How Elexon makes use of an annualised form of Group Correction Factor (GCF) – Annual Demand Ratio (ADR) – as a Key Performance Indicator (KPI) for Settlement Accuracy
The basic principles of GCF including its intended purpose, how it is calculated, who it affects and how it affects them
How anomalies in ADR can be an indicator of Settlement Error, and the steps that Elexon takes to investigate these

What this document does not cover

Details of the various Performance Assurance Techniques (PATs) Elexon operates to mitigate the likelihood of Settlement Error occurring, which are covered in their own Guidance Notes

Your Operational Support Manager (OSM) is your first point of contact for Performance Assurance queries and is available to support you.

If you have a more general question about Settlement, please raise a ticket through the online Elexon Support portal.

Settlement Accuracy and Settlement Error

Settlement is the Metered Volume data by which Suppliers and Generators are paid and charged for the correct amount of energy they trade on the wholesale market.

The accuracy of Settlement depends on the accuracy of the data inputs entered into Settlement.

Where incorrect Meter Volume data enters Settlement, a Settlement Error occurs.

Possible sources of incorrect data include, but are not limited to:

Errors in the setup of Metering Systems or Metering System faults that lead to consumption or generation volumes being recorded incorrectly
Errors in the standing data associated with Metering Systems, meaning that consumption or generation volumes are recorded correctly but processed into Settlement incorrectly or not at all
Prolonged and/or inaccurate estimation of consumption or generation volumes where metered data is not available

Elexon continually operates a range of PATs to mitigate the risk of errors in Settlement, and to detect and rectify errors that do occur. However, Elexon is not able to prevent, detect, or rectify every error in Settlement.

Ultimately, Suppliers (in the Supplier Volume Allocation (SVA) market) and Registrants (in the Central Volume Allocation (CVA) market) are accountable for ensuring that actual metered data used in Settlement is accurate, and that any estimated data is calculated using the best available method in accordance with the Balancing and Settlement Code.

Limitations of Settlement Accuracy

Settlement calculations can never be made with complete accuracy as Suppliers do not know for certain how much energy all of their customers are using in each half-hourly Settlement Period.

In particular, most energy from domestic (and some commercial) meters – even those that can record data every half-hour – is currently Settled Non-Half Hourly (NHH).

For these meters, the energy for each Settlement Period is calculated by taking the difference between two meter readings (an advance) and allocating the energy into half-hourly chunks using a statistical profile (profiling).

Even for meters that are settled using actual Half Hourly (HH) data, there will always be instances where actual consumption or generation data is not available (for example, due to communications faults) and needs to be estimated.

As well as profiled and estimated data, Settlement also needs to take into account the energy lost in the Distribution Systems, otherwise known as line losses, that take electricity from the high-voltage Transmission System (the Grid) and transform it down to lower voltages so that it can be safely distributed out to individual premises.

BSCP128 sets out provisions to ensure these line losses are calculated as accurately as possible, but even the most accurate methodology will necessarily involve a certain amount of approximation and abstraction.

Licensed Distribution System Operators (LDSOs) are accountable for using a compliant method to calculate the Line Loss Factors (LLFs) that determine how much energy is lost in their distribution systems. Suppliers are then accountable for making sure that their appointed HH and NHH Data Aggregators (DAs) apply these correctly to calculate the line losses associated with their metered volumes.

What is Group Correction Factor (GCF)?

GCF is a way of sharing the cost of the inherent error in Settlement between relevant Suppliers.

It is a multiplier applied to profiled data to bring it into line with the actual amount of energy being used in each Settlement Period across Great Britain.

The ideal value for GCF is one. A GCF of greater than one means that Suppliers’ volumes are scaled up, and a GCF of less than one means that Suppliers’ volumes are scaled down.

What is Annual Demand Ratio (ADR)?

Generally, profiling is expected to be accurate to within 10% over the course of a Settlement Period. If volumes need to be scaled up or down by more than this amount – that is, if GCF is greater than 1.1 or less than 0.9 – it can suggest that a significant amount of incorrect data may be entering Settlement.

