3. Supply Chain Issues
3.2. Energy Cost Components
Business customers’ charges for electricity and gas consist of a number of cost elements reflecting the separate functions involved from producing the energy to delivering it to its point of use. These different cost components can be
categorised into three broad areas: • the cost of the energy;
• the cost of delivering the energy to the customer and associated metering; and
• applicable duties, taxes or similar.
The cost of the energy encompasses the wholesale cost of the power, as well as suppliers’ fees for balancing, risk and margin. Whilst competition has been introduced into the generation / production and supply sides of the energy markets, the costs associated with transporting and delivering it remain regulated. Ofgem regulates these charges, generally through five-year price control cycles. In recent years, the government has also introduced a number of new environment-related levies and policies, which have added to business customers’ energy costs.
The following paragraphs outline the cost chain for each fuel in more detail.
3.2.1. Electricity
Figure 3:1 illustrates, in simplified form, financial and physical flows in the business electricity market. The solid arrows highlight physical flows of power from generator to meter and the dashed arrows show financial flows. It is worth noting that, given the integrated nature of the physical infrastructure, and given the power flows do not follow contractual paths, it is not possible to trace actual power flows from a particular power station to an individual customer.
Both the generation and supply markets are open to competition and
customers secure their physical supplies of electricity from a licensed supplier. The operating licences set out conditions that must be followed in conducting business. Amongst the obligations borne by suppliers is a requirement to abide by the terms of the BSC.
Figure 3:1: Physical and Financial Flows Embodied in Customer Bills
Green denotes regulated cost elements
Yellow denotes competitive cost elements Source: Cornwall Consulting research
Suppliers have a range of options in sourcing their power requirements. They can purchase, for example, from a generator, from another supplier, or from the power exchange (these issues are discussed further in Section 4). It is also possible for customers to become signatories to the BSC. In return for accepting the associated compliance costs, they are able to access financial and physical market participants directly, without the need for a licensed supplier to act as an intermediary.
The vast majority of customers who draw power from the public network contract with a licensed supplier for their requirements. Their bills are based on charges that the supplier passes on to the customer, including:
• the wholesale cost of the electricity;
• the supplier’s margin and administration / management costs to cover
elements such as balancing risk and billing;
• the cost of delivering the electricity, consisting of regulated charges which typically comprise:
o transmission network use of system charges (TNUoS),
o distribution use of system charges (DUoS), and
o losses incurred in delivering the power across the transmission
and distribution networks;
• metering and data charges; and
G e n e r a t o r D a t a / M e t e r i n g S u p p l i e r D i s t r i b u t i o n T r a d e r T r a n s m i s s i o n C u s t o m e r G e n e r a t o r G e n e r a t o r D a t a / M e t e r i n g D a t a / M e t e r i n g S u p p l i e r S u p p l i e r D i s t r i b u t i o n D i s t r i b u t i o n T r a d e r T r a d e r T r a n s m i s s i o n T r a n s m i s s i o n C u s t o m e r C u s t o m e r
• obligations, taxes and levies.
The exact level of prices will depend on the interaction of these different factors, and an assessment of their relative importance is provided in Section 3.3. During the mid 1990s, tighter price controls cut regulated transmission and distribution charges. More recently, new environmental levies and obligations have combined with higher wholesale prices to force delivered electricity prices very sharply higher.
There is a very wide range of ways in which suppliers present their offer prices to customers. They range from single rate and standard time of day tariff structures, similar to those used in the household sector, to very complex
arrangements where the energy element of prices is directly indexed to rates in the wholesale market. More detailed consideration is given to each element of the cost chain below.
3.2.1.1. Wholesale Costs
The wholesale cost in the price to an individual customer is usually driven by that user’s load profile. It can be thought of as the cost for generating electricity to its requirements at a power station. Generally speaking, in business
customers’ supply contracts where the individual cost components are billed separately, the wholesale cost of power also includes the generator’s, and often also the supplier’s, share of transmission losses, as well as BSUoS charges.
