Balancing and Settlement Code Code of Practice One CODE OF PRACTICE FOR THE METERING OF CIRCUITS WITH A RATED CAPACITY EXCEEDING 100MVA FOR SETTLEMENT PURPOSES Issue 3 Version 18.0 DATE: 29 February 2024 |
CODE OF PRACTICE FOR THE METERING OF CIRCUITS WITH A RATED CAPACITY EXCEEDING 100MVA FOR SETTLEMENT PURPOSES.
1. Reference is made to the Balancing and Settlement Code for the Electricity Industry in Great Britain, and in particular, to the definition of “Code of Practice” in Annex X-1 thereof.
2. This is Code of Practice One, Issue 3, Version 18.0.
3. This Code of Practice shall apply to Metering Systems comprising Metering Equipment that are subject to the requirements of Section L of the Balancing and Settlement Code.
4. This Code of Practice is effective from 29 February 2024.
5. This Code of Practice has been approved by the Panel.
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Issue | Version | Date | Description of Changes | Changes Included | Mods/ Panel/ Committee Refs |
Draft | 0.10 | 18/3/93 | Recommended to PEC; MSC | | |
1 | 1.0 | 15/4/93 | Endorsed by PEC; CoP WG | | |
1 | 1.0 | Code Effective Date | Re-badging of Code of Practice One for the implementation of the Balancing and Settlement Code; BSCCo | | Panel 16/11/00 (Paper 07/003) |
1 | 2.0 | BETTA Effective Date | Rebadging changes for the CVA Feb 05 Release; BSCCo | BETTA 6.3 | |
2 | 3.0 | 23/02/06 | February 06 Release; BSCCo | CP1051 | ISG55/002 |
2 | 4.0 | 06/11/08 | November 08 Release; BSCCo | CP1238 | ISG8801 SVG88/02 |
2 | 5.0 | 25/06/09 | June 09 Release; BSCCo | CP1264 | ISG94/01 SVG94/02 |
2 | 6.0 | 20/11/09 | P238 Modification; BSCCo | P238 | Panel 160/05 |
2 | 7.0 | 26/11/09 | P230 Modification; BSCCo | P230 | Panel |
2 | 8.0 | 24/06/10 | June 10 Release | CP1324 | ISG111/03 |
2 | 9.0 | 23/02/12 | February 2012 Release | P266 | ISG/130/08 |
2 | 10.0 | 26/02/15 | February 2015 Release | CP1422 | ISG163/01 SVG166/06 |
2 | 11.0 | 23/02/17 | February 2017 Release | CP1470 | ISG185/02 SVG188/04 |
2 | 12.0 | 02/11/17 | November 2017 Release | CP1479 | Panel 264/11 |
| | | | CP1485 | ISG194/06 |
2 | 13.0 | 27/06/19 | June 2019 Release | CP1508 | SVG213/04 ISG210/02 |
3 | 14.0 | 30/06/22 | June 2022 Release | CP1527, CP1550, CP1554 | ISG248/07, SVG233/02, ISG231/01, ISG249/09, SVG251/09 |
3 | 15.0 | 17/11/22 | November 2022 Special Release | P437 | Panel 331/04 |
3 | 16.0 | 29/06/23 | June 2023 Standard Release | CP1571, CP1572 | SVG263/03 ISG261/04 SVG263/04 ISG261/05 |
3 | 17.0 | 02/11/23 | November 2023 Standard Release | P453, CP1575 | Panel 338/03, ISG266/04 |
3 | 18.0 | 29/02/24 | February 2024 Standard Release | CP1586 | SVG275/02 ISG273/03 |
CODE OF PRACTICE FOR THE METERING OF CIRCUITS WITH A RATED CAPACITY EXCEEDING 100MVA FOR SETTLEMENT PURPOSES.
This Code of Practice defines the minimum requirements for the Metering Equipment required for the measurement and recording of electricity transfers occuring at the relevant Defined Metering Points (DMPs) where the rated circuit capacity, at Actual Metering Points (AMPs), exceeds 100MVA.
For the purpose of this Code of Practice the rated circuit capacity in MVA shall be determined by the lowest rated primary plant (eg transformer rating, line rating, etc) of the circuit (this does not include the capacity of the load or generation connected to that circuit) at the AMP. The Metering Equipment provision and accuracy requirements shall anticipate any future up-rating consistent with the installed primary plant. The primary plant maximum continuous ratings shall be used in this assessment.
For the purpose of this Code of Practice, the use of summation current transformers shall not be permitted. The use of interposing current transformers is permitted providing the overall Metering System accuracy is maintained.
Where a material change to a Metering System takes place, then this Metering System must be modified to comply with the most up to date version of this Code of Practice. Changes to a Metering System are considered to be material where they constitute a change to:
(i) Switchgear containing measurement transformers; and/or
(ii) The primary plant associated with the Metering System i.e. measurement transformers.
Where a Metering Dispensation applies and where the AMP is not at the DMP, a material change affecting the DMP may not necessarily affect the Metering System at the AMP.
BSCCo shall retain copies of, inter alia, this Code of Practice together with copies of all documents referred to in it, in accordance with the provisions of the Balancing and Settlement Code (“the Code”).
This Code of Practice states the practices that shall be employed, and the facilities that shall be provided for the measurement and recording of the quantities required for Settlement purposes on each circuit where the rated capacity, at the AMP, exceeds 100MVA.
For the avoidance of doubt, where the DMP, as set out in Appendix A, and the AMP do not coincide, the relevant Code of Practice is associated with the circuit that is being metered (located at the AMP), as opposed to the relevant Code of Practice associated with the circuit at the DMP.
It derives force from the Code, and in particular the metering provisions (Section L), to which reference should be made. It should also be read in conjunction with any relevant BSC Procedures.
Metering Equipment that meets the requirements of this Code of Practice is also applicable where the Registrant is required by its Supply Licence (and as referenced in Section L 3.2.6) to install Metering Equipment that is capable of providing measured electricity consumption data for multiple periods (at least half hourly) and providing the Registrant with remote access to such data.
This Code of Practice does not contain the calibration, testing and commissioning requirements for Metering Equipment used for Settlement purposes. These requirements are detailed in Code of Practice Four – “Code of Practice for Calibration, Testing and Commissioning Requirements for Metering Equipment for Settlement Purposes”.
Metering Dispensations from the requirements of this Code of Practice may be sought in accordance with the Code and BSCP32.
Meters and Outstations referred to in this Code of Practice shall only achieve successful compliance in respect of any testing detailed in this Code of Practice if the requirements set out in accordance with BSCP601 are also observed and successfully completed or a valid Metering Dispensation has been granted covering any departure from the requirements as detailed in this Code of Practice.
In the event of an inconsistency between the provisions of this Code of Practice and the Code, the provisions of the Code shall prevail.