However, GCF tends to be more volatile at earlier Settlement Runs, where less actual HH data and fewer NHH advances are available. At this stage of Settlement there is too much uncertainty within the data for GCF to be a reliable tool for detecting Settlement Error in all but the very worst cases.

For this reason, Elexon uses an annualised view of GCF at the Second Reconciliation (R2) Run or later – ADR – to monitor the accuracy of Settlement.

Profiling should be accurate to within 1.5% over the course of a year. Therefore, Elexon investigates instances where ADR trends above 1.015 or below 0.985 (“ADR Anomalies”). A list of possible causes, and the order in which Elexon investigates them, is given below.

ADR is published each month in the Trading Operations Report, along with updates on Elexon’s investigations into any current ADR Anomalies.

Where ADR is trending outside of tolerance, Suppliers and Registrants should be especially vigilant for indicators of potential Settlement Error in their own portfolio.

Calculating GCF and ADR

To understand how Elexon investigates ADR Anomalies, we need to understand how GCF and ADR are calculated so that we can determine how and where Settlement Errors may occur.

How are GCF and ADR Calculated?

Broadly, both GCF and ADR are calculated by dividing the amount of energy recorded entering each of the 14 Grid Supply Point (GSP) Groups by the amount of energy being used in that GSP Group.

The detailed calculation is given below, after the explanation of two key terms: GSP Group Take and Consumption Component Class (CCC) IDs.

What is GSP Group Take?

The GSP Groups are geographic regions analogous to the old nationalised Electricity Boards. Each GSP Group contains a Distribution System operated by an LDSO. A list of GSP Groups is included below as Appendix 2.

The amount of energy in a GSP Group in any given half-hourly Settlement Period is referred to as the GSP Group Take (GSPGT).

The Central Data Collection Agent (CDCA) calculate Group Take by adding together metered volumes from different kinds of Volume Allocation Unit (VAUs) in the Central Volume Allocation (CVA) market.

These are:

Grid Supply Points (GSPs) where energy enters the Distribution System from the Transmission System
Embedded Balancing Mechanism Units (E_BMUs), exceptionally large generators and (more rarely) consumers “embedded” within the Distribution Systems
Distribution System Connection Points (DSCPs) where energy moves from one Distribution System to another

Each VAU may comprise data from several different Metering Systems (MSIDs) totalled up in accordance with an Aggregation Rule (Agg Rule). A worked example of a VAU Aggregation rule can be found in Appendix 3.

The Registrant of the VAU is responsible for ensuring that the data from each Metering System is correct, and that the data from all relevant Metering Systems is properly accounted for in the Agg Rule.

There is also an Agg Rule for each GSP Group specifying how volumes from each VAU are added together to calculate GSPGT. The LDSO is accountable for making sure the Agg Rule for GSPGT in a given GSP Group is correct and up to date.

What are Consumption Component Class (CCC) IDs?

Elexon receives aggregated Supplier Volume Allocation (SVA) volumes from Data Aggregators (DAs) via the Supplier Volume Allocation Agent (SVAA). These volumes are allocated into one of 62 Consumption Component Class (CCC) IDs depending on:

Whether the volumes are Settled NHH or HH
The Measurement Class of the supply (based on its size and what kind of metering equipment is fitted)
Whether the data is Actual or Estimated
Whether the data is for consumption or generation volumes
Whether the data is for metered volumes or line losses

For the purposes of GCF, different CCC IDs are assigned a different Scaling Weight (WTN) depending on how likely it is that the energy allocated to them for each HH period is correct. These are calculated using a Standard Error Allocation Fraction equation, in line with the recommendations of Issue 55 and a subsequent consultation with the industry.

A full list of current CCC IDs and Scaling Weights, is included below as Appendix 4.

How GSP Group Take and CCC IDs are used to Calculate GCF – Worked Example

There can only be a single total amount of energy in each GSP Group at any one time.

Therefore, the total energy recorded across the CCC IDs should be the same as GSPGT.

Any discrepancy between the two figures is attributed in Settlement to inherent error on the SVA side, particularly the volumes Settled NHH.

