Introduction to electricity metering and settlement

To be able to balance the needs of producers and consumers of electricity, accurate systems need to be in place to measure each party's generation or consumption volumes. The data outputs of these metering systems feed robust central processes that ensure that parties are properly recompensed for energy generated or consumed. These processes capture corrections to data, with reconciliation payments being periodically calculated after the event. This study discusses the principles of energy measurement, how metered volumes are submitted into settlement and an overview of how the settlement process works.

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Sep 11, 2017
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Author(s): Iain David Nicoll and Elliott David Hall


Any system of measurement has to be robust and accurate to give party's confidence in the data output by it. In measurement of electricity this needs to be in terms of both the assets making up the metering system and the governance and systems in place to use those measurements. In a typical year £1.5 billion of customer funds are invoiced.

Any metering system must be accurate; the level of accuracy is based on the cost of measurement and the materiality of any inaccuracy. The requirements of any governing documents take these into account.

The balancing and settlement code (BSC) [1] is an industry code and is administrated by ELEXON Limited. The BSC defines the rules and processes that any party must adhere to including those engaged in metering and settlement.

The BSC has subsidiary documents which specify the accuracy requirements of the component parts of the metering system. These documents are the metering codes of practice (CoPs) [2] and have different requirements based on the rated capacity or demand of the circuit to be metered.

At any given point in time, no one has a complete picture of all the electricity that is being generated, consumed or lost over the network (due to resistance in the network). Furthermore, issues with meter data collection, incorrect meter configurations or disputes between parties can mean that data is not right first time. The activity of settlement involves reviewing data periodically after the event, taking into account any corrections in data and calculating reconciliation billing for parties across the industry. Settlement calculations are performed for 30 min blocks called settlement periods. There are 48 of these in each day; the exception being the two days each year with clock changes, where there are 46 or 50 settlement periods.

This paper provides an introduction to electricity metering and settlement.


The principle method of measurement in meters is to measure separately the incoming voltage and current. Solid-state meters use sampling methods to measure the current and voltage a number of times per cycle and determine the phase angle between the voltage and current waveforms (Fig 1).

Fig 1: Sampling of current and voltage waveforms

The formula to determine watts from the current, voltage and phase angle can be seen in (1) for a single-phase meter


This formula gives summated watts and this has to take account of time to convert to watt hours that is used for settlement. The sampling rate of the meter over a cycle (i.e. 1/50 Hz) determines how the meter does this.

The cumulative register reading of the meter is derived from the real time energy accumulated over time and will increment as energy flows through the meter. These cumulative readings can be split into periods to be used for billing electricity supply companies’ tariffs. For example, a different price per kWh may be charged depending on the time of that usage. This is achieved through time of use (TOU) rate registers configured in the meter that would have different prices applied to each rate (e.g. in a typical day/night split tariff TOU rate 1 records energy between 07:30 and 23:00 and TOU rate 2 records energy between 23:00 and 07:30). Every site which is not measured on a half hourly (HH) basis would be settled using cumulative readings.

In HH settlement, the meters are also required to record the energy flowing through the circuit in 30 min blocks (Great Britain (GB) settlement is based on 30 min integration periods) and different quantities are recorded in separate HH channels. A device which has the functionality to receive and store data in HH format is called an outstation. Modern meters have the functionality to do this internally (i.e. an integral outstation) or alternatively they can transmit data, based on the energy recorded by the meter, to a separate outstation.

If the meter uses output pulsing (i.e. the meter transmits a pulse every time it records a defined amount of energy, e.g. one pulse for every 50 kWh recorded by the meter) to do this the outstation counts the received pulses allocating them to 30 min periods. This is converted back to primary energy by the outstation itself or the data collector by multiplying the pulse count by 50 (i.e. if meter set to 50 kWh per pulse).