The following documents are referred to in the text, except in relation to measurement transformers where one of the conditions, set out in Section 5.1, is met:-
BS EN/IEC 62053-22 | Electricity metering equipment Particular requirements. Part 22: Static meters for AC active energy (classes 0.1S, 0.2S and 0.5S) |
BS EN/IEC 62053-23 | Electricity metering equipment Particular requirements. Part 23: Static meters for reactive energy (classes 2 and 3) |
BS EN/IEC 62056-21 | Electricity Metering. Data exchange for meter reading, tariff and load control. Direct local data exchange |
BS EN/IEC 61869-4 | Instrument transformers. Part 4: Additional requirements for combined transformers |
BS EN/IEC 61869-2 | Instrument transformers. Part 2: Additional requirements for current transformers |
BS EN/IEC 61869-3 | Instrument transformers. Part 3: Additional requirements for inductive voltage transformers |
Balancing and Settlement Code | Section X; Annex X-1 and Section L and BSC Procedures |
Code of Practice Four | Code of Practice for Calibration, Testing and Commissioning Requirements for Metering Equipment for Settlement Purposes |
BSC Procedures | BSCP06, BSCP32, BSCP75, BSCP502, BSCP601 |
Electricity Act 1989 | Schedule 7 as amended by Schedule 1 to the Competition and Services (Utilities) Act 1992. |
Retail Energy Code or REC | As per the term “Retail Energy Code” in each Supply Licence granted under Section 6 of the Electricity Act 1989. |
REC Metering Operations Schedule | Schedule 14 of the REC on obligations in respect of metering operations. |
3. DEFINITIONS AND INTERPRETATIONS
Save as otherwise expressly provided herein, words and expressions used in this Code of Practice shall have the meanings attributed to them in the Code and are included for the purpose of clarification.
Note: * indicates definitions in the Code.
Note: † indicates definitions which supplement or complement those in the Code.
Note: ‡ indicates definitions specific to this Code of Practice
Active Energy means the electrical energy produced, flowing or supplied by an electrical circuit during a time interval, and being the integral with respect to time of the instantaneous Active Power, measured in units of watt-hours or standard multiples thereof.
Active Power means the product of voltage and the in-phase component of alternating current measured in units of watts and standard multiples thereof, that is:-
3.3 Actual Metering Point ‡
Actual Metering Point means the physical location at which electricity is metered.
Apparent Energy means the integral with respect to time of the Apparent Power.
Apparent Power means the product of voltage and current measured in units of voltamperes and standard multiples thereof, that is:-
Boundary Point means a point at which any Plant or Apparatus not forming part of the Total System is connected to the Total System.
3.7 Central Data Collection Agent (CDCA) *
Central Data Collection Agent means the BSC Agent for Central Data Collection in accordance with Section E of the Code.
Communication Line means a line or link whose components are dedicated to a single Outstation System. A Communication Line shall be identified by a unique number, e.g. CTN line number 123, PSTN line number 321 or IP address 555. Communication Lines may comprise electrical circuits, optical fibres, radio links, or any other permitted media which allows data to be collected remotely on demand by a Data Collector or Meter Operator using an approved protocol.
CTN means the Electricity Supply Industry (ESI) corporate telephone network.
CVA means "Central Volume Allocation"
CVA Customer means any customer, receiving electricity directly from the Transmission System, irrespective of from whom it is supplied.
3.12 Defined Metering Point ‡
Defined Metering Point means the physical location at which the overall accuracy requirement as stated in this Code of Practice are to be met. The Defined Metering Points are identified in Appendix A and relate to Boundary Points and System Connection Points.
Demand Period means the period over which Active Energy, Reactive Energy or Apparent Energy are integrated to produce Demand Values. For Settlement purposes, each Demand Period shall be of 30 minutes duration, one of which shall finish at 24:00 hours.
Demand Values means, expressed in MW, Mvar or MVA, twice the value of MWh, Mvarh or MVAh recorded during any Demand Period. The Demand Values are half hour demands and these are identified by the time of the end of the Demand Period.
"electricity" means Active Energy and Reactive Energy.
Export means, for the purposes of this Code of Practice, an electricity flow as indicated in Figure 1 of Appendix B.
Import means, for the purposes of this Code of Practice, an electricity flow as indicated in Figure 1 of Appendix B.
3.18 Interrogation Unit ‡
Interrogation Unit means a Hand Held Unit “HHU” (also known as Local Interrogation Unit “LIU”) or portable computer which can enter Metering Equipment parameters and extract information from the Metering Equipment and store this for later retrieval.
3.19 Licensed Distribution System Operator (LDSO) *
Licensed Distribution System Operator means a Party which holds a Distribution Licence in respect of distribution activities in Great Britain, acting in that capacity.
Meter means a device for measuring Active Energy and/or Reactive Energy.
3.21 Metering Equipment *
Metering Equipment means Meters, measurement transformers (voltage, current and combination units), metering protection equipment including alarms, circuitry, associated Communications Equipment and Outstation and wiring.
Meter Register means a device, normally associated with a Meter, from which it is possible to obtain a reading of the amount of Active Energy, or the amount of Reactive Energy that has been supplied by a circuit.
Has the meaning given to that term in the Grid Code.
3.24 Offshore Power Park Module *
Has the meaning given to that term in the Grid Code.
Outstation means equipment which receives and stores data from a Meter(s) for the purpose, inter-alia, of transfer of that metering data to the Central Data Collection Agent (CDCA) or a Data Collector as the case may be and which may perform some processing before such transfer and may be in one or more separate units or may be integral with the Meter.
Outstation System means one or more Outstations linked to a single Communication Line.
PSTN means the public switched telephone network.
For Meters with integral Outstations: ‘Password’ means a string of characters of length no less than six characters and no more than twelve characters, where each character is a case insensitive or sensitive alpha character (A to Z) or a digit (0 to 9) or the underscore character (_). Passwords must have a minimum of 2,000,000 combinations, for example six characters if composed of any alphanumeric characters or eight characters if composed only of hexadecimal characters (0 to F). The characters of a hexadecimal password must be in upper case.
For separate Outstations: a Password may be described as above for integral Outstations or a single password of any format.
3.29 Rated Measuring Current ‡
Rated Measuring Current means the rated primary current of the current transformers in primary plant used for the purposes of measurement.
Reactive Energy means the integral with respect to time of the Reactive Power and for the purpose of the Code, is comprised of Active Export Related Reactive Energy and Active Import Related Reactive Energy.
Reactive Power means the product of voltage and current and the sine of the phase angle between them, measured in units of voltamperes reactive and standard multiples thereof;
means, in relation to a Metering System, the person for the time being registered in CMRS or (as the case may be) SMRS in respect of that Metering System pursuant to Section K of the Balancing and Settlement Code.
3.33 Settlement Instation ‡
Settlement Instation means a computer based system which collects or receives data on a routine basis from selected Outstation by the Central Data Collection Agent or (as the case may be) a relevant Data Collector.
