Electricity Industry Participation Code 2010

• This Schedule sets out—
  • (a) [Revoked]
  • (b) the requirement for—
    • (i) reconciliation participants to be certified to perform the functions specified in clause 15.38; and
    • (ii) generators that are not reconciliation participants to be certified to perform any of the obligations specified under clauses 13.136 to 13.138; and
  • (ba) the process for obtaining and renewing that certification.
  • (c) [Revoked]

• (1) Despite clause 15.38(1) and 15.38(1A), a reconciliation participant that is required to obtain certification under clause 15.38 must obtain certification no later than,—
  • (a) in the case of a reconciliation participant that is recorded in the registry as being responsible for fewer than 100 ICPs of the kind described in subclause (2), 12 months after the reconciliation participant first performs a function specified in clause 15.38(1); or
  • (b) in every other case, the later of—
    • (i) 6 months after the date on which the reconciliation participant first performs, including by using an agent, a function specified in clause 15.38; or
    • (ii) the date on which the reconciliation participant is recorded in the registry as being responsible for 100 or more ICPs of the kind described in subclause (2).
• (2) The kind of ICP referred to in subclause (1) is an ICP at which there is—
  • (a) 1 or more category 1 metering installations and no other kind of metering installation; and
  • (b) no unmetered load.
• (3) A generator that is not a reconciliation participant and that is required to obtain certification under clause 13.138C must obtain certification no later than 6 months after the date on which the generator first performs, including by using an agent, an obligation under clauses 13.136 to 13.138.

• (1) A participant that proposes to perform a function listed in clause 15.38 without obtaining certification (in reliance on clause 2A) must obtain the Authority's prior approval.
• (1A) A generator that is not a reconciliation participant and that proposes to perform an obligation under clauses 13.136 to 13.138 without obtaining certification (in reliance on clause 2A) must obtain the Authority's prior approval.
• (2) The Authority must give its approval if it is satisfied, on the basis of information provided to it by the participant specified in subclause (1) or subclause (1A), that the participant complies with the requirements specified in subclause (3) that apply to the participant.
• (3) The requirements are that the participant must—
  • (a) be capable of producing submission information accurately:
  • (aa) where required, be capable of providing the half-hour metering information required under clauses 13.136 to 13.138:
  • (b) be capable of performing the functions described in clause 15.38(1)(d):
  • (c) be capable of switching an ICP in accordance with Schedule 11.3:
  • (d) be capable of managing an ICP in accordance with Schedule 11.1:
  • (e) understand its obligations under this Code.

• A participant may perform any obligation under this Schedule by using an agent, and for that purpose, every act or omission of a participant’s agent is deemed to be an act or omission of the participant.

• (1) A participant requiring certification to perform the functions specified in clause 15.38 or the obligations under clauses 13.136 to 13.138 must apply in writing to the Authority in the prescribed form, at least 2 months before the intended date of certification.
• (2) When making an application under subclause (1), the participant must—
  • (a) promptly provide such other information as the Authority may reasonably request; and
  • (b) indicate to the Authority the information gathering, processing and management functions the participant intends to perform and who it intends to use to perform those functions.
• (3) [Revoked]

• (1) The Authority must grant certification to a reconciliation participant or generator only if―
  • (a) the Authority is satisfied, on the basis of an audit report provided to the Authority under Part 16A, that the participant meets the requirements relevant to the functions specified in clause 15.38 or the obligations under clauses 13.136 to 13.138 for which the participant is seeking certification.
  • (b) [Revoked]
• (2) A participant is responsible for appointing an auditor to undertake the audit required by subclause (1).
• (3) [Revoked]

• The Authority must publish, and keep updated―
  • (a) a list of participants certified under clause 13.138C and clause 15.38 including, for each participant, the date on which the certification expires.
  • (b) [Revoked]

• (1) Certification must not be granted for a term of more than 36 months.
• (2) The Authority must renew a participant’s certification for a further term of not more than 36 months if the Authority is satisfied on the basis of an audit report provided to the Authority under Part 16A that the participant continues to meet the requirements specified in clause 5.

• (1) [Revoked]
• (1A) If there is a material change to a participant's systems or processes such that an audit is required under clause 16A.11, the Authority must, on receiving the audit report required by that clause, decide whether to continue the participant's certification.
• (2) The Authority must, by notice to the participant, continue the participant’s certification if the Authority is satisfied that thparticipant will continue to meet the requirements in clause 5 after the change has come into effect.
• (3) A participant’s certification is revoked if―
  • (a) the participant fails to provide an audit report to the Authority under clause 16A.11; or
  • (b) the Authority gives written notice to the participant that the Authority is not satisfied that the participant will continue to meet the requirements in clause 5 after the change has come into effect.

• This Schedule establishes the required processes, in so far as they relate to the reconciliation process, for—
  • (a) collecting raw meter data, interrogating meters, and deriving validated meter readings; and
  • (b) creating estimated readings and permanent estimates; and
  • (c) deriving volume information from validated meter readings, estimated readings, and permanent estimates; and
  • (d) supporting data processing activities.