A meter has the ability to record multiple parameters, typically those listed below:

  • Active energy import (AI), kWh.
  • Active energy export (AE), kWh.
  • Reactive energy import (RI), kVArh.
  • Reactive energy export (RE), kVArh.
  • Reactive import associated with active import (Q1), kVArh.
  • Reactive export associated with active export (Q2), kVArh.
  • Reactive import associated with active export (Q3), kVArh.
  • Reactive export associated with active import (Q4), kVArh.

The meter can do this through its software. The user can program how the meter is set up and what parameters it needs to record. The energy recorded is allocated to the correct channel through the meter's ability to determine the phase angle between the voltage and current waveforms and allocate it to the correct channel and cumulative register (Fig 2).

Fig 2: Prevailing load channel allocation

Taking active energy as an example, when the phase angle between the voltage and current waveforms is between 270° and 90° the meter will allocate all recorded active energy to registers and channels associated with AI and where the phase angle is between 90° and 270° the meter will allocate all recorded active energy to registers and channels associated with AE.

For practical reasons any high voltage (HV) connected site or low voltage high current site (typically over 100 A) utilises measurement transformers to step the primary values down to manageable levels that a meter can measure at a low capital cost. This is achieved through voltage transformers (VT) and current transformers (CT). Typically a VT will step primary voltage levels (e.g. voltages >1000 V) down to 110 V on the secondary side and a CT will step current levels down to 5 or 1 A on the secondary side.

Meters have different configurations (Table 1) depending on the electrical system to which they have been connected and a number of measuring elements either equal to or one less than the number of primary system conductors.

Type of site


Type of connection



Direct (whole current)






small-scale commercial

three-phase four-wire




small- and medium-scale commercial and industrial

three-phase four-wire




large commercial and industrial

three-phase three-wire




transmission connected

three-phase four-wire




Table 1: Examples of common meter configurations

Fig 3 shows the connection for a three-phase three-wire HV configuration. It is crucial that consideration is given to the direction the CT faces to ensure that the meters measure primary energy flow correctly. Where the CT is facing the customer side (P1 in Fig 3) rather than the network side (P2 in Fig 3) if the meter is configured in a standard manner [i.e. secondary 1 (S1) wired to I1 in the meter] the meter current is 180° out of phase and the meter records in reverse (i.e. when the primary energy flow is import the meter records it as export). The multicore connections [i.e. the wiring from the secondary side of the CTs and VTs (terminated in the switchgear) to the metering] must be configured so the secondary facing the incoming supply (2S3 in Fig 3) is the input to the phase of the meter (e.g. I1).

Fig 3: Three-phase three-wire (Delta) connected metering system

The multicores to the meter should only be connected across one ratio (e.g. S1 and S2 or S1 and S3). Where there are multiple CT ratios available all secondary connections are wired out to a terminal block in the switchgear.

Metering multicore connections can be identified from the letter used in the ferrule number: metering current connections are identified by a ‘D’ and metering voltage connections are identified by an ‘E’.

Where VTs with multiple secondary windings (e.g. a metering class winding and a protection class winding) are used typically, three single-phase VTs in a three-wire system (Delta) will be installed and only the three phases will be wired to the meter. In the example (Fig 3), this would be E10, E30 and E50 with E30 being a link and tied to earth.

In a four-wire system (transmission connected), all connections would be wired out to the meter with E30 fused and E70 a link which is tied to earth.

The ratio of the respective measurement transformers is programmed into the meter and the meter multiplies the secondary volts and amps recorded directly by the value of the primary values divided by the secondary. For example, if the meter measures 2.5 A and the programmed CT ratio is 500/5 A, the meter multiplies the 2.5 A by 100 to get the 250 A flowing at the metered point on the primary side.

The meter can compensate for any errors in the CTs and VTs; this should be at the burden imposed on the secondary side of the measurement transformers. The errors associated with measurement transformers are split into two categories: ratio errors (measured as a percentage) which arise when the actual transformation is not equal to the rated transformation ratio and phase errors (measured in minutes), or phase displacement, which are the difference in phase between the primary and secondary vectors.