As noted above, this is because:

GSPGT is calculated from (mostly) actual HH data, from fewer meters, all of which have multiple redundancies and safeguards built in
The portion of CCC ID volumes Settled HH is also calculated from (mostly) actual HH data, from fewer meters, the largest of which also have multiple redundancies and safeguards built in
The portion of CCC ID volumes Settled NHH, by contrast, is calculated by applying a statistical profile to annualised volumes calculated from meter advances

PerSection S: Annex S-2of the BSC, GCF is calculated for each GSP Group and Settlement Period as follows:

One plus ((GSP Group Take minus all CCC ID volumes) divided by (all CCC ID volumes multiplied by their relevant Scaling Weight))

GCF is then applied to CCC IDs in accordance with their Scaling Weight, as follows:

CCC ID volume multiplied by (one plus ((GCF minus one) multiplied by the relevant Scaling Weight))

In the following simplified illustration, we can follow through an example to see GCF scaling up SVA volumes within a GSP Group to match GSP Group Take:

In this example, the total GSP Group Take is 100. The total SVA Volume is 80, so GCF will scale this up to match Group Take.

Of the total SVA Volume, 50 is from CCCs with a WTN of 0, 25 from CCCs with a WTN of 1, and 5 from CCCs with a WTN of 1.2.

In this case, GCF =

1+((100-(50+25+5))/((50*0)+(25*1)+(5*1.2))) or
1+((100-80)/(0+25+6)) or
1+(20/31) or
1.6452

GCF is then applied to the volumes on each group of CCC IDs as follows:

For energy from CCC IDs with a WTN of 0 (the most likely to be correct): 50*(1+((1.6452-1)*0)) or
For energy from CCC IDs with a WTN of 1: 25*(1+((1.6452-1)*1)) or
For energy from CCC IDs with a WTN of 1.2 (the least likely to be correct): 5*((1.6452-1)*1.2)) or

50 plus 41.129 plus 8.871 gives a total of 100, meaning that the scaled-up SVA volumes are now the same as GSP Group Take.

How GSP Group Take and CCC IDs are used to Calculate ADR – Worked Example

ADR applies a simplified version of the GCF calculation to 366 days’ worth of data to give an annualised view of GCF (the extra day is to account for leap years).

ADR is calculated as Yearly Metered Non Half Hourly Consumption (YMNHHC) divided by Yearly Profiled Non Half Hourly Consumption (YPNHHC)

YMNHHC is the amount of NHH consumption indicated by the data retrieved from Metering Systems Settled on HH data, that is: GSP Group Take minus all CCC ID volumes with Data Aggregation Type HH

YPNHHC is the amount of NHH consumption entered in to Settlement from Metering Systems Settled on NHH data, that is: all CCC ID volumes with Data Aggregation Type “NHH”

If GSP Group Take for a year is 100, CCC ID volumes with Data Aggregation Type “HH” for the same year is 50, and CCC ID volumes with Data Aggregation Type “NHH” for the same year is 30, then:

YMNHHC is (100-50=) 50
YPNHHC is 30
ADR is (50/30=) 1.6 recurring

Investigating ADR Anomalies

An ADR anomaly suggests that the amount of energy in one part of the calculation is being reported as higher or lower than it actually is (over-accounted or under-accounted).

The direction of the anomaly indicates where in Settlement this might be happening, as follows:

This could be because:

One or more of the underlying calculations is not being performed correctly; and/or
One of more of the underlying calculations contains incorrect data

The following tables itemise the various points at which an error can be made, or at which incorrect data can enter the calculations.

In each table, the first two columns give details of the relevant data or calculation, and the BSC Party accountable for ensuring that it is correct.

Different errors are likely to impact the Settlement Data underlying the GCF and ADR calculation in different ways, and so can be used to assist in the root cause analysis of ADR anomalies. These are listed in the third column.

Finally, Elexon’s Assurance and Participant Management products carry out regular Assurance activities that may act as a control for particular kinds of error. These are listed in the fourth column, with the related Settlement Risk from Elexon’s Risk Evaluation Register in the fifth column.