• (1) This clause applies to each metering installation for which a metering equipment provider is responsible, except for a metering installation—
  • (a) that only the metering equipment provider can electronically interrogate; or
  • (b) for which the metering equipment provider has an arrangement with the reconciliation participant, which prevents the reconciliation participant from electronically interrogating the metering installation.
• (2) A reconciliation participant must obtain raw meter data used to determine volume information—
  • (a) from the services access interface of the metering installation; or
  • (b) if the raw meter data can only be obtained from the metering equipment provider’s back office, from the metering equipment provider.
• (3) A reconciliation participant must ensure that the interrogation cycle for each metering installation that it interrogates does not exceed the maximum interrogation cycle in the registry.
• (4) A reconciliation participant must interrogate a metering installation at least once in each maximum interrogation cycle for the metering installation.
• (5) A reconciliation participant must, when electronically interrogating a metering installation,—
  • (a) ensure that the interrogation and processing system electronically monitors and corrects its internal clocks against a time source with a verifiable standard at a frequency sufficient, but no longer than 1 week, to ensure the internal clock is accurate, when carrying out an interrogation, to within ±5 seconds of—
    • (i) New Zealand standard time; or
    • (ii) New Zealand daylight time; and
  • (b) compare the time on the internal clock of the data storage device with the time on the interrogation and processing system clock; and
  • (c) calculate the time error for the data storage device; and
  • (d) if the time error calculated under paragraph (c) is equal to or less than the applicable time error set out in Table 1, correct the clock of the data storage device; and
  • (e) if the time error calculated under paragraph (c) is greater than the applicable time error set out in Table 1,—
    • (i) correct the clock of the data storage device; and
    • (ii) compare the time of the clock with the time of the interrogation and processing system clock; and
    • (iii) correct any affected raw meter data; and
  • (f) download the event log.
• (6) The reconciliation participant must record in the interrogation and processing system logs, the time, the date, and the extent of any change in the internal clock setting in the metering installation.

Table 1: Maximum permitted time errors

• If a meter is bridged in accordance with clause 10.33C, the trader responsible for the ICP must determine meter readings for that meter as follows:
  • (a) if a check meter or data storage device is installed at the metering installation, by substituting data from the check meter or data storage device for the period the meter was bridged; or
  • (b) in the absence of any check meter or data storage device, by determining meter readings for the period the meter was bridged from—
    • (i) half hour data from another period where the trader considers the pattern of consumption is materially similar to the period during which the meter was bridged; or
    • (ii) a non half hour estimated reading that the trader considers is the best estimate of the quantity of electricity consumed during the period the meter was bridged.

• (1) A meter reading must, in accordance with the relevant reconciliation participant’s certified processes and procedures, and using its certified facilities, be sourced directly from raw meter data, and if appropriate, be derived and calculated from financial records.
• (2) A validated meter reading must be derived from a meter reading. A meter reading that is provided by a consumer may be used as a validated meter reading only if another set of validated meter readings that has not been provided by the consumer is used during the validation process specified in clauses 16 and 17.
• (3) An estimated reading and a permanent estimate must be clearly identified as an estimate at source and in an exchange of metering data or volume information between participants (excluding the reconciliation manager).
• (4) Volume information must be directly derived, in accordance with this Schedule, from—
  • (a) validated meter readings; or
  • (b) estimated readings; or
  • (c) permanent estimates.
• (5) A reconciliation participant must ensure that all raw meter data used to derive volume information in accordance with this Schedule is not rounded or truncated from the stored data from the metering installation.

• (1) Only volume information created using validated meter readings, or if such values are unavailable, permanent estimates, has permanence within the reconciliation processes (unless subsequently found to be in error).
• (2) The relevant reconciliation participant must, at the earliest opportunity, and no later than the month 14 revision cycle, replace volume information created using estimated readings with volume information created using validated meter readings.
• (3) If, despite having used reasonable endeavours for at least 12 months, a reconciliation participant has been unable to obtain a validated meter reading, the reconciliation participant must replace volume information created using an estimated reading with volume information created using a permanent estimate in place of a validated meter reading.

• A reconciliation participant must, when manually interrogating a non half-hour metering installation, if the relevant parts of the metering installation are visible and it is safe to do so,—
  • (a) obtain the meter register value; and
  • (b) ensure seals are present and intact; and
  • (c) check for phase failure if the meter supports it; and
  • (d) check for signs of tampering or damage; and
  • (e) check for electrically unsafe situations, where “electrically unsafe” has the meaning given to it in the Electricity (Safety) Regulations 2010.

• Non half hour meter readings are deemed to apply—
  • (a) if the non half hour meter reading is also a switch event meter reading—
    • (i) for the gaining trader, from 0000 hours on the day of the relevant event date; and
    • (ii) for the losing trader, at 2400 hours at the end of the day before the relevant event date; or
  • (b) in all other cases, from 0000 hours on the day after the last meter interrogation up to and including 2400 hours on the day of the meter interrogation.

• (1) Each reconciliation participant must ensure that a validated meter reading is obtained in respect of every meter register for every non half hour metered ICP for which it is responsible, at least once during the period of supply to the ICP by the reconciliation participant, and used to create volume information. This may be a validated meter reading at the time the ICP is switched to, or from, the reconciliation participant.
• (2) If exceptional circumstances prevent a reconciliation participant from obtaining the validated meter reading described in subclause (1), the reconciliation participant is not required to comply with subclause (1).

