Third Party Access to Licence Exempt Distribution Networks |
Guidance Note |
1.1 Regulation Change & Supporting Documents
The Electricity and Gas (Internal Markets) Regulations 2011 (
Statutory Instrument (SI) 2011 No. 2704) introduced new obligations on owners of private distribution networks including a duty to facilitate Third
Party Access to
electricity and gas suppliers for customers within those networks. The Regulations set out separate obligations for private network owners and
Suppliers. Third party access gives
electricity and gas customers the right to choose
electricity and gas suppliers. Since the introduction of the regulations, certain customers that are not directly connected to a licensed distribution network (subject to certain exemptions) are entitled to request a
MSID so that they can trade
electricity with any participating
Suppliers.
This guidance focuses on the Balancing and
Settlement Code (BSC) obligations and processes associated with facilitating Third
Party Access for
electricity customers within private distribution networks that are connected to
Licenced
Distribution Systems. Some topics associated with the Third
Party Access arrangements fall outside of the scope of the BSC but for completeness, these are considered at a high level. For Third
Party Access guidance on private networks that are directly connected to the
Transmission System, it is necessary to assess these on a case-by-case basis due to their general complexity. Therefore, please contact ELEXON on email
metering@elexon.co.uk for more help and assistance.
We use the term ‘Third Party Access’ to collectively describe the above processes. This guidance also uses the following terms in the context of Third Party Access:
Third Party Access Third Party Access is the term used when a customer is embedded in a private network, has a Metering System ID (MSID) registered in the Supplier Meter Registration Service (SMRS) and has their electricity supplied by a Supplier of their choice. |
Third Party Access can be facilitated under the BSC in three ways as described in sections 2.1, 2.2 and 2.3 below.
2.1 2.1. Difference Metering option
The supply to the private network requires a Supplier and an appropriate Metering System and these are referred to as a Boundary Point Supplier and Boundary Point Meters. The energy recorded by the Boundary Point Meters will naturally include the consumption of all customers ‘downstream’ within the private network.
Prior to the regulation changes discussed in 1 above, ‘downstream’ customers would have arrangements in place with the private network owner (landlord) to purchase their electricity. However if one or more of these customers takes up the opportunity of a third party supply, then it is necessary to deduct those volumes from the main Boundary Point Meters otherwise the Boundary Point Suppliers and therefore its customers’ energy volumes will be incorrect. In order to establish the correct volumes, the Meter readings of the downstream customers (those with MSIDs) must be deducted (or ‘differenced’) from the Boundary Point Meter to avoid double-counting the metered volume in Settlement.
This arrangement is known as Difference Metering. The approach will be applicable whenever one or more customers on the private network have a half hourly Settlement Meter with a Supplier of their choice; thus requiring the deduction of the consumption through the Third Party Meter(s) from the Boundary Point Meter. Note that in the Difference Metering scenario all Settlement Metering Systems must be Half Hourly Metering Systems. The deduction of consumption through the Third Party Meter(s) from the Boundary Point Meter cannot be achieved with Non Half Hour data unless every customer on the private network has opted for third party supply; this is discussed further in section 2.2. below.
The following diagram, figure 1, illustrates the need for a differenced metering arrangement. Without any differencing the Boundary Point Meter (recording the landlord’s consumption) may record 125kWh, however 25kWh have been provided by Supplier B. Therefore, the landlord should be attributed with only (125-25) 100kWh, which it will distribute to its customers based on their (non-Settlement) meters.
Figure 1: A simple Difference Metering arrangement
BSCP514 (section 8.4.3) recognises this approach as a complex site, which allows a differencing algorithm to be implemented in
Settlement. In addition, and because it is not possible to physically locate Third
Party Meters at the point at which the private network connects to the Licensed
Distribution System as required under the BSC, it is necessary to have a
Metering Dispensation in place. This process is considered in more detail in section 3 below.
It should be noted that the embedded customers are assigned Meter Time Switch Class (MTC) 997 by virtue of a Metering Dispensation, which has been reserved to help Suppliers identify customers that are embedded within a private network arrangement.
In some cases, were for example the embedded customer has a generator, it may be necessary to consider Export volumes as well as Import volume in a differencing arrangement. A separate differencing algorithm will be provided to cater for Export volumes however, care must be taken to ensure that the difference algorithm works under all circumstances. This is particularly relevant where there is additional generating equipment elsewhere on the private network or within another customer’s installation.
How are losses accounted for in the Difference Metering option?
