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- Absolute emissions
The total of our scope 1 and scope 2 emissions, as defined under the Greenhouse Gas Protocol
- ACS - Nationally Accredited Certification Scheme
Nationally Accredited Certification Scheme for Gas Businesses and Individual Gas Fitting Operatives. Any person or business wishing to do gas work has to prove their competence, after which they have also to register with the Gas Safe RegisterTM which from 1 April 2009, has replaced the CORGI gas registration scheme in Great Britain.
If an action leads to a genuine reduction in emissions, over and above business as usual, the benefit to the environment will be 'additional'. However, if an emissions reduction project would have happened anyway then no real difference to emissions would be made as a result and it couldn't be considered 'additional'. For example, if a consumer buys renewable energy which was going to be produced anyway, or invests in a carbon-offset project which was already going to happen, then the consumer is not helping to reduce emissions.
Debates over the additionality of projects are important to ensure that environmental claims make a genuine difference to emissions. Without this concept people might believe that they are benefiting the environment through their actions when actually they have no impact.
We offer a green tariff, Sustainable Energy, which is certified as creating an additional benefit to the environment by the Green Energy Supply Certification Scheme.
Everything a firm owns.
An independent firm or person who checks the accounts against agreed standards.
- Bad debts
Amount owed to a firm by a customer that won't be recovered.
Baseload power is the minimum amount of power required to meet the demands based on reasonable expectations of customer requirements.
bcf stands for billions of cubic feet of gas. The UK consumes over 3000bcf every year in homes, businesses and power stations.
Bank overdrafts, loans and bonds issued in sterling and other major currencies with maturity dates between 2012 and 2033.
Biomass is one of the oldest sources of renewable energy; it is biological material that is derived from living or recently living organisms. For power generation, this is generally plant-based material such as timber based products in various forms or fast growing energy crops (e.g. willow, poplar and Miscanthus).
Biomethane is a mixture of gases (predominantly methane) that are sourced from organic material, such as cattle slurry, food and household waste. Also known as biogas, it is produced by a process called anaerobic digestion, where bacteria breaks down the organic material. Biomethane from all sources will make a contribution to decarbonising the gas grid by delivering renewable heat to households through the existing gas network and central heating boilers. According to a study by National Grid, it could account for at least 15% of the domestic gas market by 2020.
- Bought ledger
Contains records about purchases.
- British Gas Energy Trust
The British Gas Energy Trust, which incorporates the Scottish Gas Energy Trust, is an independent Charitable Trust established by British Gas in 2004. The Trust receives funding solely from British Gas but operates independently, providing British Gas customers as well as the wider public with help in paying energy and other household bills as well as assistance in applying for grants. The Trust also funds voluntary sector organisations to provide money and fuel debt services.
Further details can be found at: www.britishgasenergytrust.org.uk
The money invested into a firm by shareholders.
- Carbon capture and storage (CCS)
This is the removal of CO2 from fossil fuels either before or after combustion.
Sometimes called carbon sequestration, this is the long-term storage of carbon or CO2. In nature, large forests and oceans act as carbon 'sinks' and help to remove carbon dioxide from the atmosphere. Artificial sequestration, such as injecting CO2 into geological formations (often under the seabed), requires technology such as carbon capture and storage.
Estimates suggest that carbon capture and storage could reduce carbon emissions by 80-90% from a power station. Carbon capture and storage can be referred to as CCS.
- Carbon credit
A credit or permit from a greenhouse gas emissions reduction scheme, such as emissions trading, Joint Implementation (JI) or Clean Development Mechanism (CDM). See carbon trading.
- Carbon Emissions Reduction Target (CERT)
The CERT scheme ended in December 2012 and was an obligation on the major energy suppliers to improve domestic energy efficiency, which replaced the Energy Efficiency Commitment (EEC). Suppliers were required to deliver twice the energy savings under CERT as they did under EEC. The main objective of CERT was to achieve carbon reductions in order to tackle climate change but there was also a focus on delivering energy efficiency measures to low-income customers and to encourage behavioural change. The scheme originally ran from 2008-2011, but was extended until December 2012. This extension increased the carbon targets by a further 20%, and put in place minimum sub targets for installing insulation, and to target measures to the most vulnerable households. At the end of the scheme in 2012, British Gas narrowly missed the target by a shortfall of 1% which was subsequently delivered in early January. In January 2013, CERT was replaced by the UK Government's Energy Company Obligation (ECO) and the Green Deal, which focus on vulnerable customers.
- Carbon footprint
A carbon footprint is a measure of greenhouse gas emissions, usually expressed in carbon dioxide units. You can calculate the carbon footprint of a product, an individual or an organisation, for a single activity or over a period of time.
- Carbon intensity
Carbon intensity measures the volume of carbon dioxide emitted per unit of electricity generated. This allows you to compare the efficiency of two differently sized companies doing similar things, which a carbon footprint comparison would not.
We calculate our carbon intensity based on the average annual emissions from all wholly owned power generation assets and all other power generation assets from which Centrica is entitled to output under site-specific contracts.
- Carbon offsetting
Carbon offsetting involves calculating a carbon footprint and then investing in a project that reduces greenhouse gases emissions into the atmosphere by an equivalent amount. To be effective, an offset must be additional (See Additionality).
- Carbon Reduction Commitment (CRC)
The CRC Energy Efficiency Scheme is a mandatory scheme to improve energy efficiency and therefore cut CO2 emissions in large public and private sector organisations. These organisations are responsible for around 10% of the UK's CO2 emissions. The scheme features a range of reputational, behavioural and financial drivers which aim to encourage organisations to develop energy management strategies that promote a better understanding of energy usage.
- Carbon trading
Carbon trading controls carbon emissions by putting a limit on total emissions from certain activities or sectors. This puts a price on carbon and creates a market whereby participants can trade their carbon allowances. Allowances are initially allocated, perhaps through a free distribution or through an auction. The carbon price provides an economic incentive to reduce emissions and allows for any reductions to take place at the lowest cost across the scheme. The limit on total emissions is adjusted periodically, see Carbon credit.
- Cash book
A record of a firm's cash and bank accounts.
- Clean coal technologies (CCTs)
CCTs make using coal as a power source more environmentally satisfactory. There are significantly higher greenhouse gas emissions for each unit of electricity produced by coal-fired generation than there are for alternative methods of generation. CCTs involve reducing the carbon emissions per unit of energy generated from coal.
- Clean Development Mechanism (CDM)
CDM is defined within the Kyoto Protocol. The CDM rewards with Certified Emission Reductions (CER) investments in projects that reduce emissions in developing countries; each CER is each equivalent to one tonne of CO2. These CERs can then be used by industrialised nations to meet their emissions targets as part of the Kyoto Protocol. The CDM is governed by the UN's CDM Executive Board (CDM EB), which makes sure that accredited projects deliver real and enduring emissions reductions. Operators covered by the European Union Emissions Trading Scheme (EU ETS) can use a limited number of CERs for their annual compliance with the Scheme.
- Climate Change Agreement
This is an agreement between the Government and a business user in an energy-intensive industry, where the user commits to reducing energy usage or carbon emissions in return for paying a lower Climate Change Levy.
- Climate Change Levy (CCL)
CCL was introduced by the Government in 2001 following the Kyoto Protocol, as part of its commitment to tax non-domestic energy use. The CCL aims to promote energy efficiency and reduce greenhouse gas emissions. From April 2013, businesses that have Climate Change Agreements with the Government can start claiming CCL discount at the revised rate of 90% for electricity and 65% for other fuels. Other exemptions from the CCL include renewable electricity sold under a renewable source contract and energy sold to charities for certain activities. Gas and electricity suppliers are responsible for charging CCL to their business customers and then paying the Government.
- Combined cycle gas turbine (CCGT)
A combined cycle gas turbine uses a gas turbine generator to generate electricity and waste heat in the exhaust is recovered and is used to make steam to generate additional electricity via a steam turbine; this last step enhances the efficiency of electricity generation. All our gas-fired power stations are CCGT plants.
- Combined heat and power (CHP)
Combined heat and power (CHP) is a technology that generates electricity and heat at the same time. This is different to conventional power stations, where the heat produced is wasted.
- Commodity prices
The prices of raw materials and primary products for example wholesale gas.
- Community Energy Saving Programme (CESP)
The CESP obligation ran from 1 October 2009 and concluded in December 2012. The scheme was a joint funded initiative between Government, energy suppliers and power generators that targeted households in areas of social deprivation to improve energy efficiency and reduce fuel bills. The programme was delivered through community-based partnerships between Local Authorities, community groups, and energy companies in a house-by-house approach to ensure energy-efficiency measures are best suited to an individual property or area. At the end of 2012, British Gas had delivered 3.5 million tonnes of lifetime carbon savings under CESP but due to bad weather, missed the CESP target and will complete the shortfall in 2013. In January 2013, CESP was replaced by the UK Government's Energy Company Obligation (ECO) and Green Deal (see Energy company obligation and Green Deal).
- Cost of sales
Total cost of buying goods for resale.
One of the opposing parties involved in a transaction.
- Credit rating
A rating from an independent institution that assess creditworthiness or the credit risk, and provides credit ratings that are publicly available and used by investors as well as analysts as a guide for investment decisions in regard to relative credit standing or strength. (examples of credit rating agencies, Standard & Poor's and Moody's Investor Service).
- Currency fluctuations
The ongoing changes between the relative value of the currency issued by one country when compared to a different currency. Currency fluctuations may appear as both upward and downward movements. Our profitability could be adversely affected because of currency fluctuations against pounds sterling, which is the reporting currency of the Group. Our main exposure is in US and Canadian dollars and euros.
- Current ratio
It is the ratio of a company's current assets to current liabilities. It is a general indication of the solvency of a company, the adequacy of its working capital, and its ability to meet day-to-day calls upon it.
- Customer-Led Network Revolution (CLNR)
Established in 2011, the CLNR is the UK's largest smart grid project of which British Gas is one of four lead partners. The £54m project established by the UK energy regulator Ofgem, will help electricity customers across the country to reduce their carbon emissions over a three year period and will assess the affect of low carbon and microgeneration technologies on the electricity grid in order to ascertain how key challenges can be overcome to support the development of smart grid technology and assist in creating a low economy.
Loss of value of assets through wear and tear.
- Derivative financial instruments
A mechanism, such as an option, futures contract, or swap, of which the criteria and value are determined by those of an underlying asset such as a stock, currency, or commodity. Derivatives are used extensively in the hedging of financial and treasury risks.
- Distributed generation
This refers to electricity generation, usually on a relatively small scale, that is connected to the distribution networks rather than directly to the national transmission systems. At a community level this could include combined heat and power (CHP generation). At a domestic level, this could include solar panels.
Moving into another area of business.
- Dividend cover
Dividend cover takes into account all aspects of trading, tax and finance, from the ordinary shareholders' point of view. Dividend cover can also be calculated using cash flow in place of profit.
dividend cover =
Profit attributable to shareholders
divided by: Dividends
- Dividend yield
This measure shows shareholders how much income they receive in relation to the current share price. Analysts will sometimes predict dividend growth and calculate a prospective dividend yield.
dividend yield =
Gross dividend per share
divided by: Share price
Share of profits paid to shareholders twice yearly as an interim dividend and a final dividend.
- Earnings per share (EPS)
This is an important ratio, signalling the growth in earnings attributable to the ordinary shareholders for each share they hold. It must be disclosed at the bottom of the profit and loss account for listed companies such as Centrica.
Profit after tax
divided by: Weighted average ordinary shares in issue
- Economies of scale
These result in the company benefiting from a reduction in the average cost per unit.
- Emissions reduction units (ERUs)
ERUs are tradable credits awarded to emission reducing projects that take place under the Joint Implementation (JI) project. JI projects operate in a similar manner to those under the Clean Development Mechanism but take place in developed countries. One Emission Reduction Unit (ERU) equates to an emission reduction of one tonne of CO2 equivalent.
- Emissions trading (EU ETS)
The EU Emissions Trading Scheme (ETS) began in January 2005 and is a form of carbon trading using carbon allowances. The scheme covers around 45% of all EU emissions and includes power generation and industrial manufacturing plants across the EU, limiting the total amount of carbon dioxide emissions allowed. Each site must submit an allowance for every tonne of carbon dioxide emitted. We are a major trader in the scheme and a strong supporter of the ETS as we believe it remains the cornerstone mechanism for reducing emissions across the EU. Phase III of the EU ETS began in 2013 and will run until 2020. During this period, a centralised EU-wide cap on emissions will be set and the 'cap' will decline by at least 1.74% a year, so that emissions in 2020 will be at least 21% below their 2005 level.
- Energy Company Obligation (ECO)
In January 2013, ECO took over from the existing obligations made through the Carbon Emissions Reduction Target (CERT) and the Community Energy Saving Programme (CESP), which expired in 2012. The ECO requires energy suppliers to improve the insulation of harder to treat properties in the domestic sector and to invest resources in reducing heating costs for vulnerable households. It will therefore continue to support the reduction of energy bills for fuel poor households which will play an important part in the UK meeting its carbon emissions and fuel poverty targets.
- Energy mix
The Energy mix refers to a composition of energy sources. If for example, an energy company had renewable, coal, gas and oil assets, these sources of energy would form their overall energy mix.
- Energy Performance Certificate (EPCs)
EPCs give information on how to make your home more energy efficient and reduce carbon dioxide emissions. The certificate provides an energy efficiency rating for the property on a scale of A to G, with A being the most efficient with lower running costs and G being the least efficient with higher running costs. EPCs also contain a recommendation report with suggestions to reduce energy use and carbon dioxide emissions. Since 4 January 2009 all homes in the UK that are built, sold or rented require an EPC.
- Energy Ombudsman
The energy Ombudsman is an independent organisation set up to resolve disputes and disagreements between energy companies and their domestic and small business customers. The Ombudsman becomes involved in complaints in the following situations: 1) 8 weeks have passed after a complaint to an energy company has been made and it has not been sufficiently addressed; 2) the company has issued a final letter to say it will no longer be handling the complaint; 3) there have been difficulties in contacting the energy company and registering a complaint. For more information, see the energy Ombudsman website.
- Energy Services Directive (ESD)
The ESD aims to promote energy efficiency in the UK by developing a market for energy services and delivering energy efficiency programmes and measures to energy end users. The Directive's full name is the EC Directive on Energy End Use Efficiency and Energy Services. The ESD focuses on market actors and institutions rather than specific technologies or measures. It applies to providers of energy efficiency measures, energy distributors, distribution system operators and retail energy sales companies; and all energy users except those involved with the EU carbon emissions trading scheme.
The main requirements of the Directive are:
- national indicative energy savings target of 9% by 2017
- public sector to fulfil an exemplary role in meeting the target
- to place obligations on energy suppliers and distributors to promote energy efficiency
- requirements on metering and billing to allow consumers to make better informed decisions about their energy use
- Energy Retailers Association (ERA)
The ERA was formed in 2003 and represents the major electricity and gas suppliers in the domestic market in Great Britain. All the main energy suppliers, operating in the residential market, in Great Britain are members of the association.
The ERA works closely with government, NGOs, charities and other organisations in England, Scotland and Wales to ensure a coordinated approach to dealing with the key issues affecting our industry and the British consumer.
For further details - www.energy-uk.org.uk
- Equity assets
Shareholdings held in stock market listed companies.
- Equity share
Equity share refers to the proportion which Centrica owns. For example, we may take 100% of power from a facility but only own 50% it. That would make our equity share 50% and our offtake 100%.
Essentials is the name we give to the package of support measures available to our vulnerable customers. Following the launch of the government's Warm Home Discount Scheme (WHD) in 2011, this programme is now closed to new applicants and existing essentials customers transferred onto the mandatory WHD scheme, subject to eligibility. The programme included a discounted tariff and offers benefits assessments and access to free impartial debt advice, energy efficiency products and a range of extra help from our charity partners. Customers can also access free insulation. Further details are available on the British Gas website.
Costs flowing out of the firm.
A method of financing in the recovery of debts.
- Fair Billing Charter
Launched in 2011, the Fair Billing Charter is designed to support UK small businesses by making improvements in accurate billing a priority. The Charter details the rights and responsibilities of both the customer and British Gas and advises business customers on how to be more 'energy conscious' in their fuel consumption and whether they are being billed correctly.