The accuracy requirements of the metering systems component parts are defined in the CoPs. The requirements in CoPs 1, 2, 3 and 5 are summarised in Table 2.


Applicable CoP criteria

Required accuracy class





rated capacity exceeding 100 MVA


0.2 s

0.2 s


rated capacity not exceeding 100 MVA


0.2 s

0.5 s or (C)


rated capacity not exceeding 10 MVA



1 or (B)


energy transfers with maximum demand up to (and including) 1 MW



2 or (A)

Table 2: CoP accuracy requirements

All the component parts of the metering system (Table 2) must meet the requirements of the relevant International Electrotechnical Commission [3] standard. In addition to this, a meter must have been approved by the UK National Measurement and Regulation Office (NMRO) and/or the European Measurements Instrument Directive (MID) [4]. For a meter in the sub 100 kW market, NMRO will accept MID approval without further checks but will do additional approval checks for the over 100 kW market. Where the meter is used in HH Settlement ELEXON, acting as the Balancing and Settlement Code Company (BSCCo), conducts metering protocol approval and compliance testing [5] to verify that the meter is compliant with the CoPs and a HH data collector (HHDC) can communicate with and download data from that meter type (i.e. HH metered volumes, cumulative register readings and error flags).

To ensure that the metering system is accurate, it must be correctly commissioned (CoP 4 defines the calibration, testing and commissioning requirements of metering equipment used for settlement purposes). This includes tests (typically by primary injection) on the measurement transformers to confirm they are of the correct ratio and polarity to record the required power flow. Additional tests are carried out to establish the connected burden is less than the rated burden of the measurement transformer.

The meters are commissioned, either by secondary injection or using prevailing load, to confirm they have been configured correctly (e.g. set to the same ratio as the installed measurement transformers) and are recording the primary energy accurately.

Whilst commissioning will confirm the accuracy of the meter and its components, a further test is required which demonstrates that the meter readings arrive at the HHDC correctly. This is a proving test where the meter operator agent (MOA) takes a visual HH reading which is later compared with that collected by the HHDC. If the two readings are consistent then the HHDC is collecting data correctly.

The meters have the functionality to log error conditions and these are read by the HHDC who reports them to the MOA for investigation and resolution. These include:

  • Phase failure,
  • Power outage,
  • Battery monitoring,
  • Time or date change,
  • Meter programming.

Where the CoP (CoP 1, 2 and 3) requires two meters to be installed on a circuit, the HHDC performs a comparison check between them and reports any significant differences to the MOA for investigation and resolution.

Once a metering system is operational, BSCCo uses a sampling assurance technique, as part of the performance assurance framework (PAF) [6], to attend sites and test the system. The checks include determining that overall accuracy is maintained, the installed assets are the correct accuracy class and the technical details held by the meter operator and HHDC are consistent and correct.


The method of data collection and submission into settlement [7] systems depends on how the site has been registered and whether the site is non-HH (NHH) or HH. This is registered in either the Supplier Meter Registration Service (SMRS) or Central Meter Registration Service (CMRS). SMRS involves a Meter Point Administration Service (MPAS) for each grid supply point (GSP) group area (Fig 4), managed and operated as a Distribution Licence requirement by the Distribution System Operators (DSO). CMRS is under the governance of the BSC. There are also unmetered supplies (UMS), such as streetlights which represent a small proportion of total electricity consumption.

Fig 4: GSP group areas and identifiers


Traditionally suppliers deal with a large volume of metering points, many of which represent small rates of electricity consumption and based on NHH data, and so there are supplier-specific processes around how such data is aggregated and handled in settlements. This is referred to as supplier volume allocation (SVA) and aims to calculate how much electricity each supplier has consumed in a settlement period.

Focusing on NHH first, NHH data aggregators receive estimated annual consumption (EAC)/annualised advance (AA) data from NHH data collectors. An EAC is an estimated rate of consumption (kWh/year) that is used in settlement until an AA is calculated. An AA is the rate of consumption for a settlement register over the period between two meter readings.