In order for the differencing arrangement to work properly in Settlement, it is necessary to account for the electrical losses of the private network between the Third Party Meter/s and the Boundary Point Meter/s. This is so the Boundary Point Supplier is not left with the responsibility for the losses within the private network. Therefore, using the above example, a difference algorithm might be 125kWh – (25kWh + 2%). This leaves 99.50kWh with Supplier A and 25kWh with Supplier B.
The losses in this example are 2% of Supplier B’s Meter/s. How this 2% is allocated will depend on the charging methodology of the private network for the use of its system. For example, the private network can choose not apply any charges and therefore be willing to pick up the costs for the losses within its system. In that case the 2% loss is added to Supplier A’s Meter/s. Alternatively the private network may choose to pass its use of system costs to Supplier B as part of their use of system charges. Either way losses must be properly attributed in line with the private network’s use of system charging regime.
Should reactive energy be differenced?
Reactive energy is a component part of the total power flow through an Exit or Entry Point, be that the Boundary Metering Point or any embedded Metering Point inside the private network.
The treatment of reactive energy in LDSOs UoS charges is covered in more details below in section 5.
Differencing is carried out for the Boundary Point’s Active Energy Import/Export based on the sum of all the customer’s Active Energy Import/Export.
However there currently exists no requirement in the BSC to conduct the exact same differencing method upon reactive energy measurements from the Boundary Metering Point so as to avoid the broad duplication of reactive energy measurements across the Boundary and all Embedded Metering Point reactive energy measurements.
Differencing of reactive energy would leave a more commercial and technically correct net balance of reactive energy measurements for the Boundary Point reflecting reactive energy usage within the private network.
0.1 2.2. Full Settlement option
If every customer on a private network has opted for third party supply then the arrangements are considered to be a full Settlement option.
This is where every customer on a private network is to have or has a Supplier. In this case every customer will have its own MSID and Metering System. In this case, there are no Metering Systems at the interface between the Licensed Distribution System and the private network. The BSC refers to the private network in these circumstances as an ‘Associated Distribution System’.
The Full Settlement option enables both Half Hourly and non-Half Hourly Meters to be used for Third Party Supply. As each customer has its own MSID and Metering System there is no need to subtract this metering data from the Boundary Point.
How are losses accounted for in the Full Settlement option?
Because these sites are treated in the same way as, any other site connected to the Total System they are subject to the normal LDSO UoS charges. There are no special arrangements for Third Party Access and the losses within the private network are considered by the LDSO as part of their network.
0.1 2.3. Shared Metering option
Under the BSC, it is possible for multiple
Suppliers to share a
Metering System. There are a number of reasons that this may be desirable and one such arrangement can be used for Third
Party Access. The processes are set out in
BSCP550 , which describes the processes and responsibilities involved where two, or more
Suppliers receive
Active Energy through the same
Shared SVA Metering System.
For the purpose of a Third
Party Access scenario, the Shared
Metering option is described in section 4.2.5.1 of
BSCP550. Two
Suppliers may establish a Shared SVA
Metering Arrangement in which
Active Import and/or
Active Export Meter readings (recorded at the
Settlement Boundary Point) are apportioned between
Suppliers based on the meter readings from non-
Settlement Meters on a private network.
For the Shared Metering option the non-Settlement Metering Equipment must be:
BSCP550 defines ‘unaccounted for’
Active Energy as the difference between the
Boundary Point Meter reading and the total of the non-
Settlement Meter readings. The method by which ‘unaccounted for’
Active Energy is apportioned must be agreed by all
Suppliers. The agreed method must also take into account any limitations of the Half Hour
Data Collector’s (HHDCs) systems and processes.
Figure 2 details an example where ‘unaccounted for’ Active Energy is to be allocated in proportion to the non-Settlement Meter readings (M1 and M2), M3 being the Boundary Point Meter.
Figure 2: shared SVA Meter arrangement with non-Settlement sub-Meters
In the above figure 2 an example is presented where M3 represents the Boundary Point Meter.
M1 and M2 represent non-Settlement Meters for consumption supplied by separate Suppliers, Supplier A and Supplier B respectively. In this scenario the Suppliers may wish to apportion ‘unaccounted for’ Active Energy in proportion to the non-Settlement Meter readings. The HHDC therefore determines the allocation (Allocation Schedule) of M3 as:
Active Import Meter reading for Supplier A = M3 x M1 / (M1 + M2)
Active Import Meter reading for Supplier B = M3 x M2 / (M1 + M2)
This ensures that all of the electrical losses on the private network (and any metering errors in the non-Settlement Meters) are allocated between the two Suppliers at the site.