Further details can be found at: http://www.britishgas.co.uk/blog/articles/british-gas-launches-fair-billing-commitment-for-businesses-2
- Feed-in Tariff (FIT)
A FIT is a payment via energy suppliers to people who generate their own electricity through microgeneration technologies such as solar panels and wind turbines. It is intended to help finance the cost of small-scale, locally-generated power. See Ofgem's website for more information and latest rates: http://www.ofgem.gov.uk/Sustainability/Environment/fits/tariff-tables/Pages/index.aspx
- Fixed rates
Interest rates on loans fixed for the period of the loan.
- Fuel cells
Fuel cells produce heat and electricity from hydrogen and air. Since the fuel cell relies on chemistry and not combustion, emissions from this type of a system are much smaller than emissions from the cleanest fuel combustion processes. These can be used for stationary power generation (microCHP), transport (replacing the internal combustion engine) and portable power (replacing batteries in mobile phones).
- Fuel Mix Disclosure (FMD)
FMD regulations oblige all UK suppliers to calculate and publish the fuel source (eg coal, gas, nuclear, wind) and indicative CO2 emissions of all the electricity they supply between 1 April and 31 March. This includes electricity generated by the supplier and electricity bought from other generators, either through contracts or in the marketplace. It is different to the proportion (mix) of energy sources that we use to generate electricity ourselves.
- Fuel poverty
The common definition of a fuel poor household is one which has to spend more than 10% of household income to achieve adequate heating (21 degrees Celsius in the living room and 18 degrees Celsius in other occupied rooms).
- Fuel Poverty Advisory Group (FPAG)
FPAG is comprised of senior representatives from organisations such as the energy industry, charities and consumer bodies. The core role of FPAG is to examine, monitor and report the effectiveness of current policies in reducing fuel poverty and to encourage the need for greater co-ordination and partnerships to tackle fuel poverty.
Further details can be found at: http://www.decc.gov.uk/en/content/cms/about/partners/public_bodies/fpag/fpag.aspx
- Gas Safe RegisterTM
Gas Safe RegisterTM has replaced CORGI in Great Britain and the Isle of Man. See also ACS
By law, anyone carrying out work on gas installations and appliances must be on the Gas Safe RegisterTM. All British Gas engineers are on the Gas Safe RegisterTM and all registered engineers carry an ID card.
The ratio of a company's share capital to its debt.
- Green Deal
Introduced in January 2013, the Green Deal together with the Energy Company Obligation will replace the Carbon Emissions Reduction Target (CERT) and the Community Energy Saving Programme (CESP), which ended in December 2012. The Green Deal will enable domestic and commercial customers to invest in energy efficiency improvements, which qualify under the initiative, for no upfront outlay by spreading the cost through instalments on their energy bills. British Gas has been an early supporter of the Green Deal and took place in a trial of the Green Deal programme in July 2011, with the launch of the Home Energy Plan. This enabled British Gas customers who paid by direct debit to take out low cost loans to invest in energy saving measures. From the pilot, British Gas gained valuable insights about how the Green Deal might operate, including the types of energy efficiency measures that customers prefer and how to simplify the scheme to encourage participation.
- Green Tariff
We have signed upto Ofgem's Green Energy Supply Guidelines which define a Green Tariff as one that delivers an minimum additional environmental benefit as well matching a customers' usage with electricity from renewable sources. This raises the standard of industry products, ensures genuine benefits for the environment and provides transparent and consistent information to reduce consumer confusion around tariff labelling.
Our Sustainable Energy tariff is certified as creating an additional benefit to the environment by the Green Energy Supply Certification Scheme, and matches each unit of electricity you buy with a unit of 100% British renewable energy.
The 'grid' refers to the electric grid, which is a network of transmission lines, transformers and more that delivers electricity from power plants to homes and businesses.
- Gross profit margin
Total profit made in a year as a percentage of sales. This ratio is deemed to be an important indicator of profitability, and comparisons can be made against companies selling similar items.
Since gross profit is defined as 'turnover minus cost of sales' this ratio will move if the relationship between these two variables changes. This could be due to changes in selling price, unit costs or product mix (where gross margins vary between different markets). The published information can only provide a superficial guide. Analysts will seek to further analyse this ratio into appropriate market segments.
Gross margin =
divided by: Turnover
Hedging occurs when a significant proportion of gas supply is bought in advance of consumption in order to guarantee future supplies of energy and to help manage price volatility.
Any technique designed to reduce or eliminate financial risk, (the effect of fluctuations in the price of credit, foreign exchange or commodities on an organisation's profits, corporate value, investments, or liabilities). For example, taking two positions that will offset each other if prices change, using Hedging instruments such as forward contracts, forward rate agreement (FRA), swaps, futures, and options.
- Higher heating value (HHV)
The HHV (also known as the gross calorific value or gross energy) of a fuel is defined as the amount of heat released by a specified quantity (initially at 25 oC) once it is combusted and the products have returned to a temperature of 25 oC.
The higher heating value takes into account the latent heat of vaporisation of water in the combustion products, and is useful in calculating heating values for fuels where condensation of the reaction products is practical (eg, in a gas-fired boiler used for space heat). In other words, HHV assumes all the water component is in liquid state at the end of combustion (in product of combustion).
Buying equipment through financing.
- Home Energy Plan
For further information on the Home Energy Plan, please refer back to the Green Deal definition.
Money from sales, or revenue flowing into the firm.
A firm with a separate legal existence.
- Integrated Gasification Combined Cycle (IGCC)
IGCC plants initially turn the feedstock into gas, which is then passed through a conventional combined cycle set up. IGCCs can be designed to use a range of raw fuel inputs, including coal, oil products and wastes.
- Interest cover
The ratio below is used to demonstrate how easily the company can service any debt it may have by showing how many times its profit exceeds the interest charge. In particular, when used along-side a review of how much the company has borrowed from banks, this ratio can highlight the company's exposure to fluctuations in interest rates. It is also possible that an 'interest cover' ratio may be calculated for cash flow, to see whether a company is generating enough cash to pay its interest costs.
Interest cover =
Profit before interest for period
divided by: Interest charge for the period
- Interest rates
The percentage charged by a bank or other financial organisation for borrowing money or earned by placing money on deposit.
- Intergovernmental Panel on Climate Change (IPCC)
Founded in 1988, the IPCC is a scientific intergovernmental body founded by the World Meteorological Organisation (WMO) and the United Nations Environment Programme (UNEP). It aims to provide an objective source of information about climate change to policy-makers by assessing the latest scientific, technical and socio-economic literature worldwide on the human causes of climate change. It is open to all member countries of WMO and UNEP and scientists from around the globe contribute to its work as authors, contributors and reviewers.
- Internal carbon footprint
We use the term 'internal carbon footprint' to describe the carbon emissions from our property energy use, company vehicles and business travel. The target does not cover emissions from power generation or oil and gas production, the reporting and management of which we treat separately. Our internal targets concentrate instead on those areas where the majority of our employees have the ability to influence results. This is important for engagement purposes and enables us to benchmark our operational performance against the majority of other businesses. The internal carbon footprint includes all in-scope assets and activities associated with the businesses within Centrica as at 31 December 2007, together with organic growth.
- ISO 14001
ISO 14001 is an internationally accepted standard for establishing an effective Environmental Management System (EMS). It aims to balance the need for profitability with best practice in terms of protecting the environment.
- Joint implementation (JI)
Joint Implementation is a Kyoto Protocol mechanism under which industrialised countries can invest in projects to cut emissions in other industrialised countries. This could include, for example, replacing an old coal-fired power plant with a cleaner gas-fired one. Reductions achieved under JI projects are awarded emissions reduction units (ERUs), which can be traded in the European Emissions Trading Scheme.
- Kyoto Protocol
The Kyoto Protocol adopted on 11 December 1997, is an international agreement where participating nations have agreed to reduce their greenhouse gas (GHG) emissions from 1990 levels. The first commitment period spanned five-years between 2008-2012 from 1990 levels. All industrialised nations signed the Protocol but Australia only did so with a change of government in 2007, while the United States did not ratify it. Under the Kyoto Protocol, the European Union achieved the collective 5% reduction target, with the UK exceeding this by securing a 6% reduction in GHG. In addition to making absolute domestic carbon cuts, the Kyoto Protocol allows the use of flexible mechanisms to meet targets. These include Emissions Trading (ET), Clean Development Mechanism (CDM) and Joint Implementation (JI). During the second commitment period which will run between 2013-2020, nations will aim to reduce GHG emissions by at least 18% below 1990 levels; however, the composition of Parties in the second commitment period is different from the first. A revised list of GHG will also be reported during this period.
- Leading and lagging indicators
Leading indicators measure activities, while lagging indicators measure outcomes. For example, the number of training workshops held would be a leading indicator and the number of incidents recorded would be a lagging indicator.
Renting equipment through financing.
- Levy Exemption Certificate (LEC)
A LEC is issued by Ofgem to accredited power stations for each megawatt hour of renewable source electricity that they generate. All business customers need to pay a climate change levy for electricity they use. However, they can get an exemption if the electricity comes from a renewable source. Business customers who wish to purchase electricity generated from renewable sources can enter into a renewable source contract with their electricity supplier. LECs act as proof that an equivalent amount of electricity has been generated according to the terms of the contract. That's why electricity sold with LECs comes at a premium.
If an electricity supplier cannot generate enough renewable source electricity, it can purchase LECs from other suppliers to meet its obligations. Suppliers must periodically notify Ofgem of the LECs they have allocated to the renewable source electricity supplied to business customers. LECs are used to show exemption from the Climate Change Levy (see Climate Change Levy).
Everything a firm owes.
- Limited liability
Owners are not personally liable for debts.
- Liquefied Natural Gas (LNG)
When natural gas is cooled to a temperature of approximately -160 degrees Celsius at atmospheric pressure it condenses to a liquid called liquefied natural gas (LNG). This liquid takes up 600 times less the volume of the gas, making it possible to transport in container ships. Natural gas is composed primarily of methane (typically, at least 90%).
- Liquefied Petroleum Gas (LPG)
LPG is a gas, usually propane or butane, that is derived from oil and put under pressure so that it is in liquid form. It is often used to power portable cooking stoves or heaters and to fuel some types of vehicle, eg some specially adapted road vehicles and forklift trucks.
- Liquid assets ratio
The ability to meet short-term debts without selling stock.
Liquidity ratio =
divided by: Current liabilities
A firm's ability to meet short-term debts.
- Low carbon buildings programme (LCBP)
LCBP ran between 2006-2011 and was a UK Government programme that provided grant funding towards the cost of installing microgeneration and other low carbon technologies at certain types of properties. LCBP was phased-out and replaced with grant funding made through the Government's Feed-in-Tariff (FIT) scheme and the Renewable Heat Incentive (RHI) scheme.
- Low carbon economy
Addresses the global challenges of diminishing fossil fuel reserves, climate change, environmental management and finite natural resources serving an expanding world population. To achieve a low carbon economy there needs to be a transition to the following:
- Energy should be produced using low carbon energy sources and methods - renewable and alternative energy sources, fuels and sequestration
- All resources (in particular energy) should be used efficiently - more efficient energy conservation devices, combined heat and power
- Wherever practical local needs should be served by local production - food materials, energy
- All waste should be minimised - reduce, reuse, recycle
- There is high awareness and compliance with environmental and social responsibility initiatives - industry, commerce and individuals.
- Marked-up price
The price after the company has added its own profit margin on to the cost of the goods.
Microgeneration refers to the production of heat and/or electricity on a small scale. Solar panels and microCHP boilers are examples of microgeneration.
- Micro combined heat and power units (Micro-CHP)
Usually fuelled on gas, although some can burn a range of other fuels, they produce power and heat from a single fuel source. A typical domestic sized micro-CHP unit will deliver the same comfort levels as a modern boiler, whilst reducing the emissions of a typical house by 25% or 1.5 tonne of CO2 per year.
- Nationally Accredited Certification Scheme
- Nest / Nyth
Nest is the Welsh Government's fuel poverty scheme. It aims to help reduce the number of households in fuel poverty and make Welsh homes warmer and more fuel-efficient. Eligible recipients are those in Wales who are in receipt of a means tested benefit or are living in the hardest-to-heat homes. For more information see http://www.nestwales.org.uk/
- Net profit
The profit that is left after all expenses and deductions have been made.
- Net profit margin
Total profit minus cost made in a year as a percentage of sales. Since operating profit equates to 'gross profit minus operating costs' this ratio goes beyond gross margin to consider the impact of 'other expenses' as well. In addition to changes in volumes, selling price, unit costs or product mix, fluctuations in 'operating costs' will also affect this ratio.
Net margin is a key indicator of trading or operational performance.
Net margin =
divided by: Turnover
- Net Promoter Score (NPS)
NPS measures customers' responses to the question 'How likely would you be to recommend us as an energy supplier to a friend or relative (0-10)?' The score is calculated by the percentage of customers defined as promoters (scoring 9-10) minus the percentage defined as detractors (0-6). NPS are collected through customer feedback forms and telephone interviews conducted by a third party supplier. NPS for British Gas and Direct Energy are measured differently and are therefore not comparable.
- Office of the Gas and Electricity Markets (Ofgem)
Ofgem is the Office of the Gas and Electricity Markets. Protecting consumers is their first priority by promoting competition, wherever appropriate, and regulating the companies which run the gas and electricity networks.
For further information, see www.ofgem.gov.uk
Offshoring refers to outsourcing to another country.
Offtake refers to the amount of electricity Centrica takes from a power station. For example, we may take 100% of power from a facility but only own 50% of it. Our offtake would be 100%, whereas our equity share would be 50%.
Subcontracting a service such as in-house catering, back office functions such as accounting or HR services, to a third-party company. The decision to outsource is often made in the interest of lowering cost, making better use of time and gaining advantages from companies with specialist skills.
A predetermined credit limit from a bank.
- Power purchase agreement (PPA)
This is where we have a fixed arrangement to buy power from another energy supplier.
- Price/earnings (P/E) ratio
Measure that compares the earnings per share of a company to the market price of the company's shares. The earnings would normally be for a 12-month period. The share price would be for a particular day and thus it would not match the earnings period unless it were an average for that period.
This ratio can be used to gauge the perceptions of the market to holding shares in particular companies. The higher the P/E ratio, the more popular the share. P/E ratios are often quoted alongside share prices in the national newspapers.
Price/earnings ratio =
divided by: Earnings per share
A firm's income relative to expenditure. Profit before tax can be defined as 'operating profit minus losses on fixed asset sales plus net interest income'. This ratio therefore builds upon 'net margin' by also considering the impact of non-trading items on a business's profitability.
A declining figure in any of these three ratios suggests that potentially there is a problem. However, the reason for the decline must be ascertained through detailed analysis of all relevant aspects of the business before any conclusions can be drawn.
Profit before tax
divided by: Turnover
- Renewable Energy Guarantees of Origin (REGOs)
REGOs are electronic certificates attached to electricity produced from renewable sources across the EU. They were introduced in 2003 in response to the Renewables Directive, which aims to increase the amount of electricity generated in European Member States from renewable energy sources. The Directive requires Member States to issue a Guarantee of Origin, on request, for electricity produced from renewable energy sources.
In 2005 a new standard licence condition was introduced into electricity supply licences, obliging electricity suppliers to give their customers details of the mix of fuels used to produce the electricity supplied to them. Suppliers must show this on bills. REGOs (in some countries they are called Guarantees of Origin - GoOs) are issued in the UK as evidence that the electricity is generated from a 'renewable source', with one REGO representing one kilowatt/hour of electricity.
- Renewable Heat Incentive (RHI)
The RHI is a subsidy for the supply of renewable heat. From its launch in 2011, it has provided appropriate support for technologies such as biomass boilers and combined heat and power (CHP) for the commercial and industrial sector. The Government plans to expand the existing scheme to cover additional technologies and will also offer an additional domestic scheme for individual households. Final details will be announced in summer 2013 and the schemes will open for payment from spring 2014. The UK Government is committed to deliver 15% of total energy from renewables by 2020, and the RHI will help support this target and those on reducing Greenhouse Gas emissions.
- Renewables Obligation (RO)
The RO is the main government market mechanism to support renewable energy. The Obligation requires licensed electricity suppliers to source a specific and annually increasing percentage of the electricity they supply from renewable sources. It was introduced in 2002 and provides a substantial market incentive for all eligible forms of renewable energy.