Potential Errors with the ADR Calculation

Potential Error	Accountable Party	Impact on Settlement Data	Controls	Settlement Risk(s)
SVAA calculates ADR incorrectly	Elexon	ADR does not match underlying Settlement Data	Elexon has access to underlying Settlement data and is able to replicate the ADR calculation to check it has been carried out correctly	CEN-02

Potential Errors with GSP Group Take Calculation or Data

Potential Error	Accountable Party	Impact on Settlement Data	Controls	Settlement Risk(s)
CDCA calculates GSPGT incorrectly	Elexon	GSPGT figure provided by the CDCA does not match aggregated VAU volumes	Elexon has access to underlying Settlement data and is able to replicate the GSPGT calculation to check it has been carried out correctly	CEN-03
The Agg Rule for GSPGT is incorrect or out-of-date	LDSO	GSPGT trends differently to other elements of the overall ADR calculation	Elexon periodically reviews GSPGT Agg Rules, especially when VAUs are amended, added or removed	REG-02
The Agg Rule for one or more VAUs is incorrect or out-of-date	Registrant	VAU volumes trend similarly to GSPGT, which itself trends differently to other elements of the overall ADR calculation	Elexon reviews new Agg Rules and any changes to existing rules. Technical Assurance of Metering (TAM) Audit¹	REG-02
Metered data is incorrect due to a fault with one or more Metering Systems comprising a VAU, or an error in the Meter Technical Details or other standing data for one or more Metering Systems used to calculate VAU volumes, including where Metering Dispensations are applied incorrectly	Registrant	Unexplained step-changes in VAU volume. GSPGT trends differently to other elements of the overall ADR calculation	Elexon’s Change Point Tool (which uses machine learning to monitor for step-changes in GSP volumes). Elexon has access to Settlement Data from DSCPs and E_BMUs and can check these manually. BSC Audit. TAM Audit and targeted metering inspections by the Technical Assurance Agent (TAA)	REG-01, REG-03, MET-01, MET-02, MET-03, MET-04
Prolonged estimation at one or more Metering Systems comprising a VAU leads to unrepresentative data entering Settlement	Registrant	Step-changes in VAU volume consistent with estimation to trend or zero. GSPGT trends differently to other elements of the overall ADR calculation	Change Point Tool for GSPs. Elexon has access to Settlement Data from DSCPs and E_BMUs and can check these manually. Elexon periodically reviews the CDCA’s Fault and Estimation Logs for long-term issues with metering communications equipment	DAT-01
CDCA incorrectly estimates data for one or more Metering Systems comprising a VAU	Registrant	Step-changes in VAU volume consistent with estimation to trend or zero where this is not the appropriate method of estimating data, or is not otherwise reflective of prior volumes. GSPGT trends differently to other elements of the overall ADR calculation	Change Point Tool for GSPs. Elexon has access to Settlement Data from DSCPs and E_BMUs and can check these manually. Elexon periodically reviews the CDCA’s Estimation Log to check the correct method is used	DAT-02