• (1) Each reconciliation participant must ensure that, at least once every 12 months, a validated meter reading is obtained for every meter register for non half hour metered ICPs at which the reconciliation participant trades continuously for each 12 month period. In carrying out this obligation—
  • (a) each reconciliation participant must report to the Authority, in relation to each NSP, the percentage of the ICPs from which consumption information was collected and reported into the reconciliation process in the previous 12 month period. This report must be submitted no later than 20 business days after the end of each month; and
  • (b) if the percentage reported in accordance with paragraph (a) is less than 100%, the Authority may, from time to time, require the reconciliation participant to explain why that level was not achieved and to describe the steps that are being taken to achieve a level of performance that, in the Authority’s assessment, is reasonable.
• (2) If exceptional circumstances prevent a reconciliation participant from obtaining the validated meter reading described in subclause (1), the reconciliation participant is not required to comply with subclause (1).

• (1) Each reconciliation participant must ensure, in relation to each NSP, that a validated meter reading is obtained, at least once every 4 months, for 90% of the non half hour metered ICPs at which the reconciliation participant trades continuously for each 4 months for which consumption information is required to be reported into the reconciliation process. In carrying out this obligation—
  • (a) each reconciliation participant must report to the Authority the percentage, in relation to each NSP, of the ICPs from which consumption information was collected and reported into the reconciliation process in the previous 4 month period. This report must be submitted no later than 20 business days after the end of each month; and
  • (b) if the percentage reported in accordance with paragraph (a) is less than 90% in relation to any NSP, the Authority may, from time to time, require the reconciliation participant to explain why that level was not achieved and to describe the steps that are being taken to achieve acceptable performance.
• (2) If exceptional circumstances prevent a reconciliation participant from obtaining the validated meter reading described in subclause (1), the reconciliation participant is not required to comply with subclause (1).
• (3) The reconciliation participant must report to the Authority monthly on a rolling 4 month basis the percentage of non half hour meter interrogations within that period.

• To verify the accuracy of raw meter data collected during interrogation of non half hour metering, a log must be produced consisting of the following as a minimum:
  • (a) the means to establish the identity of the individual meter reader:
  • (b) the ICP identifier, and the meter and register identification:
  • (c) the method being used for this interrogation and the device ID of equipment being used for interrogation of the meter:
  • (d) the date and time of the meter interrogation.

• (1) A reconciliation participant must, as required under clause 2(2), obtain raw meter data from the services access interface for an electronically interrogated metering installation. This may be carried out through the use of portable devices or remotely by the use of a recognised communications medium.
• (2) Raw meter data obtained by the electronic interrogation of a metering installation must consist of the following as a minimum:
  • (a) the unique identifier of the data storage device in the metering installation:
  • (b) the time from the data storage device at the commencement of the download, unless the time is within specification and the interrogation log automatically records the time of interrogation:
  • (c) the metering information, which represents the quantity of electricity conveyed at the point of connection, including the date and time stamp or index marker for each half hour period. This may be limited to the metering information accumulated since the last interrogation:
  • (d) the event log, which may be limited to the events information accumulated since the last interrogation:
  • (e) for all metering information, an interrogation log generated by the interrogation software to record details of all interrogations. The reconciliation participant responsible for collecting the data must peruse the interrogation log and take appropriate action if problems are apparent. Alternatively, this process may be an automated software function that flags exceptions.
• (3) For the purposes of subclause (2)(e), the interrogation log must form part of the interrogation audit trail and must contain the following as a minimum:
  • (a) the date of interrogation:
  • (b) the time of commencement of interrogation:
  • (c) the operator identification (if available):
  • (d) the unique identifier of the data storage device:
  • (e) the time errors outside the range specified in Table 1 of clause 2:
  • (f) the method of interrogation:
  • (g) the identifier of the reading device used for interrogation (if applicable).

The trading period duration, which is normally 30 minutes, must be within ±0.1% (± 2 seconds).

• (1) If a reconciliation participant is unable to interrogate an electronically interrogated metering installation before the deadline for providing submission information or dispatchable load information, the reconciliation participant must submit to the reconciliation manager its best estimate of the quantity of electricity that was purchased or sold in each trading period during any applicable consumption period for that metering installation.
• (2) The reconciliation participant must use reasonable endeavours to ensure that estimated submission information is within the percentage specified by the Authority.

(1) All non half hour meter readings and estimated readings must be checked for validity by the relevant reconciliation participant after each interrogation.

(2) Each validity check of non half hour meter readings and estimated readings must include the following:

• (a) confirmation that the meter reading or estimated reading relates to the correct ICP, meter, and register:
• (b) checks for invalid dates and times:
• (c) confirmation that the meter reading or estimated reading lies within an acceptable range compared with the expected pattern, previous pattern or trend:
• (d) confirmation that there is no corruption of the data, including unexpected 0 values.