Forward curves are extremely important in supplier pricing, because they reflect the current wholesale price of a good. Independent suppliers must buy at their rates, and integrated suppliers tend to use them for transfer cost allocation. This is at the root of the argument which is advanced from time to time that a supplier selling at prices below the current curve will lose money, even if the market price exceeds production costs. Forward curves are used for ‘marking to market’, a discipline used by traders to value their open positions at prevailing market prices. Valuing the portfolio every day will show daily changes in its value and thus whether the trader is making money or not.
3.2.1.2. Supplier Margin
Suppliers charge a margin to cover factors including their risk exposure to balancing costs, customer acquisition and associated marketing costs,
administration / management costs in servicing the account, and their profit. Margin levels can vary significantly, and a particular factor in determining them on an individual level is the supplier’s assessment of the customer’s credit
standing, including the risk they face of possible late or non-payment. In extreme cases, suppliers may choose not to offer terms.
A further factor is the value of accurate demand forecasting in avoiding costs of uncontracted energy and balancing. Customers who are aware of this, and who have a good working knowledge of their consumption profile, can help suppliers, particularly potential new providers, reduce their exposure to such risks, and thus see a direct cost benefit in their prices. Not surprisingly, load profile issues become more significant the larger the purchase volume. Increasingly, suppliers are asking for forward notification from larger half- hourly metered customers of substantive changes in their usage patterns, for example, for a shift change or the introduction of a new production line, including this requirement in their standard terms and conditions of supply.
3.2.1.3. Delivery Charges
Ofgem regulates transmission network use of system and distribution use of system charges, typically through five-year price controls.
Transmission Network Use of System Charges (TNUoS)
NGT owns and operates the high voltage transmission system in England and Wales. In Scotland, Scottish Power Transmission Limited (SPTL) and Scottish Hydro Electric Transmission Limited (SHETL) own and operate the transmission systems in their respective regions. Under BETTA, it is intended that the
operation of the Scotland and England and Wales systems will be merged under the responsibility of NGT. Figure 3:2 provides an overview of the electricity supply infrastructure in Great Britain.
Business customers are charged indirectly via their suppliers for their deemed usage of the transmission network. These charges reflect broad power inputs to, and outputs from, the grid. The vast majority of electricity flows through the transmission system from the generating station to the local distribution network (although there are a handful of extremely large customers directly connected to the transmission network). Charges are levied by NGT, and by the two Scottish transmission network owners SPTL and SHETL.
Figure 3:2: Overview of the Electricity Supply Infrastructure in Great Britain
Two TNUoS charging methodologies are currently applied to suppliers in
England and Wales by NGT and approved by Ofgem26, one for half hourly
metered customers and the other for non-half hourly metered customers. The charges are revised annually, normally from 1 April.27 From 1 April 2005 and the
introduction of BETTA, a consistent transmission charging methodology is expected to be applied across Great Britain.
Half hourly metered customers are charged for their use of the transmission system using the ‘triad’ methodology. Regional £ per kW charges are set for each of the 12 demand zones, which align with Grid Supply Point (GSP) groups, in England and Wales. This £ per kW charge (inflated by the peak distribution loss factor) is applied to the customer’s average maximum demand at the times of the three highest periods (half hours) of demand on the national transmission system – the triad. These three periods must be separated by at least ten days, and
normally occur between the start of November and the end of February on weekday early evenings. Typically, customers are billed on a monthly basis through the year for their TNUoS charges, based on an assessment of their
expected triad charges (usually using historic data). Reconciliation of the account then takes place when actual triad times are known, usually on the March bill. A similar charging methodology is used by the two Scottish companies.
Non-half hourly metered customers in England and Wales are charged for their use of the transmission system on the basis of their consumption. Pence per kWh charges are set, again based on the demand zones, and are applied to the customer’s consumption during the peak demand afternoon period between 16.00 and 19.00 hours during the year.