Potential Errors with SVA Volumes

Potential Error	Accountable Party	Impact on Settlement Data	Controls	Settlement Risk(s)
Suppliers do not collect or submit sufficient data from Metering Systems	Supplier	Poor Settlement Performance. Over-use of Default EACs (NHH only). Aggregated consumption or generation from relevant CCC IDs trends differently to other elements of the overall ADR calculation	Elexon monitors Suppliers’ Settlement Performance and deploys PATs such as Error and Failure Resolution (EFR) as necessary to address poor performance. BSC Audit	REG-03, REG-04, REG-05, DAT-01, DAT-03
Suppliers or DAs incorrectly annualise volumes from NHH Metering Systems when profiling consumption or generation data	Supplier	Poor NHH Settlement Performance. Step-changes in NHH volumes. Increase in reported volumes from excessively large Annualised Advances (AAs) and Estimates of Annual Consumption (EACs). Aggregated consumption or generation from relevant CCC IDs trends differently to other elements of the overall ADR calculation	Elexon monitors Suppliers’ Settlement Performance and deploys PATs such as Error and Failure Resolution (EFR) as necessary to address poor performance. Elexon notifies Suppliers of the proportion of their NHH volumes Settled on excessively large AAs and EACs. BSC Audit	DAT-02, DAT-03
DAs do not submit sufficient data from Metering Systems into Settlement ("DA Defaults")	Supplier	Step-changes in HH Settlement Performance, volumes and MSID counts	SVAA notifies Elexon of DA Defaults	DAT-03
Metered data is incorrect due to a fault with one or more Metering Systems, or an error in the Meter Technical Details or other standing data for one or more Metering Systems used to calculate volumes	Supplier	Unexplained step-changes in aggregated consumption or generation from relevant CCC IDs. Aggregated consumption or generation from relevant CCC IDs trends differently to other elements of the overall ADR calculation	BSC Audit. TAM Audit (HH MC C Controls only)	REG-01, REG-03, MET-01, MET-02, MET-03, MET-04
LDSO uses a non-Compliant methodology to calculate LLFs	LDSO	Unexplained step-changes in aggregated line losses from relevant CCC IDs. Aggregated line losses from relevant CCC IDs trend differently to other elements of the overall GCF calculation	LLF Audit	CEN-01
DA applies LLFs incorrectly	Supplier	Unexplained step-changes in aggregated line losses from relevant CCC IDs. Aggregated line losses from relevant CCC IDs trend differently to other elements of the overall GCF calculation	BSC Audit	DAT-03
Energy theft is detected, but volumes are not reported into Settlement	Supplier	ADR trends above tolerance. GSPGT trends differently to other elements of the overall ADR calculation	BSC Audit	DAT-05

ADR Investigation Checklist

Where ADR is trending out of tolerance, Elexon begins an investigation process to determine the root cause of any error in Settlement.

A high-level summary of this process is provided in the checklist included as Appendix 1, below.

Elexon will include an updated version of this checklist in the Trading Operations Report each month for each ADR Anomaly it is investigating, until any Settlement Error has been detected and rectified or until ADR has trended within tolerance at R2 and later for at least 12 months.

Potential Causes of ADR Anomalies other than Settlement Error

There are several other potential causes of ADR Anomalies that do not result from incorrect data or involve a non-Compliance with the provisions of the BSC and are therefore not Settlement Errors.

Any Settlement inaccuracy resulting from the following is therefore regarded as inherent to the current Trading Arrangements, and any cost is mutualised between Suppliers through GCF.

Profiling Accuracy Drops Below 1.5%

The tolerance boundaries assume that profiling (including the Scaling Weights applied in calculating GCF) is accurate to within 1.5% over the course of a year.

In the event this was no longer true in one or more GSP Groups, ADR could trend outside of tolerance even if all Suppliers were entering compliant amounts of actual data into Settlement with perfect accuracy.

Profiling assumes that consumers use energy in a broadly consistent way both with other consumers and over time. It also relies on Suppliers correctly identifying sufficient numbers of representative consumers and obtaining their Half Hourly consumption data in order to provide a statistical basis for the profiles.

If consumers change the way in which they use energy, if consumers become less consistent with each other in their usage and/or if there is a smaller sample of data available with which to build a profile, profiling is likely to become less accurate and GCFs (and ADR) may trend further away from one.

LLF Calculations are Compliant, but not Accurate

If an LDSO calculates LLFs using a methodology that is compliant with the Code but no longer accurately reflects energy lost in their Distribution System, any over- or under-accounting of losses will prompt GCFs to fall or rise respectively to compensate for this.

Undetected Energy Theft

Undetected energy theft will push GCF and ADR upward, as the energy will be reflected in GSP Group Take but not in SVA Volumes.

Energy theft is suspected to have increased in recent years. Elexon is currently working to improve its engagement with the Retail Energy Code (REC) and United Kingdom Revenue Protection Agency (UKRPA) on this issue to establish how best to quantify the Settlement impact.

Microgeneration Spill

There is no BSC Obligation for generation from Small Scale Third Party Generating Plant (for example, solar panels or wind turbines with a capacity less than 30kW) to be recorded in Settlement.