They will aggregate the data by the following characteristics:

  • Grid supply point (GSP) group ID (distribution network area);
  • Supplier ID (4 character market participant identifier or ‘MPID’);
  • Profile class ID (1–8, e.g. domestic, non-domestic);
  • Distributor ID;
  • Line loss factor class (distributor assigned classification relating to distribution losses);
  • Standard settlement configuration ID (type of meter);
  • Time pattern regime (meter configuration at different times).

This aggregated EAC/AA data is then submitted into the settlement systems, which extrapolate the data into an ‘estimated’ volume per settlement period by applying profiles and also determines distribution losses.

HH supplier data is submitted by the HHDA to settlement systems in a similar manner; however the HHDA will determine distribution losses rather than settlement systems.

Due to the level of estimation involved with NHH data, settlement systems adjust the NHH data up or down so that total supplier consumption (NHH, HH and UMS) matches HH GSP group meter readings. This results in a ‘deemed take’ per supplier, per GSP group area, per settlement period.

The main settlement calculations are handled per balancing mechanism (BM) unit. The settlement systems therefore allocate deemed take volumes to supplier BM units (one for each GSP group area), so that it is ready for processing under CMRS (Fig 5).

Fig 5: SMRS meter to settlement process


Central volume allocation is a term that covers non-supplier-specific registration and volume management, and also the main calculations undertaken by settlement systems. Whereas SMRS concerns supplier registration of individual Meter Point Administration Numbers (MPANs) (e.g. a house) in MPAS systems, CMRS concerns BM units which generally cover larger scale metering (e.g. a power station).

There are different types of BM unit depending on the registration/licencing circumstances of the party or metering system. For instance, when a new supplier joins the market they will register 14 supplier base BM units, one for each GSP group area. As a supplier can register customers anywhere in GB, they will submit metered volumes of customers that reside in each GSP group area, e.g. customers in the north of Scotland fall within the ‘_P’ GSP group area and their volumes will be allocated to the ‘_P’ supplier base BM unit. A power plant may have multiple distinct metering systems, e.g. one for exporting electricity generated and one for keeping the lights on whilst the plant is under maintenance; therefore requiring a BM unit for each.

BM units can be grouped together in a trading unit, meaning that they will be treated the same when determining delivery mode, i.e. ‘delivering’ or ‘offtaking’, which impacts the allocation of BSC and non-BSC charges. Power stations will often have a trading unit to group their export and import BM units together so that they are all treated as delivering. Supplier base BM units across suppliers are always grouped together where they fall in the same GSP group area; so that the delivery mode of the GSP group area can be determined based on the volumes of all supplier base BM units relating to that area. If a BM unit is not in a trading unit with other BM units, it is considered as being in a sole trading unit whereby its delivery mode is determined by its metered volumes alone.

Settlement systems will determine the relevant transmission loss multiplier (TLM) for each BM unit in a given settlement period, which effectively scales down BM unit metered volumes for delivering BM units slightly and scales up for offtaking BM units. This accounts for electricity lost over the transmission network.

Under the BSC, each party holds two energy accounts: one for production and one for consumption. Settlement systems allocate BM unit metered volumes to energy accounts by multiplying BM unit metered volume by TLM to produce a gross value called credited energy volume. At this point, settlement systems also take into account any metered volume reallocation notifications which allow the lead party (registrant) of a BM unit to reallocate the volumes of that BM unit to the energy account of another party, usually by percentage (Fig 6).

Fig 6: Energy volume allocation example

Energy imbalance

One of the core concepts under the BSC is energy imbalance: essentially the difference in volume (MWh) between what a party (generator/supplier etc.) has sold or bought in advance of the settlement period (energy contracts) and what they actually generated or consumed (credited energy volume). Due to the fundamental separation between the trading of electricity between parties and the physical generation/transportation/consumption of electricity, the identification and handling of imbalance accounts for gap differences between these two activities.