Distribution Use of System Charges (DUoS)
Distribution use of system charges are applied to cover the costs of moving power from the national transmission system to the customer’s meter through the local distribution networks. Charges for each of the 14 distribution network regions in Great Britain are again regulated by Ofgem28. Distribution tariffs vary
regionally, and also according to the voltage level at which the customer is connected. Charges for customers at extra high voltage (typically defined as at voltages of 33kV and above) are usually set on a site-specific basis and, until recently, were not remunerated under the distribution regulatory price control. The structure of DUoS charges varies according to the metering configuration at the site. Typically, DUoS charges consist of a standing charge and a consumption
26 Ofgem approves the underlying principles rather than the detailed tariffs.
27 Additionally connection charges are applicable, though those are levied in the first instance on the physical connected party, typically the local distributor.
charge. The consumption charge may consist of several unit rates, especially for sites where metering records data are for more than one time block.
System Losses
Customers are charged for the thermal losses that occur as power is moved across both the national transmission and the local distribution networks. These system losses are charged through assessed loss factors. Transmission losses average 1.5%29 to all volumes injected onto, or taken off, the transmission system,
and their costs are split between the generation and supply sectors on a ratio of 45:55. NGT is also subject to an incentive scheme whereby it can keep a share of the savings if it beats an annual target set by the regulator.
Distribution loss assessments are published annually by the distribution network operators and are percentage factors which vary by time of day and connection voltage. Distribution losses average around 7%, although they can be as high as 20%. A customer’s metered energy consumption is inflated by these loss factors by suppliers in their price setting and billing processes.
3.2.1.4. Obligations, Levies and Taxes
Since 2001, as part of the Climate Change Programme, the government has introduced the Climate Change Levy and the Renewables Obligation, both of which impact business customers’ electricity bills.30 The general thrust of these
policy measures is to raise prices to encourage investment by renewable producers and make customers become more energy efficient.
Climate Change Levy (CCL)
The CCL is a tax applied to the business use of energy, and was implemented from 1st April 2001. It is designed to be revenue neutral to business in that the revenue it raises is offset by lower employers’ National Insurance Contribution. HM Customs and Excise administers the CCL, although it is collected by
suppliers as part of customers’ energy bills. A flat rate tax of 0.43 p/kWh for electricity, and 0.15 p/kWh for gas, is applied to the customer’s consumption. Not all business customers pay the full rate of the CCL. A complex range of relief mechanisms has been established to encourage better climate change
29 Peak losses are higher, at about 1.8%. 30 A Fossil Fuel Levy was introduced in 1990.
management by industry and tone down international competitiveness impacts. An important example of such a mechanism is the programme of Climate
Change Agreements, administered by DEFRA, under which relief of up to 80% from the CCL is granted in return for users signing onto energy management improvement contracts. The level of the CCL is subject to review as part of the government’s annual Budget process and, thus far, has been held constant since its introduction. Another example of available relief is the exemption from the CCL for gas used to fuel ‘good quality’ combined heat and power plant in industrial and commercial applications.
Renewables Obligation (RO)
Under the terms of the RO, suppliers are obliged to buy a certain amount of the electricity they sell on to customers from qualifying renewable power sources. These generators earn Renewable Obligation Certificates (ROCs) proportionate to their output which they can trade. ROCs have a nominal value of £30/MWh (3 p/kWh), indexed to 2002-03 levels. Suppliers face a financial penalty if they fail to secure sufficient ROCs to meet their RO targets.
In its first year in England and Wales (April 2002 to March 2003 inclusive), the RO cost to customers was the equivalent of 0.09p/kWh, based on a 3% target for suppliers. In 2003-04, the obligation had risen to 4.3% and the cost was
equivalent to 0.13 p/kWh. In the current year (April 2004 to March 2005
inclusive), the typical cost is expected to be 0.15p/kWh, based on a 4.9% target. Over time, the level of the obligation is set to increase further. Ascending targets have already been set to 2015.
The costs of the RO are accounted for in different ways in business customers’ bills. Suppliers endeavour to pass on to customers their costs in meeting the RO, although there is no legal obligation on them to do so.
Value Added Tax (VAT)
VAT is levied at the standard rate of 17.5% with limited exceptions, the most notable of which is the 5% rate levied on premises used for domestic purposes but which are owned by business organisations.
3.2.1.5. Metering and Data Charges
Customers must pay for the charges associated with the functions of metering and data services. These services encompass the measurement of energy
consumed and the collection and settlement of that data at industry level to enable balancing and settlement, and calculation of use of system charges.