- Renewables Obligation Certificates (ROCs)
ROCs are awarded to eligible renewable generators for each MWh of electricity generated. ROCs confirm that the power has come from renewable sources - for example, a wind farm. These certificates can then be sold to suppliers, in order to fulfil their Renewables Obligation (RO). Suppliers can either present enough certificates to cover the required percentage of their output, or they can pay a 'buyout' price for any shortfall. All proceeds from buyout payments are recycled to suppliers in proportion to the number of ROCs they present. The buyout price is set each year by Ofgem, and in 2012-2013 the Obligation stands at £40.71 per ROC (Source: Ofgem, Feb 2012, The Renewables Obligation buy-out price and mutualisation ceiling 2012-13). ROCs have increased the profitability of renewable energy generation as the certificates have an additional value over and above the price of electricity itself. The end date of the scheme has now been extended from the 31 March 2027, in England and Wales and Scotland until 31 March 2037, and in Northern Ireland until 31 March 2033.
- Renewable Source Contract
This is a contract where an electricity supplier agrees to supply electricity generated from renewable sources to a business customer. The contract contains a renewable source declaration. Renewable source electricity is exempt from the Climate Change Levy provided certain conditions are met.
- Renewable Source Declaration
This is a declaration made by suppliers that, in each averaging period, the amount of electricity supplied is not greater than the amount of renewable source electricity acquired or generated. It is one of the conditions for exemption from the climate change levy that a renewable source declaration is contained in each renewable source contract.
- Renewable Source Electricity
This is electricity generated from sources of energy other than fossil fuel and nuclear. Wind energy, small-scale hydro, tidal, wave and photovoltaics are all included. Supply of renewable source electricity under a renewable source contract is exempt from the Climate Change Levy (provided certain conditions are met).
Unused cash that a firm has available.
- Retained profits
Withheld dividend payments to shareholders.
- Return on capital employed (ROCE)
Percentage earnings on capital invested in the business by the shareholders. This measure is used to estimate the return the company has achieved on the assets it uses. The calculation uses average capital employed over a period (usually the financial year), attributable to funds provided by the shareholders. Average capital employed excludes interest bearing borrowings and cash deposits.
Profit before interest and taxes
divided by: Average capital employed
- Sales ledger
Contains records of customer accounts.
- Share capital
Money raised from selling shares to shareholders.
Individual investors who own part of a limited company.
- Site-specific power purchase agreement (PPA)
This is where we have a fixed arrangement to buy power from a specific facility such as a wind farm or power station. We take site-specific PPAs into account when calculating our carbon intensity because we know the intensity of the facility from which we purchase the electricity.
- Smart energy
Smart energy technologies are designed to make people more aware of their energy consumption and to provide greater control over household costs. An example of smart energy technologies are smart meters, which provide real-time and historical visibility of energy use within the home. For more information, refer to the smart metering definition.
- Smart Grid
The 'grid' refers to the electric grid, which is a network of transmission lines, transformers and more that delivers electricity from power plants to homes and businesses. With the rise of digital and computerised products, the electric 'grid' has become stretched to capacity and in response, a smart grid is needed to meet growing electric demand. Working along side the electric grid, the Smart Grid will consist of controls, automation, new technologies and equipment to respond digitally, reliably and efficiently to withstand the UK's quickly changing electrical demands.
Further information can be found at: http://energy.gov/oe/technology-development/smart-grid
- Smart metering
Smart meters provide real time information on energy consumption to help consumers control and manage their energy use, which can save money and reduce emissions. By 2019, it is expected that every home will have a smart meter. The Government have mandated that all homes must have smart meters installed between 2014-2019.
In accordance with the Government's supplier-led Central Communications model, Centrica and other leading energy companies will have the responsibility for the installation and maintenance of smart meters but a central organisation will provide the communication links. This means smart meters will be rolled out by the energy suppliers and not the energy network operators. At the end of 2012, British Gas leads the industry in the installation of smart meters in homes and businesses. For more information, refer to the smart energy definition.
- Standard assessment procedure (SAP)
This is the methodology used for assessing the energy performance of buildings for Energy Performance Certificates (see EPCs).
- Total recordable injury rate (TRIR)
Recordable rate includes lost time cases, restricted work cases and medical treatment cases.
The name or other symbol used to identify the goods or services from a particular organisation. A trademark that has been officially registered (Registered Trademark) is identified by the symbol 'TM' is legally protected and it (or a near copy) can not be use by other organisations.
- Triple bottom line
The triple bottom line measures an organisation's success in terms of economic, social and environmental factors.
Total revenue or income from sales.
The United Kingdom continental shelf (UKCS) comprises the areas of seabed and subsoil over which UK exercises sovereign rights of exploration and exploitation of natural resources. It is sometimes used interchangeably with the 'North Sea' but is geographically wider than that. According to UK Oil&Gas, the UKCS has the ability to provide the nation with 40% of its oil and gas demand in 2020 if investment there continues.
- United Nations Framework Convention on Climate Change (UNFCCC)
The UNFCCC was established in 1992 as the international framework to agree strategies to reduce emissions of greenhouse gases in relation to their impact on global climate. The key agreement of the Convention is the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which was signed 1997. The Kyoto Protocol established a timetable for reductions in the emissions of carbon dioxide, methane, nitrous oxide, CFCs and other radiatively active gases, as well as a framework for increasing the sequestration of carbon by vegetation including forests and agricultural land.
- Vulnerable customers
A vulnerable customer is defined as one that is unable to safeguard their personal welfare or the personal welfare of other members of the household, for reasons of age, health, disability or severe financial insecurity.
- Warm Home Discount (WHD)
The Warm Home Discount scheme came into effect on 1 April 2011 and as of 8 July 2011, replaced British Gas' Essentials social tariff to new applicants. The is a four year, mandatory, UK Government programme run in conjunction with energy suppliers and aims to provide assistance with energy costs for vulnerable households across England, Scotland, and Wales. The programme is designed to replace all voluntary schemes run by energy companies and our Essentials customers will therefore gradually move onto this scheme. The scheme separates eligible households into two groups - the 'Core' group are the most vulnerable customers who automatically receive discount on their electricity bills while the 'Broader' group consists of a greater number of low-income households living with for instance, long-term illness, disabilities, or has a household member either over the age of 60 or with a child under five years of age. UK energy suppliers are required to spend a combined £276m in 2012/13, rising to £310m by 2014/15 to vulnerable customers through the programme.
Further details are available on the British Gas website.
We use a definition provided by the World Business Council for Sustainable Development (WBCSD) which states that water-stress is experienced in regions where water availability does not meet the demands of human populations.
- Weightman report
Commissioned by the UK Government, the Weightman report was produced by HM Chief Inspector of Nuclear Installations, Dr Mike Weightman, to asses potential UK implications following the tsunami and nuclear disaster at Fukishima in March 2011. The report was published in October 2011 and gave a clear endorsement of the UK's safety culture and current performance of the UK nuclear industry and confirmed the necessity of new nuclear builds. He made 26 recommendations to the nuclear industry regarding standards.
- Working capital
The difference between a firm's cash and its short-term debts.
- Zero Carbon Home
A zero carbon home is usually thought of as one that produces net zero carbon dioxide emissions in a year. Homes can form part of a low carbon site; they do not have to be built in isolation. Such homes are exempt from stamp duty when they are first bought.
- Zonal Appraisal and Planning (ZAP)
Zonal Appraisal and Planning is a non-statutory process that represents a strategic approach for identifying wind farm sites within the Zone through consideration of key issues, collection of environmental data across the zone, assessment of cumulative impacts and incorporation of stakeholder views at an earlier stage in development.
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Notes to the Financial Statements
1. General information
Centrica plc is a Company domiciled and incorporated in the UK. The address of the registered office is given in Other Statutory Information. The nature of the Group's operations and principal activities are set out in note 6 and in the Directors' Report – Business Review.
The consolidated Financial Statements of Centrica plc are presented in pounds sterling. Operations and transactions conducted in currencies other than pounds sterling are included in the consolidated Financial Statements in accordance with the foreign currencies accounting policy set out in note 2.
2. Summary of significant accounting policies
The principal accounting policies applied in the preparation of these consolidated Financial Statements are set out below. These policies have been applied consistently to all the years presented, unless otherwise stated.
Basis of preparation
The consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU) and therefore comply with Article 4 of the EU IAS Regulation and the Companies Act 2006.
The consolidated Financial Statements have been prepared on the historical cost basis, except for derivative financial instruments, available-for-sale financial assets, financial instruments designated as at fair value through profit or loss on initial recognition, and the assets and liabilities of the Group pension schemes that have been measured at fair value. The carrying values of recognised assets and liabilities that are hedged items in fair value hedges, and are otherwise carried at cost, are adjusted to record changes in the fair values attributable to the risks that are being hedged. The principal accounting policies adopted are set out below.
The preparation of Financial Statements in conformity with IFRS as adopted by the EU requires the use of certain critical accounting estimates. It requires management to exercise its judgement in the processes of applying the Group's accounting policies. The areas involving a higher degree of judgement, complexity or areas where assumptions and estimates are significant to the consolidated Financial Statements are described in note 3.
(a) Standards, amendments and interpretations effective in 2010
At the date of authorisation of these consolidated Financial Statements, the following standards and amendments to existing standards were effective for the current year:
- IFRS 3 (revised), Business Combinations. The revised standard applies to business combinations completing on or after 1 January 2010 with no requirement to restate previous business combinations. The revised standard continues to apply the acquisition method to business combinations with some significant changes. For example, all payments to purchase a business are recorded at fair value at acquisition date, with contingent consideration payments classified as a liability and subsequently re-measured through the Group Income Statement. All acquisition related costs are expensed. There is a choice on an acquisition-by-acquisition basis to measure the non-controlling interest in the acquiree at either fair value or at the non-controlling interest's proportionate share of the acquiree's net assets. The Group's business combinations executed during the year are set out in note 37. There has been no material impact to the Group's Financial Statements on adopting IFRS 3 (revised).
- IAS 27 (revised), Consolidated and Separate Financial Statements. As the Group has adopted IFRS 3 (revised) it is required to adopt IAS 27 (revised) at the same time, which applies prospectively for transactions occurring after 1 January 2010. The revised standard requires the effects of all transactions with non-controlling interests to be recorded in equity if there is no change in control, and such transactions no longer result in goodwill or gains and losses arising. The revised standard also specifies the accounting when control is lost. In such instances any remaining interest in the entity is re-measured to fair value and a gain or loss is recognised in profit or loss. During the year the Group disposed of a 50% interest in Lincs Windfarm Limited, formerly known as Centrica (Lincs) Limited, as set out in note 38, such that the Group no longer has a controlling interest.
The following amendments to existing standards and interpretations were also effective for the current period, but the adoption of these amendments to existing standards and interpretations did not have a material impact on the Financial Statements of the Group:
- IFRIC 17, Distributions of Non-cash Assets to Owners;
- IAS 39 (amendment), Financial Instruments: Recognition and Measurement – Eligible Hedged Items;
- IFRS 2 (amendment), Share-based Payment – Group Cash settled Share-based Payment Transactions; and
- Improvements to IFRSs (2009).
(b) Standards, amendments and interpretations that are not yet effective and that have not been early adopted by the Group
At the date of authorisation of these Financial Statements, the following standards, amendments to existing standards and interpretations, which have not been applied in these consolidated Financial Statements, were in issue but not yet effective:
- IFRS 9, Financial Instruments, effective for annual periods beginning on or after 1 January 2013, subject to EU endorsement. The standard is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement. The impact of adopting this standard is under assessment.
The Directors anticipate that the adoption of the following standards, interpretations and amendments to existing standards and interpretations in future periods, which were also in issue at the date of authorisation of these Financial Statements, will have no material impact on the Financial Statements of the Group:
- IAS 32 (Amendment), Classification of Rights Issues, effective for annual periods commencing on or after 1 February 2010;
- IFRIC 14 (Amendment), Prepayments of a Minimum Funding Requirement, effective for annual periods beginning on or after 1 January 2011;
- IFRIC 19, Extinguishing Financial Liabilities with Equity Instruments, effective for annual periods beginning on or after 1 July 2010;
- IAS 24 (Revised), Related Party Disclosures, effective for annual periods beginning on or after 1 January 2011;
- Amendments to IFRS 7 Financial Instruments: Disclosures, effective for annual periods beginning on or after 1 July 2011, subject to EU endorsement;
- Amendment to IAS 12 Income Taxes, effective for annual periods beginning on or after 1 January 2012, subject to EU endorsement; and
- Improvements to IFRSs 2010, effective for annual periods beginning on or after 1 January 2011, subject to EU endorsement.
(c) Income Statement presentation
The Group's Income Statement and segmental note separately identify the effects of re-measurement of certain financial instruments, and items which are exceptional, in order to provide readers with a clear and consistent presentation of the Group's underlying performance, as described below.
(i) Certain re-measurements
As part of its energy procurement activities, the Group enters into a range of commodity contracts designed to achieve security of energy supply. These contracts comprise both purchases and sales and cover a wide range of volumes, prices and timescales. The majority of the underlying supply comes from high-volume, long-term contracts which are complemented by short-term arrangements. These short-term contracts are entered into for the purpose of balancing energy supplies and customer demand and to optimise the price paid by the Group. Short-term demand can vary significantly as a result of factors such as weather, power generation profiles and short-term movements in market prices.
Many of the energy procurement contracts are held for the purpose of receipt or delivery of commodities in accordance with the Group's purchase, sale or usage requirements and are therefore out of scope of IAS 39. However, a number of contracts are considered to be derivative financial instruments and are required to be fair valued under IAS 39, primarily because their terms include the ability to trade elements of the contracted volumes on a net-settled basis.
The Group has shown the fair value adjustments arising on these contracts separately in the certain re-measurements column. This is because the intention of management is, subject to short-term demand balancing, to use these energy supplies to meet customer demand. Accordingly, management believes the ultimate net charge to cost of sales will be consistent with the price of energy agreed in these contracts and that the fair value adjustments will reverse as the energy is supplied over the life of the contract. This makes the fair value re-measurements very different in nature from costs arising from the physical delivery of energy in the year.
At the balance sheet date the fair value represents the difference between the prices agreed in the respective contracts and the actual or anticipated market price of acquiring the same amount of energy on the open market. The movement in the fair value taken to certain re-measurements in the Income Statement represents the unwinding of the contracted volume delivered or consumed during the year, combined with the change in fair value of future contracted energy as a result of movements in forward energy prices during the year.
These adjustments represent the significant majority of the items included in certain re-measurements.
In addition to these, however, the Group has identified a number of comparable contractual arrangements where the difference between the price which the Group expects to pay or receive under a contract and the market price is required to be fair valued by IAS 39. These additional items relate to cross-border transportation or transmission capacity, storage capacity and contracts relating to the sale of energy by-products, on which economic value has been created which is not wholly recognised under the requirements of IAS 39. For these arrangements the related fair value adjustments are also included under certain re-measurements.
These arrangements are 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 results before certain re-measurements.
In addition, certain re-measurements includes the effects of unwinding the acquisition-date fair values attributable to forward energy procurement and energy sales contracts arising on the acquisition of Strategic Investments, as described below in section (d). The Group has shown the effect of unwinding the acquisition-date fair values attributable to forward energy procurement and energy sales contracts for these investments separately as a certain re-measurement, as the intention is to use these energy supplies in the normal course of business, and management believes the ultimate net charge reflected before the unwind of acquisition-date fair values will be consistent with the price of energy agreed within these contracts. Such presentation is consistent with the internal performance measures used by the Group.
(ii) Exceptional items
As permitted by IAS 1 (Revised), Presentation of Financial Statements, certain items are presented separately. The items that the Group separately presents as exceptional are 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 in order to obtain a clear and consistent presentation of the Group's underlying business performance. Items which may be considered exceptional in nature include disposals of businesses, business restructurings, renegotiation of significant contracts and asset write-downs.
(d) Use of adjusted profit measures
The Directors believe that reporting adjusted profit and adjusted earnings per share measures provides additional useful information on business performance and underlying trends. These measures are used for internal performance purposes. The adjusted measures in this report are not defined terms under IFRS and may not be comparable with similarly titled measures reported by other companies.