The energy imbalance calculation also takes into account any balancing services volumes that National Grid required the BM unit to meet. When a party has a positive imbalance volume, we refer to them as being ‘long’ and they are paid the system sell price (SSP) in £/MWh for that surplus volume. Parties with negative imbalance volumes are ‘short’ and must pay the system buy price (SBP) for the deficit volume (Table 3).

Example party

Credited energy volume

Less balancing services volume

Less energy contract volume

Equals imbalance volume




130 MWh generated

additional 20 MWh required to generate

100 MWh sold

10 MWh


paid SSP for 10 MWh over-generated


−100 MWh consumed


−80 MWh bought

−20 MWh


pays SBP for 20 MWh over-consumed


−60 MWh consumed


−80 MWh bought

20 MWh


paid SSP for 20 MWh under-consumed

Table 3: Energy imbalance examples

This calculation is performed for each energy account. However, when billing the energy imbalance charges, this is done at party level (i.e. imbalance charges for both energy accounts added together).

Settlement systems calculate SSP and SBP for each settlement period based on the price that National Grid paid BM units in trying to balance the network in that settlement period. BM units specify prices to change their output via bids and offers. Bid offer data is published by the BM report agent. The imbalance pricing calculation is complex and involves flagging (marking certain actions for price adjustment), tagging (removal of actions) and other adjustments to minimise inappropriate distortion of prices, e.g. actions taken to address locational system constraints. Since November 2015, SSP and SBP are always the same, because their calculation methods have been aligned.

Trading charges

Imbalance cashflow is one of five trading charges that BSC trading parties are subject to:

  1. Imbalance cashflow.
  2. Residual cashflow reallocation cashflow – the remaining monies after all imbalance cashflows for a given settlement period are summed, which is redistributed from/to parties based on market share.
  3. BM unit cashflow – monies due from/to a lead party in relation to accepted bids/offers.
  4. Non-delivery charge – monies due from a lead party in relation to failures to satisfy accepted bids/offers.
  5. Information imbalance charge – intended to incentivise accurate physical notifications to National Grid but always zero due to the penalty price being zero.

Payment systems issue advice notes and arrange daily trading charge payments to/from BSC trading parties based on data provided by the settlement systems.

Settlement runs

As discussed above, settlement involves reviewing data periodically after the event. Parties continually submit more data and corrections to data and settlement takes a series of snapshots called settlement runs (Table 4).

Settlement run


Working days after the settlement date

NHH performance target

HH performance target

interim information run





initial settlement run





first reconciliation run





second reconciliation run





third reconciliation run





final reconciliation run





dispute reconciliation run





Table 4: Settlement runs

There are performance targets that require a percentage of meter data to be based on actual readings rather than estimated readings, and for NHH these targets increase with each settlement run. In principle, this drives an increase in accuracy of the data over time, such that by the ‘RF’ final reconciliation run, the data should be correct and unlikely to change again. However, disputes can be raised (e.g. to resolve a serious metering issue) long after the settlement date and the outcome of these may require ad hoc settlement runs.

The ‘SF’ initial settlement run is the first billable run that will require the payment systems to issue invoices; the ‘II’ interim information run provides an early indication of what the invoices will be. The reconciliation runs (‘R1’ to ‘DF’) will result in amounts due from/to parties based on the difference between the last billed amount and the newly calculated values.

Additional information

This paper has aimed to provide a high-level overview of electricity metering and settlement. Further information can be found on the ELEXON website.