Larger customers must have half hourly metering installed. For smaller users, half hourly metering is an option. New rules, effective from 1 December 2004, refine the previous half hourly requirement from a site to a meter system basis. From that date, the requirement for half hourly metering will be based on
exceeding 100kW average demand in the three months of highest demand in the previous 12 months, or where the profile implies, or where there is a major change that obviously requires half hour metering. In addition, there will be a choice of either half hour or non-half hour settlement where metering systems no longer qualify as mandatory half hourly (a change of meter is not necessary). Customers should have more flexibility over the circumstances where they are required to install meters. Half hourly metered customers must also ensure that they have the appropriate communications in place to enable the daily
downloading of data. Customers in this sector of the market have the ability to appoint their service providers directly.
Smaller customers tend not to have half hourly metering and their
requirements are settled according to one of six standard industry profiles for the business energy market, as shown in Table 3:1. Non-half hourly metered
customers must also have meter operator, data collection and data aggregation arrangements in place, but these are normally provided by the supplier as part of the supply contract. Consequently, in the non-half hourly metered market, charges for these services tend to be included within the energy supply charges, rather than separately paid for.
Table 3:1: Profile Types for Non-half Hourly Metered Business Customers Profile
Class
Profile Name
03 Non domestic unrestricted
04 Non domestic Economy 7
05 Non domestic Maximum Demand with load factor less than 20%
06 Non domestic Maximum Demand with load factor greater than 20% and
less than 30%
07 Non domestic Maximum Demand with load factor greater than 30% and
less than 40%
08 Non domestic Maximum Demand with load factor greater than 40%
Source: Ofgem’s Strategy for Metering – A Consultation Paper, March 2001
3.2.2. Gas
Figure 3:3 shows the key flows in the gas supply market. The solid arrows show physical flows of gas and the dashed arrows the financial flows.
Both the wholesale and supply markets are open to competition, but customers must purchase their gas from a licensed supplier or shipper.
Suppliers must purchase their gas from shippers (operators licensed by Ofgem to transport gas on Transco’s network). Shippers have a range of options in
sourcing their gas requirements, for example, from a producer, from another shipper, or from the traded market. Shippers own the gas whilst it is in transportation, and it is they who have the responsibility for daily network balancing.
Figure 3:3: Supply Chain for the Business Gas Markets - Physical and Financial Flows
Green denotes regulated cost elements
Yellow denotes competitive cost elements
Many suppliers are also shippers, but there is no requirement to hold a supplier licence, in order to deal with business customers (from now on, the term
supplier is used to describe both gas suppliers and shippers). Charges for using the
national and regional gas transportation networks are regulated by Ofgem. Metering services are open to competition. The Climate Change Levy also applies to business users of gas.
Customers contract with suppliers for their gas requirements. The charges that suppliers pass on to their customers include:
• wholesale costs;
• supply margin and administration / management costs to cover elements
such as swing (measure of the ratio between daily maximum and average flow), credit, billing and profit;
• transportation charges, to cover the movement of the gas over the
transportation networks to the customer’s meter, with costs for use of the:
o national transmission system; and
o local distribution networks;
• metering; and
• taxes and levies.
M e t e r i n g P r o d u c e r S u p p l i e r T r a d e r T r a n s p o r t a t i o n C u s t o m e r S h i p p e r M e t e r i n g P r o d u c e r P r o d u c e r S u p p l i e r S u p p l i e r T r a d e r T r a d e r T r a n s p o r t a t i o n T r a n s p o r t a t i o n C u s t o m e r C u s t o m e r S h i p p e r S h i p p e r
More detail on each is provided below and an assessment of their relative importance is provided in Section 3.3.
3.2.2.1. Wholesale Costs
The operation of the wholesale market for gas is competitive. A customer’s wholesale gas cost is determined by its load profile, and represents the cost of the gas at a notional National Balancing Point (NBP).
3.2.2.2. Supplier Margin
Suppliers add a margin onto the wholesale cost of gas to cover their risk exposure to changes in load and balancing costs. This element can be described as swing, which is a measure of the ratio between daily maximum and average