The measure of operating profit used by management to evaluate segment performance is adjusted operating profit. Adjusted operating profit is operating profit before exceptional items and certain re-measurements and before depreciation resulting from fair value uplifts to property, plant and equipment on the acquisition of Strategic Investments, as described below. Additionally, adjusted operating profit includes the Group's share of the results from joint ventures and associates before interest and taxation. Note 6 contains an analysis of adjusted operating profit by segment and a reconciliation of adjusted operating profit to operating profit after exceptional items and certain re-measurements.
Adjusted earnings is earnings before exceptional items net of taxation, certain re-measurements net of taxation and depreciation of fair value uplifts to property, plant and equipment on the acquisition of Strategic Investments net of taxation. A reconciliation of earnings to adjusted earnings is provided in note 14.
Depreciation of fair value uplifts to property, plant and equipment on acquiring Strategic Investments
IFRS requires that a fair value exercise is undertaken allocating the cost of acquiring controlling interests and interests in associates to the fair value of the acquired identifiable assets, liabilities and contingent liabilities. Any difference between the cost of acquiring the interest and the fair value of the acquired net assets, which includes identified contingent liabilities, is recognised as acquired goodwill. The fair value exercise is performed at the date of acquisition.
The Directors have determined that for Strategic Investments it is important to separately identify the earnings impact of increased depreciation arising from the acquisition-date fair value uplifts made to property, plant and equipment 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 property, plant and equipment and the segmental results are presented on a consistent basis.
The Group has two Strategic Investments for which reported profits before certain re-measurements and exceptional items have been adjusted in arriving at adjusted profit and adjusted earnings per share. These Strategic Investments relate to the acquisition of Venture Production plc ('Venture'), the operating results of which are included within the Upstream UK – Upstream gas and oil segment, and the acquisition of the 20% interest in Lake Acquisitions Limited ('British Energy'), which owns the British Energy Group, the results (net of taxation and interest) of which are included within the Upstream UK – Power generation segment.
The Group acquired a controlling interest in Venture in 2009. Significant adjustments have been made to the acquired property, plant and equipment 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 property, plant and equipment at their acquisition-date fair values is included in overall reported profit for the year, the Directors have reversed the earnings impact of the increased depreciation and related taxation resulting from fair value uplifts to the acquired oil and gas interests in order to arrive at adjusted profit from continuing operations after taxation.
(ii) British Energy
Centrica acquired its 20% interest in Lake Acquisitions Limited and thus British Energy in 2009. The interest in British Energy is accounted for as an investment in an associate. IAS 28 requires investments in associates to be accounted for using the equity method such that the Group reports its share of the associate's profit or loss, which is net of interest and taxation, within the Group's Income Statement. IAS 28 requires that the Group's share of the associate's profit or loss includes the effects of unwinding the fair value adjustments arising from the notional fair value exercise undertaken at acquisition date.
The most significant fair value adjustments arising on the acquisition of the 20% investment in British Energy relate to the fair value uplifts made to the British Energy nuclear power stations to report the property, plant and equipment at their acquisition-date fair values and fair value uplifts made to British Energy's energy procurement contracts and energy sales contracts to report these at their acquisition-date fair values.
Whilst the impact of increased depreciation and related taxation through unwinding the fair value uplifts to the nuclear power stations is included in the share of associate's post-acquisition result included in overall reported Group profit for the year, the Directors have reversed these impacts in arriving at adjusted profit from continuing operations for the year. The impact of unwinding the acquisition-date fair values attributable to the acquired energy procurement and energy sales contracts is included within certain re-measurements as explained above.
Basis of consolidation
The Group Financial Statements consolidate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) up to 31 December each year, and incorporate the results of its share of jointly controlled entities and associates using the equity method of accounting.
Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities.
The results of subsidiaries acquired or disposed of during the year are consolidated from the effective date of acquisition or up to the effective date of disposal, as appropriate. Where necessary, adjustments are made to the Financial Statements of subsidiaries, associates and jointly-controlled entities to bring the accounting policies used into line with those used by the Group.
All intra-Group transactions, balances, income and expenses are eliminated upon consolidation.
A change in the ownership interest of a subsidiary, without loss of control is accounted for as an equity transaction. For purchases of non-controlling interests, the difference between any consideration paid and the relevant share acquired of the carrying value of the net assets of the subsidiary is recorded in equity. Gains or losses on disposals of non-controlling interests are also recorded in equity.
When the Group ceases to have control or significant influence, any retained interest in the entity is re-measured to its fair value with the change in carrying amount recognised in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as a joint venture, associate or financial asset.
Interests in joint ventures
A jointly controlled entity is a joint venture which involves the establishment of an entity to engage in economic activity, which the Group controls jointly with its fellow venturers. Under the equity method, investments in jointly controlled entities are carried at cost plus post-acquisition changes in the Group's share of net assets of the jointly controlled entity, less any impairment in value in individual investments. The Income Statement reflects the Group's share of the results of operations after tax of the jointly controlled entity.
Certain exploration and production activity is conducted through joint ventures, where the venturers have a direct interest in and jointly control the assets of the venture. The results, assets, liabilities and cash flows of these jointly controlled assets are included in the consolidated Financial Statements in proportion to the Group's interest.
Interests in associates
An associate is an entity in which the Group has an equity interest and over which it has the ability to exercise significant influence. Under the equity method, investments in associates are carried at cost plus post-acquisition changes in the Group's share of the net assets of the associate, less any impairment in value in individual investments. The Income Statement reflects the Group's share of the results of the associate, which is net of interest and taxation and presents this as a single line item in arriving at Group operating profit on the face of the Income Statement.
Revenue is recognised to the extent that it is probable that the economic benefits will flow to the Group and the revenue can be measured reliably. Revenue includes amounts receivable for goods and services provided in the normal course of business, net of discounts, rebates, VAT and other sales-related taxes.
Energy supply: Revenue is recognised on the basis of energy supplied during the year. 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 is estimated using historical consumption patterns, taking into account the industry reconciliation process for total gas and total electricity usage by supplier, and is included in accrued energy income within trade and other receivables.
Proprietary energy trading: Revenue comprises both realised (settled) and unrealised (fair value changes) net gains and losses from trading in physical and financial energy contracts.
Home services and fixed-fee service contracts: Revenue from fixed-fee service contracts is recognised in the Income Statement with regard to the incidence of risk over the life of the contract, reflecting the seasonal propensity of claims to be made under the contracts and the benefits receivable by the customer, which span the life of the contract as a result of emergency maintenance being available throughout the contract term.
Amounts paid in advance greater than recognised revenue are treated as deferred income, with any paid in arrears recognised as accrued income. For one-off services, such as installations, revenue is recognised at the date of service provision.
Storage services: Storage capacity revenues are recognised evenly over the contract period, whilst commodity revenues for the injection and withdrawal of gas are recognised at the point of gas flowing into or out of the storage facilities. Gas purchases and gas sales transactions entered into to optimise the performance of the gas storage facilities are presented net within revenue.
Gas production: Revenue associated with exploration and production sales (of natural gas, crude oil and condensates) is recognised when title passes to the customer. Revenue from the production of natural gas, oil and condensates in which the Group has an interest with other producers is recognised based on the Group's working interest and the terms of the relevant production-sharing arrangements (the entitlement method). Where differences arise between production sold and the Group's share of production, this is accounted for as an overlift or underlift (see separate accounting policy). Gas purchases and gas sales entered into to optimise the performance of gas production facilities are presented net within revenue.
Power generation: Revenue is recognised on the basis of power supplied during the period. Power purchases and sales entered into to optimise the performance of power generation facilities are presented net within revenue.
Interest income: Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying value.
Cost of sales
Energy supply includes the cost of gas and electricity produced and purchased during the year taking into account the industry reconciliation process for total gas and total electricity usage by supplier, and related transportation, distribution, royalty costs and bought-in materials and services.
Home services' and fixed-fee service contracts' cost of sales includes direct labour and related overheads on installation work, repairs and service contracts in the year.
The Group's operating segments are reported in a manner consistent with the internal reporting provided to and regularly reviewed by the Group's Executive Committee for the purposes of evaluating segment performance and allocating resources.
Borrowing costs that arise in connection with the acquisition, construction or production of a qualifying asset are capitalised and subsequently amortised in line with the depreciation of the related asset. Borrowing costs are capitalised from the time of acquisition or from the beginning of construction or production until the point at which the qualifying asset is ready for use. Where a specific financing arrangement is in place, the specific borrowing rate for that arrangement is applied. For non-specific financing arrangements, a Group financing rate representative of the weighted average borrowing rate of the Group is used. Borrowing costs not arising in connection with the acquisition, construction or production of a qualifying asset are expensed.
Carbon Emissions Reduction Target programme (CERT)
UK-licensed energy suppliers are set a carbon emission reduction target by the Government which is proportional to the size of their customer base. The current CERT programme runs from April 2008 to March 2011. The target is subject to an annual adjustment throughout the programme period to take account of changes to a UK-licensed energy supplier's customer base. Energy suppliers can meet the target through expenditure on qualifying projects which give rise to carbon savings. The carbon savings can be transferred between energy suppliers. The Group charges the costs of the programme to cost of sales and capitalises costs incurred in deriving carbon savings in excess of the annual target as inventory, which is valued at the lower of cost and net realisable value and which may be used to meet the carbon emissions reduction target in subsequent periods or sold to third parties. The inventory is carried on a first-in, first-out basis. The carbon emission reduction target for the programme period is allocated to reporting periods on a straight-line basis as adjusted by the annual determination process.
Employee share schemes
The Group operates a number of employee share schemes, detailed in the Remuneration Report and in note 35, under which it makes equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant (excluding the effect of non-market-based vesting conditions). The fair value determined at the grant date is expensed on a straight-line basis together with a corresponding increase in equity over the vesting period, based on the Group's estimate of the number of awards that will vest, and adjusted for the effect of non-market-based vesting conditions.
Fair value is measured using methods appropriate to each of the different schemes as follows:
|LTIS: EPS awards after 2005||Market value on the date of grant|
|LTIS: TSR awards after 2005||A Monte Carlo simulation to predict the total shareholder return performance|
|ESOS||Black-Scholes using an adjusted option life assumption to reflect the possibility of early exercise|
|SAS, SIP, DMSS, RSS, ESPP and DBP||Market value on the date of grant|
The consolidated Financial Statements are presented in pounds sterling, which is the functional currency of the Company and the Group's presentational currency. Each entity in the Group determines its own functional currency and items included in the Financial Statements of each entity are measured using that functional currency. Transactions in foreign currencies are, on initial recognition, recorded at the functional currency rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange ruling at the balance sheet date. All differences are included in the Income Statement for the period, with the exception of exchange differences on foreign currency borrowings that provide a hedge against a net investment in a foreign entity. These are taken directly to equity until the disposal or partial disposal of the net investment, at which time they are recognised in the Income Statement. Non-monetary items that are measured in terms of historical cost in a currency other than the functional currency of the entity concerned are translated using the exchange rates as at the dates of the initial transactions.
For the purpose of presenting consolidated Financial Statements, the assets and liabilities of the Group's foreign subsidiary undertakings, jointly controlled entities and associates are translated into pounds sterling at exchange rates prevailing on the balance sheet date. The results of foreign subsidiary undertakings, jointly controlled entities and associates are translated into pounds sterling at average rates of exchange for the relevant period. Exchange differences arising from the retranslation of the opening net assets and results for the year are transferred to the Group's foreign currency translation reserve, a separate component of equity, and are reported in the Statement of Comprehensive Income. In the event of the disposal of an undertaking with assets and liabilities denominated in a foreign currency, the cumulative translation difference arising in the foreign currency translation reserve is charged or credited to the Income Statement on disposal.
Exchange differences on foreign currency borrowings, foreign currency swaps and forward exchange contracts used to hedge foreign currency net investments in foreign subsidiary undertakings, jointly controlled entities and associates are taken directly to reserves and are reported in the Statement of Comprehensive Income. All other exchange movements are recognised in the Income Statement for the year.
Business combinations and goodwill
The acquisition of subsidiaries is accounted for using the purchase method. The cost of the acquisition is measured as the cash paid and the aggregate of the fair values, at the date of exchange, of other assets transferred, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 (revised), Business Combinations, are recognised at their fair value at the acquisition date, except for non-current assets (or disposal groups) that are classified as held for resale in accordance with IFRS 5, Non-Current Assets Held for Sale and Discontinued Operations, which are recognised and measured at fair value less costs to sell.
Goodwill arising on a business combination represents the excess of the cost of acquisition over the Group's interest in the fair value of the identifiable assets and liabilities of a subsidiary, jointly controlled entity or associate at the date of acquisition. Goodwill is initially recognised as an asset at cost and is subsequently measured at cost less any accumulated impairment losses. If, after reassessment, the Group's interest in the net fair value of the acquiree's identifiable assets, liabilities and contingent liabilities exceeds the cost of the business combination, the excess is recognised immediately in the Income Statement.
On an acquisition by acquisition basis, the interest of non-controlling shareholders in the acquiree is measured initially either at the non-controlling shareholders' proportion of the net fair value of the assets, liabilities and contingent liabilities recognised or at fair value.
Goodwill, which is recognised as an asset, is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount may be impaired. Any impairment is recognised immediately in the Income Statement and is not subsequently reversed.
For the purpose of impairment testing, goodwill is allocated to each of the Group's cash-generating units or groups of cash-generating units that expect to benefit from the business combination in which the goodwill arose. Cash-generating units to which goodwill has been allocated are tested for impairment annually, or more frequently when there is an indication that the unit may be impaired. If the recoverable amount of the cash-generating unit or groups of cash-generating units is less than the carrying amount of the unit, the impairment loss is recognised immediately in the Income Statement and allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to the other assets of the unit pro rata on the basis of the carrying amount of each asset in the unit. Any impairment is not subsequently reversed.
On disposal of a subsidiary, associate or joint venture entity, the attributable amount of goodwill is included in the determination of the profit or loss on disposal.
Other intangible assets
Intangible assets acquired separately are measured on initial recognition at cost. Intangible assets include emissions trading schemes, renewable obligation certificates, certain exploration and evaluation expenditures, brands and application software, the accounting policies for which are dealt with separately below. For purchased application software, for example investments in customer relationship management and billing systems, cost includes contractors' charges, materials, directly-attributable labour and directly-attributable overheads.
Capitalisation begins when expenditure for the asset is being incurred and activities necessary to prepare the asset for use are in progress. Capitalisation ceases when substantially all the activities that are necessary to prepare the asset for use are complete. Amortisation commences at the point of commercial deployment. The cost of intangible assets acquired in a business combination is their fair value as at the date of acquisition.
Following initial recognition, intangible assets are carried at cost less any accumulated amortisation and any accumulated impairment losses. The useful lives of intangible assets are assessed to be either finite or indefinite. Intangible assets with finite lives are amortised over their useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortisation period and the amortisation method for an intangible asset are reviewed at least at each financial year end. Changes in the expected useful life or the expected pattern of consumption of future economic benefits embodied in the asset are accounted for on a prospective basis by changing the amortisation period or method, as appropriate, and treated as changes in accounting estimates.
Intangible assets are derecognised on disposal, or when no future economic benefits are expected from their use.
Intangible assets with indefinite useful lives are tested for impairment annually, and whenever there is an indication that the intangible asset may be impaired, either individually or at the cash-generating unit level, such intangibles are not amortised. The useful life of an intangible asset with an indefinite useful life is reviewed annually to determine whether the indefinite life assessment continues to be supportable. If not, the change in the useful life assessment from indefinite to finite is made on a prospective basis.
The amortisation period for the principal categories of intangible assets are as follows:
|Application software||up to 10 years|
|Licences||up to 20 years|
|Consents||up to 25 years|
|Contractual customer relationships||up to 20 years|
|Identifiable acquired brand||Indefinite|
EU Emissions Trading Scheme and renewable obligations certificates
Granted carbon dioxide emissions allowances received in a period are recognised initially at nominal value (nil value). Purchased carbon dioxide emissions allowances are recognised initially at cost (purchase price) within intangible assets. A liability is recognised when the level of emissions exceeds the level of allowances granted. The liability is measured at the cost of purchased allowances up to the level of purchased allowances held, and then at the market price of allowances ruling at the balance sheet date, with movements in the liability recognised in operating profit.
Forward contracts for the purchase or sale of carbon dioxide emissions allowances are measured at fair value with gains and losses arising from changes in fair value recognised in the Income Statement. The intangible asset is surrendered and the liability is utilised at the end of the compliance period to reflect the consumption of economic benefits.