  1. The Balancing and Settlement Code (ELEXON Limited , 2016).
  2. Code of Practice 1: ‘The Metering of Circuits with a Rated Capacity Exceeding 100MVA for Settlement Purposes; Code of Practice 2: The Metering of Circuits with a Rated Capacity Not Exceeding 100 MVA for Settlement Purposes; Code of Practice 3: The Metering of Circuits with a Rated Capacity Not Exceeding 10 MVA for Settlement Purposes; Code of Practice 4: The Calibration, Testing and Commissioning Requirements of Metering Equipment for Settlement Purposes; Code of Practice 5: The Metering of Energy Transfers with Max Demand of up to (and including) 1MW for Settlement Purposes; Code of Practice 6: The Metering of Energy Imports via Low Voltage Circuits Fused at 100 AMPS or Less per Phase for Settlement Purposes; Code of Practice 7: The Metering of Energy Imports via Low Voltage Circuits Fused at 100 AMPS or Less per Phase for Settlement Purposes; Code of Practice 8: The Metering of Import Active Energy via Low Voltage Circuits for Non-Half Hourly Settlement Purposes; Code of Practice 9: The Metering of Import and Export Active Energy via Low Voltage Circuits for Non-Half Hourly Settlement Purposes; Code of Practice 10: The Metering of Energy via Low Voltage Circuits for Settlement Purposes’ (ELEXON Limited , 2016).
  3. IEC 60044-1 Instrument transformers – Part 1: Current Transformers (International Electrotechnical Commission, 2003); IEC 60044-2 Instrument transformers – Part 2: Inductive Voltage Transformers (International Electrotechnical Commission, 2003); IEC 62053-21 Electricity metering equipment (a.c.) – Particular requirements – Part 21: Static meters for active energy (classes 1 and 2) (International Electrotechnical Commission, 2003); IEC 62053-22 Electricity metering equipment (a.c.) – Particular requirements – Part 22: Static meters for active energy (classes 0,2 S and 0,5 S) (International Electrotechnical Commission, 2003); IEC 62053-23 Electricity metering equipment (a.c.) – Particular requirements – Part 23: Static meters for reactive energy (classes 2 and 3); IEC 62056-21 Electricity metering – Data exchange for meter reading, tariff and load control – Part 21: Direct local data exchange (International Electrotechnical Commission , 2002).
  4. EC Directive 2004/22/EC Measurement Instruments Directive (MID) (European Commission, 2004).
  5. BSCP601 ELEXON Limited, 2016 Metering Protocol Approval and Compliance Testing.
  6. Performance Assurance Framework (PAF). Available at (ELEXON Limited, 2016).
  7. BSCP01 Overview of Trading Arrangements (ELEXON Limited, 2015).
  8. BSCP27 Technical Assurance of Half Hourly Metering Systems for Settlement Purposes (ELEXON Limited, 2016).
  9. BSCP11 Trading Disputes (ELEXON Limited , 2016).

Case study: metering fault impacting settlements

As part of the PAF, ELEXON's auditor (technical assurance agent) audits a percentage of randomly selected half-hourly MPANs registered in SMRS and Metering System Identifiers (MSID) registered in CMRS. This selection forms the main sample to be tested in the audit year, the process for which is detailed in BSCP27 [8].

The auditor will request relevant technical details held by the registrant, licensed distribution systems operator (LDSO), MOAs, HHDCs [or central data collection agent (CDCA) in CMRS]. This includes:

  • Metering technical details held by the MOA and data collector,
  • Commissioning evidence for the measurement transformers and meters,
  • Calibration test certificates for the measurement transformers and meters,
  • Evidence of any compensation values applied to the meters.

As part of the main sample, the auditor was to test an MPAN for an onshore wind farm. All parties supplied the information requested by the auditor. The first stage of the audit process is to do a desk-based analysis of the submitted information and check for compliance with the code subsidiary documents, for example the applicable CoP for the site, and for consistent information, for example the MOA and HHDC both hold the same meter serial number for the installed asset.

Only one issue was identified during the analysis; the auditor identified that it was not clear what CT ratio the metering had been connected to. From the information provided by the LDSO the CT calibration test certificate was a multi-ratio type and was 800/400/5 A for the metering accuracy class. This was consistent with the commissioning evidence, also provided by the LDSO, that showed both the 800/5 and 400/5 A were primary injected during the commissioning testing.

There was no indication in the LDSO commissioning evidence as to what CT ratio the multicores to the meter were connected across. The MOA had programmed the meter with a CT ratio set to 800/5 A.