• (1) All meter readings obtained by electronic interrogation and estimated readings must be checked for validity by the relevant reconciliation participant.
• (2) Each validity check of a meter reading obtained by electronic interrogation and each estimated reading must be at a frequency that will allow a further interrogation of the data storage device before the data is overwritten within the data storage device and before the data can be used for any purpose under this Code.
• (3) [Revoked]
• (4) Each validity check of a meter reading obtained by electronic interrogation or an estimated reading must include the following:
  • (a) checks for missing data:
  • (b) checks for invalid dates and times;
  • (c) checks of unexpected 0 values:
  • (d) comparison with expected or previous flow patterns:
  • (e) comparison of meter readings with data on any data storage device registers that are available:
  • (f) a review of the meter and data storage device event log for any event that could have affected the integrity of the metering data:
  • (g) a review of the relevant metering data if there was an event that could have affected the integrity of the metering data.
• (5) A reconciliation participant must, if it finds an event that could have affected the integrity of the metering data or an event is reported to it under clause 8(5A)(d) of Schedule 10.6,—
  • (a) investigate and remediate the event if the metering equipment provider responsible for the metering installation is not responsible for investigating and remediating the event; and
  • (b) advise the metering equipment provider responsible for the relevant metering installation of the event if the investigation finds that the event may affect the integrity or operation of the metering installation.

• (1) A reconciliation participant who is responsible for interrogating a metering installation under this Part must archive all raw meter data downloaded or collected, and any changes to the raw meter data, for not less than 48 months in accordance with clause 8(6) of Schedule 10.6 with all necessary amendments.
• (2) Each reconciliation participant must ensure that procedures are in place to ensure that raw meter data for which it is responsible cannot be accessed by unauthorised personnel.
• (3) Each reconciliation participant must ensure that meter readings cannot be modified without an audit trail being created.

• (1) If a reconciliation participant detects errors while validating non half hour meter readings, the reconciliation participant must—
  • (a) confirm the original meter reading by carrying out another meter reading; and
  • (b) if the second meter reading confirms that the original meter reading is erroneous,_replace the original meter reading with the second meter reading (even if the second meter reading is at a different date).
• (1A) If a reconciliation participant detects errors while validating non half hour meter readings, but the reconciliation participant cannot confirm the original meter reading or replace it with a meter reading from another interrogation, the reconciliation participant must—
  • (a) substitute the original meter reading with an estimated reading that is marked as an estimate; and
  • (b) subsequently replace the estimated reading in accordance with clause 4(2).
• (2) If a reconciliation participant detects errors while validating half-hour meter readings, the reconciliation participant must correct the meter readings as follows:
  • (a) if the relevant metering installation has a check meter or data storage device, substitute the original meter reading with data from the check meter or data storage device; or
  • (b) if the relevant metering installation does not have a check meter or data storage device, substitute the original meter reading with data from another period provided—
    • (i) the total of all substituted intervals matches the total consumption recorded on a meter, if available; and
    • (ii) the reconciliation participant considers the pattern of consumption to be materially similar to the period in error.
• (3) A reconciliation participant may use error compensation and loss compensation as part of the process of determining accurate data. Whatever methodology is used, the reconciliation participant must document the compensation process and comply with audit trail requirements set out in this Code.
• (4) In correcting a meter reading in accordance with this clause, a reconciliation participant must not overwrite the raw meter data. If the raw meter data and the meter readings are the same, the reconciliation participant must use the processing or data correction application to—
  • (a) make an automatic secure backup of the affected data; and
  • (b) archive the affected data.
• (5) If a reconciliation participant corrects or alters data under this clause, the reconciliation participant must generate and archive a journal that contains the following information:
  • (a) the date of the correction or alteration; and
  • (b) the time of the correction or alteration; and
  • (c) the operator identifier for the person within the reconciliation participant who made the correction or alteration; and
  • (d) the half hour meter reading data or the non half hour meter reading data corrected or altered, and the total difference in volume of such corrected or altered data; and
  • (e) the technique used to arrive at the corrected data; and
  • (f) the reason for the correction or alteration.

• Transmissions and transfers of data related to metering between reconciliation participants or reconciliation participant’s agents, for the purposes of this Code, must be carried out electronically, using systems that ensure the security and integrity of the data transmitted and received.

• (1) Each reconciliation participant must ensure that a complete audit trail exists for all data gathering, validation and processing functions of the reconciliation participant.
• (2) The audit trail must—
  • (a) include details of information—
    • (i) provided to and received from the registry manager; and
    • (ii) provided to and received from the reconciliation manager; and
    • (iii) provided and received from other reconciliation participants and their agents; and
  • (b) cover all raw meter data and any changes to the raw meter data archived under clause 18.
• (3) Logs of communications and processing activities must form part of the audit trail, including if automated processes are in operation.
• (4) Logs must be printed and filed as hard copy or maintained as data files, in a secure form, along with other archived information, and must include (at a minimum) the following:
  • (a) an activity identifier; and
  • (b) the date and time of the activity; and
  • (c) the operator identifier for the person within the reconciliation participant who performed the activity.
• (5) A reconciliation participant must collect all relevant data used by the reconciliation participant to determine profile data, including external control equipment operation logs, and archive that data in accordance with clause 18.

• This Schedule provides for—
  • (a) the processing of raw meter data and supporting information to create submission information; and
  • (b) the delivery of submission information to the reconciliation manager.