Purchased renewable obligation certificates are recognised initially at cost within intangible assets. A liability for the renewables obligation is recognised based on the level of electricity supplied to customers, and is calculated in accordance with percentages set by the UK Government and the renewable obligation certificate buyout price for that period. The intangible asset is surrendered and the liability is utilised at the end of the compliance period to reflect the consumption of economic benefits.
Property, plant and equipment
Property, plant and equipment is included in the Balance Sheet at cost, less accumulated depreciation and any provisions for impairment.
The initial cost of an asset comprises its purchase price or construction cost and any costs directly attributable to bringing the asset into operation. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Subsequent expenditure in respect of items of property, plant and equipment such as the replacement of major parts, major inspections or overhauls, are capitalised as part of the cost of the related asset where it is probable that future economic benefits will arise as a result of the expenditure and the cost can be reliably measured. All other subsequent expenditure, including the costs of day-to-day servicing, repairs and maintenance, is expensed as incurred.
Freehold land is not depreciated. Other property, plant and equipment, with the exception of upstream production assets (see below), are depreciated on a straight-line basis at rates sufficient to write off the cost, less estimated residual values, of individual assets over their estimated useful lives. The depreciation periods for the principal categories of assets are as follows:
|Freehold and leasehold buildings||up to 50 years|
|Plant||5 to 20 years|
|Power stations and wind farms||up to 30 years|
|Equipment and vehicles||3 to 10 years|
|Storage||up to 40 years|
Assets held under finance leases are depreciated over their expected useful economic lives on the same basis as for owned assets, or where shorter, the lease term.
The carrying values of property, plant and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying value may not be recoverable.
Residual values and useful lives are reassessed annually and if necessary changes are accounted for prospectively.
Exploration, evaluation and production assets
Centrica uses the successful efforts method of accounting for exploration and evaluation expenditure. Exploration and evaluation expenditure associated with an exploration well, including acquisition costs related to exploration and evaluation activities, are capitalised initially as intangible assets. Certain expenditures such as geological and geophysical exploration costs are expensed. If the prospects are subsequently determined to be successful on completion of evaluation, the relevant expenditure, including licence acquisition costs, is transferred to property, plant and equipment and is subsequently depreciated on a unit of production basis. If the prospects are subsequently determined to be unsuccessful on completion of evaluation, the associated costs are expensed in the period in which that determination is made.
All field development costs are capitalised as property, plant and equipment. Such costs relate to the acquisition and installation of production facilities and include development drilling costs, project-related engineering and other technical services costs. Property, plant and equipment, including rights and concessions related to production activities, are depreciated from the commencement of production in the fields concerned, using the unit of production method, based on all of the proven and probable reserves of those fields. Changes in these estimates are dealt with prospectively.
The net carrying value of fields in production and development is compared on a field-by-field basis with the likely discounted future net revenues to be derived from the remaining commercial reserves. An impairment loss is recognised where it is considered that recorded amounts are unlikely to be fully recovered from the net present value of future net revenues. Exploration and production assets are reviewed annually for indicators of impairment.
Overlift and underlift
Offtake arrangements for oil and gas produced from jointly owned operations are often such that it is not practical for each participant to receive or sell its precise share of the overall production during the period. This results in short-term imbalances between cumulative production entitlement and cumulative sales, referred to as overlift and underlift.
An overlift payable, or underlift receivable, is recognised at the balance sheet date within trade and other payables, or trade and other receivables, respectively, and measured at market value, with movements in the period recognised within cost of sales.
Provision is made for the net present value of the estimated cost of decommissioning gas production facilities at the end of the producing lives of fields, and storage facilities and power stations at the end of the useful life of the facilities, based on price levels and technology at the balance sheet date.
When this provision gives access to future economic benefits, a decommissioning asset is recognised and included within property, plant and equipment. Changes in these estimates and changes to the discount rates are dealt with prospectively and reflected as an adjustment to the provision and corresponding decommissioning asset included within property, plant and equipment. For gas production facilities and offshore storage facilities the decommissioning asset is amortised using the unit of production method, based on proven and probable reserves. For power stations the decommissioning asset is amortised on a straight-line basis over the useful life of the facility. The unwinding of the discount on the provision is included in the Income Statement within interest expense.
The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement and requires an assessment of whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets and whether the arrangement conveys a right to use the asset. Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases. Assets held under finance leases are capitalised and included in property, plant and equipment at their fair value, or if lower, at the present value of the minimum lease payments, each determined at the inception of the lease. The obligations relating to finance leases, net of finance charges in respect of future periods, are included within bank loans and other borrowings, with the amount payable within 12 months included in bank overdrafts and loans within current liabilities.
Lease payments are apportioned between finance charges and reduction of the finance lease obligation so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly against income.
Payments under operating leases are charged to the Income Statement on a straight-line basis over the term of the relevant lease.
Impairment of property, plant and equipment and intangible assets (excluding goodwill)
At each balance sheet date, the Group reviews the carrying amounts of its intangible assets and property, plant and equipment to determine whether there is any indication that those assets have suffered an impairment loss or experienced an impairment reversal. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of any impairment loss or impairment reversal. Where the asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. An intangible asset with an indefinite useful life is tested for impairment annually, and whenever there is an indication that the asset may be impaired.
Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Discount rates are based on the estimated cost of capital of each cash-generating unit. Additionally risks specific to the cash flows of the cash-generating units are reflected within cash flow forecasts.
If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised immediately as an expense.
An impairment loss is reversed only if there has been a change in the estimate used to determine the asset's recoverable amount since the last impairment loss was recognised. Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (cash-generating unit) in prior years. A reversal of an impairment loss is recognised as income immediately. After such a reversal the depreciation or amortisation charge, where relevant, is adjusted in future periods to allocate the asset's revised carrying amount, less any residual value, on a systematic basis over its remaining useful life.
Non-current assets and disposal groups held for sale and discontinued operations
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. No depreciation is charged in respect of non-current assets classified as held for sale.
Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. Management must be committed to the sale which should be expected to qualify for recognition as a completed sale within one year from the date of classification.
The profits or losses and cash flows that relate to a major component of the Group or geographical region that has been sold or is classified as held for sale are presented separately from continuing operations as discontinued operations within the Income Statement and Cash Flow Statement.
Inventories are valued on a weighted-average cost basis at the lower of cost and estimated net realisable value after allowance for redundant and slow-moving items, where applicable.
Where payments are made to external suppliers under take-or-pay obligations for gas not taken, they are treated as prepayments and included within other receivables, as they generate future economic benefits.
Pensions and other post-retirement benefits
The Group operates a number of defined benefit pension schemes. The cost of providing benefits under the defined benefit schemes is determined separately for each scheme using the projected unit credit actuarial valuation method. Actuarial gains and losses are recognised in full in the period in which they occur. They are recognised in the Statement of Comprehensive Income.
The cost of providing retirement pensions and other benefits is charged to the Income Statement over the periods benefiting from employees' service. Past service cost is recognised immediately to the extent that the benefits are already vested, and otherwise is amortised on a straight-line basis over the average period until the benefits become vested. The difference between the expected return on scheme assets and the change in present value of scheme obligations resulting from the passage of time is recognised in the Income Statement within interest income or interest expense.
The retirement benefit obligation or asset recognised in the Balance Sheet represents the present value of the defined benefit obligation of the schemes as adjusted for unrecognised past service cost, and the fair value of the schemes' assets. The present value of the defined benefit obligation or asset is determined by discounting the estimated future cash outflows using interest rates of high-quality corporate bonds that are denominated in the currency in which the benefits are paid, and that have terms of maturity approximating to the terms of the related pension liability.
Payments to defined contribution retirement benefit schemes are charged as an operating expense as they fall due.
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, that can be measured reliably, and it is probable that the Group will be required to settle that obligation. Provisions are measured at the Directors' best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. Where discounting is used, the increase in the provision due to the passage of time is recognised in the Income Statement within interest expense. Onerous contract provisions are recognised where the unavoidable costs of meeting the obligations under a contract exceed the economic benefits expected to be received under it. Given the fungible nature of energy, contracts to purchase or sell energy are reviewed on a portfolio basis whereby it is assumed that the highest priced purchase contract supplies the highest priced sales contract and the lowest priced sales contract is supplied by the lowest priced purchase contract.
Current tax, including UK corporation tax, UK petroleum revenue tax and foreign tax is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is recognised in respect of all temporary differences identified at the balance sheet date, except to the extent that the deferred tax arises from the initial recognition of goodwill (if amortisation of goodwill is not deductible for tax purposes) or the initial recognition of an asset or liability in a transaction which is not a business combination and at the time of the transaction affects neither accounting profit nor taxable profit and loss. Temporary differences are differences between the carrying amount of the Group's assets and liabilities and their tax base.
Deferred tax liabilities may be offset against deferred tax assets within the same taxable entity or qualifying local tax group. Any remaining deferred tax asset is recognised only when, on the basis of all available evidence, it can be regarded as probable that there will be suitable taxable profits, within the same jurisdiction, in the foreseeable future, against which the deductible temporary difference can be utilised.
Deferred tax is provided on temporary differences arising on subsidiaries, jointly controlled entities and associates, except where the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will not reverse in the foreseeable future.
Deferred tax is measured at the average tax rates that are expected to apply in the periods in which the asset is realised or liability settled, based on tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Measurement of deferred tax liabilities and assets reflects the tax consequences expected from the manner in which the asset or liability is recovered or settled.
Financial assets and financial liabilities are recognised in the Group Balance Sheet when the Group becomes a party to the contractual provisions of the instrument. Financial assets are de-recognised when the Group no longer has the rights to cash flows, the risks and rewards of ownership or control of the asset. Financial liabilities are de-recognised when the obligation under the liability is discharged, cancelled or expires.
(a) Trade receivables
Trade receivables are recognised and carried at original invoice amount less an allowance for any uncollectible amounts. Provision is made when there is objective evidence that the Group may not be able to collect the trade receivable. Balances are written off when recoverability is assessed as being remote. If collection is due in one year or less they are classified as current assets. If not they are presented as non-current assets.
(b) Trade payables
Trade payables are recognised at original invoice amount. If payment is due within one year or less they are classified as current liabilities. If not, they are presented as non-current liabilities.
(c) Share capital
Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares are shown in equity as a deduction from the proceeds received. Own equity instruments that are reacquired (treasury shares) are deducted from equity. No gain or loss is recognised in the Income Statement on the purchase, sale, issue or cancellation of the Group's own equity instruments.
(d) Cash and cash equivalents
Cash and cash equivalents comprise cash in hand and current balances with banks and similar institutions, which are readily convertible to known amounts of cash and which are subject to insignificant risk of changes in value and have an original maturity of three months or less.
For the purpose of the Group Cash Flow Statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts.
(e) Interest-bearing loans and other borrowings
All interest-bearing loans and other borrowings are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method, except when they are the hedged item in an effective fair value hedge relationship, where the carrying value is also adjusted to reflect the fair value movements associated with the hedged risks. Such fair value movements are recognised in the Income Statement. Amortised cost is calculated by taking into account any issue costs, discount or premium.
(f) Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets that are designated as available-for-sale, which are recognised initially at fair value within the Balance Sheet. Available-for-sale financial assets are re-measured subsequently at fair value with gains and losses arising from changes in fair value recognised directly in equity and presented in the Statement of Comprehensive Income, until the asset is disposed of or is determined to be impaired, at which time the cumulative gain or loss previously recognised in equity is included in the Income Statement for the period. Accrued interest or dividends arising on available-for-sale financial assets are recognised in the Income Statement.
At each balance sheet date the Group assesses whether there is objective evidence that available-for-sale financial assets are impaired. If any such evidence exists, cumulative losses recognised in equity are removed from equity and recognised in profit and loss. The cumulative loss removed from equity represents the difference between the acquisition cost and current fair value, less any impairment loss on that financial asset previously recognised in profit or loss.
Impairment losses recognised in the Income Statement for equity investments classified as available-for-sale are not subsequently reversed through the Income Statement. Impairment losses recognised in the Income Statement for debt instruments classified as available-for-sale are subsequently reversed if an increase in the fair value of the instrument can be objectively related to an event occurring after the recognition of the impairment loss.
(g) Financial assets at fair value through profit or loss
The Group holds investments in gilts which it designates as fair value through profit or loss in order to reduce significantly a measurement inconsistency that would otherwise arise. Investments are measured at fair value on initial recognition and are re-measured to fair value in each subsequent reporting period. Gains and losses arising from changes in fair value are recognised in the Income Statement within interest income or interest expense.
(h) Derivative financial instruments
The Group routinely enters into sale and purchase transactions for physical delivery of gas, power and oil. A number of these transactions take the form of contracts that were entered into and continue to be held for the purpose of receipt or delivery of the physical commodity in accordance with the Group's expected sale, purchase or usage requirements, and are not within the scope of IAS 39
Certain purchase and sales contracts for the physical delivery of gas, power and oil are within the scope of IAS 39 due to the fact that they net settle or contain written options. Such contracts are accounted for as derivatives under IAS 39 and are recognised in the Balance Sheet at fair value. Gains and losses arising from changes in fair value on derivatives that do not qualify for hedge accounting are taken directly to the Income Statement for the year.
The Group uses a range of derivatives for both trading and to hedge exposures to financial risks, such as interest rate, foreign exchange and energy price risks, arising in the normal course of business. The use of derivative financial instruments is governed by the Group's policies approved by the Board of Directors. Further detail on the Group's risk management policies is included within the Directors' Report – Governance and in note 4 to the Financial Statements.
The accounting treatment for derivatives is dependent on whether they are entered into for trading or hedging purposes. A derivative instrument is considered to be used for hedging purposes when it alters the risk profile of an underlying exposure of the Group in line with the Group's risk management policies and is in accordance with established guidelines, which require the hedging relationship to be documented at its inception, ensure that the derivative is highly effective in achieving its objective, and require that its effectiveness can be reliably measured. The Group also holds derivatives which are not designated as hedges and are held for trading.
All derivatives are recognised at fair value on the date on which the derivative is entered into and are re-measured to fair value at each reporting date. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Derivative assets and derivative liabilities are offset and presented on a net basis only when both a legal right of set-off exists and the intention to net settle the derivative contracts is present.
The Group enters into certain energy derivative contracts covering periods for which observable market data does not exist. The fair value of such derivatives is estimated by reference in part to published price quotations from active markets, to the extent that such observable market data exists, and in part by using valuation techniques, whose inputs include data which is not based on or derived from observable markets. Where the fair value at initial recognition for such contracts differs from the transaction price, a fair value gain or fair value loss will arise. This is referred to as a day-one gain or day-one loss. Such gains and losses are deferred and amortised to the Income Statement based on volumes purchased or delivered over the contractual period until such time observable market data becomes available. When observable market data becomes available, any remaining deferred day-one gains or losses are recognised within the Income Statement. Recognition of the gains or losses resulting from changes in fair value depends on the purpose for issuing or holding the derivative. For derivatives that do not qualify for hedge accounting, any gains or losses arising from changes in fair value are taken directly to the Income Statement and are included within gross profit or interest income and interest expense. Gains and losses arising on derivatives entered into for speculative energy trading purposes are presented on a net basis within revenue.
Embedded derivatives: Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contracts and the host contracts are not carried at fair value, with gains or losses reported in the Income Statement. The closely-related nature of embedded derivatives is reassessed when there is a change in the terms of the contract which significantly modifies the future cash flows under the contract. Where a contract contains one or more embedded derivatives, and providing that the embedded derivative significantly modifies the cash flows under the contract, the option to fair value the entire contract may be taken and the contract will be recognised at fair value with changes in fair value recognised in the Income Statement.
(i) Hedge accounting
For the purposes of hedge accounting, hedges are classified either as fair value hedges, cash flow hedges or hedges of net investments in foreign operations.
Fair value hedges: A derivative is classified as a fair value hedge when it hedges the exposure to changes in the fair value of a recognised asset or liability. Any gain or loss from re-measuring the hedging instrument to fair value is recognised immediately in the Income Statement. Any gain or loss on the hedged item attributable to the hedged risk is adjusted against the carrying amount of the hedged item and recognised in the Income Statement. The Group discontinues fair value hedge accounting if the hedging instrument expires or is sold, terminated or exercised, the hedge no longer qualifies for hedge accounting or the Group revokes the designation. Any adjustment to the carrying amount of a hedged financial instrument for which the effective interest method is used is amortised to the Income Statement. Amortisation may begin as soon as an adjustment exists and shall begin no later than when the hedged item ceases to be adjusted for changes in its fair value attributable to the risk being hedged.