The second stage of the audit process is a site visit to check the following:

  • Installed assets match the technical details submitted;
  • A correct energy measurement check – to verify that the metering system is recording the correct amount of energy, checks shall be carried out that compare the primary load with that being recorded by the metering system;
  • A consumption data comparison check – a comparison of the metered energy data for one half-hour recorded at the time of the audit with the consumption data held by the HHDC for that same half-hour period.

In the correct energy measurement check, the instantaneous power value displayed on the meter was double the power value displayed on an independent meter on the switchgear. The secondary voltage and current measured at the metering panel was consistent, when converted to primary values, with the instantaneous power value displayed on the meter.

The auditor concluded that either the meter or the independent meter on the switchgear was set to the wrong ratio. Upon further investigation, the CT wiring in the switchgear showed that the multicore cables to the metering panel were connected across the low ratio (i.e. 400/5 A) while the meter was set to the high ratio (i.e. 800/5 A).

The auditor had identified a non-compliance that was deemed to be currently affecting the quality of data for settlement purposes, i.e. the meter was recording double the actual primary energy (by applying a multiplier of 160 and not 80 for the CT ratio) and submitting this into settlement. This is a category 1 non-compliance and the auditor notified the registrant, MOA and HHDC/CDCA of the non-compliance. The registrant is responsible for investigating and resolving the non-compliance, which in this case was the supplier.

The registrant submitted a rectification plan for the MOA to investigate and resolve the issue. The MOA attended site to confirm the incorrect ratio applied and re-programmed the meter to the correct CT ratio of 400/5 A. The MOA confirmed to the registrant that the non-compliance was from the date of energisation until the date/time of the settlement period of correction.

As the length of the fault was >14 months (in this case it was 16 months), the normal settlement process cannot correct for the error, as the last settlement run [final reconciliation run (RF)] had taken place for some settlement dates. In this instance, the registrant raised a trading dispute, the process for which is detailed in BSCP11 [9].

The registrant completed a trading dispute raising form and submits it to the disputes secretary (BSCCo); details include the settlement periods impacted, details of the site (MSID) and the nature of the error. The BSCCo disputes team investigates the issue, requests any additional information and assesses the application. The trading dispute was deemed valid and a paper was prepared to be presented to the Trading Disputes Committee (TDC) for a determination.

The TDC upheld the trading dispute on the basis that a settlement error has occurred for the affected settlement periods and, as the materiality of the trading dispute is >£3,000, determined a means of rectification. A TDC finding form was completed and distributed to the raising party, affected parties and relevant BSC agents.

The TDC decision was to perform a post-final settlement run (DF). The disputes secretary, in association with the impacted HHDA and HHDC, determines the window within which to perform the post-final settlement run. TDC met and authorised the post-final settlement run.

Following this decision of the TDC, the disputes secretary informs the raising party of the decision and all trading parties advised that a post-final settlement run would be carried out. In association with the impacted HHDA and HHDC, the disputes secretary schedules data amendments and run dates; and notifies relevant BSC agents (CDCA, settlement administration agent, SVA agent and funds administration agent).

The relevant parties performed the post-final settlement run in accordance with TDC requirements on the scheduled day. This corrects the error introduced in to settlement by the incorrect data recorded by the meter. Due to the fact that the meter was erroneously recording double export, the submission of this data had made the BSC party erroneously ‘long’ from a settlement perspective. The correction of this via the post-final settlement run would result in the party having to make payments which would then be redistributed to affected parties.

Lessons learned

  1. The LDSO should have informed the MOA, via an industry data flow of the correct ratio of the CT the multicore cable to the metering panel was connected across. The commissioning should have stated the ratio the multicore cable to the metering panel was connected across.
  2. The MOA should have checked an independent primary measurement device and compared with the meter instantaneous power values.
Go to the profile of Iain Nicoll

Iain Nicoll

Metering team leader, ELEXON

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