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Third Party Licence Exempt Distribution Guidance Note

v 8.0

Third Party Access to Licence Exempt Distribution Networks

Guidance Note

1. Background

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 for more help and assistance.

1.2 Terminology

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:

    • Boundary Point Supplier: the Supplier with responsibility for flows of electricity from (or to) the licenced distribution network. This Supplier is usually appointed by the private network owner;

    • Boundary Point Meter: a BSC Code of Practice (CoP) compliant Metering System located at the Boundary Point;

    • Third Party Supplier: a Supplier appointed by a customer on the private network;

    • Third Party Meter: a Settlement Meter installed for the customer on the private network; and

    • Non Settlement Meter: a meter that is not registered for Settlement purposes.

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.

2. BSC Arrangements

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

How is this implemented?

BSCP5021 (section 4.9.3) and the Retail Energy Code (REC) Metering Operations Schedule 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.

What about Exports?

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 BSCP5502 , 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 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:

    • Capable of providing half hourly data; and

    • Recording the same Measurement Quantity as the Settlement Meter at the Boundary Point.

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.

Supplier A

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 L3.2 requires that all Metering Equipment either:

    • Complies with the requirements set out in the relevant CoP at the time of the Metering System’s first registration for Settlement; or

    • Is the subject of, and complies with, a Metering Dispensation.

BSC Section L3.4 makes provision for the BSC Panel to establish (or the Registrant of a Metering System, or prior to the appointment of a Registrant of the Metering System BSCCo, 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.

The process for applying for a Metering Dispensation is set out in BSCP32: Metering Dispensations.

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.

For further information on D/380 and the required treatment of losses, please see the D380 Metering Dispensation guidance.

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.

5.1 5.1 LDSO UoS

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:

    • Capacity charging

    • Excess capacity charging

    • Demand and excess demand charging

    • Excessive reactive power charging

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.

Further information can be found within Ofgem’s guidance on Third Party Access charges for licence exempt gas and electricity distribution networks.

Elexon advise that participants refer to the appropriate private network use of system charging methodology or contact the private network owner.

Summary for Difference Metering option

complex image of process

* 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.

Summary for Shared Metering option

complex image of process

Need more information?

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:

For more information please contact the BSC Service Desk at or call 0370 0106950.

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1‘Half Hourly Data Collection for SVA Metering Systems Registered in SMRS’.

2Shared SVA Meter Arrangement of Half Hourly Import and Export Active Energy’.