Cash flow hedges: A derivative is classified as a cash flow hedge when it hedges exposure to variability in cash flows that is attributable to a particular risk either associated with a recognised asset, liability or a highly probable forecast transaction. The portion of the gain or loss on the hedging instrument which is effective is recognised directly in equity while any ineffectiveness is recognised in the Income Statement. The gains or losses that are recognised directly in equity are transferred to the Income Statement in the same period in which the highly probable forecast transaction affects income, for example when the future sale of physical gas or physical power actually occurs. Where the hedged item is the cost of a non-financial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-financial asset or liability on its recognition. Hedge accounting is discontinued when the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, no longer qualifies for hedge accounting or the Group revokes the designation.
At that point in time, any cumulative gain or loss on the hedging instrument recognised in equity remains in equity until the highly probable forecast transaction occurs. If the transaction is no longer expected to occur, the cumulative gain or loss recognised in equity is recognised in the Income Statement.
Net investment hedges: Hedges of net investments in foreign operations are accounted for similarly to cash flow hedges. Any gain or loss on the effective portion of the hedge is recognised in equity, any gain or loss on the ineffective portion of the hedge is recognised in the Income Statement. On disposal of the foreign operation, the cumulative value of any gains or losses recognised directly in equity is transferred to the Income Statement.
The Group's investments in Lake Acquisitions Limited and NNB Holding Company Limited are accounted for as associates. The following accounting policies are specific to the accounting for the nuclear activity of these associates.
(a) Fuel costs – nuclear front end
Front end fuel costs consist of the costs of procurement of uranium, conversion and enrichment services and fuel element fabrication. All costs are capitalised into inventory and charged to the Income Statement in proportion to the amount of fuel burnt.
(b) Fuel costs – nuclear back end
Advanced Gas-cooled Reactors (AGR)
Spent fuel extracted from the reactors is sent for reprocessing and/or long-term storage and eventual disposal of resulting waste products. Back end fuel costs comprise a loading related cost per tonne of uranium and a rebate/surcharge to this cost dependent on the out-turn market electricity price in the year and are capitalised into inventory and charged to the Income Statement in proportion to the amount of fuel burnt.
Pressurised Water Reactor (PWR)
Back end fuel costs are based on wet storage in station ponds followed by dry storage and subsequent direct disposal of fuel. Back end fuel costs are capitalised into inventory on loading and charged to the income statement in proportion to the amount of fuel burnt.
(c) Nuclear property, plant and equipment and depreciation
The depreciation period for the principal categories of nuclear assets, which are depreciated on a straight-line basis from the date of the Group acquiring its share in British Energy, are as follows:
|AGR power stations||Up to 13 years|
|PWR power station||25 years|
Expenditure on major inspection and overhauls of production plant is depreciated over the period until the next outage which for AGR power stations is two to three years and for the PWR power station is 18 months.
(d) Nuclear Liabilities Fund (NLF) funding arrangements
Under the arrangements in place with the Secretary of State, the NLF will fund, subject to certain exceptions, British Energy's qualifying uncontracted nuclear liabilities and qualifying decommissioning costs.
In part-consideration for the assumption of these liabilities by the Secretary of State and the NLF, British Energy agreed to pay fixed decommissioning contributions each year and £150,000 (indexed to RPI) for every tonne of uranium in PWR fuel loaded into the Sizewell B reactor after the date of these arrangements.
(e) NLF and nuclear liabilities receivables
The Government indemnity is provided to indemnify any future shortfall on NLF funding of qualifying uncontracted nuclear liabilities (including PWR back end fuel services) and qualifying nuclear decommissioning costs such that the receivable equals the present value of the associated qualifying nuclear liabilities.
(f) Nuclear liabilities
Nuclear liabilities represent provision for British Energy's liabilities in respect of the costs of waste management of spent fuel and nuclear decommissioning.
(g) Unburnt fuels at shutdown
Due to the nature of the nuclear fuel process there will be quantities of unburnt fuel in the reactors at station closure. The costs relating to this unburnt fuel (final core) are estimated by applying a long-term inflation index to the projected costs, which are then discounted.
3. Critical accounting judgements and key sources of estimation uncertainty
(a) Critical judgements in applying the Group's accounting policies
The Group's accounting policies as set out in note 2 and Notes to the Financial Statements include descriptions of key judgements management has made in applying the Group's accounting policies. Areas of judgement that have the most significant effect on the amounts recognised in the Financial Statements (apart from those involving estimations which are dealt with below) include the following:
- the presentation of certain items as exceptional – notes 2 and 9;
- the use of adjusted profit and adjusted earnings per share measures – notes 2 and 14; and
- the classification of energy procurement contracts as derivative financial instruments and presentation as certain remeasurements – notes 2, 4, 9 and 22.
In addition to those described above, management has made the following key judgements in applying the Group's accounting policies that have the most significant effect on the Group's Financial Statements.
Wind farm partial disposal
On 5 February 2010 the Group disposed of 50% of the equity voting share capital and 50% of the existing shareholder loan of Lincs Windfarm Limited (formerly Centrica (Lincs) Limited) ('Lincs'), the owner of the proposed wind farm (see note 38).
As part of this disposal, the Group contracted to purchase 75% of the power output and levy exemption certificates and 50% of the renewable obligation certificates produced by the wind farm under a 15-year offtake agreement. The pricing of this arrangement was on an arm's length basis. The Group also contracted to provide management, operational and transitional support services to Lincs as directed by their board (and shareholders). A shareholders' agreement was put in place which included a number of reserved matters and provides for joint management of the major decisions of the company.
The Directors have judged that the disposal of equity voting share capital is a loss of control over the financial and operating policies of Lincs. The offtake agreement pricing together with the other arrangements in place mean that the majority of the benefits and residual risks of owning the windfarms reside with Lincs and not Centrica. Accordingly, the remaining investment in Lincs is equity accounted as an investment in a joint venture (see note 19). The Directors have judged that the 15-year offtake agreement is not a leasing arrangement. This is because the Group is not purchasing substantially all of the economic output of the wind farm. This contract is considered to be outside the scope of IAS 39 apart from the embedded derivative arising from the pricing terms which is marked to market separately.
In the previous year, the Group disposed of 50% of the equity voting share capital of GLID Wind Farms TopCo Limited ('GLID'), the owner of Glens of Foudland and Lynn and Inner Dowsing wind farms on 11 December 2009. This transaction was also deemed to be a loss of control and the remaining investment in GLID is equity accounted as an investment in a joint venture (see note 19). The Directors have judged that the 15-year offtake agreement is not a leasing arrangement. The contract is assessed as falling outside the scope of IAS 39 with respect to the own-use exemption, however the embedded derivative in the pricing mechanism is being marked to market separately.
Finance lease – third-party power station tolling arrangement
The Group has a long-term tolling arrangement with the Spalding power station. The contract provides Centrica with the right to nominate 100% of the plant output until 2021 in return for a mix of capacity payments and operating payments based on plant availability. 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 judged that the arrangement should be accounted for as a finance lease as the lease term is judged to be substantially all of the economic life of the power station and the present value of the minimum lease payments at inception date of the arrangement amounted to substantially all of the fair value of the power station at that time. Details of the finance lease asset, finance lease creditor and interest charges are included in notes 18, 26 and 10 respectively.
Provision for onerous gas contract
On 1 October 2009 an onerous contract provision was established for a gas purchase contract for which a two-year notice had been served to terminate (see notes 9 and 28). This contract provided the Group with the option to purchase gas for which a significant capacity charge was incurred regardless of the offtake. The capacity charges are unavoidable costs of the contract. The economic benefits expected to be received under the contract have been estimated using the Group's standard contract valuation methodology. Management has judged that, following serving notice to terminate, this contract no longer forms part of the Group's gas supply and that any gas delivered under the contract is delivered to minimise the overall cost of the contract during the notice period rather than to satisfy the Group's overall demand for gas. Therefore the expected economic benefits have been estimated based on market prices rather than being valued on a portfolio basis as explained in note 2.
Operating Lease – third party power station tolling arrangement
The Group has a long-term tolling arrangement with the newly built Rijnmond power station in The Netherlands. The Rijnmond power station commenced operation in May 2010. The contract provides Centrica with the right to nominate 100% of the plant output until 2029 in return for a mix of capacity payments and operating payments based on plant availability. Centrica does not have the right to extend the agreement or any option to purchase the plant. The Directors have judged 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 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 39.
Business combinations and acquisitions – purchase price allocations
For business combinations and acquisitions of associates and joint ventures, IFRS requires that a fair value exercise is undertaken allocating the purchase price (cost) of acquiring controlling interests and interests in associates and joint ventures to the fair value of the acquired identifiable assets, liabilities and contingent liabilities.
Any difference between the cost of acquiring the interest and the fair value of the acquired net assets, which includes identified contingent liabilities, is recognised as acquired goodwill. The fair value exercise is performed at the date of acquisition. As a result of the nature of fair value assessments in the energy industry the purchase price allocation exercise and acquisition-date fair value determinations require 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. Business combinations are set out in note 37.
EU Emissions Trading Scheme
The Group has been subject to the EU Emissions Trading Scheme (EU ETS) since 1 January 2005. IFRIC 3, Emissions Rights, was withdrawn by the IASB in June 2005, and has not been replaced by definitive guidance. The Group has adopted an accounting policy which recognises carbon dioxide emissions liabilities when the level of emissions exceeds the level of allowances granted by the Government in the period. The liability is measured at the cost of purchased allowances up to the level of purchased allowances held, and then at market price of allowances ruling at the balance sheet date. Movements in the liability are reflected within operating profit. Forward contracts for sales and purchases of allowances are measured at fair value.
Petroleum revenue tax (PRT)
The definition of an income tax in IAS 12, Income Taxes, has led management to judge that PRT should be treated consistently with other income taxes. The charge for the year is presented within taxation on profit from continuing operations in the Income Statement. Deferred amounts are included within deferred tax assets and liabilities in the Balance Sheet.
(b) Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.
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. 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 deemed supply. The Group then 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.
Determination of fair values – energy derivatives
Derivative contracts are carried in the Balance Sheet at fair value, with changes in fair value recorded in either the Income Statement or the Statement of Comprehensive Income. 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. More detail on the assumptions used in determining fair valuations is provided in note 29.
Gas and liquids reserves
The volume of proven and probable gas and liquids reserves is an estimate that affects the unit of production depreciation of producing gas and liquids property, plant and equipment, as well as being a significant estimate affecting decommissioning estimates and impairment calculations. The factors impacting gas and liquids estimates, the process for estimating reserve quantities and reserve recognition are described in Gas and Liquids Reserves.
The impact of a change in estimated proven and probable reserves is dealt with prospectively by depreciating the remaining book value of producing assets over the expected future production. If proven and probable 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.
The estimated cost of decommissioning at the end of the producing lives of fields is reviewed periodically and is based on proven and probable 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 between 2011 and 2055, with the substantial majority of the costs expected to be paid between 2020 and 2030.
Provisions are determined for the estimated costs of decommissioning British Energy's nuclear power stations and the costs of waste management and spent fuel. Various arrangements and indemnities are in place with the Secretary of State with respect to these costs, as explained in note 2.
Impairment of goodwill and indefinite-lived intangible assets
The Group determines whether goodwill and indefinite-lived intangible assets are impaired at least on an annual basis in accordance with the Group's accounting policy, as described in note 2. This requires the determination of the recoverable amount of the cash-generating units to which goodwill and indefinite-lived intangibles are allocated. The recoverable amounts are determined by either estimating the value in use of those cash-generating units or, in the case of the Upstream UK – Upstream gas and oil cash-generating unit, determining the fair value less costs to sell of the cash-generating unit. Value in use calculations require the Group to make an estimate of the expected future cash flows to be derived from the cash-generating units and to choose a suitable discount rate in order to calculate the present value of those cash flows. The fair value less costs to sell methodology is deemed more appropriate for the Upstream UK – Upstream gas and oil cash-generating unit as it is based on post-tax cash flows arising from each field within the cash-generating unit, which is consistent with the approach taken by management in determining the economic value of the underlying assets. Fair value less costs to sell is determined by discounting the post-tax cash flows expected to be generated by the gas and oil production and development assets within the Upstream UK – Upstream gas and oil cash-generating unit, net of associated selling costs, and takes into account assumptions market participants would use in estimating fair value. Further detail on impairments arising and the assumptions used in determining the value in use and fair value less costs to sell calculations is provided in note 17.
Impairment of power generation and upstream gas assets
Power generation and upstream gas assets are assessed for indicators of impairment at each reporting date in accordance with the Group's accounting policies as described in note 2. If an indicator of impairment exists, an assessment of the recoverable amount of the asset is required to be made. Indicators of impairment for these assets may include, but are not limited to, the following:
- reductions in reserve estimates or profiles of production;
- declines in long-term commodity prices;
- increases in capital expenditure or acceleration of known capital expenditure;
- significant unplanned outages or problems with operational performance; and
- changes in regulatory or tax environments.
The recoverable amount of power generation and upstream gas assets is assessed with reference to either each individual asset's value in use or fair value less costs to sell. The value in use is based on the pre-tax cash flows expected to be generated by the asset and is dependent on views of forecast generation/production, forecast commodity prices (using market prices where available and internal estimates for the remainder of the period) and the timing and extent of capital expenditure. The fair value less costs to sell is determined by using evidence from recent acquisitions for similar assets in the local oil and gas market, or by discounting the post-tax cash flows expected to be generated, net of associated selling costs, taking into account assumptions market participants would use in estimating fair value.
For gas fired power stations, which have a high degree of production flexibility, the value in use calculation also includes a scenario-based statistical assessment of the additional value which can be generated from optimising production to take advantage of volatile forward prices. Pre-tax cash flows for the first three years are based on the Group's internal Board-approved three-year business plans and thereafter are estimated on a consistent basis to reflect cash flows up to the date of cessation of operation of the asset. Pre-tax cash flows are discounted using a pre-tax discount rate that reflects current market assessments of the time value of money. Discount rates are based on the estimated cost of capital of each cash-generating unit. Additionally, risks specific to the cash flows of the cash-generating units are reflected within cash flow forecasts. Further details of impairments arising and the carrying values of the Group's power generation and upstream gas assets are included within note 18.
Trade and other receivables – provisions for credit losses
The methodology for determining provisions for credit losses on trade and other receivables and the level of such provisions are set out in note 21. The estimates and assumptions used to determine the level of provisions are reviewed periodically. Although the provisions recognised are considered appropriate, the use of different assumptions or changes in economic conditions could lead to changes in the provisions and therefore impact profit or loss.
Pensions and other post–retirement benefits
The Group operates a number of defined benefit pension schemes. The cost of providing benefits under the defined benefit schemes is determined separately for each scheme 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 36.
North America – Wind farm onerous contract provision
In 2009 an onerous contract provision amounting to £55 million was recognised within the North America – Upstream and wholesale energy segment relating to certain wind farm power purchase agreements to reflect the fair value of the obligation to purchase power which was above the net realisable value obtained from selling the power. The profitability of the wind farm power purchase agreements is measured taking into account the expected revenue and cost streams relating to each agreement. This measurement involves the use of estimates relating to expected wind forecasts, forward curves for energy prices and renewable energy certificates prices for which there is not a liquid market for the full term of all the contracts. In 2010 the position has deteriorated further, driven predominantly by falling forward power prices, and the provision has been increased by £67 million in the period resulting, after utilisation of part of the provision in 2010, in a provision of £101 million at the balance sheet date. Although the provision recognised is considered appropriate, it is reasonably possible that changes in economic conditions or the use of different assumptions could lead to further changes in the provision and therefore impact profit or loss in the future.
4. Financial risk management
The Group's normal operating, investing and financing activities expose it to a variety of financial risks: market risk (including commodity price risk, volumetric risk, currency risk, interest rate risk and equity price risk), credit risk and liquidity risk. The Group's overall risk management process is designed to identify, manage and mitigate business risk, which includes, among others, financial risk. Further detail on the Group's overall risk management process is included within the Directors' Report – Governance.
2010 was marked by a continuing shortage of available credit in European energy markets due to the continuing impact from the financial crisis, emerging European Sovereign debt concerns and general economic conditions. Credit markets in North America have started to improve, although consolidation in the energy industry and the implications of the 'Deepwater Horizon' incident impacted overall market activity. The Group continues to be vigilant and manage credit risk in accordance with its risk management policy.