3.34 Single Line Diagram (SLD) ‡
SLD means simplified notation for representing a three-phase power system that must show the location of all relevant circuits and the Metering Equipment associated with a site.
SVA means "Supplier Volume Allocation".
means a person to whom electrical power is provided, whether or not that person is the provider of that electrical power; and where that electrical power is measured by a SVA Metering System.
3.37 SVA Meter Operator Agent *
SVA Meter Operator Agent has the meaning given to the term "Metering Equipment Manager" in the REC, to the extent that the Metering Equipment Manager has been appointed by a Supplier.
3.38 Systems Connection Point *
Systems Connection Point means a point of connection (whether consisting of one or more circuits) between two or more Systems excluding:
a point of connection between Distribution Systems in the same GSP Group; and
a point of connection between Offshore Transmission System User Assets and the Transmission System;
4.1 Measured Quantities and Demand Values for Metering Systems Registered in CMRS
The following measured quantities and Demand Values are for use with CVA Metering Systems.
4.1.1 Measured Quantities
For each separate circuit the following energy measurements are required for Settlement purposes:-
For each Demand Period for each circuit the following Demand Values shall be provided:-
4.2 Measured Quantities and Demand Values for Metering Systems Registered in SMRS
SVA Metering Systems shall use units a factor of 103 smaller than CVA i.e. kWh rather than MWh.
4.2.1 Measured Quantities
For each separate circuit the following energy measurements are required for Settlement purposes:-
(iii) Active Import related Import kvarh
(iv) Active Import related Export kvarh
(v) Active Export related Import kvarh
(vi) Active Export related Export kvarh
For each Demand Period for each circuit the following Demand Values shall be provided:-
(iii) Active Import related Import kvar
(iv) Active Import related Export kvar
(v) Active Export related Import kvar
(vi) Active Export related Export kvar
4.3 Accuracy Requirements
The overall accuracy of the energy measurements at or referred to the Defined Metering Point shall at all times be within the limits of error as shown:-
CONDITION | LIMIT OF ERRORS AT STATED SYSTEM POWER FACTOR |
Current expressed as a percentage of Rated Measuring Current | Power Factor | Limits of Error |
120% to 10% inclusive Below 10% to 5% Below 5% to 1% 120% to 10% inclusive | 1 1 1 0.5 lag and 0.8 lead | + 0.5% + 0.7% + 1.5% + 1.0% |
CONDITION | LIMIT OF ERRORS AT STATED SYSTEM POWER FACTOR |
Current expressed as a percentage of Rated Measuring Current | Power Factor | Limits of Error |
120% to 10% inclusive 120% to 20% inclusive | Zero 0.866 lag and 0.866 lead | + 4.0% + 5.0% |
These limits of error for both (i) and (ii) above shall apply at the reference conditions defined in the appropriate Meter specification.
Where Plant operating conditions mean the percentage of Rated Measuring Current and/or system power factor are outside the combinations specified in the overall accuracy tables for (i) and (ii), care must be taken to ensure the actual errors are considered at those Plant operating conditions. For example, where a site which normally Exports large quantities of Active Energy, but, when not generating, Imports Active Energy at a percentage of Rated Measuring Current below 1%, irrespective of the power factor. This could also mean the Active Energy Meter and the Reactive Energy Meter are inaccurate. If necessary, designers should take measures, wherever reasonably practicable, to ensure the actual errors are within the nearest limits of error specified in the relevant overall accuracy table, by for example, the use of more accurate Metering Equipment than specified in this Code of Practice or the selection of a suitable current transformer ratio closely aligned to the maximum primary current for the relevant circuit.
Evidence to verify that these overall accuracy requirements are met shall be available for inspection by the Panel or Technical Assurance Agent.
4.3.2 Compensation for Measurement Transformer Error
To achieve the overall accuracy requirements it may be necessary to compensate Meters for the error of the measurement transformers and the associated leads to the Meters. Values of the compensation shall be recorded and evidence to justify the compensation criteria, including wherever possible test certificates, shall be available for inspection by the Panel or Technical Assurance Agent.
4.3.3 Compensation for Power Transformer and Line Losses
Subject to Appendix A paragraph 5(ii), where the AMP and the DMP do not coincide and accuracy compensation for power transformer and/or cable/line losses and/or busbar losses is required to be applied to meet the overall accuracy limits of error requirements in paragraph 4.3.1 at the DMP then a Metering Dispensation shall be applied for.
Where the AMP and DMP do not coincide, but no accuracy compensation for power transformer and/or cable/line and/or busbar losses is required to be applied to meet overall accuracy limits of error at the DMP (i.e. the distance between the AMP and DMP does not introduce a large enough error to cause the Metering System’s overall accuracy to be outside of the limits of error detailed in paragraph 4.3.1 of this relevant Code of Practice), then a Metering Dispensation shall not be required. The Registrant shall ensure that values of the overall accuracy calculation shall be recorded and evidence to justify no accuracy compensation being required, including wherever possible test certificates, shall be available for inspection by the Panel or Technical Assurance Agent.
Where Appendix A paragraph 5(ii) applies a Metering Dispensation shall not be required and accuracy compensation for power transformer and/or cable/line and/or busbar losses (for the purpose of Section K1.1.6 of the Code) shall, where necessary, be applied to meet the overall accuracy limits of error required at the DMP.
The accuracy compensation may be achieved either within the Metering Equipment or within the CDCA’s or relevant Data Collector’s software.
Where accuracy compensation is required to be applied the values used shall be validated in accordance with BSCP32 ‘Metering Dispensations’, recorded and supporting evidence to justify the accuracy compensation criteria shall be available for inspection by the Panel or Technical Assurance Agent.
Where the AMP associated with a Settlement Metering System, is below the AMP associated with another Settlement Metering System, a differencing metering arrangement shall be used. For Metering Systems registered in CMRS this shall be done in accordance with BSCP75 ‘Registration of Meter Aggregation Rules For Volume Allocation Units’. For Metering Systems registered in SMRS this shall be done in accordance with the Metering Operations Schedule of the Retail Energy Code (REC) and BSCP502 ‘Half Hourly Data Collection for SVA Metering Systems Registered in SMRS’, via a Complex Site Supplementary Information Form.
5. METERING EQUIPMENT CRITERIA
Although for clarity this Code of Practice identifies separate items of equipment, nothing in it prevents such items being combined to perform the same task provided the requirements of this Code of Practice are met.
Metering Equipment other than outdoor measurement transformers, shall be accommodated in a clean and dry environment.
5.1 Measurement Transformers
All measurement transformers shall be of a wound construction.
For each circuit current transformers (CT) and voltage transformers (VT) shall meet the requirements set out in clauses 5.1.1 and 5.1.2.