• (1) If a reconciliation participant is required to prepare submission information for an NSP for the relevant consumption period in accordance with this Code, the submission information for each ICP about which information is provided under clause 11.7(2)—
  • (aa) must comprise all volume information for the ICP:
  • (a) must comprise half hour volume information for the total metered quantity of electricity for each category 3 or higher metering installation:
  • (ab) must not comprise half hour volume information for a non half-hour metering installation:
  • (ac) must comprise either half hour volume information or non half hour volume information for the total metered quantity of electricity for each metering installation that—
    • (i) is a category 1 metering installation or category 2 metering installation; and
    • (ii) is a half-hour metering installation:
  • (ad) must comprise non half hour volume information calculated under clauses 4 to 6 (as applicable) for the total metered quantity of electricity for each metering installation that—
    • (i) is a category 1 metering installation or category 2 metering installation; and
    • (ii) contains only non half-hour metering:
  • (ae) if a metering installation is a category 1 metering installation or category 2 metering installation, and the metering installation contains half-hour metering and non half-hour metering, may comprise—
    • (i) a combination of—
      • (A) half hour volume information for the half-hour metering; and
      • (B) non half hour volume information calculated under clauses 4 to 6 (as applicable) for the non half-hour metering; or
    • (ii) non half hour volume information for the total metered quantity of electricity for the metering installation:
  • (b) [Revoked]
  • (c) must include unmetered load quantities for each ICP that has unmetered load associated with it, which must be derived from the quantity recorded in the registry against the relevant ICP and the number of days in the period, the distributed unmetered load database, or other sources of relevant information.
• (1A) However, a reconciliation participant need not comply with subclause (1)(a) to (ae) if—
  • (a) the reconciliation participant is using a profile approved in accordance with Schedule 15.5; and
  • (b) the approved profile allows the reconciliation participant to prepare submission information that does not comply with subclause (1)(a) to (ae); and
  • (c) the reconciliation participant complies with the submission information requirements set out in the approved profile.
• (2) To create non half hour submission information, a reconciliation participant must only use information that is dependent on a control device if—
  • (a) the certification of the control device is recorded in the registry; or
  • (b) the metering installation in which the control device is located is an interim certified metering installation.
• (3) To create submission information for a point of connection for which it is responsible, a reconciliation participant must use volume information from each metering installation for the point of connection.
• (4) For the purposes of subclause (3), the reconciliation participant must calculate the volume information by applying to the raw meter data obtained from each metering installation—
  • (a) for each ICP, the compensation factor recorded in the registry for the metering installation; or
  • (b) for each NSP, the compensation factor recorded in the metering installation's most recent certification report.

• (1) Each reconciliation participant must, for each ICP that has a non half hour metering installation, allocate volume information derived from validated meter readings, estimated readings or permanent estimates, to consumption periods using the techniques described in clauses 4 to 7 to create historical estimates and forward estimates.
• (2) Each estimate that is a forward estimate or an historical estimate, must be clearly identified as such.
• (3) If a validated meter reading is not available for the purpose of clauses 4 and 5, a permanent estimate may be used in place of a validated meter reading.

• The methodology that must be used by each reconciliation participant to prepare an historical estimate of volume information for each ICP when the relevant seasonal adjustment shape is available and the reconciliation participant is not using an approved profile in accordance with clause 4A, is as follows:
  • (a) if the period between any 2 consecutive validated meter readings encompasses an entire consumption period, an historical estimate must be prepared in accordance with the following formula:

• (b) if the period between any 2 consecutive validated meter readings encompasses the 1st part of a consumption period and the period between the 2nd validated meter reading and the subsequent validated meter reading encompasses the rest of that consumption period, an historical estimate must be prepared in accordance with the following formula:

• If the Authority has approved a profile for the purpose of apportioning volume information (in kWh) to part or full consumption periods, a reconciliation participant—
  • (a) may use the profile despite the relevant seasonal adjustment shape being available; and
  • (b) if it uses the profile, must otherwise prepare the historical estimate in accordance with the methodology in clause 4.

• If a seasonal adjustment shape is not available, either due to timing (for the provision of submission information by the 4th business day of each reconciliation period) or for any other reason, and the reconciliation participant is not using an approved profile under clause 4A, the methodology for preparing an historical estimate of volume information for each ICP must be the same as in clause 4, except that the relevant quantities kWh_Px must be prorated as determined by the reconciliation participant using its own methodology or on a flat shape basis using the relevant number of days that are—
  • (a) within the consumption period; and
  • (b) within the period covered by kWh_Px.

• (1) A forward estimate is an estimation of the total quantity of electricity that flowed through an ICP during all or part of a consumption period.
• (2) A forward estimate may be used only for a period for which an historical estimate cannot be calculated.
• (3) The methodology used for calculating a forward estimate may be determined at the discretion of the reconciliation participant, and only if the reconciliation participant ensures that the accuracy of its initial submission information against each subsequent revision cycle submission information for each balancing area is within the percentage of error specified and published, from time to time, by the Authority.

• (1) If a reconciliation participant changes the profile associated with a meter, it must, when determining the volume information for that meter and its respective ICP, use a validated meter reading or permanent estimate on the day on which the profile change is to take effect.
• (2) The reconciliation participant must use the volume information from that validated meter reading or permanent estimate to calculate the relevant historical estimates of each profile for that meter.