Financial risk management is overseen by the Group Financial Risk Management Committee (GFRMC) according to objectives, targets and policies set by the Board. Commodity price risk management is carried out in accordance with individual business unit Financial Risk Management Committees and their respective financial risk management policies, as approved by the GFRMC under delegated authority from the Board. Treasury risk management, including management of currency risk, interest rate risk, equity price risk and liquidity risk is carried out by a central Group Treasury function in accordance with the Group's financing and treasury policy and collateral risk 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. Downstream credit risk management is carried out in accordance with individual business unit credit policies.
Market risk management
Market risk is the risk of loss that results from changes in market prices (commodity prices, foreign exchange rates, interest rates and equity prices). The level of market risk to which the Group is exposed at a point in time varies depending on market conditions, expectations of future price or market rate movements and the composition of the Group's physical asset and contract portfolios.
(a) Commodity price risk management
The Group is exposed to commodity price risk in its upstream assets, energy procurement contracts, downstream and proprietary energy trading activities and uses specific limits to manage the exposure to commodity prices associated with the Group's activities to an acceptable level. Volumetric limits are supported by Profit at Risk (PaR) and Value at Risk (VaR) methodologies in the UK and in North America and a VaR methodology in Europe to measure the Group's exposure to commodity price risk. Limits are also set on PaR and VaR measurements as a further control over exposure to market prices.
(i) Energy procurement, upstream and downstream activities
The Group's energy procurement, upstream and downstream activities consist of equity gas and liquids production, equity power generation, bilateral procurement and sales contracts, market-traded purchase and sales contracts and derivative positions taken on with the intent of securing gas and power for the Group's downstream customers in the UK, Europe and North America from a variety of sources at an optimal cost. The Group actively manages commodity price risk by optimising its asset and contract portfolios and making use of volume flexibility.
The Group is exposed to commodity price risk in its energy procurement, upstream and downstream activities because the cost of procuring gas and electricity to serve its downstream customers varies with wholesale commodity prices. The risk is primarily that market prices for commodities will fluctuate between the time that sales prices are fixed or tariffs are set and the time at which the corresponding procurement cost is fixed, thereby potentially reducing expected margins or making sales unprofitable.
The Group is also exposed to volumetric risk in the form of an uncertain consumption profile arising from a range of factors, including weather, energy consumption changes, customer attrition and economic climate.
In order to manage the exposure to market prices associated with the Group's energy procurement, upstream and downstream activities the Group uses a specific set of limits (including position, volumetric, VaR/PaR) established and governed by GFRMC oversight, along with business unit market risk policies.
Volumetric limits are supported by PaR and VaR methodologies in the UK and in North America and a VaR methodology in Europe to measure the Group's exposure to commodity price risk. Limits are also set on PaR and VaR measurements as a further control over exposure to market prices. PaR measures the estimated potential loss in a position or portfolio of positions associated with the movement of a commodity price for a given confidence level, over the remaining term of the position or contract portfolio. VaR measures the estimated potential loss for a given confidence level over a predetermined holding period. The standard confidence level used is 95%. In addition, stress tests are regularly performed to evaluate the impact of substantial movements in commodity prices.
The Group measures and manages the commodity price risk associated with the Group's entire energy procurement, upstream and downstream portfolio. Only certain of the Group's energy procurement, upstream and downstream contracts constitute financial instruments under IAS 39 (note 2). As a result, while the Group manages the commodity price risk associated with both financial and non-financial energy procurement, upstream and downstream contracts, it is the notional value of energy contracts being carried at fair value that represents the exposure of the Group's energy procurement, upstream and downstream activities to commodity price risk according to IFRS 7, Financial Instruments: Disclosures. This is because energy contracts that are financial instruments under IAS 39 are accounted for on a fair value basis and changes in fair value immediately impact profit or equity. Conversely, energy contracts that are not financial instruments under IAS 39 are accounted for as executory contracts and changes in fair value do not immediately impact profit or equity, and as such, are not exposed to commodity price risk as defined by IFRS 7. So whilst the PaR or VaR associated with energy procurement and downstream contracts outside the scope of IAS 39 is monitored for internal risk management purposes, only those energy contracts within the scope of IAS 39 are within the scope of the IFRS 7 disclosure requirements.
The net gain within operating profit of £1,163 million (2009: £71 million loss) on the re-measurement of energy contracts largely represents net gains on settlements or delivery of contracts. As gas and power were delivered under these contracts, net out of the money positions from 2009 unwound, generating a net credit to the income statement. There were also unrealised mark-to-market gains created by gas and power purchase contracts which are priced below the current wholesale market value of energy. These gains are calculated with reference to forward energy prices and therefore the extent of the economic gain or loss arising over the life of these contracts is uncertain, and entirely dependent upon the level of future wholesale energy prices. Generally, subject to short-term balancing, the ultimate net charge to cost of sales will be consistent with the price of energy agreed in these contracts and the fair value adjustments will reverse as the energy is supplied over the life of the contract.
The carrying value of energy contracts used in energy procurement, upstream and downstream activities at 31 December 2010 is disclosed in note 22. A sensitivity analysis that is intended to illustrate the sensitivity of the Group's financial position and performance to changes in the fair value or future cash flows of financial instruments associated with the Group's energy procurement, upstream and downstream activities as a result of changes in commodity prices is provided below in section (e).
(ii) Proprietary energy trading
The Group's proprietary energy trading activities consist of physical and financial commodity purchases and sales contracts taken on with the intent of benefiting in the short term from changes in market prices or differences between buying and selling prices. The Group conducts its trading activities in the over-the-counter market and through exchanges in the UK, North America and continental Europe. The Group is exposed to commodity price risk as a result of its proprietary energy trading activities because the value of its trading assets and liabilities will fluctuate with changes in market prices for commodities.
The Group sets volumetric and VaR limits to manage the commodity price risk exposure associated with the Group's proprietary energy trading activities. The VaR used measures the estimated potential loss for a 95% confidence level over a one-day holding period. The holding period used is based on market liquidity and the number of days the Group would expect it to take to close out a trading position.
As with any modelled risk measure, there are certain limitations that arise from the assumptions used in the VaR analysis. VaR assumes that the future will behave like the past and that the Group's trading positions can be unwound or hedged within the predetermined holding period. Furthermore, the use of a 95% confidence level, by definition, does not take into account changes in value that might occur beyond this confidence level.
The VaR, before taxation, associated with the Group's proprietary energy trading activities at 31 December 2010 was £0.2 million (2009: £1.6 million). The carrying value of energy contracts used in proprietary energy trading activities at 31 December 2010 is disclosed in note 22.
(b) Currency risk management
The Group is exposed to currency risk on foreign currency denominated forecast transactions, firm commitments, monetary assets and liabilities (transactional exposure) and on its net investments in foreign operations (translational exposure).
(i) Transactional currency risk
The Group is exposed to transactional currency risk on transactions denominated in currencies other than the underlying functional currency of the commercial operation transacting. The Group's primary functional currencies are pounds sterling in the UK, Canadian dollars in Canada, US dollars in the US, Norwegian krone in Norway and euros in The Netherlands. The risk is that the functional currency value of cash flows will vary as a result of movements in exchange rates. Transactional exposure arises from the Group's energy procurement activities in the UK and in Canada, where a number of transactions are denominated in euros or US dollars and on certain capital commitments denominated in foreign currencies. In addition, in order to optimise the cost of funding, the Group has, in certain cases, issued foreign currency denominated debt, primarily in US dollars, New Zealand dollars, euros or Japanese yen.
It is the Group's policy to hedge all material transactional exposures using forward contracts to fix the functional currency value of non-functional currency cash flows. At 31 December 2010, there were no material unhedged non-functional currency monetary assets or liabilities, firm commitments or probable forecast transactions (2009: £nil), other than foreign currency borrowings used to hedge translational exposures.
(ii) Translational currency risk
The Group is exposed to translational currency risk as a result of its net investments in North America and Europe. The risk is that the pounds sterling value of the net assets of foreign operations will decrease with changes in foreign exchange rates. The Group's policy is to protect the pounds sterling book value of its net investments in foreign operations, subject to certain parameters monitored by the GFRMC, by holding foreign currency debt, entering into foreign currency derivatives, or a mixture of both.
The Group manages translational currency risk taking into consideration the cash impact of any hedging activity as well as the risk to the net asset numbers in the Group's Financial Statements. The translation hedging programme including the potential cash impact is monitored by the GFRMC.
The Group measures and manages the currency risk associated with all transactional and translational exposures. In contrast, IFRS 7 only requires disclosure of currency risk arising on financial instruments denominated in a currency other than the functional currency of the commercial operation transacting. As a result, for the purposes of IFRS 7, currency risk excludes the Group's net investments in North America and Europe as well as foreign currency denominated forecast transactions and firm commitments. A sensitivity analysis that is intended to illustrate the sensitivity of the Group's financial position and performance to changes in the fair value or future cash flows of foreign currency denominated financial instruments as a result of changes in foreign exchange rates is provided below in section (e).
(c) Interest rate risk management
In the normal course of business the Group borrows to finance its operations. The Group is exposed to interest rate risk because the fair value of fixed rate borrowings and the cash flows associated with floating rate borrowings will fluctuate with changes in interest rates. The Group's policy is to manage the interest rate risk on long-term borrowings by ensuring the exposure to floating interest rates remains within a 30% to 70% range, including the impact of interest rate derivatives. A sensitivity analysis that is intended to illustrate the sensitivity of the Group's financial position and performance to changes in interest rates is provided below in section (e).
(d) Equity price risk management
The Group is exposed to equity price risk because certain available-for-sale financial assets, held by the Law Debenture Trust on behalf of the Company as security in respect of the Centrica Unapproved Pension Scheme, are linked to equity indices (note 36). Investments in equity indices are inherently exposed to less risk than individual equity investments because they represent a naturally diverse portfolio. Note 36 details the Group's other retirement benefit assets and liabilities.
(e) Sensitivity analysis
IFRS 7 requires disclosure of a sensitivity analysis that is intended to illustrate the sensitivity of the Group's financial position and performance to changes in market variables (commodity prices, foreign exchange rates and interest rates) as a result of changes in the fair value or cash flows associated with the Group's financial instruments. The sensitivity analysis provided discloses the effect on profit or loss and equity at 31 December 2010 assuming that a reasonably possible change in the relevant risk variable had occurred at 31 December 2010 and been applied to the risk exposures in existence at that date to show the effects of reasonably possible changes in price on profit or loss and equity to the next annual reporting date. Reasonably possible changes in market variables used in the sensitivity analysis are based on implied volatilities, where available, or historical data for energy prices and foreign exchange rates. Reasonably possible changes in interest rates are based on management judgement and historical experience.
The sensitivity analysis has been prepared based on 31 December 2010 balances and on the basis that the balances, the ratio of fixed to floating rates of debt and derivatives, the proportion of energy contracts that are financial instruments, the proportion of financial instruments in foreign currencies and the hedge designations in place at 31 December 2010 are all constant. Excluded from this analysis are all non-financial assets and liabilities and energy contracts that are not financial instruments under IAS 39. The sensitivity to foreign exchange rates relates only to monetary assets and liabilities denominated in a currency other than the functional currency of the commercial operation transacting, and excludes the translation of the net assets of foreign operations to pounds sterling, but includes the corresponding impact of financial instruments used in net investment hedges.
The sensitivity analysis provided is hypothetical only and should be used with caution as the impacts provided are not necessarily indicative of the actual impacts that would be experienced because the Group's actual exposure to market rates is changing constantly as the Group's portfolio of commodity, debt and foreign currency contracts changes. Changes in fair values or cash flows based on a variation in a market variable cannot be extrapolated because the relationship between the change in market variable and the change in fair value or cash flows may not be linear. In addition, the effect of a change in a particular market variable on fair values or cash flows is calculated without considering interrelationships between the various market rates or mitigating actions that would be taken by the Group. The sensitivity analysis provided below excludes the impact of proprietary energy trading assets and liabilities because the VaR associated with the Group's proprietary energy trading activities has already been provided above in section (a).
The impacts of reasonably possible changes in commodity prices on profit and equity, both after taxation, based on the assumptions provided above are as follows:
|Energy prices||Base price (i)||Reasonably possible change in variable||Base price (i)||Reasonably possible change in variable|
|UK gas (p/therm)||59||+/–11||41||+/–10|
|UK power (£/MWh)||51||+/–5||41||+/–5|
|UK coal (US$/tonne)||121||+/–21||99||+/–20|
|UK emissions (€/tonne)||14||+/–2||13||+/–3|
|UK oil (US$/bbl)||95||+/–18||86||+/–19|
|North American gas (USc/therm)||52||+/–9||65||+/–11|
|North American power (US$/MWh)||48||+/–4||61||+/–5|
|European power (€/MWh)||55||+/–8||53||+/–5|
|Incremental profit/(loss)||Impact on profit
|Impact on equity
|Impact on profit
|Impact on equity
|UK energy prices (combined) – increase/(decrease)||98/(79)||32/(32)||38/(38)||30/(30)|
|North American energy prices (combined) – increase/(decrease)||25/(25)||7/(7)||46/(46)||21/(21)|
|European energy prices (combined) – increase/(decrease)||10/(10)||–/–||14/(14)||–/–|
The impacts of reasonably possible changes in interest rates on profit and equity, both after taxation, based on the assumptions provided above are as follows:
|Interest rates and incremental profit/(loss)||Reasonably possible change in variable
|Impact on profit
|Impact on equity
|Reasonably possible change in variable
|Impact on profit
|Impact on equity
|UK interest rates||+/–1.0||14/(12)||14/(18)||+/–1.0||5/(9)||16/(19)|
|US interest rates||+/–1.0||2/(6)||–/–||+/–1.0||6/(7)||(7)/9|
|Canadian interest rates||+/–1.0||2/(3)||–/–||+/–1.0||4/(4)||–/–|
|Euro interest rates||+/–1.0||(7)/5||–/–||+/–1.0||(12)/12||–/–|
|Japanese interest rates||+/–1.0||–/–||(16)/21||+/–1.0||–/–||(13)/17|
The impacts of reasonably possible changes in foreign currency rates relative to pounds sterling on profit and equity, both after taxation, based on the assumptions provided above are as follows:
|Foreign exchange rates and incremental profit/(loss)||Reasonably possible change in variable
|Impact on profit
|Impact on equity
|Reasonably possible change in variable
|Impact on profit
|Impact on equity
Credit risk management
Credit risk is the risk of loss associated with a counterparty's inability or failure to discharge its obligations under a contract. The Group is exposed to credit risk in its treasury, trading, energy procurement and downstream activities. The Group continues to take steps to tighten downstream credit policies, including the tightening of credit scores in customer management processes, whilst continuing to manage credit risk in accordance with financial risk management processes.
Note 22 provides further detail of the Group's exposure to credit risk on derivative financial instruments, note 21 provides detail of the Group's exposure to credit risk on trade and other receivables, note 24 provides detail of the Group's exposure to credit risk on cash and cash equivalents and note 29 provides the carrying value of all financial assets representing the Group's maximum exposure to credit risk.
(a) Treasury, trading and energy procurement activities
Wholesale counterparty credit exposures are monitored by individual counterparty and by category of credit rating, and are subject to approved limits. The majority of significant exposures are with counterparties rated A–/A3 or better. The Group uses master netting agreements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist. In addition, the Group employs a variety of other methods to mitigate credit risk: margining, various forms of bank and parent company guarantees and letters of credit.
100% of the Group's credit risk associated with its treasury, trading and energy procurement activities is with counterparties in related energy industries or with financial institutions. The Group measures and manages the credit risk associated with the Group's entire treasury, trading and energy procurement portfolio. In contrast, IFRS 7 defines credit risk as the risk that one party to a financial instrument will cause a financial loss for the other party by failing to discharge an obligation and requires disclosure of information about the exposure to credit risk arising from financial instruments only. Only certain of the Group's energy procurement contracts constitute financial instruments under IAS 39 (note 2). As a result, whilst the Group manages the credit risk associated with both financial and non-financial energy procurement contracts, it is the carrying value of financial assets within the scope of IAS 39 (note 29) that represents the maximum exposure to credit risk in accordance with IFRS 7.