The number of CTs provided shall be equal to or one less than the number of primary system conductors. These include the neutral conductor and/or earth conductor where system configurations enable the flow of zero sequence energy. Consideration shall be given as to whether a VT neutral is required to be provided, depending on the number of CTs provided.
Where a measurement transformer has been tested and stamped to an iteration of the applicable BS EN/IEC standard and that differs from the version referenced in this Code of Practice (i.e. BS EN/IEC 61869-2; BS EN/IEC 61869-3; BS EN/IEC 61869-4) measurement transformers may still be used providing the requirements in clauses 4.3.1 and 5.1.3 are met and if one of the following conditions is met:
Additionally, where a combined unit measurement transformer (VT & CT) is provided the ‘Tests for Accuracy’ as covered in BS EN/IEC 61869-4 covering mutual influence effects shall be met.
For Metering Systems that represent low burdens on measurement transformers, consideration shall be given as to whether that operating burden is within the operating range of the measurement transformers. In such cases it may be necessary to add additional burden.
Guidance for the use of multi core cables is provided in Appendix E.
5.1.1 Current Transformers
Two sets of current transformers in accordance with BS EN/IEC 61869-2 and with a minimum standard of accuracy class 0.2S (irrespective of the secondary current rating of the current transformers) shall be provided.
The rated primary current value chosen for the current transformer shall be of a suitable value to ensure, under all running conditions wherever reasonably practicable, that rated Measuring Current (expressed as a percentage) does not fall below 1% or exceed 120%.
The current transformers supplying the main Meters shall be dedicated to that purpose.
Additional burden can be added to the current transformers supplying the main Meters so long as it is only for the purpose of ensuring that overall accuracy of the energy measurements is within the limits of error in paragraph 4.3.1, for example by bringing the total burden within the value from 25 % to 100 % of the rated output that the limits of ratio error and phase displacement are specified for in BS EN/IEC 61869-2.
The current transformers supplying the check Meters may be used for other purposes, and additional burden can be added for the purpose of ensuring that overall accuracy of the energy measurements is within the limits of error in paragraph 4.3.1, for example by bringing the total burden within the value 25% to 100% of the rated output that the limits of ratio error and phase displacement that are specified for in BS EN/IEC61869-2, provided the overall accuracy requirements in paragraph 4.3.1 are met.
Evidence of the value of the additional burden shall be made available for inspection by the Panel or Technical Assurance Agent. The additional burden shall not be modified without prior notification to the Panel, and the evidence of the value of the modified additional burden shall be available for inspection by the Panel or Technical Assurance Agent.
CT test certificates showing errors at the overall working burden or at burdens which enable the working burden errors to be calculated shall be available for inspection by the Panel or Technical Assurance Agent.
The total burden on each current transformer shall not exceed the rated burden of such CT.
5.1.2 Voltage Transformers
There are two options for the provision of voltage transformers (busbar voltage transformers shall only be permitted where the conditions for their use are met):
1.Voltage transformer primary windings shall be connected to the circuit being measured for Settlement purposes. Two voltage transformers or one voltage transformer with two or more secondary winding sets be provided.
The VT secondary winding supplying the main Meters shall be dedicated to that purpose.
Additional burden can be added to the voltage transformers supplying the main Meters so long as it is only for the purpose of ensuring that overall accuracy of the energy measurements is within the limits of error in paragraph 4.3.1, for example by bringing the total burden within the value from 25 % to 100 % of the rated output that the limits of ratio error and phase displacement that are specified for in BS EN/IEC 61869-3.
The VT secondary winding supplying the check Meters may be used for other purposes, and additional burden can be added for the purpose of ensuring that overall accuracy of the energy measurements is within the limits of error in paragraph 4.3.1, for example by bringing the total burden within the value from 25% to 100% of rated output that the limits of ratio error and phase displacement are specified for in BS EN/IEC 61869-3, provided the overall accuracy requirements in clause 4.3.1 are met. ; or
2.Voltage transformer primary windings shall be connected to a busbar that is common to multiple circuits that are being measured for Settlement purposes. The multiple circuits being measured, by the associated current transformers for those circuits, must be connected to the same busbar, which cannot be electrically split, and only where the multiple circuits are connected to that busbar at the same voltage level as it is at the DMP. A voltage transformer with a dedicated secondary winding shall be provided for all of the main metering, and a second voltage transformer with a dedicated secondary winding shall be provided for all of the check metering. Where busbars can be, or are, electrically separated, each busbar section must have a set of voltage transformers each (i.e. a voltage transformer with a dedicated secondary winding shall be provided for all of the main metering and a second voltage transformer with a dedicated secondary winding for all of the check metering, for the circuits connected to that busbar section).
Additional burden can be added to the voltage transformers supplying the Meters so long as it is only for the purpose of ensuring that overall accuracy of the energy measurements is within the limits of error in paragraph 4.3.1, for example by bringing the total burden within the value from 25 % to 100 % of the rated output that the limits of ratio error and phase displacement that are specified for in BS EN/IEC 61869-3.
Where a busbar voltage transformer has other secondary windings, these may be used for other purposes, provided the overall accuracy requirements in clause 4.3.1 are met.
Appendix G shows some examples of arrangements for busbar voltage transformers.
Each voltage transformer secondary winding shall be in accordance with BS EN/IEC 61869-3 and with a mininum standard of accuracy class 0.2
Evidence of the value of any additional burden shall be made available for inspection by the Panel or Technical Assurance Agent Any additional burden shall not be modified without prior notification to the Panel, and evidence of the value of the modified additional burden shall be available for inspection by the Panel or Technical Assurance Agent.
A VT test certificate(s) showing errors at the overall working burden(s) or at burdens which enable the working burden errors to be calculated shall be available for inspection by the Panel or Technical Assurance Agent.
The total burden on each secondary winding of a VT shall not exceed the rated burden of such secondary winding.
Separately fused VT supplies shall be provided for each of the following:-
(c) any additional burden
Such fuses shall be located as close as practicable to the VT.
5.1.3 Monitoring of Voltage Transformers
Monitoring facilities for voltage transformers shall be provided for phase failure of any one or combination of phases.
The phase failure alarm shall remain active so long as the fault condition exists.
The phase failure alarm must be dedicated to the monitoring of voltage transformers and not be combined with any other monitoring of prevailing conditions (such as an alarm monitoring for the condition where there is current being seen by the Meter but no voltage).
Meters combining integral Outstations shall provide for the data to be identified with an alarm indicating phase failure, tagged to the relevant Demand Period(s) and shall be reported via on-line communications and the local Interrogation Unit to the CDCA or Data Collector, as the case may be.
For separate Outstations, an alarm may be used which shall incorporate a time-delay feature so as to avoid spurious operation.a spare channel on the Outstation or any other available means shall be used to transmit the alarm and shall be reported via on-line communications and the local Interrogation Unit to the CDCA or Data Collector, as the case may be.