Typically, the operators of such equipment use the energy themselves. However, if excess energy “spills” onto the Distribution System overall CCC volumes will be too high as Export volumes will be under-accounted, pushing GCF and ADR downward.

Do you need more information?

For all SVA Parties, your OSM is your first point of contact for Performance Assurance queries and is available to support you. If you’re not sure who they are, check the BSC Signatories and Qualified Persons page of our website.

For all other interested Parties, please raise a ticket through Elexon Support.

Find out more about the Performance Assurance Framework on the Elexon website.

More information about specific BSC Processes and managing the Risks associated with them can be found in Elexon’s Digital BSC, especially the BSC Procedures (BSCPs) and Guidance Notes.

For any other information please raise a ticket through Elexon Support.

Intellectual Property Rights, Copyright and Disclaimer

The copyright and other intellectual property rights in this document are vested in Elexon or appear with the consent of the copyright owner. These materials are made available for you for the purposes of your participation in the electricity industry. If you have an interest in the electricity industry, you may view, download, copy, distribute, modify, transmit, publish, sell or create derivative works (in whatever format) from this document or in other cases use for personal academic or other non-commercial purposes. All copyright and other proprietary notices contained in the document must be retained on any copy you make.

All other rights of the copyright owner not expressly dealt with above are reserved.

No representation, warranty or guarantee is made that the information in this document is accurate or complete. While care is taken in the collection and provision of this information, Elexon Limited shall not be liable for any errors, omissions, misstatements or mistakes in any information or damages resulting from the use of this information or action taken in reliance on it.

Appendix 1: ADR Investigation Checklist

Affected GSP Group	Approximate Start Date

Potential Root Cause	Check	Yes/No?	Notes/Further Actions
The SVAA has calculated ADR incorrectly	Does the ADR value provided by the SVAA equal YMNHHC/PMNHHC?
The SVAA has calculated YMNHHC incorrectly	Does the YMNHHC value provided by the SVAA match the value of GSPGT provided by the CDCA (where this is correct) minus the annual sum of metered volumes and line losses for CCC IDs associated with HH Metering Systems and UMS?
The SVAA has calculated PMNHHC incorrectly	Does the YPNHHC value provided by the SVAA match the annual sum of metered volumes and line losses for CCC IDs associated with NHH Metering Systems and UMS
The CDCA has calculated GSPGT incorrectly	Does the GSPGT value provided by the CDCA match the sum of relevant CVA metered volumes in line with the GSP Group Aggregation Rule?
The Aggregation Rule used by the CDCA to calculate GSPGT is incorrect	Is the GSP Group Aggregation Rule held by Elexon correct? Has the correct Group Aggregation Rule been provided to the CDCA?
The Aggregation Rules used by the CDCA to calculate volumes for one or more VAUs are incorrect	Are the Aggregation Rules for relevant CVA Metering Systems Correct? Have the correct Metering System Aggregation rules been provided to the CDCA? Are the CDCA using the correct Metering System Aggregation Rules?
VAU volumes are incorrect due to a fault with one or more Metering Systems, or an error in the Meter Technical Details (MTDs) or other standing data for one or more Metering Systems	Is annualised GSPGT trending differently to other elements of the overall ADR calculation? Has there been a step-change in GSPGT consistent with the direction and timeframe of the anomaly? Has there been a step-change in metered volumes (including direction of flow) at any of the relevant CVA Metering Systems consistent with the direction and timeframe of the anomaly? Have the TAA carried out onsite audits of the relevant CVA Metering Systems since the date at which ADR began to trend away from one or sharply changed direction? Are there any outstanding faults with any of the relevant CVA Metering Systems consistent with the direction, scale and timeframe of the anomaly?
VAU volumes are incorrect due to prolonged estimation at one or more Metering Systems	Has metering data for any of the relevant CVA Metering Systems been estimated for a prolonged period? Has this estimation resulted in a step-change in metered volumes (including direction of flow) consistent with the direction, scale and timeframe of the anomaly?
VAU volumes for one or more Metering Systems have been incorrectly estimated by the CDCA	Where estimated data is being returned for a relevant CVA Metering System, are the CDCA using the correct estimation method as specified by the Code? Has this estimation resulted in a step-change in metered volumes (including direction of flow) consistent with the direction, scale and timeframe of the anomaly?
Aggregate SVA metered volumes and/or line losses for one or more Measurement Classes are incorrect	Is the annual sum of metered volumes and/or line losses for the CCC IDs associated with a particular class of Metering System or UMS trending differently to other elements of the overall ADR calculation? Has there been a step-change in one or more of these aggregate volumes consistent with the direction, scale and timeframe of the anomaly?

