on disposal of Ontario home service business (note 15(c))   122  
    (1,816)   (939)
Exceptional items included within Group operating profit (1,816) (1,064)
Taxation on exceptional items   515   397
Total exceptional items after taxation   (1,301)   (667)

(b) Certain re-measurements

         
Six months ended 31 December   2014
£m
  2013
£m
Certain re-measurements recognised in relation to energy contracts:    
Net gains arising on delivery of contracts 14 26
Net (losses)/gains arising on market price movements and new contracts   (1,002)   283
Net re-measurements included within gross profit (988) 309
Net gains arising on re-measurement of associates’ energy contracts (net of taxation)   7   24
Net re-measurements included within Group operating profit   (981)   333
Taxation on certain re-measurements   317   (135)
Net re-measurements after taxation   (664)   198

23. Earnings per ordinary share for the six months ended 31 December (unaudited)

                 
    2014     2013
Six months ended 31 December   £m   Pence per
ordinary
share
  £m   Pence per
ordinary
share
(Loss)/earnings – basic (1,545) (30.9) 131 2.5
Net exceptional items after taxation (note 22 (i)) 1,284 25.7 667 12.9
Certain re-measurement gains after taxation (note 22) 664 13.3 (198) (3.8)
Depreciation of fair value uplifts to property, plant and equipment from
Strategic Investments, after taxation
  29   0.6   3   0.1
Earnings – adjusted basic   432   8.7   603   11.7
                 
(Loss)/earnings – diluted (ii)   (1,545)   (30.9)   131   2.5
                 
Earnings – adjusted diluted   432   8.6   603   11.6
(i) Net exceptional items after taxation of £1,301 million are reduced by £17 million for the purpose of calculating adjusted basic and adjusted diluted EPS. The adjustment reflects the share of net exceptional items attributable to non-controlling interests.
(ii) The dilutive impact of share based payment schemes is included in the calculation of diluted EPS, unless it has the effect of increasing the profit or decreasing the loss attributable to each share. Therefore, these shares are excluded from the calculation of basic diluted EPS in 2014.

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, Canada 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 Canada are Panther, Wildcat Hills, Alderson, Stolberg, Hanlan and Ferrier. 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)   Europe   Canada   Trinidad
and Tobago (iv)
  Centrica Energy   Centrica Storage   Total
1 January 2014   2,011   1,130   128   3,269   182   3,451
Revisions of previous estimates (i) (161) (63) (224) (224)
(Disposals)/purchases of reserves in place (ii) (9) (152) (161) (161)
Extensions, discoveries and other additions (iii) 13 85 98 98
Production (v)   (223)   (91)   (19)   (333)     (333)
31 December 2014   1,631   909   109   2,649   182   2,831
                         
Estimated net 2P reserves of liquids (million barrels)   Europe   Canada   Trinidad
and Tobago (v)
  Centrica Energy   Centrica Storage   Total
1 January 2014   145   22     167     167
Revisions of previous estimates (1) (1) (1)
(Disposals)/purchases of reserves in place (4) (4) (8) (8)
Extensions, discoveries and other additions (iii) 2 2 2
Production (v)   (15)   (2)     (17)     (17)
31 December 2014   126   17     143     143
                         
Estimated net 2P reserves (million barrels of oil equivalent)   Europe   Canada   Trinidad
and Tobago (iv)
  Centrica Energy   Centrica Storage   Total
31 December 2014 (vi)   398   169   18   585   30   615
(i) Revision of previous estimates including those associated with Seven Seas, Ensign, Olympus, Grove and York.
(ii) Reflects our share of the acquisition of producing natural gas assets in the Foothills region of Alberta, Canada and the disposals of Greater Kittiwake area and Amethyst/Ravenspurn. Also includes the transfer of our wholly owned interests to the CQ Energy Canada Partnership, in which the Group has a 60% interest which results in a 40% decrease in the reported reserves associated with these interests.
(iii) Recognition of reserves including the Statfjord fields and a number of additional planned wells in Canada within Centrica Energy.
(iv) The Trinidad and Tobago reserves are subject to a production sharing contract and accordingly have been stated on an entitlement basis (including tax barrels).
(v) Represents total sales volumes of gas and oil produced from the Group’s reserves.
(vi) Includes the total of estimated gas and liquid reserves at 31 December 2014 in million barrels of oil equivalent.

Liquids reserves include oil, condensate and natural gas liquids.

OFGEM CONSOLIDATED SEGMENTAL STATEMENT

The Ofgem Consolidated Segmental Statements (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/prelims2014.

Ofgem consolidated segmental statement

 
Year ended 31 December 2014
    Electricity Generation     Electricity Supply   Gas Supply    
    Unit   Nuclear (i)   Thermal (i)   Renewables  

Aggregate
Generation
Business

  Domestic   Non-
Domestic
  Domestic   Non-
Domestic
 

Aggregate
Supply
Business

Midstream
Power (ii)

Total revenue £m 575.1   599.2   144.9 1,319.2 3,296.3   1,963.6 5,031.2   765.9 11,057.0 105.6
Sales of electricity & gas £m 570.4 587.7 53.0 1,211.1 3,260.7 1,955.3 4,986.1 765.9 10,968.0 59.9
Other revenue   £m   4.7   11.5   91.9   108.1   35.6   8.3   45.1     89.0 45.7
Total operating costs   £m   (306.4)   (663.9)   (96.7)   (1,067.0)   (3,219.0)   (1,902.6)   (4,596.0)   (694.0)   (10,411.6) (73.8)
Direct fuel costs £m (76.1) (456.6) (532.7) (1,390.5) (954.6) (2,443.8) (441.4) (5,230.3)
Direct costs   £m   (212.1)   (150.3)   (31.7)   (394.1)   (1,371.5)   (747.4)   (1,452.6)   (152.5)   (3,724.0) (58.1)
Network costs £m (34.7) (39.3) (4.9) (78.9) (870.7) (471.7) (1,147.5) (136.5) (2,626.4)
Environmental and social obligation costs £m (52.6) (52.6) (484.6) (248.3) (290.9) (1,023.8)
Other direct costs   £m   (177.4)   (58.4)   (26.8)   (262.6)   (16.2)   (27.4)   (14.2)   (16.0)   (73.8) (58.1)
Indirect costs   £m   (18.2)   (57.0)   (65.0)   (140.2)   (457.0)   (200.6)   (699.6)   (100.1)   (1,457.3) (15.7)
WACOF/E/G  

£/MWh,
P/th

  (6.7)   (50.9)   N/A   N/A   (61.0)   (58.6)   (71.1)   (68.3)   N/A N/A
EBITDA   £m   268.7   (64.7)   48.2   252.2   77.3   61.0   435.2   71.9   645.4 31.8
DA   £m   (59.0)   (55.1)   (38.3)   (152.4)   (32.1)   (6.4)   (41.5)   (3.3)   (83.3) (1.0)
EBIT   £m   209.7   (119.8)   9.9   99.8   45.2   54.6   393.7   68.6   562.1 30.8
Volume  

TWh,
MThms

  11.2   10.0   0.9   22.1   22.8   16.3