5.1.4 Measurement Transformers Installed on Existing Circuits
Where circuits, other than those newly installed, are to be metered to this Code of Practice and where the installed measurement transformers do not comply fully with clauses 5.1.1 & 5.1.2, then such measurement transformers may be used providing the requirements in clauses 4.3.1 and 5.1.3 are met.
Separate test terminal blocks or equivalent facilities shall be provided for the main Meters and for the check Meters of each circuit. The test facilities shall be nearby the Meters involved.
The quantities defined in clause 4.1.1 shall be measured by both main and check Meters.
Active Energy Meters shall meet the requirements of BS EN/IEC 62053-22 class 0.2S.
All Meters shall be set to the actual primary and secondary ratings of the measurement transformers and the actual ratios displayed on the display or nameplate of the Meter.
Active Energy Meters shall be configured such that the number of measuring elements is equal to or one less than the number of primary system conductors. and matches the configuration provided for in clause 5.1.
Reactive Energy Meters shall meet the class 2.0 requirements of BS EN/IEC 62053-23.
All Meters shall be labelled or otherwise be readily identifiable in accordance with Appendix B.
All Meters shall include a non-volatile Meter Register of cumulative energy for each measured quantity. The Meter Register(s) shall not roll-over more than once within the normal Meter reading cycle.
Meters which provide data to separate Outstations shall for this purpose provide two outputs per measured quantity.
For Meters using electronic displays due account shall be taken of the obligations of the Central Data Collection Agent (CDCA) or other Data Collectors to obtain Meter readings.
Fusing shall be placed as close as practicable to the VT. In addition, means of isolation shall be provided locally for each Meter, any additional burden, and their associated test facilities in accordance with Appendix C.
5.4 Displays and Facilities for Registrant Information
The Metering Equipment shall display the following primary information (not necessarily simultaneously):
(a) Measured quantities as per clause 4.1.1;
(b) Current time (“UTC”) and date;
(c) Measurement transformer ratios (see clause 5.3); and
(d) Any compensation factor which has been applied for measurement transformer errors and/or system losses, where this is a constant factor applied at security level 3 (i.e. where the Meter is combined with the display and/or Outstation).
Metering Equipment shall be capable of enabling the display of the following, as specified by the Registrant:
(ii) Display capabilities:
(a) Maximum Demand (MD) for kW or MW as appropriate per programmable charging period i.e. monthly or statistical review period;
(b) Maximum Demand (MD) for kVA or MVA as appropriate per programmable charging period i.e. monthly or statistical review period;
(c) Twice the kWh advance or MWh advance as appropriate since the commencement of a current Demand Period (i.e. kW or MW rising demand);
(e) Number of MD resets; and
(f) Multi-rate display sequence as specified by the Registrant with a minimum of 8 rates selectable over the calendar year.
MD shall be resettable at midnight of the last day of the charging period and for part chargeable period demands. If a manual reset button is provided then this shall be sealable.
The Metering Equipment shall be capable of providing the following information locally to the Customer or Registrant configured to their requirements taking account of the measured quantities (see clause 4.1.1):
(i) For active energy in MWh or kWh as appropriate (Import and Export), reactive energy in Mvarh or kvarh as appropriate (Import and Export) – if volt-free contacts are used, then these should use a pulse rate at full load of at least 1000 per Settlement Period with a nominal duration of 80ms per pulse; and
(ii) A 30 minute reset pulse, and if volt-free contacts are used then this pulse should be within a tolerance of ±0.1% of the Demand Period from the volt-free contacts with a minimum duration of 80ms.
Duplicate Outstation Systems shall be provided which can be interrogated by Settlement Instations using independent Communication Lines.
Where separate Outstations are provided these shall each store main and check Meter data for one or more circuits and where practicable shall be configured identically. Separate Outstations storing data from different circuits may be cascaded on to one Communication Line.
Metering Systems comprising Meters with integral Outstations need not store data from the associated main or check Meter providing that each Outstation has separate Communication Lines.
For Metering Systems located Offshore at Offshore Power Park Modules duplicate Outstation Systems with separate Communication Lines shall be provided. Main and check data shall be accessible using either of the separate Communication Lines, or, in the case of integral Outstations each storing only main or check data, each of main and check data shall be accessible using either of the two separate communication lines provided for each Outstation. A single point of failure in the communication path between an instation and an Outstation shall not prevent access to main and check metering data stored in required Outstations. Appendix F shows some examples of arrangements for Offshore Power Park Modules.
The Outstation data shall be to a format and protocol approved by the Panel in accordance with BSCP601.
The Outstation shall have the ability to allow the metering data to be read by instations other than the Settlement Instation provided the requirements of Section 7 of this Code of Practice are satisfied.
Facilities shall be provided to select a relevant demand period from one of the following values:-
30, 20, 15, 10 and 5 minutes with in each case one demand period ending on the hour.
Normally metering data will be collected by the Settlement Instations by a daily interrogation, but repeat collections of metering data shall be possible throughout the Outstation data storage period.
Outstations shall be fitted with an auxiliary terminal that provides for the Outstation’s energisation for remote interrogation purposes. The supply to the auxiliary terminal shall be free of switches and secure, and may be provided from the measurement VT as long as it is separate from the potential measurement circuits.
Where a separate modem associated with the Outstation System is used, then it shall be provided with a secure supply separately fused. Alternatively, line or battery powered modem types may be used.
The Outstations shall provide an alarm output signal via on-line communications and the local Interrogation Unit to the CDCA or Data Collector, as the case may be, in the event of a supply failure.
Data storage facilities for metering data shall be provided as follows:-
(i) A storage capacity of 48 periods per day for a minimum of 90 days for all Demand Values;
(ii) The stored Demand values shall be integer values of kW/MW or kvar/Mvar as appropriate, or pulse counts, and have a resolution of better than +0.1% (at full load);
(iii) The accuracy of the energy values derived from Demand Values shall be within +0.1% (at full load) of the amount of energy measured by the associated Meter;
(iv) The value of any energy measured in a Demand Period but not stored in that Demand Period shall be carried forward to the next Demand Period;
(v) Where a separate Outstation is used, cumulative register values shall be provided in the Outstation which can be set to match and increment with the Meter Registers;
(vi) In the event of an Outstation supply failure, the Outstation shall protect all data stored up to the time of the failure, and maintain the time accuracy in accordance with clause 5.5.2;
(vii) Partial Demand Values, those in which an Outstation supply failure and/or restoration occurs, and zero Demand Values associated with an Outstation supply failure, shall be marked so that the Settlement Instation can identify them;
(viii) To cater for continuous supply failures, the clock, calendar and all data shall be supported for a period of 10 days without an external supply connected;
(ix) Any “read” operation shall not delete or alter any stored metered data; and
(x) An Outstation shall provide any portion of the data stored upon request by an Instation.
(i) The Outstation time shall be set to the Universal Time Clock (UTC) also known as Greenwich Mean Time (GMT). No switching between UTC and British Summer Time (BST) shall occur.