Appendix 2: GSP Groups

GSP Group	LDSO	LDSO Market Participant ID (MPID)	Former Regional Electricity Board
_A	Eastern Power Networks plc	EELC	Eastern ELeCtricity Board
_B	National Grid Electricity Distribution (East Midlands)	EMEB	East Midlands Electricity Board
_C	London Power Networks Plc	LOND	LONDon Electricity Board
_D	SP Manweb Plc	MANW	Merseyside And North Wales Electricity Board
_E	National Grid Electricity Distribution (West Midlands)	MIDE	MIDlands Electricity Board
_F	Northern Powergrid (Northeast) Plc	NEEB	North Eastern Electricity Board
_G	Electricity North West Limited	NORW	NORth Western Electricity Board
_H	Southern Electric Power Distribution Plc	SOUT	SOUThern Electricity Board
_J	South Eastern Power Networks Plc	SEEB	South Eastern Electricity Board
_K	National Grid Electricity Distribution (South Wales)	SWAE	South Wales Electricity Board
_L	National Grid Electricity Distribution (South West)	SWEB	South Western Electricity Board
_M	Northern Powergrid (Yorkshire) Plc	YELG	Yorkshire ELectricity Group (formerly the Yorkshire Electricity Board)
_N	SP Distribution Plc	SPOW	Scottish POWer (formerly the South of Scotland Electricity Board)
_P	Scottish Hydro Electric Power Distribution Ltd	HYDE	North of Scotland HYDro-Electric Board

Appendix 3: VAU Aggregation Rule Example

An Aggregation Rule is a mathematical rule to calculate net flow (Metered Volume) to/from Volume Allocation Units (e.g. GSPs, GSP Groups, and relevant (i.e. CVA) BM Units, per Settlement Period, ‘as at’ the Transmission System Boundary.

Aggregation Rule for a VAU with a single circuit: Metered Volume = (AE – AI)
Aggregation Rule for a VAU with a two circuits: Metered Volume = (AE – AI) + (AE – AI)
Aggregation Rule for a VAU with a single circuit but metering above another VAU with a single (metered) circuit: Metered Volume = (AE – AI) - (AE – AI)

Example. A GSP Group has two GSPs, one DSCP and one embedded ‘CVA’ BM Unit:

GSP1 Metered Volume = (AE-AI)
GSP2 Metered Volume = (AE-AI)
DSCP1 Metered Volume = (AE-AI)
E_BM Unit Metered Volume = (AE x LLF1 – AI x LLF2)
GSP Group Metered Volume = GSP1 + GSP2… +/- DSCP1…
GSP Group Take Metered Volume = GSP Group Metered Volume – E_BM Units