In a Shared Metering Arrangement the non-Settlement Meters are used to apportion the volumes of the Settlement Meter to, in this example, Supplier A and Supplier B.
For further examples of
Allocation Schedules and rules, please see
BSCP550.
How are losses accounted for in the Shared Metering option?
The electrical losses of the private network are, in effect, transparent in this arrangement. This is because the Meter readings of the Boundary Point Meter/s (which include the losses of the private network) are attributed to the various Suppliers based on the ratio of the non-Settlement meters downstream.
Is reactive energy accounted for?
As with the differencing arrangement described in section 2.1 above the reactive energy readings of the Boundary Point Meter/s is the sum of the reactive components of the customers downstream as well as the effect of the network itself. Depending on the UoS charging methodology of the LDSO’s any reactive charges are likely to be based on the Boundary Point Meter readings.
3. Difference Metering & Metering Dispensations
3.1 What is a Metering Dispensation?
BSC Section L3.4 makes provision for the BSC
Panel to establish (or the
Registrant of a
Metering System to apply for) a
Metering Dispensation if, for financial or practical reasons,
Metering Equipment will not or does not comply with some or all the requirements of a CoP.
CoP requirements CoPs 1, 2, 3 and 5 Section 4.3.3 ‘Compensation for Power Transformer and Line Losses’ state that: ‘where the Actual Metering Point (AMP) and the Defined Metering Point (DMP) do not coincide a Metering Dispensation shall be applied for and, where necessary, accuracy compensation for power transformer and/or line losses shall be provided to meet the overall accuracy at the Defined Metering Point’. |
Why is a Metering Dispensation needed?
The BSC CoPs describe the Defined Metering Point (DMP) location as being the point where the customer connects to the Licensed Distribution Network. However, the Meters of customers who are ‘downstream’ within a private network will be located at the point of connection to the private network. This means that it is not practical to comply with the relevant CoP in these circumstances. A Metering Dispensation is therefore required to allow this departure from the CoP requirement.
To assist with this process ELEXON has established a generic type of Metering Dispensation D/380 which is described in more detail below.
4. D/380 Generic Metering Dispensation for Third Party Access
A Generic Metering Dispensation D/380 was approved for use in September 2012 and is relevant for Metering Systems for CoP5 or CoP3. D/380 applies to Registrants (Suppliers) whose customers are embedded within a Licence Exempt Distribution Network (private network) and are seeking competitive supply. Providing that the only departure from the CoP requirements is the location of the Metering Equipment, and that the other conditions associated with the Generic Dispensation are met, these Suppliers can then proceed with the arrangements without the need to apply for a Site-Specific Metering Dispensation. In all other respects the Metering Equipment must comply with the relevant CoP(s).
Note that the Generic Dispensation only relates to the location of the Meter, and that Site-Specific Dispensations will still be required where there are other CoP non-compliances. There are also certain specific conditions attached to use of the Generic Dispensation.
5. Distribution Use of System Charges
For completeness we have included a brief explanation of distribution Use of System (UoS) charges in this guidance. However, UoS charging is not covered by the BSC and so the sections below are for information only. The reader is directed to contact the relevant LDSO and/or private network owner for further clarification.
Distribution charges are designed to recover the costs incurred on the network from the distribution of energy from the Transmission Network to the Boundary Point, and is charged by the LDSO. The private network owner may also apply charges in order to recover the costs incurred on the network from the Boundary Point to the consumer; this charge is calculated and billed separately from those of the LDSO UoS charges.
Each LDSO determines its UoS charging methodology separately and is approved by Ofgem.
All LDSOs publish their approved UoS charging methodologies on their websites.
Although different, all LDSO UoS charges are likely to include sections dedicated to TPA where, in most cases, UoS charges are based on Boundary Point Meter gross volumes. However, there are other methods depending on the distribution area and these must be confirmed directly with the LDSO in question.
LDSO UoS charges will include, but are not limited to:
5.2 5.2 Private network UoS
As with the LDSOs, a private network owner who charges UoS must have an Ofgem approved use of system charging methodology.
However, a private network owner may choose whether or not it imposes UoS charging. If the private network owner decides not to charge for UoS it does not need approval from Ofgem.
Elexon advise that participants refer to the appropriate private network use of system charging methodology or contact the private network owner.
S ummary for Difference Metering option
* It may be necessary for the MOA to visit site prior to accepting an appointment to understand the existing metering arrangements of the Third Party customer.
** Reactive data differencing or mapping will not be required.
S ummary for Shared Metering option
If you require further information about the use of Generic Dispensation D/380 or the interaction between the Third Party Access arrangements and Settlement, please contact:
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