(b) Downstream activities
In the case of business customers, credit risk is managed by checking a company's creditworthiness and financial strength both before commencing trade and during the business relationship. For residential customers, creditworthiness is ascertained normally before commencing trade by reviewing an appropriate mix of internal and external information to determine the payment mechanism required to reduce credit risk to an acceptable level. Certain customers will only be accepted on a prepayment basis or with a security deposit.
In some cases, an ageing of receivables is monitored and used to manage the exposure to credit risk associated with both business and residential customers. In other cases, credit risk is monitored and managed by grouping customers according to the method of payment or profile.
Liquidity risk management and going concern
Liquidity risk is the risk that the Group is unable to meet its financial obligations as they fall due. The Group experiences significant movements in its liquidity position due primarily to the seasonal nature of its business and margin cash arrangements associated with certain wholesale commodity contracts. To mitigate this risk the Group maintains significant committed facilities and holds cash on deposit. The Group's liquidity position has remained strong throughout 2010.
|Year ended 31 December||2010
|Cash pledged as collateral at 1 January||631||626|
|Net cash (inflow)/outflow||(466)||79|
|Transferred to discontinued operations||–||(15)|
|Foreign exchange gains/(losses)||8||(59)|
|Cash pledged as collateral at 31 December (i)||173||631|
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, to 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 2010, the Group had undrawn committed credit facilities of £2,873 million (2009: £2,083 million) and £467 million (2009: £1,294 million) of cash and cash equivalents. 121% (2009: 148%) 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 10.5 years (2009: 9.6 years).
The relatively high level of undrawn committed bank borrowing facilities and available cash resources has enabled the Directors to conclude that the Group has sufficient headroom to continue as a going concern. The statement of going concern is included in the Directors' Report – Governance.
Maturities of derivative financial liabilities, trade and other payables, bank borrowings and provisions are provided in notes 22, 25, 26 and 28, respectively. Details of commitments and contingencies are provided in note 39.
5. Capital management
The Group funds its business using a combination of debt and shareholders' equity. The Group's capital employed was financed as follows:
|Current and non-current borrowings||4,036||4,680|
|Cash and cash equivalents||(467)||(1,294)|
|Current and non-current securities||(257)||(250)|
|Net debt (note 34b)||3,312||3,136|
The Group seeks to maintain an efficient capital structure with a balance of debt and equity. Debt levels are restricted to limit the risk of financial distress and, in particular, to maintain strong credit ratings. The Group's credit ratings are important in keeping the cost of debt down, in limiting collateral requirements in energy trading and hedging, and in ensuring the Group is an attractive counterparty to gas and power producers and to customers for longer term energy contracts. At 31 December 2010, the Group's long-term credit rating was A3 stable outlook for Moody's Investor Services Inc. and A– stable outlook for Standard & Poor's Rating Services. These ratings did not change during 2010.
The Group monitors its current and projected capital position on a regular basis, considering a medium-term view of three to five years, and different stress case scenarios, including the impact of changes in the Group's credit ratings and significant movements in commodity prices. A number of financial ratios are monitored, including those used by the credit rating agencies, such as debt to cash flow ratios and EBITDA (i) to gross interest expense. At 31 December 2010, the ratio of the Group's net debt to EBITDA was 1.0 (2009: 1.2). EBITDA to gross interest expense for the year ended 31 December 2010 was 6.7 (2009: 5.3).
The Group is not subject to externally-imposed capital requirements but, as is common for most companies, 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. This restriction can be amended or removed by the shareholders of the Company passing a special resolution. Based on adjusted capital and reserves as at 31 December 2010 of £5.8 billion, the limit for net debt was £17.4 billion.
The Group funds its debt principally through issuing bonds, denominated in pounds sterling, euros and US dollars. The Group also maintains substantial committed facilities from banks, but generally uses these to provide back up liquidity and does not typically draw on them.
- EBITDA is defined as earnings before interest, tax, depreciation, amortisation, and exceptional items and certain re-measurements from continuing operations.
6. Segmental analysis
Centrica's operating segments are those used internally by management to run the business and make decisions. Centrica's operating segments are based on products and services provided in each geographical area. The operating segments are also the Group's reportable segments. The types of products and services from which each reportable segment derives its revenues are:
|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|
|Upstream gas and oil||Production and processing of gas and oil and the development of new fields to grow reserves|
|Power generation||Generation and optimisation of power from gas, nuclear and wind sources|
|Industrial and commercial||Management, optimisation and scheduling of wholesale and industrial commodity sales, procurement and tolling contracts|
|Proprietary energy trading||Trading in physical and financial energy contracts|
|Storage UK||Gas storage in the UK|
|Residential energy supply||The supply of gas and electricity to residential customers in North America|
|Business energy supply||The supply of gas, electricity and energy-related services to business customers in North America|
|Residential and business services||Installation and maintenance of Heating, Ventilation and Air Conditioning (HVAC) equipment, water heaters and the provision of breakdown services in North America|
|Upstream and wholesale energy||Gas production, power generation and procurement and trading activities in the North American wholesale energy markets|
The measure of profit used by the Centrica Executive Committee is adjusted operating profit. Adjusted operating profit is operating profit before exceptional items and certain re-measurements (refer to note 9 ), before additional depreciation resulting from any fair value uplifts on Strategic Investments (refer to notes 2 and 14 ) and including the results from joint ventures and associates which are included before interest and tax. All transactions between segments are on an arm's length basis.
|Year ended 31 December||2010
|Gross segment revenue
|Less inter-segment revenue (i)
|Gross segment revenue
|Less inter-segment revenue (i)
|Residential energy supply (ii)||8,359||(4)||8,355||7,911||–||7,911|
|Residential services (ii)||1,464||–||1,464||1,338||–||1,338|
|Business energy supply and services||2,907||(1)||2,906||3,316||–||3,316|
|Upstream gas and oil||1,637||(773)||864||1,240||(689)||551|
|Industrial and commercial||2,017||(423)||1,594||1,907||(555)||1,352|
|Proprietary energy trading (iii)||17||(15)||2||52||(11)||41|
|Residential energy supply||2,502||–||2,502||2,644||–||2,644|
|Business energy supply||2,682||–||2,682||2,491||–||2,491|
|Residential and business services||485||–||485||406||–||406|
|Upstream and wholesale energy||328||(96)||232||656||(89)||567|
|European Energy (note 38)||590||–||590||2,357||–||2,357|
The Group operates in the following geographical areas:
|Year ended 31 December||Revenue
(based on location of customer)
|Trinidad and Tobago||15||–|
|Year ended 31 December|
(b) Operating profit
|2009 (restated) (i)
|Residential energy supply (i)||742||598|
|Residential services (i)||241||230|
|Business energy supply and services||233||183|
|Upstream gas and oil (ii)||581||444|
|Power generation (ii)||226||147|
|Industrial and commercial||(36)||(93)|
|Proprietary energy trading||–||27|
|Residential energy supply||177||94|
|Business energy supply||88||34|
|Residential and business services||15||18|
|Upstream and wholesale energy||(46)||7|
|Adjusted operating profit – segment operating profit before exceptional items, certain re-measurements and impact of fair value uplifts from Strategic Investments (iii)||2,390||1,857|
|Share of joint ventures/associates' interest and taxation||(78)||(11)|
|Depreciation of fair value uplifts to property, plant and equipment – Venture (ii)||(60)||(20)|
|Depreciation of fair value uplifts to property, plant and equipment (net of taxation) – associates – British Energy (ii)||(58)||(7)|
|Exceptional items (note 9)||(283)||(568)|
|Certain re-measurements included within gross profit (note 9)||1,177||(62)|
|Certain re-measurements of associates' energy contracts (net of taxation) (note 9)||(14)||(9)|
|Operating profit after exceptional items and certain re-measurements||3,074||1,175|
|European Energy (note 38) (v)||(5)||(8)|
|Year ended 31 December||Share of results of joint ventures and associates before interest and taxation||Depreciation and Impairments of property, plant and equipment (i)||Amortisation, write-downs and impairments of intangibles (restated) (v)|
(c) Included within adjusted operating profit
|Residential energy supply (ii), (v)||–||–||6||8||38||54|
|Business energy supply and services||–||–||2||2||7||7|
|Upstream gas and oil (i), (ii)||3||–||487||353||81||16|
|Power generation (i), (iii), (v)||140||28||120||112||1||4|
|Industrial and commercial||–||–||–||1||10||6|
|Proprietary energy trading||–||–||–||–||–||–|
|Residential energy supply||–||–||–||2||5||6|
|Business energy supply||–||–||1||1||4||3|
|Residential and business services||–||–||2||2||5||2|
|Upstream and wholesale energy (ii)||–||–||88||71||3||2|
|European Energy (note 38) (ii)||–||2||–||25||–||17|
|31 December||Net segment assets/(liabilities)
(restated) (ii), (iii), (vi), (vii)
|Average capital employed
Year ended 31 December
(d) Assets and liabilities
|Residential energy supply (ii), (vi)||27||(28)||195||187|
|Residential services (vi)||225||21||95||42|
|Business energy supply and services (ii)||516||445||552||502|
|Upstream gas and oil (iii)||2,691||2,355||1,245||499|
|Power generation(ii), (iii), (vii)||3,633||3,629||3,506||1,879|
|Industrial and commercial(ii), (iii)||128||–||(49)||285|
|Proprietary energy trading (iii), (iv)||119||573||(16)||(68)|
|Residential energy supply (iv)||731||790||709||808|
|Business energy supply (iv)||441||377||288||277|
|Residential and business services||400||268||323||270|
|Upstream and wholesale energy (vii)||784||638||659||594|
|Unallocated deferred tax assets (i)||233||723|
|Derivative financial instruments held for energy procurement including balances held by joint ventures and associates||(715)||(2,076)|
|Current tax liabilities (i)||(16)||(81)|
|Assets of discontinued operations (v), (vii)||87||60|
|Bank overdrafts and loans||(4,036)||(4,680)|
|Retirement benefit obligations||(239)||(565)|
|Corporate centre assets (viii)||143||1,142|
Capital employed represents the investment required to operate each of the Group's segments. Capital employed is used by the Group to calculate the return on capital employed for each of the Group's segments as part of the Group's managing for value concept. Additional value is created when the return on capital employed exceeds the cost of capital. Net segment assets of the Group can be reconciled to the Group's capital employed as follows:
|Net segment assets at 31 December||10,042||9,427|
|Margin call debtor (i)||(161)||(626)|
|Cash at bank, in transit and in hand excluding certain restricted cash||(117)||(92)|
|Effect of averaging month-end balances||(418)||(1,560)|
|Average capital employed for year ended 31 December||7,713||5,466|
|Year ended 31 December||Capital expenditure on property, plant and equipment (note 18)||Capital expenditure on intangible assets other than goodwill (note 16)|
(e) Capital expenditure
|Residential energy supply (i)||15||1||256||236|
|Business energy supply and services (i)||1||1||68||59|
|Upstream gas and oil||383||358||224||50|
|Power generation (i)||78||139||19||45|
|Industrial and commercial||4||4||15||16|
|Proprietary energy trading||–||–||–||–|
|Residential energy supply||–||–||2||6|
|Business energy supply||–||1||10||6|
|Residential and business services||2||1||5||–|
|Upstream and wholesale energy||20||52||10||2|
|Capital expenditure on continuing operations||558||654||653||464|
|Increase/(decrease) in prepayments related to capital expenditure||18||(2)||6||–|
|Unrealised gains on cash flow hedges transferred from reserves||–||4||–||–|
|Capitalised borrowing costs||(37)||(34)||–||–|
|Decrease/(increase) in trade payables related to capital expenditure||8||(28)||2||140|
|Net cash outflow||547||594||661||604|
The Group operates in the following geographical areas:
|31 December||Non-current assets
(based on location of assets) (ii)
|Trinidad and Tobago||319||5|
7. Costs of continuing operations
|Analysis of costs by nature||2010
|Transportation, distribution and metering costs||(3,627)||(3,503)|
|Commodity costs (i)||(11,295)||(12,036)|
|Depreciation, amortisation and write-downs||(770)||(590)|
|Other direct costs relating to the upstream businesses||(273)||(289)|
|Other direct costs relating to the downstream businesses||(1,065)||(753)|
|Total cost of sales before exceptional items and certain re-measurements||(17,595)||(17,663)|
|Exceptional items and certain re-measurements (note 9)||1,075||(455)|
|Total cost of sales||(16,520)||(18,118)|
|Depreciation, amortisation and write-downs||(224)||(155)|
|Exploration costs expensed||(7)||(28)|
|Impairment of trade receivables (note 21)||(269)||(354)|
|Foreign exchange gains/(losses)||1||(2)|
|Other costs associated with upstream businesses||(137)||(151)|
|Other costs associated with downstream businesses||(937)||(864)|
|Total operating costs before exceptional items and certain re-measurements||(2,641)||(2,496)|
|Exceptional items and certain re-measurements (note 9)||(181)||(175)|
|Total operating costs||(2,822)||(2,671)|
8. Directors and employees
|(a) Employee costs (i)||2010
|Wages and salaries||(1,345)||(1,223)|
|Social security costs||(115)||(103)|
|Other pension and retirement benefits costs||(134)||(77)|
|Share scheme costs||(48)||(38)|
|Capitalised employee costs||9||7|
|Employee costs recognised in the Group Income Statement||(1,633)||(1,434)|
|(b) Average number of employees during the year||2010
|Other operations (i), (ii)||327||1,302|
|Rest of World (ii)||8||994|
9. Exceptional items and certain re-measurements
|(a) Exceptional items for the year ended 31 December||2010
|Provision for UK onerous gas procurement contract||(35)||(199)|
|Termination of a UK energy sales contract||–||(139)|
|Provision for North American wind power purchase agreements||(67)||(55)|
|Exceptional items from continuing operations included within gross profit||(102)||(393)|
|Impairment of UK generation, exploration and production assets (i)||(96)||(79)|
|Impairment of North American assets||(67)||(70)|
|UK contract re-negotiation and restructuring costs (ii)||(43)||(75)|
|Profit on disposal of investments (iii)||25||49|
|Exceptional items from continuing operations included within Group operating profit||(283)||(568)|
|Taxation on exceptional items (note 11)||118||186|
|Net exceptional items from continuing operations after taxation||(165)||(382)|
|Impairment of Oxxio B.V. goodwill and other assets, provisions and write-offs after taxation||–||(24)|
|Profit on disposal of Segebel S.A. after taxation||–||297|
|Total exceptional items after taxation||(165)||(109)|
|(b) Certain re-measurements for the year ended 31 December||2010
|Certain re-measurements recognised in relation to energy contracts:|
|Net gains arising on delivery of contracts (iv)||1,023||928|
|Net gains/(losses) arising on market price movements and new contracts (v)||130||(1,097)|
|Net gains/(losses) arising on positions in relation to cross-border transportation or capacity contracts (vi)||24||(28)|
|Reversal of certain re-measurements in relation to the termination of energy sales contracts||–||135|
|Net re-measurements from continuing operations included within gross profit||1,177||(62)|
|Net losses arising on re-measurement of associates' energy contracts (net of taxation) (vii)||(14)||(9)|
|Net re-measurements included within Group operating profit||1,163||(71)|
|Taxation on certain re-measurements (note 11)||(339)||(1)|
|Net re-measurements from continuing operations after taxation||824||(72)|
|Net re-measurements on energy contracts of discontinued operations after taxation (note 38)||67||(107)|
|Total re-measurements after taxation||891||(179)|
10. Net interest
Cost of servicing net debt
|Interest expense on bonds, bank loans and overdrafts (i)||(284)||–||(284)||(253)||–||(253)|
|Interest expense on finance leases||(21)||–||(21)||(22)||–||(22)|
|(Losses)/gains on revaluation|
|(Losses)/gains on fair value hedges||(47)||47||–||(41)||43||2|
|Fair value (losses)/gains on other derivatives (i),(ii)||(121)||9||(112)||(52)||175||123|
|Fair value gains on other securities measured at fair value||–||10||10||–||3||3|
|Net foreign exchange translation of monetary assets and liabilities (iii)||–||85||85||(128)||–||(128)|
|Notional interest arising on discounted items||(43)||30||(13)||(24)||29||5|
|Interest on cash collateral balances||–||1||1||–||4||4|
|Interest on supplier early payment arrangements||–||2||2||–||5||5|
|Capitalised borrowing costs (iv)||37||–||37||34||–||34|