AE: Active Export

AI: Active Import

LLF: Line Loss Factor

Appendix 4: List of CCC IDs

CCC ID	Data Aggregation Type	Measurement Class	Actual or Estimated	Type of Consumption or Generation	GSP Group Scaling Factor
17	NHH	A	Estimated	Metered consumption	1
18	NHH	A	Actual	Metered consumption	1
20	NHH	A	Estimated	Metering system non-specific line losses for metered consumption	1.2
21	NHH	A	Actual	Metering system non-specific line losses for metered consumption	1.2
32	NHH	A	Estimated	Metered generation	0
33	NHH	A	Actual	Metered generation	0
34	NHH	A	Estimated	Metering system non-specific line losses for metered generation	0
35	NHH	A	Actual	Metering system non-specific line losses for metered generation	0
19	NHH	B	Estimated	Unmetered consumption	1
22	NHH	B	Estimated	Metering system non-specific line losses for unmetered consumption	1.2
1	HH	C	Actual	Metered consumption	0
3	HH	C	Actual	Metering system specific line losses for metered consumption	0
4	HH	C	Actual	Metering system non-specific line losses for metered consumption	0
6	HH	C	Actual	Metered generation	0
7	HH	C	Actual	Metering system specific line losses for metered generation	0
8	HH	C	Actual	Metering system non-specific line losses for metered generation	0
9	HH	C	Estimated	Metered consumption	0
11	HH	C	Estimated	Metering system specific line losses for metered consumption	0
12	HH	C	Estimated	Metering system non-specific line losses for metered consumption	0
14	HH	C	Estimated	Metered generation	0
15	HH	C	Estimated	Metering system specific line losses for metered generation	0
16	HH	C	Estimated	Metering system non-specific line losses for metered generation	0
2	HH	D	Actual	Unmetered consumption	0
5	HH	D	Actual	Metering system non-specific line losses for unmetered consumption	0
10	HH	D	Estimated	Unmetered consumption	0
13	HH	D	Estimated	Metering system non-specific line losses for unmetered consumption	0
23	HH	E	Actual	Metered consumption	0
25	HH	E	Actual	Metering system specific line losses for metered consumption	0
26	HH	E	Actual	Metering system non-specific line losses for metered consumption	0
28	HH	E	Estimated	Metered consumption	0
30	HH	E	Estimated	Metering system specific line losses for metered consumption	0
31	HH	E	Estimated	Metering system non-specific line losses for metered consumption	0
36	HH	E	Actual	Metered generation	0
37	HH	E	Actual	Metering system specific line losses for metered generation	0
38	HH	E	Actual	Metering system non-specific line losses for metered generation	0
39	HH	E	Estimated	Metered generation	0
40	HH	E	Estimated	Metering system specific line losses for metered generation	0
41	HH	E	Estimated	Metering system non-specific line losses for metered generation	0
42	HH	F	Actual	Metered consumption	1
43	HH	F	Actual	Metering system specific line losses for metered consumption	1.2
44	HH	F	Actual	Metering system non-specific line losses for metered consumption	1.2
45	HH	F	Estimated	Metered consumption	1
46	HH	F	Estimated	Metering system specific line losses for metered consumption	1.2
47	HH	F	Estimated	Metering system non-specific line losses for metered consumption	1.2
48	HH	F	Actual	Metered generation	0
49	HH	F	Actual	Metering system specific line losses for metered generation	0
50	HH	F	Actual	Metering system non-specific line losses for metered generation	0
51	HH	F	Estimated	Metered generation	0
52	HH	F	Estimated	Metering system specific line losses for metered generation	0
53	HH	F	Estimated	Metering system non-specific line losses for metered generation	0
54	HH	G	Actual	Metered consumption	1
55	HH	G	Actual	Metering system specific line losses for metered consumption	1.2
56	HH	G	Actual	Metering system non-specific line losses for metered consumption	1.2
57	HH	G	Estimated	Metered consumption	1
58	HH	G	Estimated	Metering system specific line losses for metered consumption	1.2
59	HH	G	Estimated	Metering system non-specific line losses for metered consumption	1.2
60	HH	G	Actual	Metered generation	0
61	HH	G	Actual	Metering system specific line losses for metered generation	0
62	HH	G	Actual	Metering system non-specific line losses for metered generation	0
63	HH	G	Estimated	Metered generation	0
64	HH	G	Estimated	Metering system specific line losses for metered generation	0
65	HH	G	Estimated	Metering system non-specific line losses for metered generation	0

1 The SVA TAM Audit Sample only provides sufficient data to assess the strength of controls for SVA MC C Metering at a market level. It is not a robust method for detecting individual Metering Errors or process failures at specific Parties or Party Agents. By contrast, the CVA TAA Audit Sample focusses on the detection of individual Metering Error as a primary aim due to the significantly smaller metering population.

CONTENTS

Draft Elexon ADR Guidance Note V0.1

What this document covers