• (1) For each metering installation for which it is responsible that is category 3 or higher, a reconciliation participant must provide half hour submission information to the reconciliation manager.
• (2) For each half-hour metering installation for which it is responsible that is a category 1 metering installation or category 2 metering installation, a reconciliation participant must provide to the reconciliation manager—
  • (a) half hour submission information; or
  • (b) non half hour submission information; or
  • (c) a combination of half hour submission information and non half hour submission information if—
    • (i) the half-hour metering installation contains a combination of half-hour metering and non half-hour metering; and
    • (ii) clause 2(1)(ae) of this Schedule 15.3 applies.
• (3) For each non half-hour metering installation for which it is responsible, a reconciliation participant must provide non half hour submission information to the reconciliation manager.
• (4) However, a reconciliation participant need not comply with subclause (2) and subclause (3) if—
  • (a) the reconciliation participant is using a profile approved in accordance in Schedule 15.5; and
  • (b) the approved profile allows the reconciliation participant to provide half hour submission information from a non half-hour metering installation; and
  • (c) the reconciliation participant provides submission information that complies with the requirements set out in the approved profile.
• (5) For any unmetered load at an ICP for which it is responsible, regardless of the category of any metering installation at the ICP, a reconciliation participant must provide non half hour submission information to the reconciliation manager unless—
  • (a) the Authority has approved a profile for the unmetered load that allows the reconciliation participant to provide half hour submission information to the reconciliation manager for the unmetered load; and
  • (b) the reconciliation participant provides half hour submission information in accordance with the profile.
• (6) The half hour submission information that a reconciliation participant submits under subclause (1), subclause (2), or subclause (4) must be volume information aggregated to the following levels:
  • (a) NSP code:
  • (b) reconciliation type:
  • (c) profile:
  • (d) loss category code:
  • (e) flow direction:
  • (f) dedicated NSP:
  • (g) trading period.
• (7) The non half hour submission information that a reconciliation participant submits under subclause (2), subclause (3), and subclause (5) must be volume information aggregated to the following levels:
  • (a) NSP code:
  • (b) reconciliation type:
  • (c) profile:
  • (d) loss category code:
  • (e) flow direction:
  • (f) dedicated NSP:
  • (g) consumption period or day.

• If submission information aggregated by a reconciliation participant under clause 8 is specified to more than 2 decimal places, the reconciliation participant must round the submission information—
  • (a) to 2 decimal places; and
  • (b) so that if the digit to the right of the second decimal place is greater than or equal to 5, the second digit is rounded up, and if the digit to the right of the second decimal place is less than 5, the second digit is unchanged.

• (1) By 1600 hours on the 13th business day of each reconciliation period, each reconciliation participant must report to the reconciliation manager the proportion of historical estimates prepared under clauses 4 or 4A, per NSP contained within its non half hour submission information.
• (2) By 1200 hours on the last business day of each reconciliation period, the reconciliation manager must provide to the Authority a report of the proportion of historical estimates prepared under clause 4 or clause 4A, per NSP and per reconciliation participant, being used to create non half hour consumption information in respect of each consumption period being reconciled, and the Authority must publish the information.
• (3) The proportion of submission information per retailer per NSP that is comprised of historical estimates prepared under clause 4 or clause 4A must, unless exceptional circumstances exist, be—
  • (a) at least 80% for revised data provided at the month 3 revision; and
  • (b) at least 90% for revised data provided at the month 7 revision; and
  • (c) 100% for revised data provided at the month 14 revision.

• (1) A retailer must ensure that an up-to-date database is maintained for each type of distributed unmetered load for which it is responsible. The methodology for deriving submission information in the database must comply with Schedule 15.5.
• (2) The database must contain at a minimum—
  • (a) each ICP identifier for which the retailer is responsible, and to which distributed unmetered load is electrically connected; and
  • (aa) the item or items of distributed unmetered load associated with each ICP identifier; and
  • (b) the location of each item; and
  • (c) a description of load type for each item, including any assumptions made in the assessment of its capacity; and
  • (d) the capacity of each item in watts.
• (2A) Each retailer must ensure that each item of distributed unmetered load for which the retailer is responsible is recorded in the database in accordance with this clause.
• (3) The database must track the time of additions and changes in a way that enables the total load in kW to be retrospectively derived for any day.
• (4) The database must incorporate an audit trail of all additions and changes identifying the before and after values for changes, date and time of the change or addition, and the person making the change or addition.
• (5) [Revoked]

• This Schedule relates to the parts of the reconciliation process performed by the reconciliation manager during each reconciliation period and for relevant consumption periods in accordance with the revision cycle. The following steps comprise the reconciliation process. The requirements of each of these steps are detailed in the remainder of this Schedule. The steps are that the reconciliation manager must—
  • (a) adjust submission information by ICP days scaling; and
  • (b) apply loss factors to submission information for half hour metered ICPs that have been adjusted for ICP days; and
  • (c) profile non half hour submission information into trading periods; and
  • (d) apply loss factors to submission information for non half hour metered ICPs that have been adjusted for ICP days; and
  • (e) calculate unaccounted for electricity for each balancing area; and
  • (f) allocate consumed electricity and unaccounted for electricity to purchasers; and
  • (g) allocate generated electricity to generators; and
  • (h) produce reports.