(ii) Time synchronisation of the Outstation shall only be performed by communication with the Settlement Instation.
(iii) The overall limits of error for the time keeping allowing for a failure to communicate with the Outstation for an extended period of 10 days shall be:-
(a) the completion of each Demand Period shall be at a time which is within + 10 seconds of UTC; and
(b) the duration of each Demand period shall be within + 0.1%, except where time synchronisation has occurred in a Demand Period.
5.5.3 Monitoring Facilities
Monitoring facilities shall be provided for each of the following conditions and shall be reported, tagged wherever possible to the relevant Demand Period(s), via the local interrogation facility:-
(i) Error in Outstation functionality;
(ii) Battery monitoring (where battery fitted); and
(iii) Interrogation port access which changes data.
In addition all of the above conditions shall be reported as, at minimum, a common alarm indication via the remote interrogation facility.
For integral Outstations: Outstation(s) shall accommodate both local and remote interrogation facilities, from separate ports.
To prevent unauthorised access to the data in the Metering Equipment a security scheme, as defined below and in Appendix D, shall be incorporated for both local and remote access. Separate security levels shall be provided for the following activities:
(i) Level 1 Password for:
Read-only access to the following metering data, which shall be transferrable on request during the interrogation process:
(b) Demand Values as defined in clause 4.1.2;
(c) Cumulative measured quantities as defined in clause 4.1.1;
(d) Maximum Demand (MD) for kW/MW or kVA/MVA as appropriate per programmable charging period i.e. monthly or statistical review period;
(e) Multi-rate cumulative Active Energy as specified by the Registrant;
(f) Measurement transformer ratios, where appropriate (see clause 5.3);
(g) Measurement transformer error correction factor and/or system loss factor where this is a constant factor applied to the entire dynamic range of the Meter and the Meter is combined with the display and/or Outstation;
(h) Alarm indications; and
(i) Outstation time and date.
(ii) Level 2 Password for:
(a) Corrections to the time and/or date; and
(iii) Level 3 Password for:
(a) Displays and facilities as defined in clause 5.4;
(b) Measurement transformer ratios, as appropriate (see clause 5.3);
(c) Measurement transformer error correction and/or system loss factor where this is a constant factor applied to the entire dynamic range of the Meter and the Meter is combined with the display and/or Outstation; and
(d) Passwords for levels 1, 2 and 3.
In addition it shall be possible to read additional information within the Metering Equipment to enable the programmed information to be confirmed.
(iv) Level 4 Password for:
(a) Calibration of the Metering Equipment;
(b) Setting the measurement transformer ratios, where appropriate (see clause 5.3);
(c) Setting the transformer error correction and/or system loss factors where this is other than a single factor; and
(d) Programming the level 3 Password and the level 4 Password if appropriate.
In addition to the functions specified for each level it shall be feasible to undertake the functions at the preceeding level(s). E.g. at level 3 it shall also be possible to carry out the functions specified at levels 1 and 2. This need not apply at level 4 when access is obtained via removing the cover. Different Passwords shall be utilised for each level, which shall only be circulated in accordance with the relevant BSC Procedure.
For separate Outstations: A Password shall be required to read or change any data.
5.6.1 Local Interrogation
An interrogation port shall be provided for each Outstation which preferably shall be an opto port to BS EN/IEC 62056-21, and with a serial protocol such as BS EN/IEC 62056-21, for the following purposes:-
(i) Commissioning, maintenance and fault finding;
(ii) Transfer of metering data and alarms; and
5.6.2 Remote Interrogation
Remote interrogation shall be provided with error checking of the communications between the Outstation System and the Settlement Instation.
Interrogation of an Outstation shall be possible using one of the following media:-
(i) Switched telephone networks e.g. PSTN or CTN;
(ii) Public data networks e.g. PSN;
(iii) Radio data networks e.g. Paknet or any equivalent;
(iv) Customer's own network;
(v) Mains signalling / power line carrier;
In addition any further media may be used as approved by the Panel.
The actual media employed shall be in accordance with the requirements of the CDCA for CVA Metering Systems and the Supplier for SVA Metering Systems.
The data shall be to a format and protocol approved by the Panel in accordance with BSCP601.
All Metering Equipment shall be capable of being sealed in accordance with BSCP06.
The following BSC Parties shall create, or secure the creation of, a Single Line Diagram (SLD) for all High Voltage (HV) and Extra High Voltage (EHV) connected sites, and any site, irrespective of its connection voltage, that requires a SVA Meter Operator Agent to submit a Complex Site Supplementary Information Form for a SVA Metering System ID.
SLDs shall be created by the:
NETSO for Grid Supply Points and Transmission System Boundary Points, including Interconnectors;
LDSO for Distribution System Connection Points and Distribution System Boundary Points, including Interconnectors; or
Registrant for Transmission System or Distribution System connected Customer or Generator networks, including Complex Sites.
the Boundary Point(s) and/or System Connection Point(s), including the location of each Defined Metering Point(s), where different;
all relevant circuits that have Settlement Metering Equipment that is, or is to be, registered for Settlement purposes and the physical location of the Settlement Metering Equipment (i.e. Actual Metering Point(s)). This includes Metering Equipment located within a Licence Exempt Distribution Network (private network) in an HV/EHV connected site or any Complex Site, irrespective of its connection voltage;
accuracy classes of all Settlement measurement transformers; and
the available ratio(s) of all Settlement measurement transformers and, where multi-ratio, the ratio selected.
An SLD shall be created, or updated, for:
new HV and EHV connected sites;
new connections, irrespective of that connection voltage, at existing HV and EHV connected sites;
existing HV and EHV connected sites with existing CVA Boundary Point Settlement Metering Equipment where any new CVA Settlement Metering Equipment, located within a Licence Exempt Distribution Network (private network), is to be registered for Settlement purposes;
any site, irrespective of its connection voltage, that requires a SVA Meter Operator Agent to submit a Complex Site Supplementary Information Form for a SVA Metering System ID;
material changes to any registered, or to be registered, Settlement measurement transformers (i.e. replacement of current transformers and/or voltage transformers (on a like for like basis or otherwise), or changes to the ratio selected, where multi-ratio, for existing current transformers and/or voltage transformers). Note: Material changes to Settlement Metering Equipment may impact Metering Dispensations; and
where Settlement Metering Equipment for a circuit is de-registered and other existing Settlement Metering Equipment is still required for an HV or EHV site or Complex Site.
The relevant BSC Party shall provide a copy of the SLD in accordance with the relevant BSC Procedure. The SLD shall also be made available, on request, for inspection by the Panel or Technical Assurance Agent.
The Operator may interrogate the Outstations using an Interrogation Unit (IU). The Interrogation Unit may be used for commissioning, maintenance/fault finding and when necessary the retrieval of stored metering data. The data retrieved by the Interrogation Unit shall be compatible with the Settlement Instation.
Additional features may be incorporated within or associated with the Metering Equipment provided but these shall not interfere with or endanger the operation of the Settlement process.
Access to metering data shall be in accordance with the provisions of the Code and the BSC Procedures referred to therein. Such access must not interfere with or endanger the security of the data or the collection process for Settlement purposes.
Access to stored metering data in Outstations shall also be the right of the Registrant and any party who has the permission of the Registrant.
APPENDIX A DEFINED METERING POINTS
For transfers of electricity between the following parties the Defined Metering Point (DMP) shall be at one of the following locations:-
1. For transfers between the Transmission System and a Distribution System operated by a Licensed Distribution System Operator where no other Party(s) are connected to the busbar, the DMP shall be at the point(s) of connection to the Transmission System.
2. For transfers between the Transmission System and a Distribution System operated by a Licensed Distribution System Operator where other Party(s) are connected to the busbar, the DMP shall be at the circuit connections to that Distribution System operated by a Licensed Distribution System Operator.
3. For transfers between the Transmission System and more than one Distribution System operated by a Licensed Distribution System Operator connected to the same busbar, the DMP shall be at the circuit connections of each Distribution System operated by a Licensed Distribution System Operator to such busbar.
4. For transfers between Distribution Systems operated by Licensed Distribution System Operators, not including a connection to the Transmission System, the DMP shall be at the point(s) of connection of the two Distribution Systems operated by Licensed Distribution System Operators.
5. For transfers between the Transmission System and:-
(i) Generating Plant, the DMP shall be at the point(s) of connection of the Generating Plant to the Transmission System.
(ii) An Offshore Power Park Module(s) comprising a single BM Unit, the DMP shall be at the point(s) of connection of the Offshore Power Park Module to the Transmission System. A Party may install Metering Equipment at either:
6. For transfers between a Distribution System operated by a Licensed Distribution System Operator and Generating Plant, the DMP shall be at the point(s) of connection of the generating station to the Distribution System operated by a Licensed Distribution System Operator.
7. For transfers between a Distribution System operated by a Licensed Distribution System Operator and a Customer, the DMP shall be at the point(s) of connection to the Distribution System operated by a Licensed Distribution System Operator.
8. For transfers between the Transmission System and a Customer, the DMP shall be at the point(s) of connection to the Transmission System.
9. For transfers between the Transmission System, or a Distribution System operated by a Licensed Distribution System Operator, and an External System the DMP shall be at the point(s) of connection of that External System to the Transmission System or to the Distribution System operated by a Licensed Distribution System Operator.
10. For transfers between an Offshore Transmission System (or Offshore Transmission System User Assets) and a Distribution System operated by a Licensed Distribution System Operator, the DMP shall be at the point(s) of connection to the Distribution System operated by a Licensed Distribution System Operator.
APPENDIX B LABELLING OF METERS FOR IMPORT AND EXPORT
A standard method of labelling Meters, test blocks, etc is necessary and based on the definitions for Import and Export the required labelling shall be as follows:
Meters or Meter Registers shall be labelled “Import” or “Export” according to the diagram “Figure 1”.
2 REACTIVE ENERGY FOR METERS REGISTERED IN CMRS
Within the context of this code the relationship between Active Energy and Reactive Energy can best be established by means of the power factor. The following table gives the relationship:-
Flow of Active Energy | Power Factor | Flow of Reactive Energy |
Import Import Import Export Export Export | Lagging Leading Unity Lagging Leading Unity | Import Export Zero Export Import Zero |
Meters or Meter Registers for registering Import Reactive Energy should be labelled “Import” and those for registering Export Reactive Energy should be labelled “Export”.
3 REACTIVE ENERGY FOR METERS REGISTERED IN SMRS
Within the context of this code the relationship between Active Energy and Reactive Energy can best be established by means of the power factor. The following table gives the relationship:-
Flow of Active Energy | Power Factor | Flow of Reactive Energy | Additional Information |
Import Import Import Export Export Export | Lagging Leading Unity Lagging Leading Unity | Import Export Zero Export Import Zero | Associated with Active Import Associated with Active Import n/a Associated with Active Export Associated with Active Export n/a |
Meters or Meter Registers for registering Import Reactive Energy should be labelled “Import” and those for registering Export Reactive Energy should be labelled “Export” but with additional information for reactive Meters or Registers identifying the Active Meter or Register it is associated with.
FIGURE 1 IMPORT AND EXPORT ACTIVE ENERGY FLOWS CONVENTION
Import / Export Energy Flow Convention for the labelling of Meters
Import metering measures energy flows away from the Transmission System.
Export metering measures energy flows towards the Transmission System.
Energy flows between Distribution Systems is by bilateral agreement.
Key to abbreviations used in Import / Export Diagram
DIBP Distribution Interconnector Boundary Point
DSCP Distribution System Connection Point
IBP Interconnector Boundary Point
SCP System Connection Point
TSBP Transmission System Boundary Point
The following diagram shows a typical arrangement for the fusing requirements of this Code of Practice, where a Settlement voltage transformer(s) is (are) provided for each circuit. The diagram is non-exhaustive and is provided for reference only.
Figure 1: Fusing arrangements .
The boundary between Meter Operator Equipment and the Transmission/Distribution System Operator is between the local means of isolation and the testing facilities.
The Passwords specified in clause 5.6 shall be subject to the following additional requirements:
(i) The communications protocol employed shall ensure that the Password offered determines the level of access to the data within the Metering Equipment.
(ii) A counter to log the number of illegal attempts (i.e. Password comparison failures) to access Metering Equipment via the local and remote ports shall be incorporated into the log-on process. This counter shall reset to zero at every hour change (i.e. 0100, 0200 etc).
(iii) If the counter reaches 7, then access is prohibited at all levels until the counter resets at the next hour change.
APPENDIX E GUIDANCE FOR THE USE OF MULTI CORE METERING CABLES
Multi core cables are predominantly used to provide CT and VT signals to the Meter. However, such arrangements may cause additional errors that are not readily apparent to the Metering System designer. This guidance provides information that should be considered when using multi core cables for metering, particularly if used over long cable runs.
Consideration shall be given to the cross sectional area of the conductors of multi core cables:
(i) In CT circuits the cabling resistance is likely to represent an appreciable component of the CT burden and care should be taken to ensure that the CT overall burden is not exceeded;
(ii) For the VT circuits, cabling and fuses introduce high volt drop errors. Fuses with a low current rating tend to have a relatively high resistance value and are variable from fuse to fuse. Careful selection of fuses, fuse holders and the doubling of cores can be used to mitigate these effects.
The proximity of CT and VT signals in multi core cables can cause errors due to capacitive coupling from the voltage to the current curcuits. The effect of this coupling is more prevalent at low loads with long cable runs, in particular with 1 amp rated CTs. One possible symptom of this condition is that the Meters may advance under no load conditions (circuit energised but with no load current). This coupling effect may be eliminated by careful allocation of cable core to function, or by running CT and VT signals in separate cables.