Each reconciliation participant must comply with the timing requirements summarised below:

• (1) A trader may by written notice to the reconciliation manager designate an ICP on an embedded network for which the volume information is to be calculated by difference.
• (2) A trader must give notice under subclause (1) at least 5 business days before the designation of the ICP takes effect.
• (3) Not more than 1 ICP on an embedded network may be designated at any time.
• (4) The reconciliation manager must calculate the volume information by trading period for an ICP to which a designation relates using the following formula:

• (5) The reconciliation manager must allocate the volume information calculated under subclause (4) to the ICP to which the designation relates.
• (6) A trader may, by written notice to the reconciliation manager, revoke a designation made under subclause (1).

• (1) A trader may apply to the Authority for the Authority to designate part of a local network for which the volume information is to be calculated by difference.
• (2) A trader must give notice under subclause (1) at least 10 business days before the date the trader intends the designation to take effect.
• (3) The trader must comply with any requirements specified by the reconciliation manager within 5 business days of receiving notice of the requirements.
• (4) If the Authority grants a designation, the reconciliation manager must calculate the volume information by trading period for an ICP to which the designation relates using the following formula:

• (5) The reconciliation manager must allocate the volume information calculated under subclause (4) to the trader who applied for the designation under subclause (1).
• (6) The Authority may revoke the approval of a designation granted under subclause (1).

• ICP scaling must be used to adjust each retailer’s submission information (excluding embedded generator information) by a factor determined by the number of ICP days submitted for reconciliation compared to the number of ICP days recorded in the registry.

• (1) Each retailer and each direct purchaser (excluding direct consumers) must deliver to the reconciliation manager, in accordance with clause 15.6, the number of half hour and non half hour ICP days for the NSPs that are recorded in the registry as consuming electricity at any time during the relevant consumption period, upon which the retailer’s or direct purchaser’s submission information is based.
• (2) The registry manager must deliver to the reconciliation manager, in accordance with clauses 11.24 to 11.27, the number of half hour and non half hour ICP days per NSP each retailer and direct purchaser (excluding direct consumers) is responsible for during each consumption period.

• (1) The reconciliation manager must, using the retailer and direct purchaser reported ICP days and registry reported ICP days, calculate ICP day scaling factors separately in respect of non half hour and half hour metered ICPs according to the following formula:

• provided that if—
  • (a) the ICP scaling factor is calculated to be less than 1, it must, for the purposes of this clause, be deemed to be 1; and
  • (b) the ICP scaling factor is calculated to be greater than 1, it must not exceed a figure nominated and published from time to time by the Authority.
• (2) The ICP days scaling factor for direct consumers must be 1.
• (3) If the ICP days value reported by a retailer or a direct purchaser in respect of a balancing area is 0, or if data is not supplied, but in each case the corresponding ICP days value from the registry manager is not 0, the reconciliation manager must add to that retailer’s submission information for that consumption period an amount (designated SI_ICPD-ADD) that is equal to—
  • (a) 25 kWh per ICP day, in respect of non half hour ICPs; and
  • (b) 40 kWh per trading period per ICP day, in respect of half hour ICPs.
• (4) The relevant number of ICP days is the value reported by the registry manager.
• (5) The reconciliation manager must, when processing 0 ICP days information, and if data is not supplied, use default values for profile, and loss category code, as determined by the Authority from time to time.

• (1) The reconciliation manager must separately apply the ICP scaling factors and any additional amount calculated in clause 7 to the reported half hour and non half hour submission information (excluding embedded generator information) of each retailer or direct purchaser (excluding direct consumers) so as to scale up the submission information in proportion to any under submission by the retailer or direct purchaser.
• (2) The ICP scaling factor and any amount calculated in accordance with clause 7 must be applied to the submission information according to the following formula:

• The reconciliation manager must calculate the residual profile shape for each balancing area in accordance with Schedule 15.5.

• If submission information is submitted as non half hour quantities to be allocated to trading periods by profile shape, the reconciliation manager must use the appropriate shape for the profile code contained in the submission information, if—
  • (a) the profile code has been approved by the Authority in accordance with Schedule 15.5; and
  • (b) the profile owner has given written notice to the reconciliation manager of the approved profile code; and
  • (c) the profile owner has authorised the reconciliation participant to use the approved profile code.

• If an engineered, statistically sampled or recorded profile forms part of the submission information, the shape file or operation logs associated with the profile must be provided to the reconciliation manager by the reconciliation participant authorised by the profile owner to use that profile for each relevant NSP in respect of the prior consumption period in accordance with clauses 15.4 to 15.12.

• The reconciliation manager must calculate the trading period information by applying the profile shape for the profile code specified in the submission file provided by the reconciliation participant if—
  • (a) the profile code has been approved by the Authority in accordance with Schedule 15.5; and
  • (b) the profile owner has given written notice to the reconciliation manager of the approved profile code, and the profile owner has authorised the reconciliation participant to use the approved profile code; and
  • (c) if a balancing area shape is required as part of the profile, the initial residual or final residual profile shape as defined in Schedule 15.5 must be used.