APPENDIX F: GUIDANCE FOR THE COMMUNICATION ARRANGEMENTS FOR METERING SYSTEMS LOCATED OFFSHORE AT OFFSHORE POWER PARK MODULES
In this Code of Practice, it is a minimum requirement that two sets of Measurement Transformers be provided, one set feeding main Meters and the other feeding check Meters for each2 measured circuit. It is also a minimum requirement that two Outstations be provided which can be interrogated using independent Communication Lines. For Outstations which are not integral with an associated Meter, both main and check Meter data should be stored on both Outstations. Outstations storing data from different circuits may be cascaded on to one Communication Line as if they were parts of one Outstation.
For Metering Systems located Offshore measuring Offshore Power Park Module export and import, main and check data shall be accessible by either of separate Communication Lines, and a single point of failure in the communication path between an instation and an Outstation shall not prevent access to main and check metering data stored in required Outstations.
Where shared communication network components are used, for example copper wire or optical fibre and associated connectors, routers and switches with Internet Protocol (IP) addressing of end points, the Registrant should ensure that the requirement for independent communication lines is achieved by the existence of sufficient duplication and redundancy to ensure that two or more independent end to end communication paths exist between the instation and Outstation. The following examples show some possible arrangements for guidance, using an optical fibre cable in which at least two of the fibres are independently allocated to settlement metering data in order to satisfy the requirement for independent Communication Lines. Use of more optical fibres within the cable would be preferable.
Example 1 Meters with integral Outstations using optical fibre communications
In this example, there is a single power cable connecting the Offshore Power Park Module to the mainland which incorporates a fibre optic communication cable.
The communication cable contains multiple optical fibres and is used amongst other things to provide communications between the Settlement Instation and the Outstations which are located on the offshore platform. Sufficient optical fibres should be allocated to the Settlement communications to ensure that main and check data can continue to be collected automatically without requirement for physical access to the Offshore Metering Equipment in the event of failure of any individual allocated fibre.
The Meters have integral Outstations each storing main and check data separately. If each Outstation stored data from both main and check Meters then only two Outstations and two Communication Lines would be necessary (OI1 and OI3 or OI2 and OI4) as the failure of either Outstation or Communication Line would not prevent access to both main and check metering data (as in Example 2). However in this example this is not the case therefore additional Communication Lines are required so that there is not a single point of failure. Each Meter has two optical interfaces (OI1, OI2 and OI3, OI4) and each has a unique IP address.
There are two Outstation Systems and four Communication Lines.
This example shows a single optical cable being used but would equally apply to multiple cables or any other communications media such as satellite communications or PSTN.
Example 2 Fibre optic communications using Meters with separate Outstations
In this example, there is a single power cable connecting the Offshore Power Park Module to the mainland which incorporates a fibre optic communication cable.
The communication cable contains multiple optical fibres and is used amongst other things to provide communications between the Settlement Instation and the Outstations which are located on the offshore platform. Sufficient optical fibres should be allocated to the Settlement communications to ensure that main and check data can continue to be collected automatically without requirement for physical access to the Offshore Metering Equipment in the event of failure of any individual allocated fibre.
The Meters transfer readings to both the separate Outstations and each Outstation has one optical interface (OI1 and OI2). Each optical interface has a unique IP address.
There are two Outstation Systems and two Communication Lines.
This example shows a single optical cable being used but would equally apply to multiple cables or any other communications media such as satellite communications or PSTN.
APPENDIX G: GUIDANCE FOR THE USE OF BUSBAR VOLTAGE TRANSFORMERS
In this Code of Practice, it is a minimum requirement that where a set of voltage transformer primary windings connect to a busbar this is only permitted where the following conditions are met:
The busbar is common to the multiple circuits being measured for Settlement purposes;
The busbar cannot be split electrically;
The busbar voltage level is the same voltage level as it is at the DMP;
A voltage transformer is provided with a dedicated secondary winding for the all of the main metering;
A second voltage transformer is provided with a dedicated secondary winding for all of the check metering; and
The total burden on each secondary winding of a voltage transformer shall not exceed the rated burden of such secondary winding.
Where busbars are electrically separate, or can be run split, each separate busbar must have a set of voltage transformers and meet the conditions stated above.
The associated current transformers must be located at the DMP as defined in Appendix A. Where the current transformers are not located at the DMP a Metering Dispensation shall be required, unless the AMP is permitted to be away from the DMP for the purposes of this Code of Practice. Where the voltage transformers’ primary windings do not connect at the same voltage level as it is at the DMP, a Metering Dispensation shall be required.
The following examples show some possible arrangements in simplified single line diagrams for guidance.
Example 1 is for Metering Systems located Offshore, measuring Offshore Power Park Module Export and Import. The voltage transformers’ primary windings are to connect electrically to a single busbar and at the same voltage level as the strings of wind turbine generators (WTGs) being measured for Settlement purposes.
Example 1 Offshore wind farms metering at string level on the Offshore platform with a single busbar
Example 2 is for Metering Systems located Offshore, measuring Offshore Power Park Module Export and Import. The voltage transformers’ primary windings connect to each electrically separate busbar and at the same voltage level as the strings of WTGs being measured for Settlement purposes.
Example 2 Offshore wind farms metering at string level on the Offshore platform with electrically split busbars
Examples 3 and 4 are for Metering Systems located onshore where the site has a single point of connection but is, or has the potential in the future, to be split into separate parts that are to be traded and settled separately (i.e. under separate MSIDs). Each Metering System shall measure Import and/or Export, and where the voltage transformers’ primary windings are connected to the same voltage level as the separate parts of the site and the DMP.
In these examples (3 and 4) a Metering Dispensation shall be required for the AMP not being at the DMP (i.e. the current transformers are installed at the AMP and not the DMP), unless the AMP is permitted to be away from the DMP for the purposes of this Code of Practice18. In this scenario, all voltage transformers shall be compliant with the current version of this Code of Practice. Where any additional circuit is installed against a version of this Code of Practice with different requirements to those specified in 5.1.2 from the original part of the site, each circuit should be metered separately or a Metering Dispensation shall be required.
In Example 3 the site is originally built and split into two parts (e.g. one part for renewable generation and a second part for battery storage), with the option of future expansion. This example could also apply to a single use site that has the option of future expansion, whether or not that future expansion will need to be traded and settled separately from the original part of the site. Example 4 shows an example where future expansion has occurred and there are four parts to the site that require to be traded and settled separately.
Scenarios described in these examples are not exhaustive and can cover other scenarios where multiple Metering Systems are installed behind a single DMP.
Example 3 Onshore metering with two Metering Systems behind a single DMP
Example 4 Onshore metering with multiple Metering Systems behind a single DMP.