• (1) The reconciliation manager must calculate the trading period information by applying the balancing area derived profile code specified in the submission file provided by the reconciliation participant, if—
  • (a) the profile code has been approved by the Authority for use as a balancing area derived profile in accordance with Schedule 15.5; and
  • (b) the profile owner has given written notice to the reconciliation manager of the approved profile code, and that the profile owner has authorised the reconciliation participant to use the approved profile code.
• (2) If the Authority has not approved the profile code, or submitted the profile to the reconciliation manager in accordance with clause 12(1) of Appendix 1 of Schedule 15.5, the reconciliation manager must calculate the trading period information using the final residual profile shape as defined in Schedule 15.5.

• If invalid submission information is submitted, and the reconciliation manager cannot obtain corrected information within a reasonable time period from the reconciliation participant, the reconciliation manager must—
  • (a) use the default values specified in this Code (if any); or
  • (b) if the default values described in paragraph (a) do not exist, use the default values specified by the Authority (if any); or
  • (c) if the default values described in paragraph (b) do not exist, temporarily replace the invalid data with an estimate.

• (1) The Authority may, from time to time, direct the reconciliation manager to apply certain values for loss factors for each loss category for a reconciliation period for which the registry manager does not, for whatever reason, provide the reconciliation manager with the loss factors for each loss category in accordance with clause 11.26(b).
• (2) If the Authority makes such a direction, the reconciliation manager must, after adjustment for ICP days scaling and the application of profiles, apply such loss factors to all submission information for all reconciliation periods during which the Authority’s direction is current.
• (3) The reconciliation manager must apply loss factors to submission information in respect of each embedded network and interconnection point, and submission information in respect of parent networks for the appropriate reconciliation period.

• (1) The reconciliation manager must calculate the unaccounted for electricity for each balancing area for each trading period in accordance with the following formula after all relevant quantities have been loss adjusted and scaled for ICP days:

• (2) The reconciliation manager must calculate the UFE factor in respect of each balancing area for each trading period as follows:

• (1) The reconciliation manager must rate each retailer relative to all other retailers using a scorecard rating. The numerical scores must be determined in accordance with this clause and clause 18 and used to weight the portion of unaccounted for electricity to be allocated to each retailer.
• (2) Each retailer must provide to the reconciliation manager, in accordance with clause 15.7, the quantity of electricity supplied.
• (3) The reconciliation manager must allocate electricity supplied quantities, to reconciliation periods for reporting and calculation purposes and in the event of unusual circumstances that must have been approved beforehand in writing by the Authority, re-allocate quantities on a reasonable basis to reflect the month(s) of actual usage.

• (1) The reconciliation manager must calculate, publish and apply the scorecard rating for each retailer as follows:
  • (a) the scorecard rating for each retailer must be calculated and published by the reconciliation manager in respect of each reconciliation period from which the reconciliation manager processes submission information, but must only be applied in respect of the 7 and 14 month revisions:
  • (b) the scorecard rating for each retailer for each balancing area (SC_Ri) must, subject to subclause (4), be calculated according to the following formula (provided that if the scorecard rating is calculated through the application of the formula to be less than 1, then SC_Ri is set to 1):

• • (c) in all cases, the latest electricity supplied and submission information quantities submitted to the reconciliation manager by the retailer must be used.
• (2) The scorecard rating for each retailer must be set to 1.25 if the retailer has not provided the reconciliation manager with any of the required information.
• (3) Despite subclauses (1) and (2), the scorecard rating for direct consumers and direct purchasers must be 1.
• (4) Despite anything else in this Code, the scorecard rating must be set to 1 until such time as the Authority gives written notice to participants that the scorecard rating will be calculated and applied in accordance with this clause.

• The reconciliation manager must apportion unaccounted for electricity to each retailer and direct purchaser at each NSP and for each trading period using the following formulae:

and, for each consumption period

The reconciliation manager must add each retailer’s or direct purchaser’s share of unaccounted for electricity to the previously calculated ICP days and loss adjusted submission information at each NSP for each trading period using the following formula:

Q_{ICPD-LA Ri} and UFE_Ri have the meaning given to them in clause 19.

• A portion of the UFE from the balancing area to which an embedded network is connected must be allocated by the reconciliation manager to each reconciliation participant trading on the embedded network. The quantity of UFE to be allocated by the reconciliation manager to the embedded network must be allocated in proportion to the ratio of the embedded network’s, and upstream balancing area's, submission information quantities (that have been adjusted for losses and ICP days).

The reconciliation manager must balance the UFE inclusive, ICP days and loss adjusted submission information so that the sum of each reconciliation participant’s quantities equals each NSP metered quantity during each trading period. The following process must be used by the reconciliation manager:

• (a) for each retailer or direct purchaser, at each NSP, any quantities that have been designated as being attributable to a specific NSP within the balancing area must be separated off from the remaining non-dedicated quantity and remain allocated to the specific NSP. If the sum of each retailer’s dedicated-NSP quantities exceeds the amount of electricity conveyed at the NSP in any trading period, the NSP total must be apportioned to the relevant retailers or direct purchasers in proportion to their dedicated-NSP quantities. The net quantities of non-dedicated electricity at each NSP must be determined by subtracting the dedicated quantities from the NSP totals:
• (b) the NSPs within a balancing area that have been over-allocated electricity must be identified by comparing the sum of the non-dedicated quantities for each retailer and direct purchaser with the net NSP quantity. The non-dedicated quantities for each retailer and direct purchaser at each over-allocated NSP must be adjusted in order to achieve balance as follows: