Part 12: Transport

Subpart 1—General

12.1 Contents of this Part

This Part relates to the following aspects of transmission:
- (a) transmission agreements (subpart 2):
- (b) grid reliability and industry information (subpart 3):
- (c) the transmission pricing methodology (subpart 4):
- (d) [Revoked]
- (e) interconnection asset services (subpart 6):
- (f) the Outage Protocol (subpart 7).

Compare: Electricity Governance Rules 2003 rule 1 section I part F

Clause 12.1(d): revoked, on 1 October 2011, by clause 5 of the Electricity Industry Participation (Financial Transmission Rights) Code Amendment 2011.

12.2 Discretion to waive Code requirements

(1) The Authority may agree to waive Code requirements under this Part if, before the commencement of an amendment to this Part,—
- (a) Transpower or any other participant required to complete actions under this Code has in substance done what it would have been required to do under this Code; and
- (b) the Authority is satisfied that the actions have been completed.
(2) If the Authority agrees to waive Code requirements under subclause (1), the Authority must publish its decision and reasons for agreeing to waive Code requirements.

Compare: Electricity Governance Rules 2003 rule 2 section I part F

12.3 Interaction between Parts 7 and 8 and this Part

(1) The principal performance obligations in relation to the real time delivery of common quality and dispatch under Part 7 relate to the functions and obligations of the system operator.
(2) When it is exercising its functions and powers under this Part, the Authority must have regard to the desirability of Parts 7 and 8 and this Part operating in an integrated and consistent manner.
(3) The performance or non-performance of a function or obligation of the system operator under Parts 7 or 8, and a claim against the system operator under Parts 7 or 8, is without prejudice to the functions and obligations of Transpower under this Part.
(4) The performance or non-performance of a function or obligation of Transpower under this Part, and any claim against Transpower under this Part or a transmission agreement, is without prejudice to the functions and obligations of the system operator under Parts 7 or 8.

Compare: Electricity Governance Rules 2003 rule 3 section I part F

Subpart 2—Transmission agreements

12.4 Contents of this subpart

This subpart deals with transmission agreements, and provides for the following:
- (a) [Revoked]
- (b) the categories of participants that must enter into transmission agreements:
- (c) an obligation on Transpower and designated transmission customers to enter into transmission agreements:
- (d) matters to be included in transmission agreements:
- (e) provisions relating to the default transmission agreement template, which—
  - (i) provides the basis for the negotiation of transmission agreements; or
  - (ii) provides the basis for a default transmission agreement:
- (f) a process for the Authority to determine a Connection Code that forms part of the default transmission agreement template:
- (g) a process for variations in transmission agreements from the default transmission agreement template:
- (h) a process for resolving disputes arising from the negotiation of transmission agreements and the failure to agree to the terms of default transmission agreements:
- (i) existing agreements.

Compare: Electricity Governance Rules 2003 rule 1 section II part F

Clause 12.4(a): revoked, on 1 October 2023, by clause 5(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clauses 12.4(e) to 12.4(h): amended, on 1 October 2023, by clause 5(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.5 [Revoked]

Compare: Electricity Governance Rules 2003 rule 2.1.2 section II part F

Clause 12.5: revoked, on 1 October 2023, by clause 6 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.6 [Revoked]

Compare: Electricity Governance Rules 2003 rules 2.1.3 to 2.1.5 section II part F

Clause 12.6(3): amended, on 1 November 2018, by clause 73 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

Clause 12.6: revoked, on 1 October 2023, by clause 7 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.7 Categories of participants required to enter into transmission agreements

(1) The categories of designated transmission customers required to enter into transmission agreements with Transpower under clause 12.8 are as specified in Schedule 12.1.
(2) The Authority must record in the register whether a registered participant is a designated transmission customer.
(3) Registration has no effect on a participant’s status as a designated transmission customer.

Compare: Electricity Governance Rules 2003 rule 2.2 section II part F

Transpower and designated transmission customers must enter transmission agreements

12.8 Obligation to enter transmission agreements

Transpower and designated transmission customers must enter into transmission agreements.

Compare: Electricity Governance Rules 2003 rule 3.1.1 section II part F

12.9 When designated transmission customer must enter into transmission agreement

A participant who becomes a designated transmission customer must enter into a transmission agreement with Transpower within 2 months after the participant becomes a designated transmission customer.

Compare: Electricity Governance Rules 2003 rule 3.1.2.3 section II part F

12.10 Default transmission agreements

(1) Subject to clause 12.49 the terms in the default transmission agreement template (other than incomplete terms) apply as a default transmission agreement as soon as a participant becomes a designated transmission customer.
(1A) Subject to clause 12.49, if, at the expiry of 2 months after a participant becomes a designated transmission customer, the designated transmission customer and Transpower have not entered into a transmission agreement in accordance with clause 12.9, the designated transmission customer and Transpower must comply with the process specified in this clause.
(2) If this clause applies:
- (a) within 10 business days of the date that is 2 months after the participant became a designated transmission customer, the designated transmission customer must provide Transpower, at the address for service for Transpower registered at the New Zealand Companies Office, with—
  - (i) the designated transmission customer’s full name; and
  - (ii) the designated transmission customer’s physical address, postal address and electronic address to which notices under the default transmission agreement are to be sent; and
  - (iii) the name of the contact person of the designated transmission customer to whom such notices should be addressed:
- (b) by the date 20 business days after the receipt of the designated transmission customer’s details under paragraph (a), Transpower must provide the designated transmission customer with a draft default transmission agreement completed in accordance with the default transmission agreement template, which must include the following:
  - (i) the designated transmission customer’s details as provided under paragraph (a):
  - (ii) Transpower’s physical address, postal address and electronic address to which notices under the default transmission agreement are to be sent:
  - (iii) the contact person to whom notices under the default transmission agreement should be addressed:
  - (iv) Transpower’s designated bank account for the purposes of receiving payments under the default transmission agreement:
  - (v) draft Schedules 1 and 2, which set out the connection locations, points of service and points of connection of the assets owned or operated by the designated transmission customer to the grid:
  - (vi) a draft Schedule 4 setting out, in the same form as the diagram in Schedule 4 of the default transmission agreement template, the configuration of the connection assets in relation to each connection location listed in Schedule 1:
  - (vii) a draft Schedule 5 setting out proposed service levels for each connection location listed in Schedule 1 determined in accordance with subclause (3):
  - (viii) if applicable, a draft Schedule 6, including identifying the facilities, facilities area, and land that are to be subject to the access and occupation terms set out in the schedule and the licence charges under the schedule:
- (c) the designated transmission customer and Transpower may discuss the schedules proposed under paragraph (b)(v) to (viii), as a result of which Transpower may amend any of the schedules:
- (d) the designated transmission customer must advise Transpower in writing no later than 20 business days after receiving the draft default transmission agreement under paragraph (b) whether—
  - (i) it accepts the schedules as proposed by Transpower under paragraph (b)(v) to (viii); or
  - (ii) if Transpower has amended any of those schedules under paragraph (c), it accepts the schedules as amended.
(3) The service levels set out in Schedule 5 of a default transmission agreement must be determined on the following basis:
- (a) the capacity service levels for each branch must be consistent with—
  - (i) the capacities of the branch or component assets in the most recent asset capability statement provided by Transpower under clause 2(5) of Technical Code A of Schedule 8.3; or
  - (ii) if the relevant information is not contained in the asset capability statement, the manufacturer’s specification for the component assets:
- (b) the service levels for the voltage range specified in the capacity service measures for each branch must be consistent with,—
  - (i) for assets of voltages of 50kV or above,—
    - (A) the voltage ranges for the component assets specified in the AOPOs, if any; or
    - (B) the voltage range specified in any equivalence arrangement approved or any dispensation granted under clauses 8.29 to 8.31 in respect of any asset that does not comply with the voltage range specified in the AOPOs; or
  - (ii) for assets of voltages less than 50kV, the normal operating voltage of the component assets:
- (c) Transpower must ensure that each connection asset is included in a branch:
- (d) the availability and reliability service levels must—
  - (i) be set at a level equivalent to the average annual availability and reliability at each point of service subject to the default transmission agreement over the 5 year period (being years ending 30 June) immediately before the date that is 2 months after the participant became a designated transmission customer; or
  - (ii) if a point of service subject to the default transmission agreement has not been in existence for 5 years (being years ending 30 June) before the date referred to in subparagraph (i), reflect a reasonable estimate of the expected availability and reliability at the point of service having regard to the performance data available for the point of service and average annual availability and reliability of assets similar to the connection assets at the connection location at which the point of service is located:
- (e) the reporting and response service levels must be consistent with Transpower’s practices existing on the date that is 2 months after the participant became a designated transmission customer, including Transpower’s documented policies and procedures, and must not result in changes to the management or operation of the grid that could materially affect Transpower or any other participant or end use customer, or require Transpower to materially alter the level of its normal on-going grid expenditure.
(4) If the designated transmission customer accepts the schedules as proposed by Transpower under subclause (2)(b)(v) to (viii), or as amended by Transpower under subclause (2)(c), the draft default transmission agreement proposed under subclause (2)(b)(v) to (viii), or as amended by Transpower under subclause (2)(c), (as applicable) is deemed to apply as a default transmission agreement from the date the participant became a designated transmission customer.
(5) If Transpower and a designated transmission customer are unable to agree on the terms of any of the schedules proposed by Transpower under subclause (2)(b)(v) to (viii), or as amended by Transpower under subclause (2)(c), either party may refer the matter to the Rulings Panel for determination under clauses 12.45 to 12.48.
(6) If a dispute is referred to the Rulings Panel, under subclause (5)—
- (a) the default transmission agreement as determined by the Rulings Panel in accordance with clauses 12.45 to 12.48 is deemed to apply between Transpower and the designated transmission customer from the date the participant became a designated transmission customer; and
- (b) until the Rulings Panel makes a determination, the draft default transmission agreement proposed under subclause (2)(b)(v) to (viii), or as amended by Transpower under subclause (2)(c), (as applicable) is deemed to apply as a default transmission agreement from the date the participant became a designated transmission customer.

Compare: Electricity Governance Rules 2003 rule 3.1.3 section II part F

Clause 12.10 Heading: amended, on 1 October 2023, by clause 8(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(1): amended, on 16 December 2013, by clause 5 of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Clause 12.10(1): amended, on 1 October 2023, by clause 8(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(1A): inserted, on 1 October 2023, by clause 8(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(2)(a)(ii) and (b)(ii): amended, on 5 October 2017, by clause 287 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.10(2): amended, on 1 October 2023, by clause 8(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(3): amended, on 1 October 2023, by clause 8(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(4): amended, on 1 October 2023, by clause 8(4) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(4): amended, on 1 March 2024, by clause 55(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

Clause 12.10(5): amended, on 1 October 2023, by clause 8(5) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(6)(a): amended, on 1 October 2023, by clause 8(6) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(6)(b): amended, on 1 October 2023, by clause 8(7) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.10(6): replaced, on 1 March 2024, by clause 55(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.11 Subsequent transmission agreements

If a default transmission agreement applies, it may be superseded by a subsequent transmission agreement entered into by Transpower and the designated transmission customer.

Compare: Electricity Governance Rules 2003 rule 3.1.4 section II part F

Clause 12.11: amended, on 1 October 2023, by clause 9 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.12 Changes to connection assets under default transmission agreements

(1) If Transpower reconfigures, replaces, enhances, or permanently removes a connection asset from service in accordance with the provisions of a default transmission agreement—
- (a) within 20 business days, to the extent necessary, Transpower must provide the designated transmission customer who is a party to that agreement with a revised Schedules 1 and 2, a revised Schedule 4, and a revised Schedule 5, and a revised Schedule 6 for that agreement, reflecting any changes to the description of the connection locations, points of service, or points of connection in Schedules 1 and 2, the diagram in Schedule 4, the service levels specified in Schedule 5, or the information in Schedule 6 resulting from the replacement or enhancement of the connection asset; and
- (b) the designated transmission customer and Transpower may discuss the revised schedules, as a result of which Transpower may amend any of the revised schedules; and
- (c) the designated transmission customer must advise Transpower within 20 business days of receiving the revised schedules under paragraph (a) whether—
  - (i) it accepts the revised schedules as proposed by Transpower under paragraph (a); or
  - (ii) if Transpower has amended any of those revised schedules under paragraph (b), it accepts the revised schedules as amended; and
- (d) the revised schedules apply under the default transmission agreement from the date that acceptance is received by Transpower under paragraph (c).
(2) If the designated transmission customer does not accept the revised schedules under subclause (1)(c), either party may refer the matter to the Rulings Panel for determination under clauses 12.45 to 12.48.
(3) If a dispute is referred to the Rulings Panel in accordance with subclause (2)—
- (a) the revised schedules proposed by Transpower under subclause (1)(a) apply from the date on which Transpower provides the designated transmission customer with the revised schedules under subclause (1)(a) until the date on which the Rulings Panel makes its determination or the determination comes into effect; and
- (b) the revised schedules as determined by the Rulings Panel under clauses 12.45 to 12.48 apply under the default transmission agreement from the date determined by the Rulings Panel.

Compare: Electricity Governance Rules 2003 rule 3.1.5 section II part F

Clause 12.12: amended, on 1 October 2023, by clause 10(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.12(1) and (1)(a): amended, on 1 October 2023, by clause 10(2) and 10(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.13 Expiry or termination of transmission agreements

If a participant and Transpower are party to an existing transmission agreement or written agreement to which clause 12.49 applies, and do not enter into a new transmission agreement before the existing agreement expires or terminates, upon expiry or termination of the existing agreement the provisions in clause 12.10 apply with all necessary modifications.

Compare: Electricity Governance Rules 2003 rule 3.1.6 section II part F

Clause 12.13: amended, on 1 October 2023, by clause 11(1) and 11(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.13(a)(ii) and (b)(ii): amended, on 5 October 2017, by clause 288 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.13(b)(v): amended, on 1 October 2023, by clause 11(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.13(e): amended, on 1 October 2023, by clause 11(4) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.13(g)(i): amended, on 1 October 2023, by clause 11(5) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.13(g)(ii): amended, on 1 October 2023, by clause 11(6) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.13: replaced, on 1 March 2024, by clause 56 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

Content of transmission agreements

12.14 Transmission agreements to be consistent with default transmission agreement template and grid reliability standards

Subject to clauses 12.35 to 12.38, a transmission agreement entered into between Transpower and a designated transmission customer under clause 12.8 must be consistent in all material respects with—
- (a) the default transmission agreement template; and
- (b) the grid reliability standards,—
as at the date the transmission agreement is entered into.

Compare: Electricity Governance Rules 2003 rule 3.2.1 section II part F

Clause 12.14 Heading: amended, on 1 October 2023, by clause 12(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.14(a): amended, on 1 October 2023, by clause 12(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.15 Transpower to publish information about transmission agreements and provide them on request

(1) Transpower must publish and update annually a list of all transmission agreements it has with designated transmission customers that includes, in respect of each transmission agreement contained in the list, the following information:
- (a) the full name of the designated transmission customer that is a party to the transmission agreement; and
- (b) the date on which the transmission agreement was executed; and
- (c) whether the transmission agreement includes any material variations from the default transmission agreement; and
- (d) if the transmission agreement includes any material variations from the default transmission agreement; a description of the variations; and
- (e) if any schedule to the transmission agreement has been revised in accordance with clause 12.12, the date from which the revised schedule began to apply.
(2) A person may request from Transpower a copy of a transmission agreement that Transpower has with a designated transmission customer, and Transpower must provide a copy to the person as soon as practicable after receiving the request.
(3) Despite subclause (2), Transpower may refuse to provide information from a transmission agreement if it considers that there would be grounds for withholding the information under the Official Information Act 1982.

Compare: Electricity Governance Rules 2003 rule 3.2.2 section II part F

Clause 12.15: substituted, on 1 February 2016, by clause 46 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.15(1): amended, on 1 October 2023, by clause 13 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Connection Code

12.16 [Revoked]

Clause 12.16: revoked, on 1 October 2023, by clause 14 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.17 Purpose of Connection Code

The purpose of the Connection Code is to set out the technical requirements and standards that designated transmission customers must meet in order to be connected to the grid and that Transpower and designated transmission customers must comply with under transmission agreements.

Compare: Electricity Governance Rules 2003 rule 3.3.1 section II part F

Clause 12.17: amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.17: amended, on 5 October 2017, by clause 289 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.17: amended, on 1 October 2023, by clause 15 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.18 Review of Connection Code

(1) The Authority may review the Connection Code at any time.
(2) Clauses 12.19 to 12.25 apply to any such review.

Compare: Electricity Governance Rules 2003 rule 3.3.10 section II part F

12.19 Transpower to submit Connection Code

(1) Transpower must submit a proposed Connection Code to the Authority within 90 days (or such longer period as the Authority may allow) of receipt of a written request from the Authority. The Authority may issue such a request at any time. The proposed Connection Code must provide for the matters set out in clause 12.20 and give effect to the principles set out in clause 12.21.
(2) With its proposed Connection Code, Transpower must submit to the Authority an explanation of the proposed Connection Code and a statement of proposal for the proposed Connection Code.

Compare: Electricity Governance Rules 2003 rule 3.3.2 section II part F

12.20 Required content of Connection Code

The Connection Code must provide for the following matters:
- (a) connection requirements for designated transmission customers:
- (b) technical requirements for assets, including assets owned by Transpower, and for other equipment and plant that is connected to a local network or an embedded network or that forms part of an embedded network or embedded generating station if the operation of that equipment and plant could affect the grid assets:
- (c) operating standards for equipment that is owned by a designated transmission customer, used in relation to the conveyance of electricity, and that is situated on land owned by Transpower:
- (d) information requirements to be met by designated transmission customers before equipment is connected to the grid and before changes are made to the equipment:
- (e) an obligation on Transpower to provide a 10 year forecast of the expected maximum fault level of each point of service to designated transmission customers set out in the transmission agreement between Transpower and each designated transmission customer.

Compare: Electricity Governance Rules 2003 rule 3.3.3 section II part F

Clause 12.20: amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.20(a): amended, on 5 October 2017, by clause 290(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.20(b) and (d): amended, on 5 October 2017, by clause 290(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.20(c): amended, on 5 October 2017, by clause 290(3) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.20(e): amended, on 5 October 2017, by clause 290(4) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.21 Principles for developing Connection Code

The Connection Code must give effect to the following principles:
- (a) the principles of the default transmission agreement template in clause 12.30:
- (b) the desirability of the Connection Code and Part 8 operating in an integrated and consistent manner, if possible:
- (c) the need to ensure that the grid owner can meet all obligations placed on it by the system operator for the purpose of meeting common security and power quality requirements under Part 8:
- (d) the need to ensure that the safety of all personnel is maintained:
- (e) the need to ensure that the safety and integrity of equipment is maintained.

Compare: Electricity Governance Rules 2003 rule 3.3.4 section II part F

Clause 12.21: amended, on 1 October 2023, by clause 16 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.22 Authority may initially approve proposed Connection Code or refer back to Transpower

(1) After consideration of Transpower’s proposed Connection Code, and accompanying explanation and statement of proposal, the Authority may—
- (a) provisionally approve the proposed Connection Code having regard to the matters set out in clause 12.20 and the principles in clause 12.21; or
- (b) refer the proposed Connection Code and accompanying explanation and statement of proposal back to Transpower if, in the Authority’s view,—
  - (i) the proposed Connection Code does not contain the matters set out in clause 12.20; or
  - (ii) the proposed Connection Code does not adequately provide for the principles in clause 12.21; or
  - (iii) the explanation or statement of proposal provided with the proposed Connection Code in accordance with clause 12.19(2) is inadequate.
(2) Transpower may, no later than 20 business days (or such longer period as the Authority may allow) after the Authority advises Transpower of its decision under subclause (1), consider the Authority’s concerns and resubmit its proposed Connection Code and accompanying explanation and statement of proposal for consideration by the Authority.

Compare: Electricity Governance Rules 2003 rule 3.3.5 section II part F

Clause 12.22(2): amended, on 1 November 2018, by clause 74 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

12.23 Amendment of proposed Connection Code by Authority

If the Authority considers that the Connection Code resubmitted by Transpower under clause 12.22(b) does not adequately provide for the matters set out in clause 12.20 or adequately give effect to the principles in clause 12.21, the Authority may make any amendments to the proposed Connection Code it considers necessary.

Compare: Electricity Governance Rules 2003 rule 3.3.6 section II part F

12.24 Authority must consult on proposed Connection Code

(1) The Authority must publish the proposed Connection Code, either as provisionally approved by the Authority or as amended by the Authority, as soon as practicable, for consultation with any person that the Authority thinks is likely to be materially affected by the proposed Connection Code.
(2) As well as the consultation required under subclause (1), the Authority may undertake any other consultation it considers necessary.

Compare: Electricity Governance Rules 2003 rules 3.3.7 and 3.3.8 section II part F

12.25 Decision on Connection Code

When the Authority has completed its consultation on the proposed Connection Code it must decide whether to amend the Connection Code.

Compare: Electricity Governance Rules 2003 rule 3.3.9 section II part F

Clause 12.25(2): amended, on 1 August 2023, by clause 41 of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.25(1) and 12.25(2): amended, on 1 October 2023, by clause 17 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.26 [Revoked]

Clause 12.26(1): amended, on 5 October 2017, by clause 291 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.26(1): amended, on 1 August 2023, by clause 42(1) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.26(2): revoked, on 1 August 2023, by clause 42(2) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.26: revoked, on 1 October 2023, by clause 18 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Default transmission agreement template

Cross heading: amended, on 1 October 2023, by clause 19 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.27 [Revoked]

Clause 12.27(1)(e): amended, on 1 February 2016, by clause 47 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.27: revoked, on 1 October 2023, by clause 20 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.28 [Revoked]

Compare: Electricity Governance Rules 2003 rule 7 section II part F

Clause 12.28: revoked, on 1 October 2023, by clause 20 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.29 Purpose of default transmission agreement template

The purpose of default transmission agreement template is to—
- (a) facilitate commercial arrangements between Transpower and designated transmission customers by providing a basis for negotiating transmission agreements required under clause 12.8 that meet the particular requirements of Transpower and designated transmission customers; and
- (b) provide the basis for default transmission agreements

Compare: Electricity Governance Rules 2003 rule 4.1 section II part F

Clause 12.29 heading and clause: amended, on 1 October 2023, by clause 21(1) and (2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.29(b): amended, on 1 October 2023, by clause 21(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.30 Principles for default transmission agreement template

The default transmission agreement template should—
- (a) reflect a fair and reasonable balance between the requirements of designated transmission customers and the legitimate interests of Transpower as asset owner; and
- (b) reflect the interests of end use customers; and
- (c) reflect the reasonable requirements of designated transmission customers at the grid injection points and grid exit points, and the ability of Transpower to meet those requirements; and
- (d) reflect the differing needs of different classes of designated transmission customers; and
- (e) be appropriate to the technical requirements of services provided at the point of connection to the grid, but not duplicate requirements that are more appropriately included in the grid reliability standards; and
- (f) establish common standards for a common configuration based on factors such as size of connection and voltage level; and
- (g) encourage efficient and effective processes for enforcement of obligations and dispute resolution.

Compare: Electricity Governance Rules 2003 rule 4.2 section II part F

Clause 12.30(f): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.30(f): amended, on 5 October 2017, by clause 292 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.30 heading and clause: amended, on 1 October 2023, by clause 22(1) and (2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.31 Contents of default transmission agreement template

(1) The default transmission agreement template must include—
- (a) an obligation on the parties to design, construct, maintain and operate all relevant plant and equipment in accordance with—
  - (i) relevant laws; and
  - (ii) the requirements of this Code (including obligations on designated transmission customers to provide information to facilitate system planning, as set out in clause 12.54); and
  - (iii) good electricity industry practice and applicable New Zealand technical and safety standards; and
- (b) an obligation on designated transmission customers to comply with Transpower’s reasonable technical connection and safety requirements; and
- (c) an obligation on designated transmission customers to pay prices calculated in accordance with the transmission pricing methodology approved by the Authority under subpart 4; and
- (d) arbitration or mediation processes for resolving disputes; and
- (e) service definitions, service levels, and service measures to the extent practicable for transmission services, other than the services to which the clauses in subpart 6 apply; and
- (f) the charging of a fee by Transpower to recover its settlement residue processing costs from designated transmission customers; and
- (g) the recovery of any negative settlement residue by Transpower from designated transmission customers.
(2) The default transmission agreement template must be consistent in all material respects with the grid reliability standards.

Compare: Electricity Governance Rules 2003 rule 4.3 section II part F

Clause 12.31(1)(b): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.31(1)(b): amended, on 5 October 2017, by clause 293 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.31 heading: amended, on 1 October 2023, by clause 23(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.31(1) and (1)(e): amended, on 1 October 2023, by clause 23(2) and (3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.31(1)(f) and (g): inserted, on 1 October 2023, by clause 23(4) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.31(2): amended, on 1 October 2023, by clause 23(5) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.32 [Revoked]

Compare: Electricity Governance Rules 2003 rules 4.4 and 4.5 section II part F

Clause 12.32(2): amended, on 1 November 2018, by clause 75 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

Clause 12.32: revoked, on 1 October 2023, by clause 24 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.33 [Revoked]

Compare: Electricity Governance Rules 2003 rule 4.6 section II part F

Clause 12.33(2): amended, on 1 August 2023, by clause 43 of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.33: revoked, on 1 October 2023, by clause 24 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.34 [Revoked]

Clause 12.34(1): amended, on 5 October 2017, by clause 294 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.34(1): amended, on 1 August 2023, by clause 44(1) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.34(2): revoked, on 1 August 2023, by clause 44(2) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.34: revoked, on 1 October 2023, by clause 24 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Variations from default transmission agreement template and grid reliability standards and enhancement and removal of connection assets

Cross heading: amended, on 1 October 2023, by clause 25 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.35 Increased service levels and reliability

(1) This clause applies if—
- (a) a proposed transmission agreement is not consistent in all material respects with the default transmission agreement template because it increases the service levels above those in the template; or
- (b) subject to clause 12.39, a proposed transmission agreement or other agreement between Transpower and a designated transmission customer increases the level of reliability above the grid reliability standards for a particular grid injection point or grid exit point.
(2) If this clause applies, the parties to the proposed transmission agreement must confirm in writing to the Authority that—
- (a) they have consulted with affected end use customers in relation to—
  - (i) the proposed service levels or the proposed increase in reliability; and
  - (ii) any resulting price implications; and
- (b) there are no material unresolved issues affecting the interests of those end use customers.

Compare: Electricity Governance Rules 2003 rule 5.1 section II part F

Clause 12.35 Heading: amended, on 15 May 2014, by clause 32(a) of the Electricity Industry Participation (Minor Code Amendments) Code Amendment 2014.

Clause 12.35(1)(a): amended, on 15 May 2014, by clause 32(b) of the Electricity Industry Participation (Minor Code Amendments) Code Amendment 2014.

Clause 12.35(1)(a): amended, on 1 October 2023, by clause 26 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.35(2): replaced, on 5 October 2017, by clause 295 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.36 Decreased service levels and reliability

(1) This clause applies if—
- (a) a proposed transmission agreement is not consistent in all material respects with the default transmission agreement template because it decreases the service levels below those in the template; or
- (b) subject to clause 12.39, a proposed transmission agreement or other agreement between Transpower and a designated transmission customer decreases the level of reliability below the grid reliability standards for a particular grid injection point or grid exit point.
(2) If this clause applies, the parties must obtain the Authority's approval of the proposed service levels or the lower level of reliability.
(3) The parties must satisfy the Authority that the Authority should grant an approval under subclause (2), having regard to any potential material adverse impacts of the proposed service levels or the lower level of reliability on—
- (a) current and future service levels or reliability for any affected designated transmission customer or end use customer; and
- (b) the price paid for transmission or distribution services, or electricity, by any affected designated transmission customer or end use customer.

Compare: Electricity Governance Rules 2003 rule 5.2 section II part F

Clause 12.36 Heading: amended, on 15 May 2014, by clause 33(a) of the Electricity Industry Participation (Minor Code Amendments) Code Amendment 2014.

Clause 12.36(1)(a): amended, on 15 May 2014, by clause 33(b) of the Electricity Industry Participation (Minor Code Amendments) Code Amendment 2014.

Clause 12.36(1)(a): amended, on 1 October 2023, by clause 27 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.37 Variations that may increase or decrease reliability

If it is uncertain whether, subject to clause 12.39, a proposed transmission agreement or other agreement increases or decreases the service levels from those that would apply if the default transmission agreement template applied, or whether a proposed transmission agreement or other agreement increases or decreases the level of reliability above or below the grid reliability standards, for a particular grid injection point or grid exit point, the parties must obtain the Authority’s approval described in clause 12.36(2).

Compare: Electricity Governance Rules 2003 rule 5.3 section II part F

Clause 12.37: amended, on 1 October 2023, by clause 28 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.38 Other variations from terms of default transmission agreement template

(1) This clause applies if a proposed transmission agreement to be entered into by Transpower and a designated transmission customer under clause 12.8 is not consistent in all material aspects with the default transmission agreement template , other than a situation to which clauses 12.35 to 12.37 apply.
(2) If this clause applies, the parties must obtain the Authority’s approval to the proposed variation from the default transmission agreement template. The parties to the proposed transmission agreement must satisfy the Authority that they have consulted with any affected end use customers and designated transmission customers in relation to the proposed variation, and there are no material unresolved issues affecting the interests of those persons.

Compare: Electricity Governance Rules 2003 rule 5.4 section II part F

Clause 12.38 heading: amended, on 1 October 2023, by clause 29(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.38: amended, on 1 October 2023, by clause 29(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.39 Customer specific value of expected unserved energy

(1) [Revoked]
(2) Transpower or a designated transmission customer may apply to the Authority—
- (a) if permitted under a transmission agreement, for provisional approval to use a different value of expected unserved energy than the value specified in clause 4 of Schedule 12.2 for the purposes of determining whether to replace or enhance connection assets as provided for under that transmission agreement; or
- (b) for approval to use a different value of expected unserved energy than the value specified in clause 4 of Schedule 12.2 for the purposes of applying the grid reliability standards under clauses 12.35 to 12.37 for a grid injection point or grid exit point, regardless of whether Transpower or the designated transmission customer has applied for the Authority's provisional approval under subclause (4).
(3) An application under subclause (2) must be made in writing to the Authority—
- (a) in the case of an application under subclause (2)(a), within 20 business days of the designated transmission customer proposing that different value to Transpower under the transmission agreement; and
- (b) in the case of an application under subclause (2)(b), within 20 business days of the designated transmission customer reaching an agreement with Transpower to which clauses 12.35 to 12.37 apply.
(4) If Transpower or a designated transmission customer applies for approval of a different value of expected unserved energy under subclause (2)(a), the Authority may provisionally approve that value if the Authority considers that the value is a reasonable estimate of the value of expected unserved energy in respect of the grid injection point or grid exit point for the designated transmission customer concerned.
(5) If Transpower or a designated transmission customer applies for approval of a different value of expected unserved energy under subclause (2)(b) the Authority—
- (a) may approve that value if the Authority considers that the value is a reasonable estimate of the value of expected unserved energy in respect of the grid injection point or grid exit point for the designated transmission customer concerned; and
- (b) may decline to approve that value despite having provisionally approved that value under subclause (4).
(6) If the Authority approves the value of expected unserved energy proposed by Transpower or the designated transmission customer under subclause (2)(b), that value of expected unserved energy applies for the purposes of applying the grid reliability standards under clauses 12.35 to 12.37 for the grid injection point or grid exit point instead of the value of expected unserved energy specified under clause 4 of Schedule 12.2.
(7) If the Authority does not approve the value of expected unserved energy proposed by Transpower or the designated transmission customer under subclause (2)(b), the value of expected unserved energy under clause 4 of Schedule 12.2 applies for the purposes of applying the grid reliability standards under clauses 12.35 to 12.37 for the grid injection point or grid exit point.

Compare: Electricity Governance Rules 2003 rule 5.5 section II part F

Clause 12.39 Heading: amended, on 1 February 2016, by clause 48(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39: amended, on 1 February 2016, by clause 48(3) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39(1): revoked, on 1 February 2016, by clause 48(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39(2)(b): amended, on 1 February 2016, by clause 48(4) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39(4): amended, on 1 February 2016, by clause 48(5) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39(6): amended, on 1 February 2016, by clause 48(6) and (7) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.39(7): amended, on 1 February 2016, by clause 48(8) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.40 Replacement and enhancement of shared connection assets

(1) If 2 or more designated transmission customers are connected to a point of connection and Transpower has advised those designated transmission customers, in accordance with the provisions of a transmission agreement between Transpower and each of the designated transmission customers, that a grid reliability report published by Transpower in accordance with clause 12.76 sets out that the power system is not reasonably expected to meet the N-1 criterion at all times over the next 5 years because of a connection asset related to that point of connection, Transpower must—
- (a) as soon as practicable after advising the designated transmission customers, investigate whether the connection asset meets the grid reliability standards; and
- (b) if it finds that the connection asset does not meet the grid reliability standards, develop proposals for investment in the grid to ensure that the connection asset meets the grid reliability standards and propose them to the designated transmission customers as soon as reasonably possible after publication of the grid reliability report.
(2) Transpower and the designated transmission customers advised under subclause (1) must attempt in good faith, within 6 months of the date on which Transpower makes its proposals to the designated transmission customers under subclause (1)(b), or such longer period as the Authority may allow, to reach an agreement for an investment or other solution that will have the effect of—
- (a) maintaining the level of reliability for the connection asset at the level of reliability in the grid reliability standards; or
- (b) increasing or decreasing the level of reliability for the connection asset above or below the grid reliability standards, so long as Transpower and the designated transmission customers have complied with clauses 12.35 to 12.37 and 12.39.
(3) Transpower may undertake an investment proposed under subclause (2) only—
- (a) if the designated transmission customers unanimously agree with the proposal in accordance with subclause (2); or
- (b) if the designated transmission customers do not unanimously agree or none of the designated transmission customers agree with the proposed investment, if—
  - (i) the proposal has been approved under a grid upgrade plan requested by the Electricity Commission in accordance with rule 5.10 of section II of part F of the rules before this Code came into force; or
  - (ii) the proposal is approved by the Commerce Commission under an investment proposal requested by the Commerce Commission in accordance with clause 12.44(1); or
  - (iii) the proposal is permitted under an input methodology determined by the Commerce Commission under section 54S of the Commerce Act 1986.

Compare: Electricity Governance Rules 2003 rule 5.6 section II part F

Clause 12.40(1): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.40(1): amended, on 5 October 2017, by clause 296 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.40(1) and (2): amended, on 1 November 2018, by clause 76(a) and (b) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

12.41 Removal of shared connection assets from service

(1) If 2 or more designated transmission customers are connected to a point of connection, and Transpower is required by a transmission agreement between Transpower and each of those designated transmission customers to provide the connection assets at the point of connection, Transpower may decommission a connection asset at that point of connection from service only—
- (a) if the designated transmission customers unanimously agree with the decommissioning and clauses 12.35 to 12.37 (if applicable) are complied with; or
- (b) if the designated transmission customers do not unanimously agree, or none of the designated transmission customers agree, with the decommissioning, if the decommissioning results in a net benefit, as calculated under the test set out in clause 12.43.
(2) To avoid doubt, this clause applies only if Transpower proposes to remove a connection asset from service and not replace the asset with another connection asset.

Compare: Electricity Governance Rules 2003 rule 5.7 section II part F

Clause 12.41(1): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.41(1): amended, on 5 October 2017, by clause 297 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.42 Reconfiguration of shared connection assets

If 2 or more designated transmission customers are connected to a point of connection, and Transpower is required by a transmission agreement between Transpower and each of those designated transmission customers to provide the connection assets in the configuration specified in each of those transmission agreements, Transpower may only change that configuration—
- (a) if the designated transmission customers unanimously agree with the reconfiguration and clauses 12.35 to 12.37 (if applicable) are complied with; or
- (b) if the designated transmission customers do not unanimously agree, or none of the designated transmission customers agree with the reconfiguration, if the reconfiguration results in a net benefit, as calculated under the test set out in clause 12.43.

Compare: Electricity Governance Rules 2003 rule 5.8 section II part F

Clause 12.42: amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.42: amended, on 5 October 2017, by clause 298 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.43 Net benefits test

(1) When Transpower is required to apply a net benefit test, Transpower must—
- (a) estimate the following costs:
  - (i) any additional fuel costs incurred by a generator in respect of any generating units that will be dispatched or are likely to be dispatched during or after the removal of the connection asset or the reconfiguration of the connection assets, arising as a result of the removal or reconfiguration:
  - (ii) any direct labour and material costs that will be incurred by Transpower and the designated transmission customers undertaking the removal of the connection asset or the reconfiguration of the connection assets:
  - (iii) any increase in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy, arising as a result of the removal of the connection asset or the reconfiguration of the connection assets:
  - (iv) any of the following costs, if the cost is to a person that produces, transmits, retails, or consumes electricity in New Zealand:
    - (A) changes in fuel costs of existing assets, committed projects and modelled projects:
    - (B) changes in the value of involuntary demand curtailment:
    - (C) changes in the costs of demand-side management:
    - (D) changes in costs resulting from deferral of capital expenditure on modelled projects:
    - (E) changes in costs resulting from differences in the amount of capital expenditure on modelled projects:
    - (F) changes in costs resulting from differences in operations and maintenance expenditure on existing assets, committed projects, and modelled projects:
    - (G) changes in costs for ancillary services:
    - (H) changes in losses, including local losses:
    - (I) subsidies or other benefits provided under or arising pursuant to all applicable laws, regulations and administrative determinations:
    - (J) the value of the expected change in economic surplus due to a change in competition among participants arising as a result of the removal of the connection asset or the reconfiguration of the connection assets, excluding any expected change in economic surplus due to a change in another cost in this net benefit test:
  - (v) any other relevant cost to a person that produces, transmits, retails or consumes electricity in New Zealand; and
- (b) estimate the following benefits:
  - (i) any reduction in maintenance costs arising as a result of the removal of the connection asset or the reconfiguration of the connection assets (including Transpower’s and any designated transmission customer’s costs):
  - (ii) any reduction in fuel costs incurred by a generator in respect of any generating units, arising or likely to arise during or after the removal of the connection asset or the reconfiguration of the connection assets, as a result of the removal or reconfiguration:
  - (iii) any decrease in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy, arising as a result of the removal of the connection asset or the reconfiguration of the connection assets:
  - (iv) any of the following benefits, if the benefit is to a person that produces, transmits, retails or consumes electricity in New Zealand:
    - (A) changes in fuel costs of existing assets, committed projects and modelled projects:
    - (B) changes in the value of involuntary demand curtailment:
    - (C) changes in the costs of demand-side management:
    - (D) changes in costs resulting from the deferral of capital expenditure on modelled projects:
    - (E) changes in costs resulting from differences in the amount of capital expenditure on modelled projects:
    - (F) changes in costs resulting from differences in operations and maintenance expenditure on existing assets, committed projects, and modelled projects:
    - (G) changes in costs for ancillary services:
    - (H) changes in losses, including local losses:
    - (I) subsidies or other benefits provided under or arising pursuant to all applicable laws, regulations and administrative determinations:
    - (J) the value of the expected change in economic surplus due to a change in competition among participants arising as a result of the removal of the connection asset or the reconfiguration of the connection assets, excluding any expected change in economic surplus due to a change in another benefit in this net benefit test:
  - (v) any other relevant benefit to a person that produces, transmits, retails or consumes electricity in New Zealand; and
- (c) deduct the costs estimated under paragraph (a) from the benefits estimated under paragraph (b) to determine the net benefit of the proposed removal of the connection asset or the reconfiguration of the connection assets.
(2) Transpower may apply the test under this clause at differing levels of rigour in different circumstances, which may include taking into account the number of assets to be removed or reconfigured, the value of the assets involved, and the size of the load served by the assets.
(3) Transpower is only required to—
- (a) make a reasonable estimate of the costs and benefits identified in subclause (1), based on information reasonably available to it at the time it undertakes the test, and taking into account the proposed number of assets to be removed or reconfigured, the value of the assets involved, and the size of the load served by the assets; and
- (b) take account of events that can be reasonably foreseen.
(4) Transpower’s estimate of fuel costs under subclause (1) must—
- (a) in relation to thermal generating stations, be a reasonable estimate of the fuel costs, based on the economic value of the fuel required for the relevant thermal generating station, and justified by Transpower with reference to opinions on the economic value of the fuel, provided by 1 or more independent and suitably qualified persons; and
- (b) in relation to hydroelectric generating stations—
  - (i) be a reasonable estimate of the fuel costs, based on the economic value of the water stored at a hydroelectric generating station, provided by a suitably qualified person other than—
    - (A) Transpower; or
    - (B) an employee of Transpower; and
  - (ii) be published, as provided for in the Outage Protocol.
(5) The direct labour costs of Transpower and designated transmission customers under subclause (1)(a) may include any amounts paid to contractors, but must not include any apportionment of the overheads or office costs of Transpower or designated transmission customers.
(6) The material costs of Transpower and designated transmission customers under subclause (1)(a) are the costs of the materials used in carrying out the work during the removal of the connection asset or the reconfiguration of the connection assets.
(7) In assessing costs and benefits under subclause (1), Transpower must consider any reasonably expected operating conditions, forecasts in the system security forecast, likely fuel costs, and any other reasonable assumptions.
(8) The estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy under subclause (1) must be based on—
- (a) the estimated amount and value of the expected unserved energy as agreed between Transpower and each affected designated transmission customer; or
- (b) if Transpower and a designated transmission customer cannot agree on the amount and value of the expected unserved energy under paragraph (a), the value of expected unserved energy in clause 4 of Schedule 12.2 and Transpower’s estimate of the expected unserved energy in respect of each affected designated transmission customer and end use customer.

Compare: Electricity Governance Rules 2003 rule 5.9 section II part F

Clause 12.43: substituted, on 16 December 2013, by clause 5 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.43(8)(b): amended, on 1 February 2016, by clause 49 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.43(8)(b): amended, on 1 November 2018, by clause 77 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

12.44 Request to the Commerce Commission to request an investment proposal be submitted

(1) Transpower may request in writing that the Commerce Commission request that Transpower submit an investment proposal to the Commerce Commission—
- (a) for the purposes of clause 12.40(3); or
- (b) if permitted by a transmission agreement.
(2) Unless requested to do so by the Commerce Commission, Transpower must not submit an investment proposal to the Commerce Commission for approval in respect of an investment that has been proposed by Transpower in accordance with a transmission agreement or clause 12.40(3).

Compare: Electricity Governance Rules 2003 rules 5.10 section II, and 12.2.2 section III part F

Resolutions of disputes

12.45 Certain disputes relating to transmission agreements may be referred to Rulings Panel

If a dispute between Transpower and a designated transmission customer concerning—
- (a) the customer specific terms of a transmission agreement being negotiated between those parties; or
- (b) a requested variation of any of the terms of a default transmission agreement (other than a variation under clause 12.12) that applies between Transpower and the designated transmission customer in accordance with clauses 12.10 to 12.13 (including a requested variation from the services described in the default transmission agreement); or
- (c) the schedules proposed by Transpower under clauses 12.10(2)(b)(v) to (viii), or as amended by Transpower under clause 12.10(2)(c) or
- (d) any revision to Schedule 4 or Schedule 5 of a default transmission agreement proposed by Transpower under clause 12.12; or
- (e) the schedules proposed or amended by Transpower under clause 12.13 on the expiry or termination of a transmission agreement—
is not resolved within a reasonable time, either party may refer the matter to the Rulings Panel for determination.

Compare: Electricity Governance Rules 2003 rule 6.1 section II part F

Clause 12.45(b), (c), and (d): amended, on 1 October 2023, by clause 30(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.45(c): amended, on 1 October 2023, by clause 30(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.45(e): amended, on 1 October 2023, by clause 30(3) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.46 Rulings Panel has discretion to determine dispute

(1) The Rulings Panel may, in its discretion, decide whether or not to undertake the determination of a dispute under clause 12.45(a) or (b).
(2) If the Rulings Panel decides not to undertake the determination of the dispute, the Rulings Panel must inform Transpower or the designated transmission customer—
- (a) that the Rulings Panel intends to do no more in relation to the matter; and
- (b) of the reasons for that intention.

Compare: Electricity Governance Rules 2003 rule 6.2 section II part F

12.47 Determinations by Rulings Panel

(1) In determining a dispute under this clause, the Rulings Panel must take into account—
- (a) the principles for the default transmission agreement template in clause 12.30; and
- (b) the desirability of consistent treatment of designated transmission customers except if special circumstances justify a departure; and
- (c) the potential impact of a decision on the contents of other transmission agreements or existing agreements as described in clauses 12.49 and 12.50.
(2) The Rulings Panel must not determine disputes relating to the interpretation or enforcement of a transmission agreement.
(3) The Rulings Panel must give notice to the parties of its determination, as soon as reasonably practicable.

Compare: Electricity Governance Rules 2003 rules 6.3 and 6.4 section II part F

Clause 12.47(1)(c): amended, on 16 December 2013, by clause 6 of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Clause 12.47(1)(a): amended, on 1 October 2023, by clause 31(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.47(2): amended, on 1 October 2023, by clause 31(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.48 Status of default transmission agreement while Rulings Panel determining dispute

Nothing in clauses 12.45 to 12.47 overrides the application of a default transmission agreement pending a determination of the Rulings Panel.

Compare: Electricity Governance Rules 2003 rule 6.5 section II part F

Clause 12.48: amended, on 1 October 2023, by clause 32 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Existing agreements not affected

12.49 Existing agreements

(1) Except as provided for by clauses 12.50B and 12.95, this Part does not apply to or affect the rights, powers or obligations of a participant or Transpower under a written agreement entered into between that participant and Transpower for connection to and/or use of the grid that is—
- (a) entered into before 29 October 2003; or
- (b) based on Transpower’s standard connection contract and entered into before 28 June 2007.
(2) The exceptions from this Part in subclause (1) do not apply to a right, power or obligation of a participant that arises because of the variation of an agreement described in subclause (1).
(3) To avoid doubt, the posted terms and conditions of Transpower do not constitute a written agreement.

Compare: Electricity Governance Rules 2003 rule 8.1 section II part F

Clause 12.49(1): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.49(1): amended, on 5 October 2017, by clause 299 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.49(1): amended, on 1 October 2023, by clause 33(1) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

Clause 12.49(2): amended, on 1 October 2023, by clause 33(2) of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.50 Copies of other agreements to be provided to the Authority

If requested to do so by the Authority, Transpower or a participant must provide a copy of any written agreement for connection to and/or use of the grid that Transpower or the participant is a party to and that was entered into before 28 June 2007, including any amendments.

Compare: Electricity Governance Rules 2003 rule 8.2 section II part F

Clause 12.50(1): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.50(1): amended, on 5 October 2017, by clause 300 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.50: amended, on 1 October 2023, by clause 34 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.50A

Amending default transmission agreement template

(1) An amendment of the default transmission agreement template must have regard to the purpose, principles, and content of the default transmission agreement template in clause 12.29 to 12.31.
(2) An amendment of the Connection Code must be carried out in accordance with clause 12.18.
(3) For the purpose of this clause and clause 12.50B an amendment of the default transmission agreement template includes a replacement of the agreement.

Clause 12.50A: inserted, on 1 October 2023, by clause 35 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.50B

Effect of amendment of default transmission agreement template on existing agreements

(1) This clause applies when the Authority amends the default transmission agreement template.
(2) Subject to subclause (3), all transmission agreements and agreements referred to in clause 12.49(1) are deemed to be amended to the extent necessary to make them consistent with an amendment to the default transmission agreement template, from the date of the amendment.
(3) Subclause (2) applies except where an amendment to the default transmission agreement template provides otherwise.

Clause 12.50B: inserted, on 1 October 2023, by clause 35 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023.

12.50C

Effect of first default transmission agreement template

Despite anything else in this Code, agreements referred to in clause 12.49(1) are deemed to be amended in respect of the first default transmission agreement template inserted into this Code, only to the extent necessary to make them consistent with Part D of that template.

Clause 12.50C: inserted, on 1 October 2023, by clause 35 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023

12.51 [Revoked]

Compare: Electricity Governance Rules 2003 rule 8.3 section II part F

Clause 12.51: revoked, on 16 December 2013, by clause 7 of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Subpart 3—Grid reliability and industry information

12.52 Contents of this subpart

This subpart relates to—
- (a) grid reliability standards; and
- (b) investment contracts; and
- (c) [Revoked]
- (d) grid reliability reporting.

Compare: Electricity Governance Rules 2003 rule 1 section III part F

Clause 12.52(c): revoked, on 1 February 2016, by clause 50 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.53 Purpose of the reliability and industry information clauses

The purposes of this subpart are to—
- (a) facilitate Transpower’s ability to develop and implement long term plans (including timely securing of land access and resource consents) for investment in the grid; and
- (b) assist participants to identify and evaluate investments in transmission alternatives; and
- (c) facilitate efficient investment in generation; and
- (d) facilitate any processes pursuant to Part 4 of the Commerce Act 1986.

Compare: Electricity Governance Rules 2003 rule 2 section III part F

12.54 Obligations to provide information

(1) Each participant must provide information reasonably required by the Authority for the purposes of this subpart and respond to requests from the Authority under this subpart promptly and accurately.
(2) Each participant must use reasonable endeavours to provide accurate information.
(3) The Authority is not liable for the accuracy of information provided by a participant.
(4) Subject to the Official Information Act 1982, the Authority may at its discretion, or on the application of an affected party, withhold publication of confidential aspects of the information provided by a participant to the Authority if the Authority reasonably considers that there is good reason for withholding it.

Compare: Electricity Governance Rules 2003 rule 3 section III part F

Grid reliability standards

12.55 Authority determines grid reliability standards

(1) The Authority must determine the most appropriate grid reliability standards.
(2) The Authority must consider and determine grid reliability standards, having regard to the purposes set out in clause 12.56 and the principles set out in clause 12.57.
(3) The grid reliability standards that apply at the commencement of this Code are the grid reliability standards in Schedule 12.2.

Compare: Electricity Governance Rules 2003 rule 4.1 section III part F

12.56 Purpose of grid reliability standards

The purpose of the grid reliability standards is to provide a basis for Transpower and other parties to appraise opportunities for transmission investments and transmission alternatives.

Compare: Electricity Governance Rules 2003 rule 4.2 section III part F

12.57 Principles of grid reliability standards

The grid reliability standards should—
- (a) take into account that transmission investments are long-lived assets and require a long-term planning perspective; and
- (b) reflect the public interest in reasonable stability in planning, having regard to the long term nature of investment in transmission assets; and
- (c) be consistent with good electricity industry practice; and
- (d) provide flexibility to allow the form of the standards to evolve over time, reflecting any changes in good electricity industry practice.

Compare: Electricity Governance Rules 2003 rule 4.3 section III part F

12.58 Content of grid reliability standards

(1) The grid reliability standards must contain 1 or more standards for reliability of the grid, which may include without limitation a primary reliability standard and other reliability standards.
(2) The reliability standards set out in the grid reliability standards may differ to reflect differing circumstances in different regions supplied by the grid.
(3) The grid reliability standards may include 1 or more standards for reliability of the core grid.
(4) The grid reliability standards may contain supporting information, such as information summarising economic assessments balancing different levels of reliability and the expected value of energy at risk.

Compare: Electricity Governance Rules 2003 rule 4.4 section III part F

Review of grid reliability standards

12.59 Interested parties may request review of grid reliability standards

(1) 1 or more interested parties may request a review by the Authority of the grid reliability standards. The request must be in the form of a written submission to the Authority describing—
- (a) the nature of the interest of each party seeking the review; and
- (b) how the review might enable the grid reliability standards to better reflect the purpose and principles set out in clauses 12.56 and 12.57.
(2) In addition to receiving written submissions, the Authority may elect to hear 1 or more oral submissions.
(3) The Authority must either undertake a review of the grid reliability standards, or decline to review the grid reliability standards and publish reasons for declining.

Compare: Electricity Governance Rules 2003 rule 5.1 section III part F

12.60 Authority review of grid reliability standards

The Authority may initiate a review of the grid reliability standards for any reason consistent with the mainobjective of the Authority in section 15 of the Act and the purpose and principles set out in clauses 12.56 and 12.57.

Compare: Electricity Governance Rules 2003 rule 5.2 section III part F

Clause 12.60: amended, on 1 March 2024, by clause 57 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.61 Authority must publish draft grid reliability standards

(1) This clause applies if the Authority undertakes a review of the grid reliability standards under clauses 12.59 or 12.60.
(2) The Authority must publish draft grid reliability standards.
(3) At the time the Authority publishes the draft grid reliability standards the Authority must publish the date by which submissions on the draft grid reliability standards are to be received by the Authority. The date must be no earlier than 15 business days from the date of publication of the draft grid reliability standards.
(4) Each submission on the draft grid reliability standards must be made in writing to the Authority and be received on or before the submission expiry date. In addition to receiving written submissions, the Authority may elect to hear 1 or more oral submissions.

Compare: Electricity Governance Rules 2003 rules 4.5 and 4.6 section III part F

Clause 12.61(3): amended, on 5 October 2017, by clause 301 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.62 Decision on grid reliability standards

Within 20 business days of the submission expiry date (or such longer period as the Authority may allow), the Authority must complete its consideration of all submissions it receives on the draft grid reliability standards and consider whether to include the grid reliability standards as a schedule to this Part, in accordance with the Act.

Compare: Electricity Governance Rules 2003 rule 4.7 section III part F

Core grid determination

12.63 Authority determines core grid determination

(1) The Authority must determine the most appropriate core grid determination.
(2) The core grid specified in the core grid determination must include—
- (a) at a minimum, those assets that comprise the main elements of the grid; and
- (b) at most, all assets that form part of the grid and operate at nominal voltages of 66kV and above.
(3) In determining the most appropriate core grid determination, and in a subsequent review of the core grid determination, the Authority must have regard to—
- (a) the purposes set out in clause 12.64; and
- (b) the principles set out in clause 12.57 for the grid reliability standards; and
- (c) the objectives set out in clause 12.65.
(4) In determining the most appropriate core grid determination, the Authority may engage Transpower or any other person to assist in the preparation of all or part of the core grid determination.
(5) The core grid determination that applies at the commencement of this Code is the core grid determination in Schedule 12.3.

Compare: Electricity Governance Rules 2003 rule 5A.1 section III part F

12.64 Purpose of core grid determination

The purpose of the core grid determination is to provide a basis for—
- (a) the Authority to determine the grid reliability standards; and
- (b) Transpower and other parties to appraise opportunities for transmission investment and transmission alternatives.

Compare: Electricity Governance Rules 2003 rule 5A.2 section III part F

12.65 Objectives of core grid determination

The Authority must have regard to the following objectives in determining, and in any subsequent review of, the core grid determination:
- (a) avoiding the failure or removal from service of any asset forming part of the core grid, if the failure or removal from service of that asset may result in cascade failure:
- (b) providing flexibility to allow the core grid to evolve over time, reflecting any changes in the grid:
- (c) reflecting the public interest in reasonable stability in planning for transmission.

Compare: Electricity Governance Rules 2003 rule 5A.3 section III part F

Review of core grid determination

12.66 Interested parties may request review of core grid determination

(1) 1 or more interested parties may request a review by the Authority of the core grid determination. The request must be in the form of a written submission to the Authority describing—
- (a) the nature of the interest of each party seeking the review; and
- (b) how the review might enable the core grid determination to better reflect the purpose and objectives set out in clauses 12.64 and 12.65 respectively.
(2) In addition to receiving written submissions, the Authority may elect to hear 1 or more oral submissions.
(3) The Authority must either undertake a review of the core grid determination, or decline to review the core grid determination and publish reasons for declining.

Compare: Electricity Governance Rules 2003 rule 5B.1 section III part F

12.67 Authority review of grid determination

The Authority may initiate a review of the core grid determination for any reason consistent with the main objective of the Authority in section 15 of the Act and the purpose and objectives set out in clauses 12.64 and 12.65 respectively.

Compare: Electricity Governance Rules 2003 rule 5B.2 section III part F

Clause 12.67: amended, on 1 March 2024, by clause 58 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.68 Authority must publish draft core grid determination

(1) This clause applies if the Authority undertakes a review of the core grid determination in accordance with clauses 12.66 or 12.67.
(2) The Authority must publish a draft core grid determination.
(3) When the Authority publishes the draft core grid determination the Authority must publish the date by which submissions on the draft core grid determination are to be received by the Authority. The date must be no earlier than 15 business days from the date of publication of the draft core grid determination.
(4) Each submission on the draft core grid determination must be made in writing to the Authority and be received on or before the submission expiry date. In addition to receiving written submissions, the Authority may elect to hear 1 or more oral submissions.

Compare: Electricity Governance Rules 2003 rules 5A.4 and 5A.5 section III part F

Clause 12.68(3): amended, on 5 October 2017, by clause 302 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.69 Decision on core grid determination

Within 20 business days of the submission expiry date (or such longer period as the Authority may allow), the Authority must complete its consideration of all submissions it receives on the draft core grid determination and consider whether to include the core grid determination in a schedule to this Part.

Compare: Electricity Governance Rules 2003 rule 5A.6 section III part F

Investment contracts

12.70 Purpose

Clause 12.71 provides for investment contracts to be agreed between designated transmission customers and Transpower, and establishes a process to manage any potential implications for grid reliability standards.

Compare: Electricity Governance Rules 2003 rule 8.1 section III part F

12.71 Investment contracts

Transpower may enter into an investment contract with implications for grid reliability standards only if—
- (a) the investment contract is consistent with the grid reliability standards or the proposed investment has been approved by the Authority under clause 12.36(2), and clause 12.36(2) will apply as if the investment contract was a transmission agreement; and
- (b) Transpower advises the Authority of the proposed investment contract.

Compare: Electricity Governance Rules 2003 rule 8.2 section III part F

Clause 12.71(b): amended, on 1 November 2018, by clause 78 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

[Revoked]

Cross Heading: revoked, on 1 February 2016, by clause 51(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.72 [Revoked]

Compare: Electricity Governance Rules 2003 rule 11.1 section III part F

Clause 12.72: revoked, on 1 February 2016, by clause 51(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.73 [Revoked]

Compare: Electricity Governance Rules 2003 rule 11.2 section III part F

Clause 12.73: revoked, on 1 February 2016, by clause 51(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.74 [Revoked]

Compare: Electricity Governance Rules 2003 rule 11.3 section III part F

Clause 12.74: revoked, on 1 February 2016, by clause 51(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.75 Public access to centralised data set [Revoked]

Compare: Electricity Governance Rules 2003 rule 11.4 section III part F

Clause 12.75: revoked, on 1 February 2016, by clause 51(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Grid reliability reporting

12.76 Transpower to publish grid reliability report

(1) Transpower must publish a grid reliability report setting out—
- (a) a forecast of demand at each grid exit point over the next 10 years; and
- (b) a forecast of supply at each grid injection point over the next 10 years; and
- (c) whether the power system is reasonably expected to meet the N-1 criterion, including in particular whether the power system would be in a secure state at each grid exit point, at all times over the next 10 years; and
- (d) proposals for addressing any matters identified in accordance with paragraph (c).
(2) Transpower must publish a grid reliability report no later than 2 years after the date on which it published the previous grid reliability report, or such other date as determined by the Authority (having consulted with Transpower).
(3) If there is a material change in the forecast demand at a grid exit point or in the forecast supply at a grid injection point in the period to which the most recent grid reliability report relates, Transpower must publish a revised grid reliability report as soon as reasonably practicable after the material change.

Compare: Electricity Governance Rules 2003 rule 12A section III part F

Clause 12.76(2): amended, on 21 September 2012, by clause 17 of the Electricity Industry Participation (Minor Amendments) Code Amendment 2012.

Clause 12.76(1): amended, on 5 October 2017, by clause 303 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Subpart 4—Transmission pricing methodology

12.77 Recovery of investment costs by Transpower

The costs incurred by Transpower (irrespective of when they are incurred) in relation to an approved investment are recoverable by Transpower from designated transmission customers on the basis of the transmission pricing methodology and must be paid by designated transmission customers accordingly.

Compare: Electricity Governance Rules 2003 rule 17.1 section III part F

12.78 Purpose for establishing transmission pricing methodology

The purpose of the transmission pricing methodology is to ensure that, subject to Part 4 of the Commerce Act 1986, the full economic costs of Transpower’s services are allocated in accordance with the Authority’s main objective in section 15 of the Act.

Compare: Electricity Governance Rules 2003 rule 1 section IV part F

Clause 12.78: amended, on 1 June 2011, by clause 4 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.78: amended, on 1 March 2024, by clause 59 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.79 Main statutory objective

Transpower, in developing the transmission pricing methodology, and the Authority, in approving the transmission pricing methodology, must assess the transmission pricing methodology against the Authority’s main objective in section 15 of the Act.

Compare: Electricity Governance Rules 2003 rule 2 section IV part F

Clause 12.79: substituted, on 1 June 2011, by clause 5 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.79 Heading: amended, on 1 March 2024, by clause 60(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

Clause 12.79: amended, on 1 March 2024, by clause 60(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.80 [Revoked]

Compare: Electricity Governance Rules 2003 rule 3 section IV part F

Clause 12.80: revoked, on 1 June 2011, by clause 6 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

12.81 Authority must prepare an issues paper

(1) The Authority must prepare an issues paper on—
- (a) the process for development and approval of the transmission pricing methodology; and
- (b) the guidelines to be followed by Transpower in preparing a methodology for allocating Transpower’s revenues to designated transmission customers.
(2) The process and guidelines must be developed in accordance with the Authority’s main objective in section 15 of the Act.

Compare: Electricity Governance Rules 2003 rule 4 section IV part F

Clause 12.81: substituted, on 1 June 2011, by clause 7 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.81(2): amended, on 1 March 2024, by clause 61 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.82 Authority must consult on issues paper

(1) When the Authority publishes the issues paper, the Authority must publish of the date by which submissions are to be received by the Authority. The date must be no earlier than 15 business days from the date of publication of the issues paper.
(2) Each submission on the issues paper must be made in writing to the Authority and received on or before the submission expiry date. In addition to receiving written submissions, the Authority may elect to hear one or more oral submissions.
(3) Within 20 business days of the submission expiry date (or such longer period as the Authority may allow), the Authority must complete its consideration of all submissions it receives on the issues paper.

Compare: Electricity Governance Rules 2003 rule 5 section IV part F

Clause 12.82(1): amended, on 5 October 2017, by clause 304 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.83 Authority must publish process and guidelines for development of transmission pricing methodology

After consideration of submissions in clause 12.82(3), the Authority must, as soon as reasonably practicable, publish—
- (a) the process for the development of the transmission pricing methodology; and
- (b) any guidelines that Transpower must follow in developing the transmission pricing methodology.

Compare: Electricity Governance Rules 2003 rule 6 section IV part F

Clause 12.83 heading: amended, on 1 June 2011, by clause 8(1) of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.83(b): amended, on 1 June 2011, by clause 8(2) of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Development of transmission pricing methodology by Transpower

12.84 Transmission pricing methodology

The transmission pricing methodology that applies at the commencement of this Code is the transmission pricing methodology in Schedule 12.4.

Clause 12.83(b): amended, on 1 June 2011, by clause 8(2) of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.84 heading: amended, on 20 December 2021, by clause 49 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2019.

Review of an approved transmission pricing methodology

Heading: amended, on 1 June 2011, by clause 9 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

12.85 Review by Transpower

At any time, Transpower may submit to the Authority a proposed variation of its transmission pricing methodology, provided that the submission is made at least 12 months after the last Authority approval of the transmission pricing methodology.

Compare: Electricity Governance Rules 2003 rule 11.1 section IV part F

12.86 Review by Authority

The Authority may review an approved transmission pricing methodology if it considers that there has been a material change in circumstances.

Compare: Electricity Governance Rules 2003 rule 11.2 section IV part F

Clause 12.86 heading: amended, on 20 December 2021, by clause 50 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2019.

12.87 Process for review

A review of the transmission pricing methodology must take into account the requirements of clauses 12.79 and 12.89(1). The Authority must follow the processes outlined in clauses 12.91 to 12.94 when reviewing a transmission pricing methodology.

Compare: Electricity Governance Rules 2003 rule 11.3 section IV part F

12.88 Transpower to submit methodology

(1) Transpower must submit a proposed transmission pricing methodology to the Authority within 90 days (or such longer period as the Authority may allow) of receipt of a written request from the Authority.
(2) The Authority may, after publishing the process described in clause 12.83(a) and the guidelines described in clause 12.83(b), issue such a request.

Compare: Electricity Governance Rules 2003 rule 7.1 section IV part F

12.89 Form of proposed transmission pricing methodology

(1) Transpower must develop its proposed transmission pricing methodology consistent with—
- (a) any determination made under Part 4 of the Commerce Act 1986; and
- (b) the Authority’s main objective in section 15 of the Act; and
- (c) any guidelines published under clause 12.83(b).
(2) Transpower’s proposed transmission pricing methodology must include indicative prices to allow the Authority and interested parties to understand the impact of the methodology on designated transmission customers.

Compare: Electricity Governance Rules 2003 rule 7.2 section IV part F

Clause 12.89(1)(b): substituted, on 1 June 2011, by clause 10 of the Electricity Industry Participation (Transmission Pricing) Code Amendment 2011.

Clause 12.89(1)(b): amended, on 1 March 2024, by clause 62 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024..

12.90 Authority may decline to consider proposed transmission pricing methodology

(1) The Authority may decline to consider the proposed Transpower transmission pricing methodology if, in the Authority’s view, Transpower has not provided sufficient information for the Authority to make an informed assessment of the matters referred to in clauses 12.91 to 12.94.
(2) If the Authority so declines, the Authority must advise Transpower of the extra information required, and Transpower must provide a revised transmission pricing methodology by a date specified by the Authority.

Compare: Electricity Governance Rules 2003 rule 7.3 section IV part F

Process for determination of transmission pricing methodology

12.91 Authority may approve proposed transmission pricing methodology or refer back to Transpower

(1) After consideration of Transpower’s proposed transmission pricing methodology, the Authority may either—
- (a) approve the proposed transmission pricing methodology having regard to the requirements of clause 12.89(1); or
- (b) refer the proposed transmission pricing methodology back to Transpower if in the Authority’s view the proposed transmission pricing methodology does not adequately conform to the requirements of clause 12.89(1) and Transpower will have 20 business days to consider the Authority’s concerns and to resubmit its proposed transmission pricing methodology for consideration by the Authority.
(2) If the Authority considers that the transmission pricing methodology resubmitted by Transpower under subclause (1)(b) does not conform to the requirements of clause 12.89(1), the Authority may make any amendments it considers necessary to ensure that the proposed transmission pricing methodology adequately conforms to the requirements of clause 12.89(1).

Compare: Electricity Governance Rules 2003 rule 8.1 section IV part F

12.92 Authority must publish proposed transmission pricing methodology

(1) The Authority must publish the proposed transmission pricing methodology as soon as practicable.
(2) At the time the Authority publishes the proposed transmission pricing methodology the Authority must publish the date by which submissions are to be received by the Authority. The date must be no earlier than 15 business days from the date of publication of the proposed transmission pricing methodology.
(3) Each submission on the proposed transmission pricing methodology must be made in writing to the Authority and received on or before the submission expiry date. In addition to receiving written submissions, the Authority may elect to hear 1 or more oral submissions.

Compare: Electricity Governance Rules 2003 rules 8.2 and 8.3 section IV part F

Clause 12.92(2): amended, on 5 October 2017, by clause 305 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.93 Decision on transmission pricing methodology

Within 40 business days of the submission expiry date (or such longer period as the Authority may allow), the Authority must complete its consideration of all submissions it receives on a proposed transmission pricing methodology and consider whether to include the transmission pricing methodology in a schedule to this Part and, if so, the date that the transmission pricing methodology will take effect.

Compare: Electricity Governance Rules 2003 rule 8.4 section IV part F

12.94 Authority to determine commencement date

In determining a date on which the transmission pricing methodology must take effect, the Authority must consult with Transpower.

Compare: Electricity Governance Rules 2003 rule 8.5 section IV part F

Amending the transmission pricing methodology

Cross Heading: inserted, on 25 July 2022, by clause 4 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2022.

12.94A

Amending the transmission pricing methodology

(1) Despite anything else in this Code, the Authority may amend the transmission pricing methodology under section 38 of the Act if—
- (a) the Authority complies with section 39(1) of the Act; or
- (b) the Authority is satisfied on reasonable grounds regarding any of the matters in section 39(3)(a), (b) or (c) of the Act (in which case sections 39(1)(b) and (c) of the Act will not apply to the amendment); or
- (cc) section 40 of the Act applies (in which case section 39(1) of the Act will not apply to the amendment).
(2) When consultation is required on an amendment to the transmission pricing methodology under subsection (1), the Authority must include an explanation of whether it considers the amendment to be consistent with the intent of the most recent guidelines published under clause 12.83(b), and if it does not consider the amendment to be consistent, the reasons why the Authority considers the amendment to nevertheless be consistent with section 32(1) of the Act.

Clause 12.94A: inserted, on 25 July 2022, by clause 4 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2022.

Clause 12.94A: replaced, on 17 June 2024, by clause 4 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

Application of approved transmission pricing methodology

12.95 Charges to comply with transmission pricing methodology

Transpower must charge for those transmission services affected only in accordance with the transmission pricing methodology.

Compare: Electricity Governance Rules 2003 rule 9.1 section IV part F

Clause 12.95(1): amended, on 16 December 2013, by clause 8(1) of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Clause 12.95(2): revoked, on 16 December 2013, by clause 8(2) of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Clause 12.95: replaced, on 1 April 2023, by clause 5 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) (No 2) 2022.

12.96 Development of transmission prices

After approval of the transmission pricing methodology, Transpower must—
- (a) develop and publish transmission prices consistent with the transmission pricing methodology based on its total revenue requirement for connection to or use of the grid; and
- (b) demonstrate to the Authority that the prices are consistent with the transmission pricing methodology.

Compare: Electricity Governance Rules 2003 rule 9.2 section IV part F

Clause 12.96(a): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Clause 12.96(a): amended, on 5 October 2017, by clause 306 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Audit of transmission prices

12.97 Audit of transmission prices

(1) The Authority may appoint an auditor to confirm whether Transpower’s transmission prices have been calculated in accordance with the transmission pricing methodology.
(2) Transpower must ensure that the auditor's report includes the auditor's view on whether the application of the transmission pricing methodology by Transpower contains errors or inconsistencies that may have a material impact on the prices of any individual designated transmission customers, or designated transmission customers in general.
(3) Transpower must provide the auditor with all relevant information required by the auditor to complete its review.

Compare: Electricity Governance Rules 2003 rule 9.3 section IV part F

Clause 12.97(2): amended, on 1 February 2016, by clause 52 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.98 Transpower may respond to auditor’s report

Transpower must ensure that the auditor's report includes any comments that Transpower provided to the auditor within 15 business days of Transpower receiving a draft of the report.

Compare: Electricity Governance Rules 2003 rule 9.4 section IV part F

Clause 12.98: substituted, on 1 February 2016, by clause 53 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.99 Final auditor report to the Authority

(1) Transpower must ensure that, within 10 business days after the auditor receives Transpower’s response under clause 12.98, the auditor provides a report to the Authority certifying that either—
- (a) Transpower had applied correctly the approved transmission pricing methodology; or
- (b) material errors remained in Transpower’s application of the transmission pricing methodology.
(2) Within 5 business days of receiving the report, the Authority must publish the auditor's report.

Compare: Electricity Governance Rules 2003 rules 9.5 and 9.6 section IV part F

Clause 12.99(1): amended, on 1 February 2016, by clause 54 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.100 Transpower to redetermine transmission prices

If the auditor concludes that there are material errors in Transpower’s application of the transmission pricing methodology, Transpower must recalculate and publish revised transmission prices to correct identified errors.

Compare: Electricity Governance Rules 2003 rule 9.7 section IV part F

12.101 Auditor’s costs

Transpower must meet the actual and reasonable expenses of the auditor.

Compare: Electricity Governance Rules 2003 rule 9.8 section IV part F

12.102 Enforcement of transmission charges

(1) The approved transmission pricing methodology must be incorporated in transmission agreements between Transpower and designated transmission customers.
(2) The amount payable by a designated transmission customer under a transmission agreement under subclause (1)—
- (a) is recoverable in any court of competent jurisdiction as a debt due to Transpower; and
- (b) may be challenged in any proceedings to recover the debt on the ground that Transpower has incorrectly applied the transmission pricing methodology in a manner that is adverse to the designated transmission customer but the transmission pricing methodology itself may not be challenged.

Compare: Electricity Governance Rules 2003 rule 10 section IV part F

Information for calculating transmission charges

Cross Heading: inserted, on 25 July 2022, by clause 5 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2022.

12.102A

Information held by system operator may be used to calculate charges

(1) The system operator may provide to Transpower any information the system operator holds that the system operator or Transpower considers Transpower reasonably needs to calculate charges under the transmission pricing methodology.
(2) Transpower may use any information provided to it by the system operator under this clause to calculate charges under the transmission pricing methodology. Transpower must not use the information for any other purpose except—
- (a) as provided for in this Code; or
- (b) as required by law; or
- (c) if the information is or becomes publicly available; or
- (d) if the information is or has been provided to Transpower other than under this clause and without restriction as to Transpower’s use of it for the other purpose; or
- (e) otherwise as may be agreed with the participant or other person who is the subject of the information.

Clause 12.102A: inserted, on 25 July 2022, by clause 5 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2022.

12.102B

Information about embedded electricity

(1) In this clause, “AMDR”, “capacity”, “consuming plant”, “difference cap”, “embedded electricity”, and “generating plant” have the meanings given to those terms in the transmission pricing methodology.
(2) This clause applies where the Authority or Transpower reasonably considers a participant owns generating plant with a total capacity of 10 MW or more directly or indirectly connected to the same point of connection in respect of which Transpower holds insufficient information to calculate embedded electricity under the transmission pricing methodology.
(3) If subclause (2) applies, the Authority or Transpower may request that the participant provide the information specified in subclause (5) to Transpower in a format reasonably requested by the Authority or Transpower.
(4) The Authority or Transpower (as applicable) must withdraw a request made under subclause (3) if the participant satisfies the Authority or Transpower (as applicable) within 10 business days (or such longer period as provided for by the Authority or Transpower) of the request that—
- (a) the participant does not own the generating plant referred to in subclause (2); or
- (b) the generating plant does not have a total capacity of 10 MW or more directly or indirectly connected to the same point of connection; or
- (c) the total capacity of any consuming plant supplied or potentially supplied by the generating plant, without that electricity first flowing through a point of connection, is 1 MW or less.
(5) The information referred to in subclause (3) is any information about the electricity generated by the participant’s generating plant referred to in subclause (2) (whether metered or estimated) for any trading period or trading periods specified by the Authority or Transpower from (and including) trading period 1 on 1 July 2014 to (and including) trading period 48 on the day immediately before the date of the request under subclause (3).
(6) Transpower may use any information provided to it by a participant under this clause to calculate charges under the transmission pricing methodology. Transpower must not use the information for any other purpose except—
- (a) as provided for in this Code; or
- (b) as required by law; or
- (c) if the information is or becomes publicly available; or
- (d) if the information is or has been provided to Transpower other than under this clause and without restriction as to Transpower’s use of it for the other purpose; or
- (e) otherwise as may be agreed with the participant.
(7) Subject to subclause (9), if—
- (a) a participant does not provide to Transpower any or all of the information requested by the Authority or Transpower under subclause (5) within 20 business days (or such longer period as provided for by the Authority or Transpower) of the date of the request under subclause (3); or
- (b) any or all of the information provided is not provided in the requested format or another format Transpower can reasonably use for calculating charges under the transmission pricing methodology; or
- (c) Transpower reasonably considers any or all of the information provided is not sufficiently reliable for calculating charges under the transmission pricing methodology,
Transpower must use the values specified in subclause (8) to calculate charges under the transmission pricing methodology in place of the information that is not provided, is not in the requested format or another format Transpower can reasonably use, or is not sufficiently reliable.
(8) The values referred to in subclause (7) are, for calculating the relevant designated transmission customer’s AMDR and difference cap under the transmission pricing methodology, a value or values of electricity generated by the generating plant calculated as if it were operating at its capacity.
(9) Subclause (7) is subject to any requirement on Transpower in this Code to use information from a specific source to calculate charges under the transmission pricing methodology.

Clause 12.102B: inserted, on 25 July 2022, by clause 5 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2022.

12.102C

Authority may provide information

Subject to any applicable law including any other provision of this Code, the Authority may provide to Transpower any information it holds for the purpose of enabling Transpower to calculate transmission charges. The Authority may provide the information subject to any conditions the Authority considers appropriate.

Clause 12.102C: inserted, on 17 June 2024, by clause 5 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

Subpart 5—[Revoked]

Subpart 5: revoked, on 1 October 2011, by clause 6 of the Electricity Industry Participation (Financial Transmission Rights) Code Amendment 2011.

12.103 [Revoked]

Compare: Electricity Governance Rules 2003 rule 1 section V part F

Clause 12.103: revoked, on 1 October 2011, by clause 6 of the Electricity Industry Participation (Financial Transmission Rights) Code Amendment 2011.

12.104 [Revoked]

Compare: Electricity Governance Rules 2003 rule 2 section V part F

Clause 12.104: revoked, on 1 October 2011, by clause 6 of the Electricity Industry Participation (Financial Transmission Rights) Code Amendment 2011.

Subpart 6—Interconnection asset services

12.105 Purpose of this subpart

The purpose of this subpart is to—
- (a) create incentives on Transpower, through enforceable service measures, to provide interconnection assets at the capacity ratings required by designated transmission customers and other grid users; and
- (b) ensure that Transpower provides information on the capacity of interconnection assets, and their reliability and availability, to enable grid users to monitor the capacity and performance of interconnection assets; and
- (c) establish processes for the identification of investments in the grid, and alternatives to such investments, to ensure efficient decision-making on the use of and upgrades to the grid; and
- (d) specify the circumstances in which Transpower may permanently or temporarily remove interconnection assets from service or reconfigure the grid.

Compare: Electricity Governance Rules 2003 rule 1 section VI part F

Clause 12.105(d): amended, from 2 March 2012 to 3 December 2012, by clause 4 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.105(d): amended, from 15 March 2013 to 15 December 2013, by clause 4 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.105(d): amended, on 16 December 2013, by clause 6 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

12.106 Interconnection asset capacity and grid configuration

(1) The interconnection asset capacity and grid configuration set out in schedule F6 of section VI of part F of the rules immediately before this Code came into force, continues in force and is deemed to be the interconnection asset capacity and grid configuration that applies at the commencement of this Code.
(2) Clause 12.110 applies to the interconnection asset capacity and grid configuration.

12.107 Transpower to identify interconnection branches, and propose service measures and levels

(1) Transpower must provide the Authority with the information set out in subclause (4) and a diagram showing the configuration of the grid, other than connection assets.
(2) Transpower must provide the information and diagram referred to in subclause (1) to the Authority in the form specified by the Authority.
(3) The interconnection asset capacity and grid configuration referred to in subclause (1) must be provided within 3 months of the date on which the Authority, in accordance with subclause (2), sets the form in which the interconnection asset capacity and grid configuration must be provided.
(4) The information required under subclause (1) is—
- (a) for each interconnection circuit branch, the following service measures and service levels:
  - (i) the overall continuous capacity rating of the interconnection circuit branch, for both summer and winter periods in MVA and amperes:
  - (ii) the level of impedance of the interconnection circuit branch both resistive and reactive and for assets arranged in both shunt and series in PU, using a base of 100 MVA, provided the impedance of the interconnection circuit branch is equal to or more than 0.0001 PU, using 100 MVA as the base:
  - (iii) the nominal high voltage rating of each interconnection circuit branch in kV:
  - (iv) the high voltage range that each interconnection circuit branch can be operated over in kV, specified as a maximum and a minimum; and
- (b) for each interconnection transformer branch, the following information:
  - (i) the overall 24 hour post contingency capacity rating of the interconnection transformer branch, for both the summer and winter period, in amperes and MVA as follows:
    - (A) for 2 Winding interconnection transformer branches, the overall 24 hour post contingency capacity rating:
    - (B) for 3 Winding interconnection transformer branches, the overall 24 hour post contingency capacity rating, at HV, MV, and LV:
  - (ii) the continuous capacity rating of the interconnection transformer branch in amperes and MVA as follows:
    - (A) for 2 Winding interconnection transformer branches, the continuous capacity rating:
    - (B) for 3 Winding interconnection transformer branches, the continuous capacity rating, at HV, MV, and LV:
  - (iii) the level of impedance of the interconnection transformer branch, both resistive and reactive and for assets arranged in both shunt and in series in PU, using a base of 100 MVA, as follows:
    - (A) for 2 Winding interconnection transformer branches, the level of impedance of the interconnection transformer branch:
    - (B) for 3 Winding interconnection transformer branches, the level of impedance of the interconnection transformer branch, at HV, MV, and LV:
  - (iv) the nominal high voltage rating of the interconnection transformer branch in kV:
  - (v) the high voltage range that the interconnection transformer branch can be operated over in kV, specified as a maximum, and a minimum:
  - (vi) in respect of the tapping steps and ranges of the interconnection transformer branch:
    - (A) the tap voltage range in volts, specified as a maximum and a minimum:
    - (B) the number of tapping steps:
    - (C) the size of each tapping step as a percentage of the operational voltage range:
    - (D) whether the tapping step is on-load or off-load:
    - (E) whether on-load tapping capacity is automatic or manual;
    - (F) if on-load tapping capacity is automatic, whether it is auto-selected:
    - (G) if on-load tapping capacity is manual, the tap step it is normally set to, which for the purposes of this clause is the actual or expected position at winter peak demand; and
- (c) the transfer capacity in the North and South transfer for each HVDC link configuration expressed as follows:
  - (i) DC sent in MW:
  - (ii) AC received in MW; and
- (d) for each shunt asset, the following service measures and service levels:
  - (i) the overall capacity rating, in MVAr, in terms of both absorption or provision:
  - (ii) the nominal voltage rating of the shunt asset in kV:
  - (iii) the maximum and minimum voltage range in kV that the shunt asset can operate over; and
- (e) in addition to the information required under paragraph (d) in relation to shunt assets:
  - (i) whether each shunt asset is dynamic or static:
  - (ii) if the shunt asset is dynamic, whether it is an SVC or synchronous compensator:
  - (iii) any shunt assets that may directly affect the capacity of the HVDC link as set out in paragraph (c) and the likely magnitude of such effect; and
- (f) the dates for the summer and winter periods or other such defined periods as may apply for the purposes of paragraphs (a) and (b).
(5) The information provided under subclause (4) must,—
- (a) in the case of information provided under subclause (4)(a), (c) and (d), be consistent with the information disclosed by Transpower in the most recent asset capability statement provided by Transpower under clause 2(5) of Technical Code A of Schedule 8.3; and
- (b) in the case of information provided under subclause (4)(b), be consistent with the manufacturer’s specification for the component assets and the information disclosed by Transpower in the most recent asset capability statement provided under clause 2(5) of Technical Code A of Schedule 8.3, if this differs from the manufacturer’s specifications;
- (c) in the case of information provided under subclause (4)(a), be consistent with the thermal design rating of each interconnection branch; and
- (d) cover every interconnection asset, either as part of an interconnection circuit branch, interconnection transformer branch, the HVDC link or as a shunt asset.
(6) After reviewing the interconnection asset capacity and grid configuration provided under subclause (1), the Authority may request Transpower to reconsider whether any of the interconnection asset capacity and grid configuration, is accurate, and require Transpower to resubmit the interconnection asset capacity and grid configuration to the Authority for reconsideration.

Compare: Electricity Governance Rules 2003 rules 2.1 to 2.6 section VI part F

Clause 12.107(2): replaced, on 5 October 2017, by clause 307(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.107(4): amended, on 5 October 2017, by clause 307(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.107(4)(c): amended, on 20 December 2021, by clause 51 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2019.

Clause 12.107(5): amended, on 5 October 2017, by clause 307(3) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.107(4)(c): amended, on 1 March 2024, by clause 63 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.108 Consultation on proposed interconnection asset capacity and grid configuration

(1) If the Authority is provisionally satisfied that the interconnection asset capacity and grid configuration provided under clause 12.107(1) or resubmitted under clause 12.107(6) are correct, the Authority must publish the proposed interconnection asset capacity and grid configuration as soon as practicable for consultation with any person that the Authority thinks is likely to be materially affected by the incorporation of the proposed interconnection asset capacity and grid configuration by reference in this Code.
(2) As well as the consultation required under subclause (1), the Authority may undertake any other consultation it considers necessary.

Compare: Electricity Governance Rules 2003 rules 2.7 and 2.8 section VI part F

12.109 Decision on interconnection asset capacity and grid configuration

(1) When the Authority has completed its consultation on the proposed interconnection asset capacity and grid configuration, it must consider whether to incorporate the proposed interconnection asset capacity and grid configuration by reference in this Code.
(2) If the Authority decides to incorporate the interconnection asset capacity and grid configuration by reference in this Code, the Authority must determine a date on which the incorporation by reference takes effect.

Compare: Electricity Governance Rules 2003 rule 2.9 section VI part F

Clause 12.109(2): amended, on 1 August 2023, by clause 45 of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

12.110 Incorporation of interconnection asset capacity and grid configuration by reference

(1) The interconnection asset capacity and grid configuration is incorporated by reference in this Code.
(2) [Revoked]

Clause 12.110(1): amended, on 5 October 2017, by clause 308 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.110(1): amended, on 1 August 2023, by clause 46(1) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.110(2): revoked, on 1 August 2023, by clause 46(2) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

12.111 Transpower to make interconnection branches and other assets available and keep grid configuration

(1) Transpower must make each interconnection circuit branch, interconnection transformer branch, the HVDC link, and each shunt asset identified in the interconnection asset capacity and grid configuration available for use by the system operator for the conveyance of electricity—
- (a) at least at the service levels specified in the interconnection asset capacity and grid configuration in accordance with clause 12.107(4); and
- (b) in accordance with good electricity industry practice and relevant health and safety standards.
(2) Transpower must keep the grid in the configuration set out in the interconnection asset capacity and grid configuration.
(3) Transpower is not required to comply with subclauses (1)(a) or (2) if clause 12.112(1) applies.

Compare: Electricity Governance Rules 2003 rule 3 section VI part F

12.112 Exceptions to clause 12.111

(1) Transpower is not required to comply with clause 12.111(1)(a) or (2) if—
- (a) permitted under the Outage Protocol made under subpart 7; or
- (b) an interconnection asset that forms part of an interconnection branch or the HVDC link, or a shunt asset—
  - (i) is permanently removed from service, the grid is permanently reconfigured, or the transmission capacity of such an asset is reduced, and the decision to remove the asset from service or reconfigure the grid or reduce the transmission capacity of the asset takes into account the effect of the removal of the asset, reconfiguration of the grid, or the reduction in transmission capacity of the asset, on other materially affected parties, and is undertaken—
    - (A) in order to maintain the health and safety of any person; or
    - (B) in order to maintain the safety and integrity of equipment; or
    - (C) in accordance with demonstrably prudent economic criteria; or
  - (iaa) has been temporarily removed from service, or the grid has been temporarily reconfigured, in accordance with clause 12.116AA; or
  - (ia) [Expired]
  - (ii) has been permanently removed from service, or the grid has been permanently reconfigured, in accordance with clause 12.117; or
- (c) a modification to an interconnection branch, the HVDC link, a shunt asset or to the configuration of the grid, has been made as a result of an investment in the grid; or
- (d) a modification to an interconnection branch, the HVDC link, a shunt asset or to the configuration of the grid has been made as a result of an investment made under an investment contract entered into in accordance with clauses 12.70 and 12.71; or
- (e) the voltage range specified in the AOPOs for an interconnection asset that forms part of an interconnection branch is modified, or any equivalence arrangement is approved or dispensation is granted under clauses 8.29 to 8.31 in respect of the asset; or
- (ea) in relation to the HVDC link—
  - (i) the HVDC owner is operating the HVDC link in accordance with—
    - (A) a commissioning plan agreed with the system operator under clause 2(6) to (9) of Technical Code A of Schedule 8.3; or
    - (B) a test plan provided to the system operator under clause 2(6) to (9) of Technical Code A of Schedule 8.3; and
  - (ii) the HVDC link configuration is—
    - (A) Pole 3 and Pole 2 bipole round power; or
    - (B) Pole 3 and Pole 2 bipole not round power; or
- (f) Transpower and a designated transmission customer have agreed otherwise in accordance with clause 12.128.
(2) If subclause (1)(c) to (e) applies, or the grid is reconfigured under subclause (1)(b)(i) or (ii), Transpower must—
- (a) make the interconnection branch, the HVDC link or the shunt asset available to the system operator at least at its modified capacity rating, and at its modified service levels; and
- (b) keep the grid in its modified configuration.
(2AA) Subclause (2AB) applies—
- (a) if subclause (1)(b)(iaa) applies; and
- (b) while—
  - (i) an interconnection asset that forms part of an interconnection branch or the HVDC link, or a shunt asset, has been temporarily removed; or
  - (ii) the grid has been temporarily reconfigured.
(2AB) Transpower must make the interconnection branch, the HVDC link or the shunt asset available to the system operator at least at its modified capacity rating, and at its modified service levels.
(2A) [Expired]
(2B) [Expired]
(3) If a decision to remove an asset, or reconfigure the grid, or reduce the transmission capacity of an asset has been made under subclause (1)(b)(i) or (ii), Transpower must as soon as reasonably possible publish the analysis it undertook in accordance with subclause (1)(b)(i) or (ii), or a summary of that analysis.

Compare: Electricity Governance Rules 2003 rule 4 section VI part F

Clause 12.112(1)(b): amended, from 2 March 2012 to 3 December 2012, by clause 5(1) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.112(1)(b)(i): amended, from 15 March 2013 to 15 December 2013, by clause 5(1)(a) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(b)(i): amended, on 16 December 2013, by clause 7(1) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(b)(iaa): inserted, from 15 March 2013 to 15 December 2013, by clause 5(1)(b) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(b)(iaa): inserted, on 16 December 2013, by clause 7(2) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(b)(ii): amended, from 15 March 2013 to 15 December 2013, by clause 5(1)(c) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(b)(ii): amended, on 16 December 2013, by clause 7(3) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(1)(ea): inserted, on 26 September 2013, by clause 4 of the Electricity Industry Participation (HVDC Link Bipole Control System Testing) Code Amendment 2013.

Clause 12.112(1)(ea)(i)(A): amended, on 5 October 2017, by clause 309(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.112(2): amended, from 2 March 2012 to 3 December 2012, by clause 5(2) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.112(2): amended, from 15 March 2013 to 15 December 2013, by clause 5(2) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(2): amended, on 16 December 2013, by clause 7(4) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(2): amended, on 5 October 2017, by clause 309(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.112(2AA) and (2AB): inserted, from 15 March 2013 to 15 December 2013, by clause 5(3) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(2AA) and (2AB): inserted, on 16 December 2013, by clause 7(5) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(2A) and (2B): inserted, from 2 March 2012 to 3 December 2012, by clause 5(3) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.112(3): amended, from 15 March 2013 to 15 December 2013, by clause 5(4) of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(3): amended, on 16 December 2013, by clause 7(6) of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.112(3): amended, on 5 October 2017, by clause 309(3) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.112(1)(ea)(ii): amended, on 1 March 2024, by clause 63 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2024.

12.113 Transpower to maintain interconnection assets

Transpower must design, construct, maintain and operate all interconnection assets in accordance with good electricity industry practice.

Compare: Electricity Governance Rules 2003 rule 5 section VI part F

Clause 12.113: amended, on 20 December 2021, by clause 52 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2019.

Transpower to propose investments

12.114 Investments to meet the grid reliability standards

(1) If a grid reliability report identifies, in accordance with clause 12.76(1)(c), that the power system is not reasonably expected to meet the N-1 criterion at a grid exit point at all times over the 5 years following the date on which the report is published and that this is due to an interconnection asset, Transpower must—
- (a) as soon as practicable, investigate whether the interconnection asset meets the grid reliability standards; and
- (b) if the interconnection asset does not meet the grid reliability standards, consider reasonably practicable options for ensuring that the grid reliability standards can be met in respect of that asset; and
- (c) if Transpower considers that 1 or more investments are required in respect of that interconnection asset in order to meet the grid reliability standards, submit an investment proposal to the Commerce Commission—
  - (i) in sufficient time to avoid a breach of the grid reliability standards; or
  - (ii) if the grid reliability standards have already been breached, within 6 months, or such longer period as the Authority may allow, after the publication of the grid reliability report that sets out the investment or investments that Transpower proposes to make; and
- (d) if it considers that an investment is not necessary, publish the reasons for this and any alternative measures that Transpower proposes to undertake.
(2) If an investment proposal submitted under this clause is approved by the Commerce Commission under section 54R of the Commerce Act 1986 or permitted under an input methodology determined under section 54S of that Act, Transpower must undertake the investment—
- (a) before the grid falls below the grid reliability standards for the reason referred to in subclause (1); or
- (b) if the grid had already fallen below the grid reliability standards, or if it is not reasonably practicable to undertake the investment as provided in paragraph (a), as soon as reasonably practicable.
(3) Transpower does not need to submit an investment proposal under subclause (1)(c) if the investment to which the proposal relates has previously been included in an investment proposal submitted to, and considered—
- (a) before this Code came into force, by the Electricity Commission under section III of part F of the rules; or
- (b) after this Code came into force, by the Commerce Commission under section 54R or section 54S of the Commerce Act 1986.

Compare: Electricity Governance Rules 2003 rule 6.1 section VI part F

12.115 Other investments

(1) Transpower must publish a grid economic investment report on whether there are investments that it considers, other than the investments identified under clause 12.114, could be made in respect of the interconnection assets.
(2) Transpower must publish a grid economic investment report no later than 2 years after the date on which it published the previous grid economic investment report, or such other date as determined by the Authority.
(3) If a grid economic investment report identifies that there are investments that could be made, Transpower must publish within 6 months a report setting out a proposed timetable for Transpower to consider whether to submit 1 or more investment proposals to the Commerce Commission in respect of those possible investments.
(4) The grid economic investment report does not need to report on possible investments that have been previously included in an investment proposal submitted to, and considered,—
- (a) before this Code came into force, by the Electricity Commission under section III of part F of the rules; or
- (b) after this Code came into force, by the Commerce Commission under section 54R or section 54S of Part 4 of the Commerce Act 1986.

Compare: Electricity Governance Rules 2003 rule 6.2 section VI part F

12.116 Information on capacities of individual interconnection assets

(1) Transpower must publish the following information in respect of each interconnection asset:
- (a) for each transformer that is an interconnection asset, the overall 24 hour post contingency capacity rating of the asset in amperes and MVA, for both the summer and winter periods:
- (b) for all other interconnection assets, the overall capacity rating of the asset in amperes and MVA and, if the interconnection assets are circuits, for both the summer and winter periods.
(2) The information required under subclause (1)—
- (a) must be consistent with the manufacturer’s specification for the asset or with the most recent asset capability statement provided by Transpower under clause 2(5) of Technical Code A of Schedule 8.3, if this differs from the manufacturer’s specification; and
- (b) must be in a form that allows the branch to which each asset belongs to be easily identified; and
- (c) must be published in the form determined by the Authority as soon as reasonably practicable after the Authority has determined the form.

Compare: Electricity Governance Rules 2003 rule 7 section VI part F

Clause 12.116(1): amended, on 5 October 2017, by clause 310(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.116(2)(b): amended, on 5 October 2017, by clause 310(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.116(2)(c): substituted, on 1 February 2016, by clause 55 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

12.116AA

Temporary removal of interconnection assets from service or temporary grid reconfiguration

(1) Transpower must temporarily remove 1 or more interconnection assets from service, or temporarily reconfigure the grid as permitted under clause 12.112(1)(b)(iaa), if—
- (a) the removal or reconfiguration is requested by the system operator in accordance with clause 9.13B; and
- (b) the removal or reconfiguration will result in a net benefit, as calculated under the test set out in clause 12.117.
(2) If Transpower temporarily removes interconnection assets from service or temporarily reconfigures the grid in response to a notice given under clause 9.13B, Transpower must, as soon as is reasonably practicable after the circumstances specified in that notice cease to exist—
- (a) restore the interconnection assets to service; or
- (b) restore the grid to its original configuration.

Clause 12.116AA: inserted, from 15 March 2013 to 15 December 2013, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.116AA: inserted, on 16 December 2013, by clause 8 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.116AA(1): amended, on 5 October 2017, by clause 311 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.116AB

[Expired]

Clause 12.116AB: inserted, from 15 March 2013 to 15 December 2013, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

12.116AC

Information to be published

If Transpower receives a notice given in accordance with clause 9.13B, Transpower must publish,—
- (a) as soon as practical, a copy of the notice; and
- (b) by no later than 5 business days after receiving the notice, a summary of Transpower’s application of the net benefit test that relates to the exceptional circumstances stated in the notice.

Clause 12.116AC heading: amended, on 5 October 2017, by clause 312(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.116AC: inserted, from 15 March 2013 to 15 December 2013, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.116AC: inserted, on 16 December 2013, by clause 8 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.116AC: amended, on 5 October 2017, by clause 312(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.116A

[Expired]

Clause 12.116A: inserted, from 2 March 2012 to 3 December 2012, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

12.116B

[Expired]

Clause 12.116B: inserted, from 2 March 2012 to 3 December 2012, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

12.116C

[Expired]

Clause 12.116C: inserted, from 2 March 2012 to 3 December 2012, by clause 6 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

12.117 Permanent removal of interconnection assets from service or permanent grid reconfiguration

(1) Transpower may permanently remove interconnection assets from service or permanently reconfigure the grid as permitted under clause 12.112(1)(b) only if removal of the asset or reconfiguration of the grid results in a net benefit, as calculated under the test set out in subclause (2).
(2) When Transpower is required to apply a net benefit test, Transpower must—
- (a) estimate the following costs:
  - (i) any additional fuel costs incurred by a generator in respect of any generating units that will be dispatched or are likely to be dispatched during or after the removal of the interconnection asset or the reconfiguration of the grid, arising as a result of the removal or reconfiguration:
  - (ii) any direct labour and material costs that will be incurred by Transpower and the designated transmission customers undertaking the removal of the interconnection asset or the reconfiguration of the grid:
  - (iii) any increase in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy, arising as a result of the removal of the interconnection asset or the reconfiguration of the grid:
  - (iv) any relevant cost specified in clause 12.43(1)(a)(iv):
  - (v) any other relevant cost to a person that produces, transmits, retails or consumes electricity in New Zealand; and
- (b) estimate the following benefits:
  - (i) any reduction in maintenance costs arising as a result of the removal of the interconnection asset or the reconfiguration of the grid (including Transpower’s and any designated transmission customer’s costs):
  - (ii) any reduction in fuel costs incurred by a generator in respect of any generating units, arising or likely to arise during or after the removal of the interconnection asset or the reconfiguration of the grid, as a result of the removal or reconfiguration:
  - (iii) any decrease in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy, arising as a result of the removal of the interconnection asset or the reconfiguration of the grid:
  - (iv) any relevant benefit specified in clause 12.43(1)(b)(iv):
  - (v) any other relevant benefit to a person that produces, transmits, retails or consumes electricity in New Zealand; and
- (c) deduct the costs estimated under paragraph (a) from the benefits estimated under paragraph (b) to determine the net benefit of the proposed removal of the interconnection asset or the reconfiguration of the grid.
(3) Transpower may apply the test under this clause at differing levels of rigour in different circumstances, which may include taking into account the number of assets to be removed or reconfigured, the value of the assets involved, and the size of the load served by the assets.
(4) Transpower is only required to—
- (a) make a reasonable estimate of the costs and benefits identified in subclause (2), based on information reasonably available to it at the time it undertakes the test, and taking into account the proposed number of assets to be removed or reconfigured, the value of the assets involved, and the size of the load served by the assets; and
- (b) take account of events that can be reasonably foreseen.
(5) Transpower’s estimate of fuel costs under subclause (2) must—
- (a) in relation to thermal generating stations, be a reasonable estimate of the fuel costs, based on the economic value of the fuel required for the relevant thermal generating station, and justified by Transpower with reference to opinions on the economic value of the fuel, provided by 1 or more independent and suitably qualified persons; and
- (b) in relation to hydroelectric generating stations—
  - (i) be a reasonable estimate of the fuel costs, based on the economic value of the water stored at a hydroelectric generating station, provided by a suitably qualified person other than—
    (A) Transpower; or
    (B) an employee of Transpower; and
  - (ii) be published, as provided for in the Outage Protocol.
(6) The direct labour costs of Transpower and designated transmission customers under subclause (2)(a) may include any amounts paid to contractors, but must not include any apportionment of the overheads or office costs of Transpower or designated transmission customers.
(7) The material costs of Transpower and designated transmission customers under subclause (2)(a) are the costs of the materials used in carrying out the work during the removal of the interconnection asset or the reconfiguration of the grid.
(8) In assessing the costs and benefits under subclause (2), Transpower must consider any reasonably expected operating conditions, forecasts in the system security forecast, likely fuel costs, and any other reasonable assumptions.
(9) The estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy under subclause (2) must be based on the value of expected unserved energy in clause 4 of Schedule 12.2 and Transpower’s estimate of the expected unserved energy in respect of each affected designated transmission customer and end use customer.
(10) To avoid doubt, this clause applies to the removal of interconnection assets from service if Transpower does not propose to replace those assets with another asset.

Compare: Electricity Governance Rules 2003 rule 8 section VI part F

Clause 12.117 heading: amended, on 5 October 2017, by clause 313(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.117: substituted, on 16 December 2013, by clause 9 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.117(1): amended, from 2 March 2012 to 3 December 2012, by clause 7 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.117(1): amended, from 15 March 2013 to 15 December 2013, by clause 7 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.117(1): amended, on 5 October 2017, by clause 313(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.117(9): amended, on 1 February 2016, by clause 56 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.117(9): amended, on 1 November 2018, by clause 79 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

12.118 Transpower to provide and publish annual report on interconnection asset capacity and grid configuration

(1) Transpower must provide the Authority with and publish an annual report including—
- (a) any matter required to be reported on for the purposes of this clause by the Outage Protocol; and
- (b) the extent to which, in the preceding year ending 30 June, it has complied with the requirements of clause 12.111(1)(a) and (2); and
- (c) any specific instances in which Transpower has not complied with clause 12.111(1)(a) and (2); and
- (d) to the extent practicable, the circumstances that have given rise to any failure to comply with clause 12.111(1)(a) and (2); and
- (e) to the extent practicable, any steps that it intends to take or other options to reduce the likelihood of failing to comply with clause 12.111(1)(a) and (2) in the future; and
- (f) any modifications made to interconnection circuit branches, the HVDC link, and each shunt asset under clause 12.112(c) to (e) in the preceding year ending 30 June and the extent to which it has complied with clause 12.112(2) in respect of those modifications, including any specific instances in which Transpower has not complied; and
- (g) any interconnection assets that have been removed from service, or any reconfigurations to the grid made, in accordance with clause 12.116AA or clause 12.117; and
- (h) copies of any agreements made under clause 12.128 or, in respect of interconnection assets only, clause 12.151 in the preceding year ending 30 June; and
- (i) an update of the interconnection asset capacity and grid configuration required under clause 12.107(1), as at the end of the preceding year ending 30 June.
(2) Transpower must provide to the Authority and publish, the report referred to in subclause (1) by 30 November each year.
(3) The Authority may incorporate by reference in this Code the updated interconnection asset capacity and grid configuration referred to in subclause (1)(i) in accordance with clause 12.110. The Authority may consult with any person the Authority considers is likely to be materially affected by the proposed amendments to the interconnection asset capacity and grid configuration, as it sees fit. Transpower must comply with the interconnection asset capacity and grid configuration incorporated by reference in this Code in accordance with clause 12.110.

Compare: Electricity Governance Rules 2003 rule 9 section VI part F

Clause 12.118(1)(g): amended, from 2 March 2012 to 3 December 2012, by clause 8 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2012.

Clause 12.118(1)(g): amended, from 15 March 2013 to 15 December 2013, by clause 8 of the Electricity Industry Participation (Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.118(1)(g): amended, on 16 December 2013, by clause 10 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.118(1): amended, on 5 October 2017, by clause 314(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.118(2): amended, on 5 October 2017, by clause 314(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Reporting on availability and reliability

12.119 Index measures for availability and reliability

The index measures for availability and reliability for each interconnection branch, shunt asset and the HVDC link are the index measures for reliability for each interconnection branch, shunt asset and the HVDC link in Schedule 12.5.

12.120 Updating of availability and reliability index measures

(1) This clause applies if interconnection assets—
- (a) are modified or replaced as permitted under clause 12.112(1); or
- (b) have been damaged or degraded but, after conducting the investigation required under clause 12.114(1), Transpower considers that they still meet the grid reliability standards.
(2) If this clause applies, if, after the availability and the reliability or availability index measures for an interconnection branch, shunt asset and the HVDC link or aggregated interconnection branches or shunt assets no longer meet the requirements of clause 12.122, the availability and reliability index measures in Schedule 12.5 must be updated following the procedure specified in clauses 12.121 to 12.127.
(3) Transpower must propose the revised index measures under clause 12.121 within 20 business days of the modification or replacement, or such longer period as the Authority may allow.

Compare: Electricity Governance Rules 2003 rule 10.9 section VI part F

12.121 Transpower to submit draft index measures for availability and reliability

(1) Transpower must provide the Authority with proposed index measures for availability and reliability for each interconnection branch, shunt asset and the HVDC link, in accordance with this clause.
(2) For the purposes of subclause (1), Transpower must categorise interconnection branches and shunt assets into groups of interconnection branches and shunt assets comprising similar assets.
(3) The index measures to be provided under subclause (1) are—
- (a) annual unavailability of each interconnection branch, shunt asset and the HVDC link due to planned outages of 1 minute or longer in hours per year ending 30 June, expressed as a percentage; and
- (b) annual unavailability of each interconnection branch, shunt asset and the HVDC link due to unplanned outages of 1 minute or longer in hours per year ending 30 June, expressed as a percentage; and
- (c) annual number of planned interruptions of 1 minute or longer caused by planned outages of 1 minute or longer of each interconnection branch, shunt asset and the HVDC link; and
- (d) annual number of unplanned interruptions of 1 minute or longer caused by unplanned outages of 1 minute or longer of each interconnection branch, shunt asset and the HVDC link;
- (e) total unserved energy per year ending 30 June in MWh resulting from planned interruptions of 1 minute or longer caused by planned outages of 1 minute or longer of each interconnection branch, shunt asset and the HVDC link; and
- (f) total unserved energy per year ending 30 June in MWh resulting from unplanned interruptions of 1 minute or longer caused by unplanned outages of 1 minute or longer of each interconnection branch, shunt asset and the HVDC link.
(4) At the same time, Transpower must propose availability and reliability index measures for aggregated interconnection branches and shunt assets, such as by asset class or for all of the grid.

Compare: Electricity Governance Rules 2003 rule 10.1 section VI part F

Clause 12.121(2): amended, on 5 October 2017, by clause 315(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.121(3): amended, on 5 October 2017, by clause 315(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.122 Requirements for index measures

(1) The proposed availability and reliability index measures under clause 12.121(3) must be based on the average annual availability and reliability of each category of interconnection branch, or shunt asset and of the HVDC link over the 5 year period (ending 30 June) immediately before this clause came into force.
(2) The proposed index measures under clause 12.121(3) must be accompanied by an explanation showing how the requirements of subclause (1) were applied.
(3) The index measure for unserved energy under clause 12.121(3)(e) and (f) must be determined in accordance with the methodology for determining expected unserved energy relating to outages of interconnection assets specified in the Outage Protocol.
(4) In proposing the availability and reliability index measures under clause 12.121(4), Transpower must specify its reasons for proposing those measures.

Compare: Electricity Governance Rules 2003 rule 10.2 section VI part F

Clause 12.122(1): amended, on 5 October 2017, by clause 316 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.123 Authority may initially approve proposed index measures or refer back to Transpower

After considering Transpower’s proposed availability and reliability index measures and accompanying reasons the Authority may either—
- (a) provisionally approve the proposed availability and reliability index measures; or
- (b) refer the proposed availability and reliability index measures and accompanying explanation back to Transpower if in the Authority’s view—
  - (i) the proposed availability and reliability index measures under clause 12.121 are not consistent with the requirements of clause 12.122(1) or the methodology referred to in clause 12.122(3); or
  - (ii) the proposed availability and reliability index measures under clause 12.121 do not provide sufficient information to meet the reasonable needs of grid users; or
  - (iii) the reasons provided with the availability and reliability targets in accordance with clause 12.122 are inadequate—
- and Transpower must within 20 business days (or such longer period as the Authority may allow) consider the Authority’s concerns and resubmit the proposed availability and reliability index measures and accompanying explanations for consideration by the Authority.

Compare: Electricity Governance Rules 2003 rule 10.3 section VI part F

12.124 Amendment of proposed index measures by the Authority

If the Authority considers that the availability and reliability index measures resubmitted by Transpower under clause 12.123(b) are not consistent with the requirements of clause 12.122(1) or the methodology referred to in clause 12.122(3), or do not provide relevant information to grid users, the Authority may make any amendments to the index measures it considers necessary.

Compare: Electricity Governance Rules 2003 rule 10.4 section VI part F

12.125 Authority must consult on proposed index measures

(1) The Authority must publish the proposed availability and reliability index measures, either as provisionally approved by the Authority or as amended by the Authority, as soon as is practicable, for consultation with any person that the Authority thinks is likely to be materially affected by the proposed index measures.
(2) As well as the consultation required under subclause (1), the Authority may undertake any other consultation it considers necessary.

Compare: Electricity Governance Rules 2003 rules 10.5 and 10.6 section VI part F

12.126 Decision on index measures

When the Authority has completed its consultation on the proposed availability and reliability measures it must consider whether to include the index measures as a schedule to this Part.

Compare: Electricity Governance Rules 2003 rule 10.7 section VI part F

12.127 Transpower to report on availability and reliability

(1) By 30 November in each year, Transpower must publish and provide to the Authority information on availability and reliability of interconnection assets including—
- (a) annual unavailability of each interconnection branch, shunt asset and the HVDC link due to planned outages of 1 minute or longer in the preceding year ending 30 June in hours per year expressed as a percentage; and
- (b) annual unavailability of each interconnection branch, shunt asset and the HVDC link due to unplanned outages of 1 minute or longer in the preceding year ending 30 June in hours per year, expressed as a percentage; and
- (c) annual number of planned interruptions of 1 minute or longer caused by planned outages of one minute or longer of each interconnection branch, shunt asset and the HVDC link in the preceding year ending 30 June; and
- (d) annual number of unplanned interruptions of 1 minute or longer caused by unplanned outages of 1 minute or longer of each interconnection branch, shunt asset and the HVDC link in the preceding year ending 30 June; and
- (e) total unserved energy in the preceding year ending 30 June resulting from planned interruptions of 1 minute or longer caused by planned outages of 1 minute or longer of interconnection branches, shunt assets and the HVDC link; and
- (f) total unserved energy in the preceding year ending 30 June resulting from unplanned interruptions of 1 minute or longer caused by unplanned outages of 1 minute or longer of interconnection branches, shunt assets and the HVDC link; and
- (g) annual number of outages of each interconnection branch, shunt asset and the HVDC link that are shorter than 1 minute in the preceding year ending 30 June; and
- (h) the annual number of interruptions shorter than 1 minute caused by outages that are shorter than 1 minute of each interconnection branch, shunt asset and the HVDC link, in the preceding year ending 30 June; and
- (i) a comparison of the information required by paragraphs (a) to (f) against the availability and reliability index measures for interconnection branches, shunt assets and the HVDC link included in a schedule to this Part under clause 12.126;
- (j) to the extent practicable, an explanation of the reasons for not meeting the reliability and availability index measures for interconnection branches, shunt assets and the HVDC link included in a schedule to this Part under clause 12.126 and any steps or other options it intends to take in future to meet the index measures; and
- (k) information on its performance against the reliability and availability index measures for aggregated interconnection branches included in a schedule to this Part under clause 12.126.
(2) The information published under subclause (1) must be specified in the same units of measurement as the corresponding index measures included in a schedule to this Part under clause 12.126.
(3) Transpower does not breach this Code by reason of a failure to meet the index measures included in a schedule to this Part under clause 12.126.

Compare: Electricity Governance Rules 2003 rule 10.8 section VI part F

Clause 12.127(1): amended, on 5 October 2017, by clause 317 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.128 Transpower and designated transmission customers may agree on other requirements

(1) Transpower and each designated transmission customer must comply with this Part, unless agreed otherwise by Transpower and the designated transmission customer in respect of specified interconnection circuit branches, the HVDC link, shunt assets or interconnection assets, or the designated transmission customer in accordance with subclause (2).
(2) An agreement between Transpower and a designated transmission customer under this clause must not exclude the application of subclause (3)(b) and must be conditional in all respects on—
- (a) obtaining agreement from all other potentially affected designated transmission customers that this Part does not apply to the specified interconnection circuit branches, the HVDC link, shunt assets or interconnection assets, or the designated transmission customer; and
- (b) Transpower and the designated transmission customer confirming in writing to the Authority that they have consulted with all potentially affected end use customers on this Part not applying to the specified interconnection branches, circuit branches, the HVDC link, shunt assets or interconnection assets or the designated transmission customer, and that there are no material unresolved issues affecting the interests of those end use customers.
(3) Transpower must—
- (a) give written notice to the Authority as soon as practicable if Transpower enters into an agreement with a designated transmission customer under this clause; and
- (b) publish the agreement no later than 20 business days after entering into the agreement.

Compare: Electricity Governance Rules 2003 rule 11 section VI part F

Clause 12.128(2): amended, on 5 October 2017, by clause 318(a) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.128(3): replaced, on 5 October 2017, by clause 318(b) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Subpart 7—Preparation of Outage Protocol

12.129 Purpose of this subpart

The purpose of this subpart is to provide for the making of an Outage Protocol, with input from Transpower and in consultation with other interested parties, that—
- (a) specifies the circumstances in which Transpower may temporarily remove any assets forming part of the grid from service or reduce the capacity of assets to efficiently manage the operation of the grid; and
- (b) specifies procedures and policies for Transpower to plan for outages and for carrying out such outages to—
  - (i) ensure Transpower involves designated transmission customers in making decisions on planned outages as much as possible; and
  - (ii) ensure coordination between Transpower and designated transmission customers; and
  - (iii) enable Transpower to efficiently manage the operation of the grid; and
- (c) specifies procedures and policies for dealing with unplanned outages of the grid.

Compare: Electricity Governance Rules 2003 rule 1 section VII part F

12.130 Definition of outage

(1) An outage exists when interconnection assets or connection assets are temporarily not provided in accordance with—
- (a) the requirements of a transmission agreement; or
- (b) the requirements of subpart 6.
(2) Without limiting subclause (1), an outage includes any situation in which—
- (a) Transpower removes assets from service temporarily; or
- (b) assets are not able to be provided due to grid emergencies, in order to deal with health and safety issues, or due to circumstances beyond Transpower’s reasonable control; or
- (c) Transpower reduces the capacity of branches below the capacity required by a transmission agreement or clause 12.111; or
- (d) Transpower changes the configuration of the grid; or
- (e) Transpower is required by law to carry out an outage.

Compare: Electricity Governance Rules 2003 rule 2 section VII part F

12.131 Outage Protocol

(1) The Outage Protocol set out in schedule F7 of section VII of part F of the rules immediately before this Code came into force, continues in force and is deemed to be the Outage Protocol that applies at the commencement of this Code, with the following amendments:
- (a) every reference to the Board must be read as a reference to the Authority:
- (b) every reference to the rules must be read as a reference to the Code:
- (c) every reference to a provision of the rules must be read as a reference to the corresponding provision of the Code:
- (d) the reference in clause 3.1.2(d), clause 3.3.5(c), and clause 3.3.8(a) to a reliability investment or an economic investment approved by the Board must be read as a reference to an approved investment:
- (e) the reference in clause 10.2.1(a) and (b) to the benchmark agreement in schedule F2 must be read as a reference to the default transmission agreement template:
- (f) the reference in clauses A1.1(a)(ii), A7.2(a)(ii), and A7.2(b)(i) to the value of unserved energy in clause 8.3.4 of schedule F4 of section III must be read as a reference to the value of expected unserved energy in clause 4 of Schedule 12.2:
- (g) the reference in clauses A6.1(f) and A6.2(e) to the matters specified in clauses 27.1 to 27.9 of schedule F4 of section III must be read as the matters specified in clause 12.43(1)(a)(iv) and (b)(iv):
- (h) the reference in clause A8.1(a)(i) to fuel costs specified in the statement of opportunities must be read as a reference to fuel costs calculated in accordance with clause 12.141(3)(a)(i).
(2) The Authority must as soon as practicable after this Code comes into force, publish a version of the Outage Protocol in which the provisions of this Code that correspond to the provisions of the rules referred to in the Outage Protocol are shown.
(3) Clause 12.150 applies to the Outage Protocol.

Clause 12.131(1)(e): amended, on 1 October 2023, by clause 36 of the Electricity Industry Participation Code Amendment (Default Transmission Agreement) 2023

Review of Outage Protocol

12.132 Review of Outage Protocol

The Authority may review the Outage Protocol at any time, in accordance with the requirements of clauses 12.133 and 12.145 to 12.149.

Compare: Electricity Governance Rules 2003 rule 14 section VII part F

12.133 Transpower to submit proposed Outage Protocol

(1) Transpower must submit a proposed Outage Protocol to the Authority within 3 months (or such longer period as the Authority may allow) of receipt of a written request from the Authority. The Authority may issue such a request at any time.
(2) The proposed Outage Protocol must give effect to or promote the principles set out in clause 12.134 and provide for the matters set out in clauses 12.135 to 12.144.
(3) With its proposed Outage Protocol, Transpower must submit to the Authority an explanation of the proposed Outage Protocol and a statement of proposal for the proposed Outage Protocol.

Compare: Electricity Governance Rules 2003 rule 8 section VII part F

Principles and required content of Outage Protocol

12.134 Principles for developing Outage Protocol

The Outage Protocol must give effect to the following principles:
- (a) the matters in clause 12.129;
- (b) the need for a fair and reasonable balance of interests between the grid owner and designated transmission customers:
- (c) the need to ensure that the grid owner can meet all obligations placed on it by the system operator for the purpose of meeting common security and power quality requirements under Part 8 of this Code;
- (d) the need to ensure that the safety of all personnel is maintained:
- (e) the need to ensure that the safety and integrity of equipment is maintained:
- (f) the desirability of the Outage Protocol and Part 8 operating in an integrated and consistent manner, if possible.

Compare: Electricity Governance Rules 2003 rule 3 section VII part F

12.135 Required content of Outage Protocol

(1) The Outage Protocol must—
- (a) require Transpower to plan for outages, other than outages that are not reasonably foreseeable, in accordance with clause 12.136; and
- (b) require Transpower and designated transmission customers to act reasonably and in good faith in planning for outages, in accordance with clause 12.137; and
- (c) set out the situations and times at which Transpower must reconsider the timing of proposed planned outages, as specified in clause 12.138; and
- (d) permit Transpower to vary a proposed planned outage, as specified in clause 12.139;
- (e) set out the requirements for Transpower to consider when planning for outages, in order to give effect to the net benefit principle, as specified in clause 12.140; and
- (f) permit Transpower to undertake outages in order to give effect to an approved investment, and to undertake outages that are required by the Electricity Act 1992, as specified in clause 12.142; and
- (g) permit Transpower to undertake outages, or take such other steps, as the system operator may reasonably require.
(2) The Outage Protocol must require Transpower to set out the procedures and policies for dealing with unplanned outages, as specified in clause 12.143.
(3) The Outage Protocol must require Transpower to report on compliance with the Outage Protocol, in accordance with clause 12.144.
(4) The Outage Protocol must set out—
- (a) processes for Transpower to consult with designated transmission customers and to determine an outage plan setting out planned outages for each year ending 30 June, and processes for the outage plan to be updated; and
- (b) requirements on Transpower to keep designated transmission customers informed about planned outages, including minimum notice periods for Transpower to advise affected designated transmission customers of planned outages not set out in the outage plan; and
- (c) procedures for outage co-ordination by Transpower and between Transpower and designated transmission customers; and
- (d) requirements on Transpower to provide information to designated transmission customers about unplanned outages.
(5) The Outage Protocol is not limited to the matters referred to in this clause, and may provide for any other matters related to outages.

Compare: Electricity Governance Rules 2003 rule 4 section VII part F

Clause 12.135(4)(a): amended, on 5 October 2017, by clause 319 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

12.136 Planning for outages

The Outage Protocol must require Transpower to plan for outages, other than outages that are not reasonably foreseeable—
- (a) in respect of interconnection assets, in accordance with the requirements of the Outage Protocol specified under clause 12.140(1); and
- (b) in respect of connection assets, by agreeing with each affected designated transmission customer on the timing and duration of the outage or, failing agreement, in accordance with the requirements of the Outage Protocol specified under clause 12.140(1); and
- (c) in respect of outages of both interconnection assets and connection assets that are required in order to give effect to an approved investment or are required by the Electricity Act 1992, in accordance with the requirements of the Outage Protocol specified under clause 12.142.

Compare: Electricity Governance Rules 2003 rule 5.1 section VII part F

12.137 Transpower and designated transmission customers to act reasonably and in good faith

(1) The Outage Protocol must require Transpower, in planning for outages in accordance with clauses 12.136, 12.140, and 12.142, reconsidering the timing of proposed planned outages in accordance with clause 12.138 or varying proposed planned outages in accordance with clause 12.139, to act reasonably and in good faith, taking into account the information reasonably known at the time or that can be reasonably forecast.
(2) The Outage Protocol must require designated transmission customers, in exercising rights or undertaking obligations under the Outage Protocol, to act reasonably and in good faith.

Compare: Electricity Governance Rules 2003 rule 5.2 section VII part F

12.138 Reconsideration of planned outages

The Outage Protocol must set out the situations and the times at which Transpower must reconsider the timing of proposed planned outages, and the extent to which the proposed timing of planned outages needs to be reconsidered, which may include—
- (a) whenever material new information has been provided to Transpower about the likely effect of a proposed planned outage; and
- (b) whenever circumstances relating to a proposed planned outage have changed sufficiently to justify reconsideration of the requirements specified under clauses 12.140 or 12.142, and Transpower is aware or has been made aware of the change in circumstances.

Compare: Electricity Governance Rules 2003 rule 5.3 section VII part F

12.139 Variations to planned outages

(1) The Outage Protocol may permit Transpower to vary a proposed planned outage only if—
- (a) in respect of a proposed planned outage of interconnection assets, the variation of the proposed planned outage is permitted in accordance with the requirements of the Outage Protocol specified under clauses 12.140 or 12.142; or
- (b) in respect of a proposed planned outage of connection assets, Transpower and each affected designated transmission customer agree on the variation as provided for in the Outage Protocol or, failing agreement, the variation of the proposed planned outage is permitted in accordance with the requirements of the Outage Protocol specified under clauses 12.140 or 12.142; or
- (c) the variation is necessary as a result of a grid emergency, in order to deal with health and safety issues, in order to comply with the Act or due to other circumstances beyond Transpower’s reasonable control; or
- (d) the variation is required to meet a request of the system operator that Transpower vary a proposed planned outage.
(2) The Outage Protocol must require Transpower, if possible, to give notice of a variation before the proposed planned outage, and if prior notice is not possible, to advise of the variation to the proposed planned outage as soon as possible after the variation occurs.

Compare: Electricity Governance Rules 2003 rule 5.4 section VII part F

12.140 Net benefit principle, requirements and methodologies

(1) The requirements of the Outage Protocol relating to planning for outages under clause 12.136(a) or (b), or for varying proposed planned outages under clause 12.139(1)(a) or (b)—
- (a) must give effect to the net benefit principle specified in subclause (2), in determining the timing and duration of a planned outage, and whether to undertake a planned outage, either by including the particular requirements set out in clause 12.141(2), or by some other means; and
- (b) may include methodologies and processes for Transpower to apply when planning for outages; and
- (c) may include other requirements that may apply in different situations.
(2) The net benefit principle is that, in planning and varying a planned outage, Transpower must ensure that the planned outage is likely to result in net benefits to persons who produce, transmit, distribute, retail or consume electricity—
- (a) in respect of interconnection assets, to the extent those persons are affected by an outage; and
- (b) in respect of connection assets, if Transpower has not agreed the timing and duration of the outage with the relevant designated transmission customer in accordance with the Outage Protocol, to the extent those persons are affected by an outage.

Compare: Electricity Governance Rules 2003 rule 5.5 section VII part F

12.141 Consideration of likely effects of planned outages

(1) The Outage Protocol may require Transpower to determine the likely effect of a proposed planned outage on the power system, generators and consumers, and—
- (a) if a proposed outage is not reasonably expected to—
  - (i) result in the power system failing to meet the grid reliability standards; and/or
  - (ii) give rise to binding constraints; and/or
  - (iii) result in loss of supply to consumers,
- may permit Transpower to undertake the outage; and
- (b) if a proposed outage is likely to result in, or give rise to, the matters referred to in paragraph (a), the Outage Protocol may require Transpower to comply with the particular requirements specified in subclause (2).
(2) The requirements in subclause (1) that the Outage Protocol may provide are—
- (a) if a proposed planned outage is likely to result in the power system failing to meet the grid reliability standards, but is not expected to give rise to binding constraints or result in loss of supply to consumers, Transpower must—
  - (i) estimate the following costs:
    - (A) any direct labour and material costs that Transpower will incur in undertaking the outage:
    - (B) any direct labour and material costs that designated transmission customers will incur as a result of Transpower undertaking the outage:
    - (C) if the outage will result in an increased risk of loss of supply, any increase in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy:
    - (D) any relevant cost specified in clause 12.43(1)(a)(iv):
    - (E) any other relevant cost to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (ii) estimate the following benefits:
    - (A) if the outage will result in a decreased risk of loss of supply, any decrease in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy:
    - (B) any reduction in maintenance costs arising as a result of the outage (including Transpower’s and any designated transmission customer’s costs):
    - (C) any relevant benefit specified in clause 12.43(1)(b)(iv):
    - (D) any other relevant benefit to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (iii) carry out the outage only if the costs estimated under subparagraph (i) are less than the benefits estimated under subparagraph (ii); and
- (b) if a proposed planned outage is likely to give rise to binding constraints, whether or not the outage is also likely to result in a loss of supply to consumers, Transpower must—
  - (i) estimate the following costs:
    - (A) any direct labour and material costs that Transpower will incur in undertaking the outage:
    - (B) any direct labour and material costs that designated transmission customers will incur as a result of Transpower undertaking the outage:
    - (C) if the outage will result in an increased risk of loss of supply, any increase in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy:
    - (D) any additional fuel costs incurred by a generator in respect of any generating units that will be dispatched or are likely to be dispatched during or after the outage and as a result of the outage:
    - (E) any relevant cost specified in clause 12.43(1)(a)(iv):
    - (F) any other relevant costs to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (ii) estimate the following benefits:
    - (A) any reduction in maintenance costs resulting from the outage (including Transpower’s and any designated transmission customer’s costs):
    - (B) any reduction in fuel costs incurred by a generator in respect of any generating units, arising or likely to arise during or after the outage and as a result of the outage:
    - (BA) if the outage will result in a decreased risk of loss of supply, any decrease in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy:
    - (C) any relevant benefit specified in clause 12.43(1)(b)(iv):
    - (D) any other relevant benefit to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (iii) carry out the outage only if the costs estimated under subparagraph (i) are less than the benefits estimated under subparagraph (ii); and
- (c) if a proposed planned outage is likely to lead to loss of supply to consumers, whether or not the outage is also likely to give rise to binding constraints, Transpower must—
  - (i) estimate the following costs:
    - (A) any direct labour and material costs that Transpower will incur in undertaking the outage:
    - (B) any direct labour and material costs that designated transmission customers will incur as a result of Transpower undertaking the outage:
    - (C) any increase in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy, arising from the loss of supply during the outage:
    - (CA) any additional fuel costs incurred by a generator in respect of any generating units that will be dispatched or are likely to be dispatched during or after the outage and as a result of the outage:
    - (D) any relevant cost specified in clause 12.43(1)(a)(iv):
    - (E) any other relevant cost to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (ii) estimate the following benefits:
    - (A) any reduction in maintenance costs resulting from the outage (including Transpower’s and any designated transmission customer’s costs):
    - (B) if the outage will result in a decreased risk of loss of supply, any decrease in the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy:
    - (C) any reduction in fuel costs incurred by a generator in respect of any generating units, arising or likely to arise during or after the outage and as a result of the outage:
    - (D) any relevant benefit specified in clause 12.43(1)(b)(iv):
    - (E) any other relevant benefit to a person that produces, transmits, retails or consumes electricity in New Zealand; and
  - (iii) carry out the outage only if the costs estimated under subparagraph (i) are less than the benefits estimated under subparagraph (ii).
(3) In providing for the matters referred to in subclause (2), the Outage Protocol must include the following requirements:
- (a) Transpower's estimate of the fuel costs under subclause (2)(b) and (c) must—
  - (i) in relation to thermal generating stations, be a reasonable estimate of the fuel costs, based on the economic value of the fuel required for the relevant thermal generating station, and justified by Transpower with reference to opinions on the economic value of the fuel, provided by 1 or more independent and suitably qualified persons; and
  - (ii) in relation to hydroelectric generating stations—
    - (A) be a reasonable estimate of the fuel costs, based on the economic value of the water stored at a hydroelectric generating station, provided by a suitably qualified person other than—
      - (1) Transpower; or
      - (2) an employee of Transpower; and
    - (B) be published, as provided for in the Outage Protocol:
- (b) the direct labour costs of Transpower and designated transmission customers under subclause (2) may include any amounts paid to contractors, but must not include any apportionment of the overheads or office costs of Transpower or designated transmission customers:
- (c) the material costs of Transpower and designated transmission customers under subclause (2) are the costs of the materials used in carrying out the work during the outage:
- (d) the estimate of expected unserved energy in MWh multiplied by the value per MWh of that expected unserved energy under subclause (2) must—
  - (i) in the case of connection assets, be based on—
    - (A) the estimated amount and value of the expected unserved energy as agreed between Transpower and each affected designated transmission customer; or
    - (B) if Transpower and a designated transmission customer cannot agree on the amount and value of the expected unserved energy under subsubparagraph (A), the value of expected unserved energy in clause 4 of Schedule 12.2 and Transpower's estimate of the expected unserved energy in respect of each affected designated transmission customer and end use customer; and
  - (ii) in the case of interconnection assets, be based on—
    - (A) the value of expected unserved energy in clause 4 of Schedule 12.2; and
    - (B) Transpower's estimate of the expected unserved energy in respect of each affected designated transmission customer and end use customer.
(4) In addition to the requirements in subclause (3), the Outage Protocol must require Transpower, in planning for outages, to consider any reasonably expected operating conditions, forecasts in the system security forecast, likely fuel costs, and any other reasonable assumptions.
(5) The Outage Protocol must include a methodology for determining expected unserved energy for the purposes of subclause (2)(a) to (c) that complies with subclauses (3)(d) and (4).
(6) The Outage Protocol may permit Transpower to—
- (a) make only a reasonable estimate of the matters specified in subclauses (2) to (4) based on information reasonably available to it at the time Transpower considers whether to carry out a planned outage, and taking into account the number of assets to which the proposed outage applies, the value of the assets involved, the size of the load served by the assets, the proposed duration of the outage; and
- (b) apply differing levels of rigour in different circumstances, which may include taking into account the number of assets to which a proposed outage applies, the value of the assets involved, the size of the load served by the assets, the proposed duration of the outage, and any other relevant matters.

Compare: Electricity Governance Rules 2003 rule 5.6 section VII part F

Clause 12.141 heading: amended, on 20 December 2021, by clause 53 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2019.

Clause 12.141(2) to (4): substituted, on 16 December 2013, by clause 11 of the Electricity Industry Participation (Urgent Temporary Grid Reconfiguration) Code Amendment 2013.

Clause 12.141(3)(d)(i)(B): amended, on 1 February 2016, by clause 57(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.141(3)(d)(i)(B): amended, on 1 November 2018, by clause 80 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

Clause 12.141(3)(d)(ii)(A): amended, on 1 February 2016, by clause 57(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Clause 12.141(3)(d)(ii)(B): amended, on 1 November 2018, by clause 80 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2018.

12.142 Planned outages required in order to give effect to an investment or required by the Act

(1) The Outage Protocol must set out requirements for Transpower to consider when determining the timing of planned outages that are required in order to give effect to an approved investment or that are required by the Electricity Act 1992.
(2) The requirements specified under subclause (1) must require Transpower to give effect to the net benefit principle in clause 12.140(2) in determining the timing and duration of outages subject to this clause, and may require Transpower to consider some or all of the costs and benefits specified in clause 12.141.

Compare: Electricity Governance Rules 2003 rule 5.7 section VII part F

12.143 Required content of Outage Protocol in relation to unplanned outages

(1) The Outage Protocol must—
- (a) set out procedures and policies for dealing with unplanned outages, so as to minimise the costs and, if relevant, maximise the benefits arising from an unplanned outage; and
- (b) set out the reasonable steps and measures that Transpower must take in order to be prepared for unplanned outages, so as to ensure that it is readily able to deal with unplanned outages in a way that minimises the costs and, if relevant, maximises the benefits arising from an unplanned outage; and
- (c) require Transpower to deal with unplanned outages as quickly as reasonably possible, in accordance with the procedures specified in the Outage Protocol.
(2) The costs and benefits under subclause (1) are the costs and benefits of the outage to persons who produce, transmit, distribute, retail, or consume electricity.

Compare: Electricity Governance Rules 2003 rule 6 section VII part F

12.144 Reporting on compliance with Outage Protocol

The Outage Protocol must require Transpower to publish and report to designated transmission customers and the Authority, whether in the report provided under clause 12.118 or otherwise, on its compliance with the requirements of the Outage Protocol, including the requirements specified in clause 12.140(1) for giving effect to the net benefit principle specified in clause 12.140(2) and the requirements of the Outage Protocol relating to unplanned outages specified in clause 12.143.

Compare: Electricity Governance Rules 2003 rule 7 section VII part F

Decisions on Outage Protocol

12.145 Authority may initially approve the proposed Outage Protocol or refer back to Transpower

After consideration of Transpower’s proposed Outage Protocol and accompanying explanation and statement of proposal, the Authority may—
- (a) provisionally approve the proposed Outage Protocol having regard to the principles in clause 12.134 and the matters set out in clauses 12.135 to 12.144; or
- (b) refer the proposed Outage Protocol and accompanying explanation and regulatory statement back to Transpower, if in the Authority’s view—
  - (i) the proposed Outage Protocol does not adequately give effect to or promote the principles in clause 12.134; or
  - (ii) the proposed Outage Protocol does not adequately provide for the matters set out in clauses 12.135 to 12.144; or
  - (iii) the explanation or statement of proposal provided with the Outage Protocol in accordance with clause 12.133(3) is not adequate—
and Transpower must, within 20 business days (or such longer period as the Authority may allow), consider the Authority’s concerns and resubmit its proposed Outage Protocol and accompanying explanation and statement of proposal for reconsideration by the Authority.

Compare: Electricity Governance Rules 2003 rule 9 section VII part F

12.146 Reconsideration of revised Outage Protocol by the Authority

After reconsideration of Transpower’s proposed Outage Protocol, and accompanying explanation and statement of proposal, as revised under clause 12.145(b), the Authority may either—
- (a) provisionally approve the proposed Outage Protocol, as revised, having regard to the principles in clause 12.134 and the matters set out in clauses 12.135 to 12.144; or
- (b) if the Authority considers that the Outage Protocol resubmitted by Transpower under clause 12.145(b) does not adequately give effect to or promote the principles in clause 12.134, or adequately provide for the matters set out in clauses 12.135 to 12.144, the Authority may make any amendments to the proposed Outage Protocol, as revised, that it considers necessary.

Compare: Electricity Governance Rules 2003 rule 10 section VII part F

12.147 Authority must consult on the proposed Outage Protocol

The Authority must publish the proposed Outage Protocol, either as provisionally approved by the Authority or as amended by the Authority, as soon as is practicable, for consultation with any person that the Authority thinks is likely to be materially affected by the proposed Outage Protocol.

Compare: Electricity Governance Rules 2003 rule 11 section VII part F

12.148 Authority may undertake additional consultation

As well as the consultation required under clause 12.147, the Authority may undertake any other consultation it considers necessary.

Compare: Electricity Governance Rules 2003 rule 12 section VII part F

12.149 Decision on Outage Protocol

(1) When the Authority has completed its consultation on the proposed Outage Protocol, it must consider whether to incorporate the proposed Outage Protocol by reference as the Outage Protocol.
(2) If the Authority decides to incorporate the Outage Protocol by reference in this Code, the Authority must determine a date on which the incorporation by reference takes effect.

Compare: Electricity Governance Rules 2003 rule 13 section VII part F

Clause 12.149(2): amended, on 1 August 2023, by clause 47 of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

12.150 Incorporation of Outage Protocol by reference

(1) The Outage Protocol is incorporated by reference in this Code.
(2) [Revoked]

Clause 12.150(1): amended, on 5 October 2017, by clause 320(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.150(1): amended, on 1 August 2023, by clause 48(1) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Clause 12.150(2): amended, on 5 October 2017, by clause 320(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.150(2): revoked, on 1 August 2023, by clause 48(2) of the Electricity Industry Participation Code Amendment (System Operation Documents) 2023.

Complying with Outage Protocol

12.151 Compliance with Outage Protocol

(1) Transpower and each designated transmission customer must comply with the Outage Protocol, unless agreed otherwise by Transpower and a designated transmission customer in respect of specified assets or the designated transmission customer in accordance with subclause (2).
(2) An agreement between Transpower and a designated transmission customer to which the Outage Protocol does not apply in respect of specified assets must not exclude the application of subclause (3)(b) and must be conditional in all respects on—
- (a) obtaining agreement from all other potentially affected designated transmission customers that the Outage Protocol does not apply in respect of the specified assets or the designated transmission customer; and
- (b) Transpower and the designated transmission customer satisfying the Authority that they have consulted with all potentially affected end use customers on the Outage Protocol not applying in respect of the specified assets or the designated transmission customer and that there are no material unresolved issues affecting the interests of those end use customers.
(3) Transpower must—
- (a) give written notice to the Authority as soon as practicable if Transpower enters into an agreement with a designated transmission customer under this clause; and
- (b) publish the agreement no later than 20 business days after entering into the agreement.

Compare: Electricity Governance Rules 2003 rule 15 section VII part F

Clause 12.151(2): amended, on 5 October 2017, by clause 321(a) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Clause 12.151(3): replaced, on 5 October 2017, by clause 321(b) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Schedule 12.1

cl 12.7

Categories of designated transmission customers

1 Categories of designated transmission customers required to enter into transmission agreements with Transpower

(1) The categories of designated transmission customers required to enter into transmission agreements with Transpower are—
- (a) connected asset owners; and
- (b) [Revoked]
- (c) generators that are directly connected to the grid.
(2) [Revoked]
(3) [Revoked]
(4) [Revoked]
(5) [Revoked]

Compare: Electricity Governance Rules 2003 schedule F1 part F

Schedule 12.1, clause 1(1): amended, on 16 December 2013, by clause 9(1) of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Schedule 12.1, clause 1(1)(a): amended, on 1 February 2016, by clause 58(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Schedule 12.1, clause 1(1)(b): revoked, on 1 February 2016, by clause 58(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Schedule 12.1, clause 1(1)(c): amended, on 23 February 2015, by clause 75 of the Electricity Industry Participation Code Amendment (Distributed Generation) 2014.

Schedule 12.1, clause 1(1)(c): amended, on 5 October 2017, by clause 322 of the Electricity Industry Participation Code Amendment (Code Review Programme) 2017.

Schedule 12.1, clause 1(2) to (5): revoked, on 16 December 2013, by clause 9(2) of the Electricity Industry Participation (Revocation of Part 16) Code Amendment 2013.

Schedule 12.2

cl 12.55

Grid reliability standards

1 Preamble

Clause 12.55 of this Code, requires the Authority to determine the most appropriate grid reliability standards and in so doing must have regard to the purposes in clause 12.56 and the principles set out in clause 12.57, as required by clause 12.55.

Compare: Electricity Governance Rules 2003 clause 2 schedule F3 part F

2 The grid reliability standards

(1) The purpose of the grid reliability standards is to provide a basis for Transpower and other parties to appraise opportunities for transmission investments and transmission alternatives.
(2) For the purpose of subclause (1), the grid satisfies the grid reliability standards if—
- (a) the power system is reasonably expected to achieve a level of reliability at or above the level that would be achieved if all economic reliability investments were to be implemented; and
- (b) with all assets that are reasonably expected to be in service, the power system would remain in a satisfactory state during and following a single credible contingency event occurring on the core grid.
(3) For the purpose of subclause (2)(a), the expected level of reliability of the power system must be assessed at each and every grid exit point and grid injection point (wherever located on the grid).
(4) For the purpose of subclause (2)(a) and (b), the expected level of reliability, and state, of the power system must be assessed using the range of relevant operating conditions that could reasonably be expected to occur.

Compare: Electricity Governance Rules 2003 clauses 3 to 6 schedule F3 part F

3 Interpretation and definitions

(1) For the purposes of these grid reliability standards, unless the context calls for another interpretation—
- (a) the terms defined in Part 1 of this Code take that defined meaning; and
- (b) the term defined in subclause (2) takes that defined meaning; and
- (c) a reference—
  - (i) to the singular includes the plural and conversely; and
  - (ii) to a person includes an individual, company, other body corporate, association, partnership, firm, joint venture, trust, or Government Agency; and
- (d) the word including or includes means including, but not limited to, or includes, without limitation; and
- (e) the other grammatical forms of the term defined in subclause (2) have a corresponding meaning.
(2) Economic reliability investments means investments in the grid and transmission alternatives that would satisfy the economic test for an investment proposal applied by the Commerce Commission under Part 4 of the Commerce Act 1986—
- (a) assuming that the economic test was applied to both investments in the grid and transmission alternatives; and
- (b) having regard to Parts 7 and 8 (including the policy statement).

Compare: Electricity Governance Rules 2003 clauses 7 and 8 schedule F3 part F

4 Value of expected unserved energy

(1) The value of any expected unserved energy is—
- (a) $20,000 per MWh; or
- (b) such other value as the Authority may determine.
(2) The Authority may determine different values of expected unserved energy under this clause for different purposes and for different times.
(3) If the Authority determines a value of expected unserved energy under this clause, the Authority must publish its determination.

Schedule 12.2, clause 4(1): amended, on 1 February 2016, by clause 59(1) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Schedule 12.2, clause 4(2): amended, on 1 February 2016, by clause 59(2) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Schedule 12.2, clause 4(3): amended, on 1 February 2016, by clause 59(3) of the Electricity Industry Participation Code Amendment (Code Review Programme) 2015.

Schedule 12.3

cl 12.63

Core grid determination

1 Background

Clause 12.63 of this Code, requires the Authority to determine the most appropriate core grid determination and in so doing to have regard to the purposes set out in clause 12.64, the principles set out in clause 12.57 for the grid reliability standards and the objectives set out in clause 12.65.

Compare: Electricity Governance Rules 2003 clause 2 schedule F3A part F

2 The core grid determination

(1) The purpose of this core grid determination is to define the core grid for the purposes of the grid reliability standards and so provide a basis for—
- (a) the Authority to determine the grid reliability standards; and
- (b) Transpower and other parties to appraise opportunities for transmission investment and transmission alternatives.
(2) The core grid consists of those assets that comprise the transmission links listed in Table 1 below:

Table 1

North Island core grid links	South Island core grid links
220kV Huapai-Marsden 220kV Huapai-Bream Bay 220kV Bream Bay-Marsden 110kV Marsden-Maungatapere 220 kV Henderson-Huapai 220 kV Albany-Huapai 220 kV Albany-Henderson 110kV Albany-Henderson 110kV Henderson-Hepburn Rd 220kV Otahuhu-Henderson 220kV Otahuhu-Southdown 220kV Southdown-Henderson 220kV Otahuhu-Penrose 110kV Mangere-Roskill 110kV Otahuhu-Roskill 110kV Otahuhu-Pakuranga 110kV Otahuhu-Wiri 220kV Otahuhu-Takanini 220kV Huntly-Takanini 110kV Wiri-Bombay 220kV Huntly-Glenbrook 220kV Glenbrook-Takanini 220kV Otahuhu-Whakamaru 220kV Otahuhu-Huntly 220kV Huntly-Hamilton 110kV Mt Maunganui-Tarukenga 110kV Tarukenga-Tauranga 220kV Tarukenga-Edgecumbe 220kV Edgecumbe-Kawerau 220kV Kawerau-Ohakuri 220kV Wairakei-Ohakuri 220kV Ohakuri-Atiamuri 220kV Atiamuri-Tarukenga 220kV Atiamuri-Whakamaru 220kV Wairakei-Redclyffe 220kV Wairakei-Whirinaki 220kV Whirinaki-Redclyffe 220kV Hamilton-Whakamaru 220kV Tokaanu-Whakamaru 220kV Bunnythorpe-Tokaanu 220kV Bunnythorpe-Tangiwai 220kV Rangipo-Tangiwai 220kV Rangipo-Wairakei 220kV Wairakei-Poihipi 220kV Poihipi-Whakamaru 220kV Stratford-New Plymouth 110kV New Plymouth-Carrington St 220kV Bunnythorpe-Haywards 220kV Haywards-Wilton 220kV Haywards- Linton 220kV Wilton-Linton 220kV Bunnythorpe-Linton 110kV Wilton-Central Park 110kV Takapu Rd-Wilton 220kV Bunnythorpe-Brunswick 220kV Brunswick-Stratford 110kV Otahuhu-Mangere 110kV Haywards-Takapu Rd 220/110kV interconnection Marsden 220/110kV interconnection Albany 220/110kV interconnection Henderson 220/110kV interconnection Penrose 220/110kV interconnection Otahuhu 220/110kV interconnection Hamilton 220/110kV interconnection Tarukenga 220/110kV interconnection New Plymouth 220/110kV interconnection Stratford 220/110kV interconnection Redclyffe 220/110kV interconnection Bunnythorpe 220/110kV interconnection Haywards 220/110kV interconnection Wilton	220kV Islington-Kikiwa 220kV Kikiwa-Stoke 220kV Twizel-Tekapo B 220kV Tekapo B-Islington 220kV Twizel-Opihi-Timaru-Ashburton 220kV Ashburton-Bromley 220kV Bromley-Islington 220kV Twizel-Opihi-Timaru-Islington 220kV Livingstone-Islington 220kV Benmore-Ohau B 220kV Ohau B-Twizel 220kV Benmore-Twizel 220kV Benmore-Ohau C 220kV Ohau C-Twizel 220kV Benmore-Aviemore 220kV Clyde-Cromwell 220kV Cromwell-Twizel 220kV Roxburgh-Clyde 220kV Naseby-Livingstone 220kV Roxburgh-Naseby 220kV Roxburgh-Three Mile Hill 220kV Three Mile Hill-Half Way Bush 220kV Three Mile Hill-Sth Dunedin 220kV Sth Dunedin-Half Way Bush 220kV Manapouri-Invercargill 220kV Manapouri-Nth Makarewa 220kV Nth Makarewa-Invercargill 220kV Invercargill-Roxburgh 220kV Invercargill-Tiwai Pt 220kV Nth Makarewa-Tiwai Pt 220/66kV interconnection Islington 66kV Islington-Addington 220/66kV interconnection Bromley

North Island core grid links

South Island core grid links

220kV Huapai-Marsden

220kV Huapai-Bream Bay

220kV Bream Bay-Marsden

110kV Marsden-Maungatapere

220 kV Henderson-Huapai

220 kV Albany-Huapai

220 kV Albany-Henderson

110kV Albany-Henderson

110kV Henderson-Hepburn Rd

220kV Otahuhu-Henderson

220kV Otahuhu-Southdown

220kV Southdown-Henderson

220kV Otahuhu-Penrose

110kV Mangere-Roskill

110kV Otahuhu-Roskill

110kV Otahuhu-Pakuranga

110kV Otahuhu-Wiri

220kV Otahuhu-Takanini

220kV Huntly-Takanini

110kV Wiri-Bombay

220kV Huntly-Glenbrook

220kV Glenbrook-Takanini

220kV Otahuhu-Whakamaru

220kV Otahuhu-Huntly

220kV Huntly-Hamilton

110kV Mt Maunganui-Tarukenga

110kV Tarukenga-Tauranga

220kV Tarukenga-Edgecumbe

220kV Edgecumbe-Kawerau

220kV Kawerau-Ohakuri

220kV Wairakei-Ohakuri

220kV Ohakuri-Atiamuri

220kV Atiamuri-Tarukenga

220kV Atiamuri-Whakamaru

220kV Wairakei-Redclyffe

220kV Wairakei-Whirinaki

220kV Whirinaki-Redclyffe

220kV Hamilton-Whakamaru

220kV Tokaanu-Whakamaru

220kV Bunnythorpe-Tokaanu

220kV Bunnythorpe-Tangiwai

220kV Rangipo-Tangiwai

220kV Rangipo-Wairakei

220kV Wairakei-Poihipi

220kV Poihipi-Whakamaru

220kV Stratford-New Plymouth

110kV New Plymouth-Carrington St

220kV Bunnythorpe-Haywards

220kV Haywards-Wilton

220kV Haywards- Linton

220kV Wilton-Linton

220kV Bunnythorpe-Linton

110kV Wilton-Central Park

110kV Takapu Rd-Wilton

220kV Bunnythorpe-Brunswick

220kV Brunswick-Stratford

110kV Otahuhu-Mangere

110kV Haywards-Takapu Rd

220/110kV interconnection Marsden

220/110kV interconnection Albany

220/110kV interconnection Henderson

220/110kV interconnection Penrose

220/110kV interconnection Otahuhu

220/110kV interconnection Hamilton

220/110kV interconnection Tarukenga

220/110kV interconnection New Plymouth

220/110kV interconnection Stratford

220/110kV interconnection Redclyffe

220/110kV interconnection Bunnythorpe

220/110kV interconnection Haywards

220/110kV interconnection Wilton

220kV Islington-Kikiwa

220kV Kikiwa-Stoke

220kV Twizel-Tekapo B

220kV Tekapo B-Islington

220kV Twizel-Opihi-Timaru-Ashburton

220kV Ashburton-Bromley

220kV Bromley-Islington

220kV Twizel-Opihi-Timaru-Islington

220kV Livingstone-Islington

220kV Benmore-Ohau B

220kV Ohau B-Twizel

220kV Benmore-Twizel

220kV Benmore-Ohau C

220kV Ohau C-Twizel

220kV Benmore-Aviemore

220kV Clyde-Cromwell

220kV Cromwell-Twizel

220kV Roxburgh-Clyde

220kV Naseby-Livingstone

220kV Roxburgh-Naseby

220kV Roxburgh-Three Mile Hill

220kV Three Mile Hill-Half Way Bush

220kV Three Mile Hill-Sth Dunedin

220kV Sth Dunedin-Half Way Bush

220kV Manapouri-Invercargill

220kV Manapouri-Nth Makarewa

220kV Nth Makarewa-Invercargill

220kV Invercargill-Roxburgh

220kV Invercargill-Tiwai Pt

220kV Nth Makarewa-Tiwai Pt

220/66kV interconnection Islington

66kV Islington-Addington

220/66kV interconnection Bromley

Compare: Electricity Governance Rules 2003 clauses 3 and 4 schedule F3A part F

3 Interpretation

For the purposes of this core grid determination, unless the context calls for another interpretation, a term has the meaning given to that term in the grid reliability standards.

Compare: Electricity Governance Rules 2003 clause 5 schedule F3A part F

Schedule 12.4

cl 12.93

Transmission Pricing Methodology

Schedule 12.4: replaced, on 20 December 2022, by clause 4 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology) 2022.

Part A Preliminary

Introduction

1 Purpose

The transmission pricing methodology is used to recover the cost of transmission services provided by Transpower, other than costs recovered under investment agreements, but not more than recoverable revenue for each pricing year. This transmission pricing methodology allocates that cost to customers through transmission charges.

2 Overview of Transmission Charges

The transmission charges are—
- (a) connection charges, which recover part of recoverable revenue by reference to the cost of connection investments. Part C specifies how connection charges are calculated; and
- (b) benefit-based charges, which recover part of recoverable revenue by reference to the covered cost of benefit-based investments. Part D specifies how benefit-based charges are calculated; and
- (c) cap recovery charges, which are a redistribution of transmission charges that would otherwise be payable by capped customers who are receiving cap reductions; and
- (d) prudent discount recovery charges, which are a redistribution of transmission charges that would otherwise be payable by prudent discount recipients; and
- (e) residual charges, which recover the remainder of recoverable revenue. Part E specifies how residual charges are calculated.

Clause 2(a): amended, on 31 July 2023, by clause 4(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 2(b): amended, on 31 July 2023, by clause 4(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 2(e): amended, on 31 July 2023, by clause 4(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Interpretation

3 General Definitions

In this transmission pricing methodology, unless the context otherwise requires—

2020 guidelines means the guidelines the Authority published under paragraph 12.83(b) of this Code on 10 June 2020

AC assets means grid assets other than HVDC assets

AC switch means a switch that is an AC asset

accelerated depreciation means depreciation or tax depreciation (as the context requires) of an asset exclusively due to damage to, or destruction, stranding, decommissioning or disposal of, the asset

adjustment event means a connection charge adjustment event, benefit-based charge adjustment event or residual charge adjustment event

alleviated price means, for a regional customer group, factual and counterfactual, a price at a market node in the regional customer group’s modelled region that, due to a modelled constraint is—

(a) higher in the counterfactual than the factual; or
(b) higher in the counterfactual than a price at another market node in the counterfactual that is in a modelled region for a different regional customer group of the same type (regional demand group or regional supply group)

allocation data means any data about supply, demand, injection, offtake or gross energy that affects a customer’s allocation of transmission charges

allowance means, for a cost or charge over a period, the forecast MAR building block under the Transpower IPP over the period for the cost or charge

alternative project means—

(a) for an inefficient bypass prudent discount, an investment by the customer in a transmission alternative that, if implemented, would bypass existing grid assets; or
(b) for a stand-alone cost prudent discount, an investment in the grid or 1 or more transmission alternatives by an efficient transmission services provider that, if implemented, would provide transmission services in substitution for all transmission services the customer currently receives

alternative project costs has the meaning in clause 117

ancillary service BBI means a post-2019 BBI that is expected to have a material impact on prices or quantities in the wholesale market for a specified ancillary service relative to the post-2019 BBI’s counterfactual. An ancillary service BBI may also be a market BBI or reliability BBI, but cannot be a resiliency BBI

ancillary service regional customer group means a regional customer group defined in subclause 53(3)

ancillary service regional NPB means regional NPB arising from changes in prices or quantities in the wholesale market for a specified ancillary service. Ancillary service regional NPB may be calculated for ancillary service BBIs

annual benefit-based charge has the meaning in subclause 35(2)

annual cap recovery charge has the meaning in subclause 112(1)

annual charges means the following transmission charges for a customer and pricing year:

(a) annual connection charges:
(b) annual benefit-based charges:
(c) annual cap recovery charge:
(d) annual prudent discount recovery charge:
(e) annual residual charge

annual connection charge has the meaning in subclause 24(2) or 24(3)

annual prudent discount recovery charge has the meaning in subclause 138(5)

annual residual charge has the meaning in subclause 68(2)

anticipatory BBI has the meaning in subclause 27(2)

anticipatory connection asset has the meaning given in subclause 26(3)

anytime maximum demand (connection) or AMDC means, for a customer, connection location and pricing year, the average of the 12 highest offtake quantities for the customer at the connection location during CMP A for the pricing year, multiplied by 2 to convert to average demand

anytime maximum demand (residual) or AMDR means the amount calculated under clause 69 for a load customer and pricing year

anytime maximum injection (connection) or AMIC means, for a customer, connection location and pricing year, the average of the 12 highest injection quantities for the customer at the connection location during CMP A for the pricing year, multiplied by 2 to convert to average supply

Appendix A allocation means, for an Appendix A customer and Appendix A BBI and subject to clause 10(8), the Appendix A customer’s BBI customer allocation for the Appendix A BBI specified in Appendix A to 2 decimal places

Appendix A BBI means the following interconnection investments:

Bunnythorpe Haywards
- the interconnection investment approved by the Commission on 9 May 2014 as the Bunnythorpe-Haywards A and B Lines Conductor Replacement Project, including all amendments to that approved project subsequently approved by the Commission
HVDC
- all interconnection investments in the HVDC link commissioned on or before 23 July 2019
LSI Reliability
- the interconnection investment approved by the Electricity Commission on 6 September 2010 as the Lower South Island Reliability Transmission Investment, including all amendments to that approved project subsequently approved by the Electricity Commission or Commission
LSI Renewables
- the interconnection investment approved by the Electricity Commission on 9 August 2010 as the Lower South Island Renewables Investment, including all amendments to that approved project subsequently approved by the Electricity Commission or Commission, but excluding the post-2019 CUWLP investment
NIGU
- the interconnection investment approved by the Electricity Commission on 5 July 2007 as the North Island Grid Upgrade, including all amendments to that approved project subsequently approved by the Electricity Commission or Commission
UNIDRS
- the interconnection investment approved by the Electricity Commission on 5 July 2010 as the Upper North Island Dynamic Reactive Support Investment, including all amendments to that approved project subsequently approved by the Electricity Commission or Commission
Wairakei Ring
- the interconnection investment approved by the Electricity Commission on 20 February 2009 as the Wairakei Ring Investment, including all amendments to that approved project subsequently approved by the Electricity Commission or Commission

Appendix A beneficiary means, for an Appendix A BBI, an Appendix A customer who has a positive Appendix A allocation for the Appendix A BBI

Appendix A customer means a person specified in Appendix A, even if not a current customer at the time this definition is applied

application means an application to Transpower under this transmission pricing methodology, including an application for a prudent discount or reassignment

application fee means a fee for a type of application published by Transpower, if any

application requirements means, for an application, the content requirements for the application published by Transpower

asseted means, for an asset comprised in a BBI, that there is sufficient information about the asset in Transpower’s fixed asset register for Transpower to calculate accurately the part of the BBI’s covered cost for a pricing year that relates to the asset

Clause 3 asseted: inserted, on 31 July 2023, by clause 5(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

assumptions book means a document published by Transpower containing assumptions and detailed methodologies that Transpower—

(a) intends to apply for allocating and adjusting benefit-based charges; and
(b) does not expect to vary between BBIs except according to the method (standard method, simple method or Appendix A) used to calculate their BBI customer allocations

avoided charges means—

(a) for an inefficient bypass prudent discount—
- (i) the transmission charges the relevant customer would avoid paying if the relevant alternative project were implemented—
  - (A) assessed relative to the transmission charges the customer would pay if the alternative project were not implemented; and
  - (B) assuming none of the alternative project costs for the alternative project would be recovered through transmission charges; less
- (ii) the absolute value of any reduction in settlement residue that would be paid to the customer if the alternative project were implemented, assessed relative to the settlement residue that would be paid to the customer if the alternative project were not implemented; and
(b) for a stand-alone cost prudent discount—
- (i) the relevant customer’s connection charges, benefit-based charges and residual charge; less
- (ii) settlement residue paid to the customer

Clause 3 avoided charges: inserted, on 31 July 2023, by clause 5(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

avoided transmission charges [Revoked]

Clause 3 avoided transmission charges: revoked, on 31 July 2023, by clause 5(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

back-dated prudent discount means a prudent discount for which the application—

(a) is received by Transpower within 6 months of the date on which Transpower first publishes the application requirements and the application fee, if any, for the relevant type of prudent discount (inefficient bypass prudent discount or stand-alone cost prudent discount); and
(b) is not rejected by Transpower under subclause 14(1), 115(1) or 115(2)

battery storage means equipment functioning together as a single entity that is able to both—

(a) take electricity and store the energy in another form; and
(b) inject that energy as electricity into the grid, a local network, a non-grid network or consuming plant

BBI customer allocation means a customer’s allocation of the benefit-based charge for a BBI—

(a) specified in or calculated under this transmission pricing methodology; and
(b) as adjusted under this transmission pricing methodology

BBI prudent discount recovery charge means a charge calculated under subclause 138(1) for a prudent discount, customer and pricing year

BBI reassignment factor has the meaning in subclause 102(4)

beneficiary means, for a BBI, a customer who has a positive BBI customer allocation for the BBI

benefit factor has the meaning in subclause 83(7)

benefit-based charge means a charge described in subclause 2(b) and calculated under clause 35 for a BBI, beneficiary and pricing year

benefit-based charge adjustment event has the meaning in subclause 81(1)

benefit-based investment or BBI means—

(a) an Appendix A BBI; or
(b) a post-2019 BBI

benefitting customer means, for an application for an inefficient bypass prudent discount, any customer named in the application whose transmission charges would be reduced if the alternative project for the application were implemented

cap condition means the condition specified in subclause 110(2)

cap recovery charge means a charge described in subclause 2(c) and calculated under clause 112 for a customer and pricing year

cap recovery-relevant charges means, for a customer and pricing year, the customer’s—

(a) annual benefit-based charges for the Appendix A BBIs and pricing year; and
(b) annual residual charge for the pricing year,

net of any prudent discount of those transmission charges for the customer and pricing year

cap reduction means the total reduction in a capped customer’s transmission charges for a pricing year under subclause 110(1)

capacity means the rated capacity of an asset to (as the case may be)—

(a) consume or generate electricity; or
(b) take electricity from or inject electricity into a network; or
(c) transmit or distribute electricity,

in each case measured in units appropriate for the context

capacity measurement period or CMP means a period over which a calculation under this transmission pricing methodology is made, being either:

CMP A
- for pricing year n, capacity year n-2. CMP A is relevant to calculating connection charges
CMP B
- for a BBI, the period ending on the last trading period of the most recent complete capacity year before the final investment decision date for the BBI (capacity year n) and starting on the first trading period of capacity year n-4. CMP B is relevant to calculating benefit-based charges for BBIs under the standard method
CMP C
- for the first simple method period, the period ending on the last trading period of the second most recent complete capacity year before the first pricing year (capacity year n) and starting on the first trading period of capacity year n-4
- for a subsequent simple method period, the period ending on the last trading period of the second most recent complete capacity year before the first pricing year of the simple method period (capacity year n) and starting on the first trading period of capacity year n-4.
- CMP C is relevant to calculating benefit-based charges for BBIs under the simple method
CMP D
- the period from the first trading period of financial year 2014 to the last trading period of financial year 2017. CMP D is relevant to calculating benefit factors and residual charges
CMP E
- for pricing year n, the period from the first trading period of financial year n-8 to the last trading period of financial year n-5. CMP E is relevant to calculating residual charges
CMP F
- for a SSCGU, the period ending on the last trading period of the most recent complete capacity year before the SSCGU occurred (capacity year n) and starting on the first trading period of capacity year n-4. CMP F is relevant to adjusting benefit-based charges for high-value BBIs
CMP G
- the period from the first trading period of pricing year 2015 to the last trading period of pricing year 2019. CMP G is relevant to calculating difference caps

capacity year means a period of 12 months starting on 1 September and ending on 31 August. Capacity year n means the capacity year starting in year n

capital charge means Transpower’s return on its investment in an asset

capped charges means, for a capped customer and pricing year, the capped customer’s:

(a) annual benefit-based charges for the Appendix A BBIs and pricing year; and
(b) annual residual charge for the pricing year
(c) [Revoked]

Clause 3 capped charges paragraph (b): amended, on 31 July 2023, by clause 5(2)(a) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 3 capped charges paragraph (c): revoked, on 31 July 2023, by clause 5(2)(b) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

capped customer means—

(a) for the first pricing year, a customer, other than in its capacity as a generator, who was a customer during pricing year 2019 and at least 2 pricing years preceding pricing year 2019; and
(b) for each subsequent pricing year, any such customer who had a cap reduction for the previous pricing year

closing RAB value has the meaning in the Transpower IMs

coincident peak offtake has the meaning in subclause 65(8)

Commission means the Commerce Commission established by section 8 of the Commerce Act 1986

commissioned has the meaning in clause 5

commissioning date means the date an asset, connection investment or interconnection investment (including a BBI) is commissioned

compliance investment means an investment by Transpower in an existing grid asset or transmission alternative to ensure the grid asset or transmission alternative is maintained, and can be operated, in accordance with good electricity industry practice. A compliance investment may also be an enhancement investment, refurbishment investment or replacement investment

connection asset has the meaning in subclause 21(1), and includes “deep” connection assets as described in paragraph 22(5)(b)

connection charge means a charge described in subclause 2(a) and calculated under clause 24 for a customer and pricing year and—

(a) a connection asset and connection location; or
(b) a connection transmission alternative

connection charge adjustment event has the meaning in clause 76

connection customer allocation means a customer’s allocation of the connection charge for a connection asset and connection location calculated under clause 32

connection investment means a transmission investment or group of related transmission investments exclusively in 1 or more connection assets or connection transmission alternatives

connection link has the meaning in paragraph 20(1)(e)

connection node has the meaning in paragraph 20(1)(d)

connection region means a region determined by Transpower under subclause 62(4)

connection transmission alternative means a transmission alternative to the extent it is an alternative to an investment in a connection asset, as determined by Transpower

consuming plant means—

(a) equipment that consumes electricity, regardless of size, including electrical appliances as defined in the Electricity Act 1992; and
(b) battery storage when charging

continuing BBI has the meaning in subclause 84(5) or 85(4)

contributing customer means, for a funded asset—

(a) a customer who funded, or is funding, all or part of the capital cost of the funded asset under an investment agreement; or
(b) a customer who funded, or is funding, all or part of the capital cost of the funded asset through connection charges

counterfactual means, for a BBI, the expected future grid state assuming the BBI is not commissioned

covered cost means the amount of recoverable revenue allocated to a BBI for a pricing year calculated under subclause 39(1)

CPI means the consumers price index (all groups) published by Stats NZ

curtailed energy means unserved energy or unsupplied energy

customer means a designated transmission customer

demand factor means the scaling factor for regional NPB for regional demand groups under the simple method calculated under clause 64(4)

depreciation means depreciation of an asset calculated in accordance with the Transpower IMs

de-rate means, for an asset or plant, to alter the asset or plant physically so that the asset’s or plant’s capacity is permanently reduced

difference cap has the meaning in clause 111(1)

direct supplied load customer means, for a connection location and trading period, a connected asset owner who—

(a) owns or controls a local network or consuming plant connected to the grid at the connection location; and
(b) has embedded electricity at the connection location of the type defined in paragraph 4(1)(b) for the trading period

discounted BBI means—

(a) for an inefficient bypass prudent discount, a BBI that would be bypassed by the relevant alternative project; or
(b) for a stand-alone cost prudent discount, a BBI of which the prudent discount recipient is a beneficiary

economic life means, for an asset, the asset’s physical asset life as defined in the Transpower IMs

EDB ID determination means the Electricity Distribution Information Disclosure Determination 2012 [2012] NZCC 22

EDB IMs means the Electricity Distribution Services Input Methodologies Determination 2012 [2012] NZCC 26

efficient stand-alone investment has the meaning in clause 135

eligible BBI means a BBI, including a BBI that is currently reassigned or was previously reassigned, for which both of the following conditions are satisfied (as applicable):

(a) the total closing RAB value of all assets comprised in the BBI for the most recent complete financial year, adjusted by the BBI reassignment factor for any current reassignment the BBI is subject to, is at least the reassignment threshold:
(b) if the BBI is a post-2019 BBI, either—
- (i) at least 10 years have passed since the BBI’s commissioning date; or
- (ii) since the BBI’s commissioning date—
  - (A) a customer permanently disconnected from the grid at a connection location at which the customer was a beneficiary of the BBI when it disconnected; and
  - (B) that disconnection, by itself and without taking into account other events, caused the BBI’s BBI reassignment factor to decrease by at least 0.2; or
- (iii) since the BBI’s commissioning date—
  - (A) a customer who is a beneficiary of the BBI permanently disconnected plant from the grid; and
  - (B) that disconnection, by itself and without taking into account other events, caused the BBI’s BBI reassignment factor to decrease by at least 0.2

eligible person means, for an application for reassignment or a proposal to reverse a reassignment—

(a) a beneficiary of the BBI to which the application or proposal relates; or
(b) a person who owns or controls embedded plant connected to the local network or grid-connected plant of a beneficiary of the BBI

embedded means, for plant, that the plant is connected to a local network or to grid-connected plant. If the plant is also connected to the grid, Transpower may treat the plant as part embedded and part grid-connected

embedded electricity has the meaning in paragraph 4(1)(b), 4(1)(c) or 4(1)(d) for a customer and trading period

enhancement investment means a transmission investment that is not a refurbishment investment or replacement investment. An enhancement investment may also be a compliance investment

event pricing year means the pricing year during which an adjustment event occurs

exacerbated price means, for a regional customer group, factual and counterfactual, a price at a market node in the regional customer group’s modelled region that, due to a modelled constraint is—

(a) higher in the factual than the counterfactual; or
(b) lower in the counterfactual than a price at another market node in the counterfactual that is in a modelled region for a different regional customer group of the same type (regional demand group or regional supply group)

exempt post-2019 investment means an interconnection investment, other than the post-2019 CUWLP investment, that is—

(a) commissioned after 23 July 2019 and before the start of financial year 2021; and
(b) a refurbishment investment, replacement investment or enhancement investment in respect of an Appendix A BBI or another interconnection investment commissioned on or before 23 July 2019

exempt pricing year means, for an adjustment event and customer—

(a) the event pricing year; and
(b) the pricing year after the event pricing year if the adjustment event occurred less than 1 month before the deadline for Transpower notifying the customer of its transmission charges for the pricing year under the relevant transmission agreement

expected effective full commissioning date means, for a BBI, a date determined by Transpower, which must fall within the period from (and including) the BBI’s expected commissioning date to (and including) the BBI’s expected full commissioning date, by which sufficient grid assets and transmission alternatives comprised in the BBI are expected to have been commissioned such that all of the BBI’s principal benefits will have been released

factual means, for a BBI, the expected future grid state assuming the BBI is fully commissioned

final investment decision date means, for a BBI, the date Transpower makes its final decision to proceed with its investment in the BBI

financial year means a period of 12 months starting on 1 July and ending on 30 June. Financial year n means the financial year starting in year n

first pricing year means the first pricing year to which this transmission pricing methodology applies

forecast loading period has the meaning in subclause 102(1)

forecast peak loading has the meaning in subclause 102(2)

full commissioning date means the date a connection investment or interconnection investment (including a BBI) is fully commissioned

fully commissioned has the meaning in clause 5

funded asset means a connection asset—

(a) commissioned after the start of the first pricing year; and
(b) (all or part of the capital cost of which was funded, or is being funded, by a customer under an investment agreement

future regional customer group means a regional customer group—

(a) that is expected to have no members when the relevant post-2019 BBI is commissioned; and
(b) the future members of which (if any) will be new customers and customers who connect new plant to the grid

GAAP means generally accepted accounting practice in New Zealand

GEIP (standing for good electricity industry practice) means, for an alternative project, the exercise of that degree of skill, diligence, prudence, foresight and economic management that would reasonably be expected from a skilled and experienced asset owner engaged in the management of the alternative project, under conditions comparable to those applicable to the alternative project, consistent with applicable law, safety and environmental protection

generating plant has the meaning in Part 1 of this Code and includes battery storage when discharging

grid assets has the meaning in subclause 17(1)

grid point of connection means a point of connection to the grid

gross energy has the meaning in subclause 4(5)

GXP tie means a situation in which a connected asset owner’s assets are simultaneously connected to the grid at more than 1 point of connection

high-value means, for a BBI, that the sum of—

(a) the depreciated value of the assets comprised in the BBI; and
(b) expected future TA opex for the interconnection transmission alternatives comprised in the BBI,

is, at the relevant time, more than the base capex threshold as defined in the Transpower Capex IM

high-value intervening BBI means a post-2019 BBI—

(a) with a final investment decision date before the start of the first pricing year; and
(b) commissioned on or before the last day of the financial year that precedes the pricing year after the first pricing year; and
(c) expected to be high-value when fully commissioned

high-voltage grid means the part of the grid with a nominal voltage of 220 kV or mor

HILP event means a low probability event or group of events that, if it or they occurred, would have a high impact on unserved energy other than by way of cascade failure, as determined by Transpower

host customer means, for embedded plant, the customer who owns or controls the local network or grid-connected plant the embedded plant is connected to

HVDC asset means a grid asset that is part of the HVDC link

HVDC opex means—

(a) availability costs allocated to the HVDC owner; and
(b) insurance premiums for the HVDC link

ID WACC means, for Transpower or a distributor, the post-tax or pre-tax (as the context requires) WACC determined by the Commission under the Transpower IMs or EDB IMs for the purposes of Transpower’s or the distributor’s information disclosure regulation under Part 4 of the Commerce Act 1986

independent expert means an independent person who is a recognised technical expert in the matter that has been referred to him or her. In appointing an independent expert, the party referring the matter to the independent expert must nominate 3 persons and the other party may agree that any 1 of them be appointed. Failing agreement between the parties, the independent expert will be appointed by the Authority

independent verification means, for an application, a written report on the accuracy and sufficiency of the information and analysis contained in the application prepared by 1 or more persons who are—

(a) recognised technical experts on the subject matter of the application; and
(b) independent of the customer making the application; and
(c) approved by Transpower

indirect supplied load customer means, for a connection location and trading period, an asset owner who—

(a) owns or controls a local network, consuming plant or generating plant connected to the grid at the connection location; and
(b) has embedded electricity at the connection location of the type defined in paragraph 4(1)(c) for the trading period

individual NPB means NPB for a customer calculated under clause 47 or 57 or subclause 61(1)

inefficient bypass prudent discount means a discount of a customer’s transmission charges provided under this transmission pricing methodology for the purpose in clause 127

injection means—

(a) for a trading period and a customer’s grid point of connection, the positive net quantity of electricity flow into the grid at the grid point of injection from the customer’s assets during the trading period (if any); and
(b) for a trading period and a customer’s connection location, the positive net quantity of electricity flow into the grid at all of the customer’s grid points of connection at the connection location during the trading period (if any)

injection customer means, for a connection location and trading period, a customer at the connection location who has injection at the connection location for the trading period

interconnection asset has the meaning in subclause 21(2)

interconnection investment means a transmission investment or group of related transmission investments exclusively in 1 or more interconnection assets or interconnection transmission alternatives

interconnection link has the meaning in paragraph 20(1)(f)

interconnection node has the meaning in paragraph 20(1)(a)

interconnection transmission alternative means a transmission alternative to the extent it is not a connection transmission alternative

intra-regional allocator has the meaning in subclause 65(1), 65(2), 65(3) or 65(4) for the relevant regional customer group

investment agreement means—

(a) a contract entered into at any time between Transpower and another person (who may or may not be a customer) under which—
- (i) Transpower agrees to provide any new, upgraded or modified transmission investment; or
- (ii) the other person agrees to make a contribution to the capital, maintenance, operating or other cost of a transmission investment,
- including—
  - (iii) a new investment agreement contract; and
  - (iv) a contract to move or remove grid assets; or
(b) an agreement deemed to be an investment agreement under paragraph 28(5)(b)

investment agreement asset means a grid asset provided under an investment agreement

investment grid means a simplified model of the grid for a market BBI’s factual or counterfactual that models—

(a) all existing branches and market nodes, as those branches and market nodes may be added to or removed in the market BBI’s factual or counterfactual (as the case may be); and
(b) the constraints of the HVDC link, as those constraints would be in the market BBI’s factual or counterfactual (as the case may be); and
(c) the market BBI’s modelled constraints, as those constraints would be in the market BBI’s factual or counterfactual (as the case may be)

investment reassignment factor has the meaning in subclause 102(3)

investment region means a modelled region under the simple method where a BBI or part of a BBI is located

investment test means the investment test applied to a tested investment under section III of Part F of the rules or the Transpower Capex IM

land and buildings has the meaning in subclause 17(3)

large means, subject to clause 7—

(a) for plant, that the plant—
- (i) is connected to the grid; or
- (ii) has capacity of at least 10 MW; and
(b) for an upgrade of plant, that the plant’s capacity has increased by at least 10 MW compared to the plant’s capacity before the upgrade; and
(c) for a de-rating of plant, that the plant’s capacity has reduced by at least 10 MW compared to the plant’s capacity before the de-rating

link has the meaning in subclause 19(3)

load customer means a customer who, at a connection location during a trading period, is or was (as the context requires) 1 or more of the following:

(a) an offtake customer:
(b) a direct supplied load customer:
(c) an indirect supplied load customer:
(d) a supplying load customer

loop has the meaning in paragraph 20(1)(b)

low-value means, for a BBI, that the sum of—

(a) the depreciated value of the assets comprised in the BBI; and
(b) expected future TA opex for the interconnection transmission alternatives comprised in the BBI,

is, at the relevant time, not more than the base capex threshold as defined in the Transpower Capex IM

low-voltage grid means the part of the grid with a nominal voltage of less than 220 kV

market BBI means a post-2019 BBI that is expected to have a material impact on prices or quantities in the wholesale market for electricity relative to the post-2019 BBI’s counterfactual. A market BBI may also be an ancillary service BBI or a reliability BBI, but cannot be a resiliency BBI

market node means a GXP or GIP

market regional NPB means regional NPB arising from changes in prices or quantities in the wholesale market for electricity. Market regional NPB is calculated for market BBIs

market scenario means, for a BBI, a future state for factors that influence NPB for the BBI

material damage means destruction of, or substantial damage to, a BBI, as determined by Transpower

maximum gross demand has the meaning in subclause 4(6)

maximum revenue means, for a pricing year, the maximum revenue Transpower is permitted to recover for the pricing year, as determined by the Commission under Part 4 of the Commerce Act 1986. At the date of this transmission pricing methodology, this is the most recently updated forecast SMAR for the pricing year under the Transpower IPP

MCP opex means operating costs of the type described in clause 3.1.3(1)(d) of the Transpower IMs, being operating costs relating to major capex projects

mixed connection asset means a connection asset that, as well as connecting a customer, is used for grid operation generally

modelled constraint means, for a market BBI—

(a) a constraint affecting a new grid asset comprised in the market BBI; or
(b) a constraint that would be alleviated materially if the market BBI were fully commissioned, as determined by Transpower

modelled region means a region defined in, or determined by Transpower under—

(a) for a BBI under the price-quantity method, subclause 50(1), 54(3), 55(4) or 56(3) depending on the type of regional NPB being calculated; and
(b) for a BBI under the resiliency method, clause 58; and
(c) for a BBI under the simple method, subclause 62(1)

monthly benefit-based charge has the meaning in subclause 35(3)

monthly cap recovery charge has the meaning in subclause 112(2)

monthly charges means the following transmission charges for a customer and pricing year:

(a) monthly connection charges:
(b) monthly benefit-based charges:
(c) monthly cap recovery charge:
(d) monthly prudent discount recovery charge:
(e) monthly residual charge

monthly connection charge has the meaning in subclause 24(4)

monthly prudent discount recovery charge has the meaning in subclause 138(6)

monthly residual charge has the meaning in subclause 68(3)

net private benefit or NPB (which may be negative, zero or positive)—

(a) means, for a regional customer group or customer, the sum of the quantified benefits (positive values) and disbenefits (negative values) the regional customer group or customer is expected to receive from the relevant BBI; and
(b) for a host customer, includes the sum of the quantified benefits (positive values) and disbenefits (negative values) the embedded plant owners connected to the host customer’s local network or grid-connected plant are expected to receive from the relevant BBI

node has the meaning in subclause 19(1)

nominated peak kVar means, for a connected asset owner, zone and capacity year, the quantity ∑_jQ_xjzin subclause 8.67(2) of this Code calculated using the connected asset owner’s nomination for the zone applying from the most recent 1 March before the start of the capacity year

non-contributing customer means, for a funded asset, a customer who—

(a) is connected by the funded asset at a connection location; and
(b) was not a contributing customer for the funded asset before connecting to it

non-grid network means a system of lines, substations and other works, used primarily for the conveyance of electricity, that is not part of the grid or connected to the grid, including an embedded network

notional IRA value has the meaning in clause 67

offtake means—

(a) for a trading period and a customer’s grid point of connection, the positive net quantity of electricity flow out of the grid at the grid point of connection into the customer’s assets during the trading period (if any); and
(b) for a trading period and a customer’s connection location, the positive net quantity of electricity flow out of the grid at all of the customer’s grid points of connection at the connection location during the trading period (if any)

offtake customer means, for a connection location and trading period, a customer at the connection location who has offtake at the connection location for the trading period

opening RAB value has the meaning in the Transpower IMs

optimised replacement cost means, for any grid asset or group of grid assets, the optimised replacement cost of the grid asset or group of grid assets as at 1 July 2006, as determined by Transpower

other regional NPB means regional NPB that is not market regional NPB, ancillary service regional NPB or reliability regional NPB. Other regional NPB may be calculated for market BBIs, ancillary service BBIs or reliability BBIs

outage scenario means, for a reliability BBI, an outage or other event or group of events affecting access to transmission services in respect of which the reliability BBI is expected to have a material impact on curtailed energy

peak BBI means a post-2019 BBI for which the investment need is primarily attributable to meeting peak demand

peak offtake trading period has the meaning in paragraph 65(8)

periods of benefit has the meaning in paragraph 51(3)(b)

plant means consuming plant or generating plant

post-2019 BBI means an interconnection investment commissioned after 23 July 2019 excluding any exempt post-2019 investment. To avoid doubt—

(a) the post-2019 CUWLP investment is a post-2019 BBI; and
(b) an interconnection investment that is an Appendix A BBI is not a post-2019 BBI; and
(c) an interconnection investment carried out or approved as a single project or programme may comprise more than 1 post-2019 BBI; and
(d) a post-2019 BBI may comprise more than 1 interconnection investment, each of which is carried out or approved as a single project or programme

post-2019 CUWLP investment means the interconnection investment comprising the following transmission investments approved by the Electricity Commission on 9 August 2010 as part of the Lower South Island Renewables Investment:

(a) thermal upgrade of the circuits between Cromwell and Twizel:
(b) re-conductoring of the circuits between Roxburgh and Livingstone

PQ WACC means, for Transpower or a price-quality regulated distributor, the vanilla or pre-tax (as the context requires) WACC determined by the Commission under the Transpower IMs or EDB IMs for the purposes of Transpower’s or the distributor’s price-quality regulation under Part 4 of the Commerce Act 1986

pre-commencement adjustment event means an event that occurred before the start of the first pricing year and—

(a) would have been an adjustment event had it occurred at or after the start of the first pricing year; or
(b) Transpower determines is analogous to an adjustment event

pre-existing customer means a customer who has been a member of a regional customer group for (as the case may be)—

(a) at least 2 full capacity years during CMP B for the relevant BBI; or
(b) at least 2 full capacity years during CMP C for the relevant simple method period

pre-existing load customer means a load customer who was a customer for the whole of CMP D

pre-start adjustment event means, for a post-2019 BBI, an event that occurred before the start of the post-2019 BBI’s start pricing year and would have been a benefit-based charge adjustment event for the post-2019 BBI had it occurred at or after the start of the post-2019 BBI’s start pricing year. To avoid doubt, a pre-start adjustment event may be a pre-commencement adjustment event

previous discount means—

(a) a prudent discount provided under the previous transmission pricing methodology; or
(b) a discount provided under a notional embedding contract; or
(c) any other discount or effective discount of transmission charges provided under an agreement between Transpower and a customer entered into before the start of the first pricing year

previous transmission pricing methodology means, as applicable, the transmission pricing methodology comprised in this Code when it came into force, as subsequently amended up to the date this transmission pricing methodology came into force

price-quantity method means the method for calculating NPB for a post-2019 BBI specified in clauses 44 to 55

pricing year has the meaning given to that term in the Transpower IMs. At the date of this transmission pricing methodology, a pricing year is a period of 12 months starting on 1 April and ending on 31 March. Pricing year n means the pricing year starting in year n

prior contributing customer means, for a funded asset and in respect of a non-contributing customer for the funded asset, a contributing customer who was connected to the funded asset before the non-contributing customer became connected to the funded asset

prudent discount means an inefficient bypass prudent discount or stand-alone cost prudent discount. The amount of a prudent discount for a pricing year is—

(a) the absolute value of the reduction in the prudent discount recipient’s transmission charges for the pricing year under the prudent discount agreement; less
(b) the annuity payable by the prudent discount recipient under the prudent discount agreement

prudent discount calculation period means, for a prudent discount, the period—

(a) starting at the start of the prudent discount’s start pricing year, or estimated start pricing year assuming the prudent discount is approved; and
(b) ending—
- (i) for an inefficient bypass prudent discount, at the end of the remaining economic life of the grid assets the relevant alternative project would bypass, up to a maximum of 15 years after the start of the prudent discount calculation period; or
- (ii) for a stand-alone cost prudent discount, 15 years after the start of the prudent discount calculation period

prudent discount confirmation date means, for a prudent discount decision, the date the following conditions are satisfied:

(a) either—
- (i) the relevant customer has confirmed to Transpower in writing that it does not intend to refer any aspect of Transpower’s decision to an independent expert; or
- (ii) the customer did not refer any aspect of Transpower’s decision to an independent expert before time to do so expired under subclause 120(3); or
- (iii) an independent expert has made final binding decisions on all aspects of Transpower’s decision referred to the independent expert:
(b) for an approved prudent discount, Transpower and the customer have entered into a prudent discount agreement for the prudent discount

prudent discount practice manual means a document published by Transpower containing assumptions and detailed methodologies that Transpower—

(a) intends to apply for assessing applications for prudent discounts; and
(b) does not expect to vary between prudent discount applications except according to whether the application is for an inefficient bypass prudent discount or stand-alone cost prudent discount

prudent discount rate means—

(a) subject to paragraph 128(c), for an inefficient bypass prudent discount—
- (i) if the applicant customer is a distributor, the distributor’s ID WACC at the time of the application for the prudent discount; or
- (ii) if the applicant customer is not a distributor but is subject to another regulated WACC, that WACC; or
- (iii) otherwise, a WACC for the applicant customer determined by Transpower by applying the methodology for estimating ID WACC for distributors in the EDB IMs; or
(b) for a stand-alone cost prudent discount, Transpower’s ID WACC at the time of the application for the prudent discount

prudent discount recipient means a customer receiving a prudent discount

prudent discount recovery charge means a charge described in subclause 2(d), being a BBI prudent discount recovery charge or residual prudent discount recovery charge

reassignment means a reassignment of all or part of the covered cost of a BBI to residual revenue, and reassigned has a corresponding meaning

reassignment amount has the meaning in clause 97

reassignment confirmation date means, for a reassignment decision, the date any of the following conditions is satisfied:

(a) the relevant eligible person has confirmed to Transpower in writing that it does not intend to refer any aspect of Transpower’s decision to an independent expert:
(b) expert the eligible person did not refer any aspect of Transpower’s decision to an independent before time to do so expired under subclause 104(3) or paragraph 107(2)(c):
(c) an independent expert has made final binding decisions on all aspects of Transpower’s decision referred to the independent expert

reassignment practice manual means a document published by Transpower containing assumptions and detailed methodologies that Transpower—

(a) intends to apply for assessing applications for reassignment; and
(b) does not expect to vary between reassignment applications

reassignment threshold has the meaning in subclause 98(2)

recent customer means a customer who has been a member of a regional customer group for (as the case may be)—

(a) less than 2 full capacity years during CMP B for the relevant BBI; or
(b) less than 2 full capacity years during CMP C for the relevant simple method period

recent load customer means a load customer who is not a pre-existing load customer

recoverable revenue means, for a pricing year—

(a) maximum revenue for the pricing year; less
(b) any part of maximum revenue for the pricing year Transpower is able or required to recover other than through transmission charges, including by way of annuities paid by prudent discount recipients

reduction event means, for a pre-existing load customer, a reduction in the pre-existing load customer’s expected maximum gross demand compared to the pre-existing load customer’s AMDR baseline calculated under clause 70(1)—

(a) of at least 10 MW; and
(b) due to an event or series of directly related events that—
- (i) occurred, or Transpower determines will occur, after the start of CMP D and before the start of the first pricing year; and
- (ii) Transpower determines was, were or will be beyond the pre-existing load customer’s reasonable control, not being—
  - (A) a change in the basis for calculating future transmission charges; or
  - (B) a change in the market for the pre-existing load customer’s products or services, other than the services the pre-existing load customer supplies to an embedded plant owner connected to the pre-existing load customer’s local network or grid-connected plant who is not a related entity of the pre-existing load customer; or
  - (C) any of the events specified in paragraph (d) of the definition of force majeure event in clause 1.1(1) of this Code occurring in respect of the pre-existing load customer or a related entity of the pre-existing load customer; or
  - (D) 1 or more events that could have been prevented by the customer by the exercise of a reasonable standard of care; and
(c) that Transpower determines is reasonably likely to persist for at least 5 years after the event or series of directly related events occurred or will occur

refurbishment investment means a transmission investment that—

(a) is asset refurbishment as defined in the Transpower Capex IM; or
(b) would be asset refurbishment as defined in the Transpower Capex IM if an investment in a transmission alternative were an investment in the grid.

A refurbishment investment may also be a compliance investment

regional customer group means a regional demand group or regional supply group

regional demand group means a group of customers in a modelled region defined in, or determined by Transpower under—

(a) for a BBI under the price-quantity method, subclause 50(2), 53(3), 55(4) or 55(3) depending on the type of regional NPB being calculated; and
(b) for a BBI under the resiliency method, clause58; and
(c) for a BBI under the simple method, clause 63

regional NPB means NPB for a regional customer group calculated in accordance with, or assumed under, a standard method or the simple method

regional supply group means a group of customers in a modelled region defined in, or determined by Transpower under—

(a) for a BBI under the price-quantity method, subclause 50(2), 54(3), 55(4) or 56(3) depending on the type of regional NPB being calculated; and
(b) for a BBI under the simple method, clause 63

regulatory asset base or RAB means Transpower’s record of commissioned assets and their depreciated values used to calculate maximum revenue under the Transpower IMs

regulatory control period or RCP means a regulatory period as defined in the Transpower IPP

related entity of a person means another person that controls, is controlled by, or is under common control with the first person, including a person that—

(a) is a related company of the first person as defined in section 2(3) of the Companies Act 1993; or
(b) would be a related company of the first person under that section if both the first person and the other person were companies registered under that Act

reliability BBI means a post-2019 BBI that is expected to reduce materially curtailed energy relative to the post-2019 BBI’s counterfactual if there is an outage or other event or group of events affecting access to transmission services. A reliability BBI may also be a market BBI or ancillary service BBI, but cannot be a resiliency BBI

reliability regional NPB means regional NPB arising from changes in curtailed energy. Reliability regional NPB is calculated for reliability BBIs

replacement cost means, for a grid asset and subject to subclause 34(5), the cost of replacing the grid asset, either separately or as part of a group of grid assets, with a modern equivalent grid asset with the same service potential

replacement cost adjustment factor means, for a grid asset or group of grid assets, the optimised replacement cost for the grid asset or group of grid assets divided by the cost, as at (or about) 1 July 2006, of replacing the grid asset or group of grid assets with the then modern equivalent grid asset with the same service potential, as determined by Transpower

replacement investment means a transmission investment that—

(a) is asset replacement as defined in the Transpower Capex IM; or
(b) would be asset replacement as defined in the Transpower Capex IM if an investment in a transmission alternative were an investment in the grid.

A replacement investment may also be a compliance investment

residual charge means a charge described in subclause 2(e) and calculated under clause 68 for a load customer and pricing year

residual charge adjustment event has the meaning in subclause 92(1)

residual charge adjustment factor or RCAF means the factor calculated under clause 71 for a load customer and pricing year

residual prudent discount recovery charge means a charge calculated under subclause 138(3) for a prudent discount, customer and pricing year

residual revenue means, for a pricing year, recoverable revenue for the pricing year less all transmission charges for the pricing year other than residual charges. The minimum value of residual revenue for a pricing year is 0

resiliency BBI means a post-2019 BBI for which the investment need is primarily attributable to mitigating a risk of cascade failure or a HILP event. A resiliency BBI cannot also be a market BBI, ancillary service BBI or reliability BBI

resiliency method means the method for calculating NPB for a resiliency BBI specified in clauses 56 to 58

reverse flow means electricity exiting the grid at a GXP and entering the grid at another GXP as a result of a GXP tie

scenario means a market scenario or outage scenario

Schedule 1 allocation means, for a Schedule 1 customer and Appendix A BBI, the Schedule 1 customer’s allocation for the Appendix A BBI specified in Schedule 1 of the 2020 guidelines to 2 decimal places

Schedule 1 beneficiary means, for an Appendix A BBI, a Schedule 1 customer who has a positive Schedule 1 allocation for the Appendix A BBI

Schedule 1 customer means a person specified in Schedule 1 of the 2020 guidelines, even if not a current customer at the time this definition is applied

simple method means the method for calculating NPB for a low-value post-2019 BBI specified in clauses 59 to 64

simple method BBC cap has the meaning in subclause 83(5B)

Clause 3 simple method BBC cap: inserted, on 10 April 2024, by clause 4 of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

simple method contribution has the meaning in clause 64(7)

simple method factor has the meaning in subclause 61(2)

simple method period has the meaning in clause 60

small regional loop has the meaning in paragraph 20(1)(c)

specified ancillary service means instantaneous reserve, frequency keeping or voltage support

specified pre-start adjustment event means, for a post-2019 BBI and pre-existing customer, a pre-start adjustment event for the post-2019 BBI that would have been a benefit-based charge adjustment event in any of paragraphs 81(1)(d) to 81(1)(h) in respect of the pre-existing customer

stand-alone cost prudent discount means a discount of a customer’s transmission charges provided under this transmission pricing methodology for the purpose in clause 133

standard method means the price-quantity method or resiliency method

standard method calculation period means, for a BBI, the period—

(a) starting on the first 1 January after the BBI’s expected effective full commissioning date; and
(b) ending on the earlier of—
- (i) 20 years after that 1 January; and
- (ii) the end of the useful life of the BBI, as determined by Transpower

standard method rate means, for a BBI—

(a) if the BBI is a tested investment, the pre-tax, real discount rate used when the BBI was assessed under the investment test, excluding discount rates used only for sensitivity analysis; or
(b) otherwise—
- (i) the applicable rate published in the assumptions book; or
- (ii) if there is no applicable rate published in the assumptions book, the rate in clause D6(3)(a) of the Transpower Capex IM

start pricing year means—

(a) for a connection investment, the first pricing year that starts after the end of the financial year during which the connection investment was commissioned; or
(b) for a BBI, the first pricing year that starts after the end of the financial year during which the BBI was commissioned (which, for an Appendix A BBI, is the first pricing year); or
(c) for a SSCGU, the first pricing year that starts at least 6 months (or such shorter period as Transpower may determine is practicable) after the date of the SSCGU; or
(d) for a reassignment, the first pricing year that starts at least 6 months (or such shorter period as Transpower may determine is practicable) after the reassignment confirmation date; or
(e) for an inefficient bypass prudent discount and subject to paragraph 122(2), the first pricing year that starts—
- (i) at least 6 months (or such shorter period as Transpower may determine is practicable) after the prudent discount confirmation date; and
- (ii) on or after a date determined by Transpower based on the time that would be required for the prudent discount recipient to implement the relevant alternative project if the project to implement the alternative project had started on the date Transpower received the application for the inefficient bypass prudent discount; or
(f) for a stand-alone cost prudent discount and subject to paragraph 122(2), the first pricing year that starts at least 6 months (or such shorter period as Transpower may determine is practicable) after the prudent discount confirmation date

station means a substation or switching station

substantial sustained increase means, for large plant, an increase in the large plant’s expected annual electricity consumption or generation (as the case may be)—

(a) of at least 25% since the last time the relevant customer’s BBI customer allocations for 1 or more BBIs were calculated, as assessed under subclause 81(4); and
(b) that is not attributable to a large upgrade of the large plant; and
(c) that Transpower determines is reasonably likely to persist for at least 5 years after the start of the relevant event pricing year

substantial sustained change in grid use or SSCGU means an event or series of directly related events that result in a change in expected total annual injection or offtake—

(a) of at least 5% of average total annual injection or offtake (as the case may be) over CMP F; and
(b) that Transpower determines is reasonably likely to persist for at least 5 years after the event or series of directly related events occurred

supplying load customer means, for a connection location and trading period, a generator who—

(a) owns or controls generating plant connected to the grid at the connection location; and
(b) has embedded electricity at the connection location of the type defined in paragraph 4(1)(d) for the trading period

system limit means a level of supply, demand or electricity flow at which the power system would not remain in a satisfactory state during and following an outage scenario, potentially requiring involuntary post-contingency generation or demand reduction

system limit model means a simplified model of the grid that—

(a) models a reliability BBI’s factual, counterfactual, system limits and market scenarios; and
(b) applies the reliability BBI’s outage scenarios to the factual, counterfactual, system limits and market scenarios to model the change in curtailed energy between the reliability BBI’s factual and counterfactual

TA opex means operating costs for transmission alternatives

tested investment means a connection investment or interconnection investment that—

(a) was approved by the Electricity Commission under section III of Part F of the rules; or
(b) was individually approved by the Commission as a major capex project or listed project under the Transpower Capex IM; or
(c) is a base capex project to which Transpower was required to apply a cost-benefit analysis under the Transpower Capex IM

total gross energy has the meaning in subclause 4(7)

transmission charges means the charges specified in clause 2

transmission investment means an investment by Transpower in the grid or a transmission alternative, including such an investment for which another person contributes to the capital, maintenance, operating or other cost under an investment agreement

transmission services means the following services provided by a grid owner:

(a) electricity lines services, as defined in section 54C of the Commerce Act 1986, but excluding system operator services:
(b) the provision of transmission alternatives

Transpower Capex IM means the Transpower Capital Expenditure Input Methodology Determination 2012 [2012] NZCC 2

Transpower IMs means the Commerce Act (Transpower Input Methodologies) Determination 2010 [2012] NZCC 17

Transpower IPP means the Transpower Individual Price-Quality Path Determination 2020 [2019] NZCC 19

Transpower operations facility means a facility that is used by Transpower only to operate the grid and is not a station

upgrade means, for an asset or plant, to alter the asset or plant physically so that the asset’s or plant’s capacity is permanently increased

unserved energy (measured in kWh or MWh) means an amount by which offtake at 1 or more GXPs is curtailed

unsupplied energy (measured in kWh or MWh) means an amount by which injection at 1 or more GIPs is curtailed

value of commissioned asset has the meaning in the Transpower IMs

value of lost load or VOLL means, for a reliability BBI—

(a) if the reliability BBI is a tested investment, the value of unserved energy used when the reliability BBI was assessed under the investment test, excluding values of unserved energy used only for sensitivity analysis; or
(b) otherwise—
- (i) the applicable value of unserved energy published in the assumptions book; or
- (ii) if there is no applicable value of unserved energy published in the assumptions book, the value of unserved energy referred to in subclause 4(1) of Schedule 12.2 of this Code

WACC means weighted average cost of capital

wholesale market model means a simplified model of prices and quantities in the wholesale market for electricity (and only in that wholesale market) that—

(a) models a market BBI’s factual, counterfactual and market scenarios; and
(b) assumes suppliers offer prices based on their marginal variable costs of supply; and
(c) assumes perfectly inelastic demand up to 1 or more estimated costs of self-supply that are the same for all demand types; and
(d) applies least-cost dispatch to the market BBI’s factual, counterfactual and market scenarios, under the assumptions in paragraphs (b) and (c) to model the change in prices and quantities in the wholesale market for electricity between the market BBI’s factual and counterfactual

write-down means a reduction in an asset’s RAB value or value of commissioned asset exclusively due to damage to, or destruction, stranding, decommissioning or disposal of, the asset, which may be a partial impairment or write-off

zero RNPB investment region has the meaning in subclause 83(12).

4 Load Customers, Gross Energy and Maximum Gross Demand

(1) The different types of load customer are shown in figures 1, 2, 3 and 4 below. In figures 1, 2, 3 and 4, “LN” means local network, “CP” means consuming plant, “GP” means generating plant, “NGN” means non-grid network and “POC” means a grid point of connection. This subclause (1) is subject to subclause (2):
- (a) In figure 1, a customer owning or controlling LN, CP or GP is an offtake customer to the extent of the offtake for the relevant trading period:
- (b) In figure 2, a customer owning or controlling LN or CP is a direct supplied load customer to the extent of the generated electricity net of any coincident injection through LN or CP for the relevant trading period (embedded electricity). The embedded electricity is referred to as the direct supplied load customer’s embedded electricity “at” POC and the relevant connection location for the trading period:
- (c) In figure 3, a customer owning or controlling LN, grid-connected CP or grid-connected GP is an indirect supplied load customer to the extent of the generated electricity net of any coincident injection through LN or grid-connected CP for the relevant trading period (embedded electricity). The embedded electricity is referred to as the indirect supplied load customer’s embedded electricity “at” POC and the relevant connection location for the trading period:
- (d) In figure 4, a customer owning or controlling GP is a supplying load customer to the extent of the embedded electricity for the relevant trading period. The embedded electricity is referred to as the supplying load customer’s embedded electricity “at” POC and the relevant connection location for the trading period.

Figure 1

Figure 2

Figure 3

Figure 4

(2) If—
- (a) GP in figure 2 above is battery storage, the generated electricity referred to in paragraph (1)(b) is deemed to be 0; or
- (b) embedded GP in figure 3 above is battery storage, the generated electricity referred to in paragraph (1)(c) is deemed to be 0; or
- (c) GP in figure 4 above is battery storage, the embedded electricity referred to in paragraph (1)(d) is deemed to be 0.
(3) If Transpower determines it has insufficient information to determine whether, or the extent to which, an amount of electricity was generated by battery storage, Transpower must assume none of that amount of electricity was generated by battery storage.
(4) If a configuration of consuming plant and generating plant connected to the grid is such that the customer may be treated as either a direct supplied load customer or supplying load customer, the customer’s status as a direct supplied load customer or supplying load customer must be determined by Transpower.
(5) Gross energy (measured in kWh or MWh) means, for a load customer, connection location or grid point of connection, and trading period—
- (a) the load customer’s offtake at the connection location or grid point of connection for the trading period; plus
- (b) the load customer’s embedded electricity at the connection location or grid point of connection for the trading period.
(6) Maximum gross demand (measured in kW or MW) means, for a load customer, connection location or grid point of connection, and period, the load customer’s maximum per-trading period gross energy at the connection location or grid point of connection during the period multiplied by 2.
(7) Total gross energy (measured in kWh or MWh) for a load customer and period (TGE) is calculated as follows:

where

GE_tl

is the load customer’s gross energy for trading period t at connection location 1 during the period

E_battery

is total injection from all of the load customer’s grid-connected battery storage over the period, if any.

5 Commissioning

(1) An asset is commissioned when it is first commissioned as defined in the Transpower IMs.
(2) A connection investment or interconnection investment (including a BBI) is commissioned when the first grid asset or transmission alternative comprised in it is commissioned or started (as the case may be).
(3) A connection investment or interconnection investment (including a BBI) is fully commissioned when all grid assets and transmission alternatives comprised in it are commissioned or started (as the case may be).
(4) Subject to subclauses (1) to (3), the time an asset, connection investment or interconnection investment (including a BBI) is commissioned or fully commissioned is to be determined by Transpower.

6 Connection and Disconnection

In this transmission pricing methodology, unless the context otherwise requires—
- (a) an asset becomes connected to a network at a point of connection at the time the point of connection is commissioned; and
- (b) an asset becomes disconnected from a network at a point of connection at the time the point of connection is decommissioned; and
- (c) subject to paragraphs (a) and (b), the time an asset becomes connected to or disconnected from a network or plant is to be determined by Transpower; and
- (d) plant is grid-connected only if it is directly connected to the grid; and
- (e) embedded plant is connected to a local network or grid-connected plant if the embedded plant is—
  - (i) directly connected to the local network or grid-connected plant; or
  - (ii) indirectly connected to the local network or grid-connected plant through other plant or a non-grid network.

7 Large Plant

Where Transpower is required under this transmission pricing methodology to assess whether plant, or an upgrade or de-rating of plant, is large, Transpower may make that assessment by combining 2 or more units of plant that are—
- (a) of the same type (consuming plant or generating plant); and
- (b) owned by the same person or related parties,
if Transpower determines it is reasonable in all the circumstances to do so.

8 Interpretation

In this transmission pricing methodology, unless the context otherwise requires—
illustrated by the figure, table or associated commentary, the provisions being illustrated take precedence; and
- (a) all defined terms are shown in bold text; and
- (b) a term in bold text not defined in this transmission pricing methodology has the meaning given to it in Part 1 of this Code; and
- (c) any other grammatical form of a defined term has a corresponding meaning; and
- (d) if there is any inconsistency between the text description of a calculation for which there is formula and the formula, the formula takes precedence; and
- (e) if there is any inconsistency between an illustrative figure, table or associated commentary and the provisions of this transmission pricing methodology being
- (f) a reference to Transpower means Transpower in its capacity as a grid owner; and
- (g) a reference—
  - (i) to the singular includes the plural and vice versa; and
  - (ii) to a person includes an individual, company, other body corporate, association, partnership, firm, joint venture, trust or Crown entity; and
  - (iii) to a clause, subclause, paragraph, subparagraph, Part or figure is to a clause, subclause, paragraph, subparagraph or Part of, or figure in, this transmission pricing methodology; and
  - (iv) to any legislation, including this Code, the Transpower IPP, the Transpower IMs and the Transpower Capex IM, includes that legislation as amended or replaced from time to time; and
- (h) the word “including” is to be read as “including, but not limited to”, and the word “includes” is to be read as “includes, without limitation”; and
- (i) a reference to a preceding financial year is a reference to the most recent complete financial year that precedes the start of the pricing year in respect of which the relevant calculation is undertaken or assessment is made; and
- (j) a reference to a plant owner is a reference to the person who owns or controls the plant; and
- (k) a reference to a customer’s offtake, embedded electricity or injection at a connection location is a reference to the customer’s offtake, embedded electricity or injection at all grid points of connection at the connection location where the customer offtakes electricity, has embedded electricity or injects electricity (as the case may be); and
- (l) a reference to a load customer’s (including an offtake customer’s) or injection customer’s connection location:
  - (i) is a reference to all grid points of connection at the connection location where the load customer offtakes electricity or has embedded electricity or where the injection customer injects electricity (as the case may be); and
  - (ii) does not include any connection location where the load customer does not offtake electricity or have embedded electricity or where the injection customer does not inject electricity (as the case may be).

Calculation of Transmission Charges

9 Transmission Charges Calculated Separately

A customer may be both a load customer and an injection customer at a connection location (but cannot be both an offtake customer and injection customer at the connection location for the same trading period). If a customer is both a load customer and an injection customer at a connection location, the customer’s transmission charges are calculated separately for the customer as a load customer and an injection customer, except as otherwise stated in this transmission pricing methodology.

10 Calculations and Estimations

(1) Except as otherwise stated in this transmission pricing methodology—
- (a) any calculation or estimation of a value under this transmission pricing methodology (including any transmission charge) is to be carried out by Transpower; and
- (b) any input to a calculation or estimation of a value under this transmission pricing methodology is to be determined by Transpower; and
- (c) to the extent a calculation or estimation of a value under this transmission pricing methodology requires modelling, Transpower may use the modelling tools it uses in its business from time to time, which may change over time.
(2) To avoid doubt, Transpower is not required to maintain its access to a modelling tool it no longer uses in its business merely for the purpose of verifying previous calculations or estimations of values under this transmission pricing methodology that were made using the modelling tool.
(3) If this transmission pricing methodology specifies a source for an input to a calculation or estimation of a value under this transmission pricing methodology but the source is not available or the input is not included in or provided by the source, the input is to be determined by Transpower.
(4) Except as otherwise stated in this Code, Transpower may use the following information to calculate allocation data and is not required to (but may) use any other information:
- (a) metering information:
- (b) information required to be provided by the reconciliation manager to Transpower under this Code, including under clause 28(b) of Schedule 15.4 of this Code:
- (c) other reconciled quantities published or made available to Transpower:
- (d) half-hour metering information required to be provided by generators to Transpower under this Code, including under clauses 13.136, 13.137 and 13.137A of this Code:
- (e) indications and measurements required to be provided by a participant to the system operator under this Code, including under Technical Code C of Schedule 8.3 of this Code, that are published or made available to Transpower.
(5) Except as otherwise stated in this transmission pricing methodology, connection customer allocations, BBI customer allocations and any other transmission charge allocators, and adjustments to those allocators, are calculated without regard to the impact of any prudent discount or previous discount.
(6) Transpower must calculate or estimate all values under this transmission pricing methodology—
- (a) that are connection customer allocations, BBI customer allocations or other transmission charge allocators intended to sum to 1 or 100%, to at least 4 decimal places (if expressed as a decimal) or 2 decimal places (if expressed as a percentage), and Transpower is not obliged to calculate or estimate the values any more precisely than that; and
- (b) that are in units of dollars, to 2 decimal places; and
- (c) that are supply or demand, in whole kW; and
- (d) that are electricity, in whole kWh.
(7) If, after any methodology in this transmission pricing methodology is applied—
- (a) the connection customer allocations for a connection asset; or
- (b) the BBI customer allocations for a BBI; or
- (c) any other transmission charge allocators that are intended to sum to 1 or 100%,
do not sum to 1 or 100%, Transpower must adjust all of the relevant transmission charge allocators on a pro rata basis to achieve a sum of 1 or 100% or as close to 1 or 100% as practicable given the precision of the transmission charge allocators.
(8) The BBI customer allocations specified in Appendix A do not sum to 100% for every Appendix A BBI because they have been rounded to 2 decimal places. However, Transpower has calculated those BBI customer allocations to a greater number of decimal places and must use those more precise BBI customer allocations, as adjusted under this transmission pricing methodology, to calculate benefit-based charges and the benefit factors for the Appendix A BBIs. References in this transmission pricing methodology to an Appendix A allocation are to be interpreted accordingly.
(9) If an ID WACC, PQ WACC or other regulated WACC is determined by the relevant regulator on a post-tax and not pre-tax basis, and a pre-tax WACC based on the post-tax WACC is required for a calculation under this transmission pricing methodology, the pre-tax WACC (W_pre-tax) must be calculated as follows:

where

W_post-tax

is the post-tax WACC

r

is the corporate tax rate, as defined in the Transpower IMs, at the relevant time.

(10) Subclause (9) also applies to calculating a post-tax WACC from a regulated pre-tax WACC, with a corresponding change to the formula.

11 Determinations

(1) Matters under this transmission pricing methodology determined by Transpower are determined in Transpower’s sole discretion while acting—
- (a) reasonably; and
- (b) subject to subclause (2), in accordance with GAAP; and
- (c) subject to subclause (3), with reference to—
  - (i) information made available to Transpower by or on behalf of participants and other persons with an interest in the determination; and
  - (ii) Transpower’s and (where published) other persons’ financial and regulatory records, registers and disclosures, including the RAB; and
  - (iii) other information relevant to the determination Transpower is reasonably able to obtain.
(2) If there is any inconsistency between the requirements of GAAP and the requirements of this transmission pricing methodology, this transmission pricing methodology takes precedence.
(3) Transpower is not required to give equal weight to the information referred to in paragraph (1)(c).

12 Reverse Flow

(1) This clause 12 applies if all of the following conditions are satisfied:
- (a) a customer has an agreement with the system operator under clause 6 of Technical Code A of Schedule 8.3 of this Code:
- (b) the customer has notified Transpower in writing that there is reverse flow at a connection location as a result of a GXP tie authorised under the agreement referred to in paragraph (a):
- (c) the customer notified Transpower under paragraph 0 within 20 business days of the reverse flow starting:
- (d) Transpower is reasonably satisfied there is reverse flow at the connection location as a result of a GXP tie authorised under the agreement referred to in paragraph (a).
(2) Subject to subclause (3), Transpower must, despite anything else in this transmission pricing methodology—
- (a) adjust the customer’s allocation data for the connection location to mitigate or eliminate the impact of the reverse flow, as determined by Transpower; and
- (b) use the adjusted allocation data to calculate future transmission charges.
(3) Subclause (2) does not apply to any allocation data used to calculate regional NPB for a regional customer group under the simple method.
(4) Transpower must publish the details of any adjustment it makes under subclause (2) within 20 business days of making the adjustment.

13 Exceptional Operating Circumstances

(1) Subject to subclause (2), if Transpower determines—
- (a) a Transpower requirement, system operator requirement, or planned or unplanned outage has caused exceptional operating circumstances in the power system; and
- (b) those circumstances have resulted in a customer’s allocation data not reflecting normal operating circumstances in the power system (a distortion),
Transpower may, despite anything else in this transmission pricing methodology—
- (c) adjust the allocation data to mitigate or eliminate the distortion, as determined by Transpower; and
- (d) use the adjusted allocation data to calculate future transmission charges.
(2) Subclause (1) does not apply to any allocation data used to calculate regional NPB for a regional customer group under the simple method.
(3) Transpower must publish the details of any adjustment it makes under subclause (1) within 20 business days of making the adjustment.

General

14 Applications, Application Fees and Application Requirements

(1) Transpower—
- (a) is not obliged to start assessing an application; and
- (b) may suspend its assessment of, or reject, an application,
- if—
- (c) the application fee, if any, for the application has not been paid; or
- (d) the application does not comply with the relevant application requirements; or
- (e) the applicant otherwise does not comply, or has not complied, with this transmission pricing methodology in relation to the application.
(2) Subject to subclause (1), Transpower must—
- (a) prioritise assessment of applications in the order they are received by Transpower; and
- (b) complete its assessment of an application within a reasonable time of receiving it, having regard to the complexity of the application and the quality of the information provided by the applicant in support of it.
(3) Any application fee must be reasonable having regard to Transpower’s expected costs of assessing applications of the relevant type, and may be—
- (a) fixed or based on actual costs; and
- (b) capped or uncapped; and
- (c) up-front or staged; and
- (d) refundable or non-refundable.
(4) Application requirements must be reasonable having regard to the matters relevant to Transpower’s assessment of applications of the relevant type.

15 Consultation on Transmission Charges

(1) Transpower must consult on the following matters with at least the following groups before the relevant transmission charges or adjustments to them are finalised:

subject matter	minimum group to be consulted
Proposed annual connection charges	Customers who will pay the connection charges
Proposed material adjustment to connection charges during a pricing year	Customers who will pay the adjusted connection charges
Proposed starting BBI customer allocations for a post-2019 BBI expected to be high-value when fully commissioned	Public consultation
Proposed adjustment to the BBI customer allocations for a post-2019 BBI due to a SSCGU	Public consultation
Other proposed material adjustment to the BBI customer allocations for a post-2019 BBI expected to be high-value immediately before the adjustment	Customers who are or will be beneficiaries of the post-2019 BBI
Proposed allocation of residual charges for a pricing year	All load customers
Proposed material adjustment to the allocation of residual charges during a pricing year	All load customers

(2) Transpower must consult publicly on the proposed modelled regions and regional NPBs under the simple method, and proposed simple method factors, for—
- (a) the first simple method period, before the start of the first pricing year; and
- (b) each subsequent simple method period, before the start of the simple method period.
(3) Consultation—
- (a) under subclause (1) on the proposed starting BBI customer allocations for a high-value post-2019 BBI or a proposed material adjustment to the BBI customer allocations for a high-value post-2019 BBI; and
- (b) under subclause (2)
must include information about any material departures from the assumptions and methodologies published in the assumptions book and the reasons for those departures.
(4) Consultation under subclause (1) on—
- (a) the proposed starting BBI customer allocations for a high-value post-2019 BBI; or
- (b) a proposed material adjustment to the BBI customer allocations for a high-value post-2019 BBI, including due to a SSCGU,
must include an estimate of the high-value post-2019 BBI’s covered cost when fully commissioned.
(5) Consultation under subclause (1) or (2) may occur as part of Transpower or Commission consultation required under the Transpower Capex IM, other parts of this Code, or transmission agreements, either before or after the start of the first pricing year.

16 Information about Transmission Charges

(1) Transpower must provide each customer with reasonable information that is sufficient for the customer to understand the basis on which the customer’s annual charges and monthly charges have been calculated. For a load customer, this information must include, for the relevant pricing year—
- (a) the amount of otherwise unallocated operating costs included in residual revenue; and
- (b) reassignment amounts included in residual revenue.
(2) The information referred to in subclause (1) may be provided to a customer as part of Transpower’s obligation under a transmission agreement to notify the customer of annual charges, monthly charges and changes to them, either before or after the start of the first pricing year.

Part B Grid Asset Classification

17 Grid Assets and Land and Buildings

(1) Subject to subclause (3), grid assets are assets and other works (including land, easements, leases and other interests in land, buildings, containment facilities and other structures, but excluding Transpower’s fibre optic network) that—
- (a) comprise or support the grid; and
- (b) are—
  - (i) owned by or leased to Transpower, provided that if the assets or other works are leased by Transpower to another person then the assets or other works will only be grid assets if Transpower has expressly agreed in writing with that person that the assets or other works are to be treated as grid assets for the purposes of this transmission pricing methodology; or
  - (ii) owned by another person and not leased to Transpower, but only if Transpower has expressly agreed in writing with that person that the assets or other works are to be treated as grid assets for the purposes of this transmission pricing methodology.
(2) Transpower’s provision of, or agreement to provide, grid assets that facilitate the connection of other assets to the grid does not constitute Transpower’s agreement to treat the other assets as grid assets for the purposes of subparagraph (1)(b)(ii).
(3) An asset that was, immediately before the start of the first pricing year—
- (a) treated as a grid asset under the previous transmission pricing methodology; and
- (b) not owned by or leased to Transpower,
will not cease to be a grid asset merely because neither subparagraph (1)(b)(i) nor subparagraph (1)(b)(ii) applies to the asset.
(4) Land and buildings are grid assets that are land, easements, leases or other interests in land, buildings, oil containment facilities, or other structures that are not comprised in the grid.
(5) Land and buildings that support a part of the grid are referred to as being “part of” that part of the grid, together with the grid assets that comprise that part of the grid.

18 Partial Funding of Grid Assets

Subject to other legal requirements and GAAP, a grid asset the capital cost of which is partially funded under an investment agreement—
- (a) may be represented in Transpower’s financial and regulatory records, registers and disclosures, including the RAB, as multiple grid assets; and
- (b) those grid assets may be treated as separate grid assets for the purposes of calculating transmission charges,
as necessary or convenient to ensure Transpower does not under-recover the total cost of the grid asset through this transmission pricing methodology and the investment agreement. To avoid doubt, Transpower must not use its discretion under this clause to over-recover the total cost of a grid asset.

19 Nodes and Links

(1) A node is any of the following:
- (a) a connection location:
- (b) a station that is not a connection location:
- (c) a location in the grid where a circuit diverges or terminates (such as a “tee” point, or a deviation of a circuit within a line to connect to a station where the line does not terminate).
(2) For the purposes of paragraph (1)(c)—
- (a) a circuit does not “diverge” at a location merely because it changes direction at the location, or transitions from overhead to underground or vice versa at the location; and
- (b) adjacent towers, poles or other structures at which a circuit diverges may be treated as a single location.
(3) Subject to subclause (8), a link is either a single circuit or multiple parallel circuits (of the same voltage) that are grid assets and connect 2 nodes (and includes any grid assets, such as circuit breakers, that are required to connect the link at either node).
(4) To avoid doubt—
- (a) a Transpower operations facility is not a node; and
- (b) a circuit or multiple parallel circuits that are grid assets and connect—
  - (i) a node; and
  - (ii) a Transpower operations facility that is not connected to any other node,
- is not a link.
(5) Figures 5 and 6 below illustrate how nodes and links are identified under subclauses (1) to (4):
- (a) Figure 5 shows a physical grid configuration. CL1, CL2 and CL3 are connection locations. TOF is a Transpower operations facility. T1, T2, T3 and T4 are towers. The lines are circuits between the connection locations or Transpower operations facility and the towers. All of the circuits are grid assets except the circuit between CL2 and CL3:
- (b) Figure 6 shows the same grid configuration as figure 5 but in the form of nodes and links. Nodes N2, N4 and N5 correspond to connection locations CL1, CL2 and CL3 respectively. Node N1 corresponds to the divergence at tower T1. Node N3 corresponds to the divergence at towers T2 and T3, which are adjacent and treated as a single location. There is no node corresponding to tower T4 because the change of direction of the circuits at T4 is insufficient to constitute a divergence. There is no node corresponding to Transpower operations facility TOF because a Transpower operations facility is not a node. There is no link between N4 and N5 because the circuit between CL2 and CL3 is not a grid asset. There is no link between T3 and TOF because TOF is not a node.

Figure 5

Figure 6

(6) Subclauses (1) to (3) must be applied to identify nodes and links contemporaneously and not prospectively or retrospectively. If a grid asset is expected to change from being a node or link to not being a node or link, or vice versa, once a future event occurs (such as the commissioning or decommissioning of it or another asset), that does not affect the node or link status of the grid asset before the event occurs.
(7) Subject to subclause (8), if a grid asset was a node or link before this transmission pricing methodology came into effect or before an event occurred, that does not prevent the grid asset ceasing to be a node or link when this transmission pricing methodology came into effect or when the event occurred, or vice versa.
(8) A circuit or circuits that are not grid assets but, immediately before this transmission pricing methodology came into effect, comprised a “link” under the previous transmission pricing methodology—
- (a) will be treated as a link despite not being grid assets; but
- (b) will cease to be a link if the circuit or circuits otherwise cease to meet the requirements for comprising a link under this transmission pricing methodology.

20 Connection and Interconnection Nodes and Links

(1) Nodes and links are identified as connection nodes or connection links or interconnection nodes or interconnection links according to the following rules:
- (a) an interconnection node is any node connected to 2 or more nodes in a loop, other than a small regional loop:
- (b) a loop is a continuous path of nodes and links with the same start and end node:
- (c) a small regional loop is a loop between any group of nodes (excluding the nodes at the Benmore and Haywards substations) with only a single link from the loop to a node outside the loop that—
  - (i) is part of another loop; or
  - (ii) ultimately links to another loop, either directly or indirectly through other nodes:
- (d) a connection node is any node that is not an interconnection node, including all nodes in a small regional loop:
- (e) a connection link is a link with a connection node at 1 or both of its ends:
- (f) an interconnection link is a link that connects 2 interconnection nodes.
(2) Figures 7, 8 and 9 below illustrate how small regional loops, interconnection nodes and links, and connection nodes and links are identified under subclause (1):
- (a) In figures 7 and 8, nodes N2, N3 and N4 comprise a small regional loop because in each case there is only 1 link (from N4) to another loop. In figure 7, the link from N4 to the other loop is direct because interconnection node N6 is part of the other loop. In figure 8, the link from N4 to the other loop is indirect through connection node N5. In figures 7 and 8, N2, N3 and N4 are connection nodes and the links between and to them are connection links. In figure 8, the link from N5 to N6 is also a connection link:
- (b) In figure 9, nodes N2, N3 and N4 do not comprise a small regional loop because there is more than 1 link (from N3 and N4) to another loop. Even if the link from N4 to N6 did not exist, N2, N3 and N4 would still not comprise a small regional loop because there are 2 links to another loop from N3. In figure 9, N2, N3 and N4 are interconnection nodes and (apart from the link from connection node N1 to N2, which is a connection link) the links between and to them are interconnection links.

Figure 7

Figure 8

Figure 9

(3) Subject to subclause (4), subclause (1) must be applied to classify nodes and links contemporaneously and not prospectively or retrospectively. If a node or link is expected to change from a connection node or link to an interconnection node or link, or vice versa, once a future event occurs (such as the commissioning or decommissioning of it or another asset), that does not affect the classification of the node or link before the event occurs.
(4) If a group of nodes or links that are to be provided as part of the same project are commissioned in a staged manner, the connection or interconnection status of each node and link in the group must be determined prospectively based on all nodes and links in the group being commissioned. However—
- (a) if all the nodes and links have not been commissioned by the start of the pricing year that is at least 9 months after the first node or link is commissioned—
  - (i) subclause (3) will apply from the start of that pricing year and not this subclause (4) (so that the nodes and links will be classified contemporaneously from the start of that pricing year); and
  - (ii) once all the nodes and links are commissioned, subclause (3) will apply from the start of the first pricing year that starts after the last node or link is commissioned (so that the nodes and links will be classified contemporaneously from the start of that pricing year); and
- (b) this subclause (4) must not be applied to classify an interconnection node or interconnection link as a connection node or connection link.
(5) If a node or link was classified as a connection node or link before this transmission pricing methodology came into effect or before an event occurred, that does not prevent the node or link being re-classified as an interconnection node or link when this transmission pricing methodology came into effect or when the event occurred, or vice versa.

21 Connection and Interconnection Assets

(1) A connection asset is any of the following that is not an HVDC asset:
- (a) a grid asset at a connection node, other than voltage support equipment that is not an investment agreement asset:
- (b) at an interconnection node that is a connection location—
  - (i) any grid asset that is used to connect a customer’s assets to the grid. This may include:
    - (A) a supply transformer, feeder bay, or supply transformer high voltage or low voltage breaker:
    - (B) a low voltage breaker, low voltage bus section breaker, voltage transformer, revenue meter, or other equipment that is on the same bus as a feeder; and
  - (ii) a proportion of the land and buildings at the connection location (LB_conn) calculated as follows:

where

RC_conn total

is the total replacement cost of all grid assets described in subparagraph (i) at the connection location at the end of the preceding financial year

RC_total

is the total replacement cost of all grid assets (excluding land and buildings) at the connection location at the end of the preceding financial year:

- (c) a grid asset that is part of a connection link. If a line is included in a connection link and 1 or more other links, the part of the line ascribed to the connection link must be determined according to the length of the line included in the connection link relative to the total length of the line.
(2) An interconnection asset is any grid asset that is not a connection asset, and includes any HVDC asset.

22 Associating Connection Assets with Connection Locations and Customers

(1) A connection asset that—
- (a) is at a connection location; or
- (b) if the connection location is a connection node, connects the connection location (directly or indirectly) to an interconnection node,
- is referred to as a connection asset “for” the connection location, “that connects” (or other grammatical form of that phrase) the customers at the connection location and that those customers are “connected to” (or other grammatical form of that phrase).
(2) A customer who owns or controls assets connected at a connection location is referred to as a customer “at” the connection location.
(3) Subject to subclause (4), a connection asset for a connection location is referred to as “shared” between the customers at the connection location.
(5) Figure 10 below is the node and link configuration in figure 7 above and illustrates how connection assets are associated with connection locations and customers under subclauses (1) to (3):
- (a) N1, N3, N4 and N6 are connection locations at which customers A, B, C, D and E are connected. The smaller circles within N1, N3, N4 and N6 are connection assets at those connection locations that connect the specific customers shown only:
- (b) The following table shows which connection assets are “for” the connection locations at N1, N3, N4 and N6. The links with an asterisk are “deep” connection assets for the relevant connection location because they are not located at, and do not directly connect to, the connection location:

connection assets	N1	N3	N4	N6
at connection location	Y	Y	Y	Y
in link N1-N2	Y	N	N	N
in link N2-N3	Y*	Y	N	N
in link N3-N4	Y*	Y	N	N
in link N2-N4	Y*	Y*	N	N
in link N4-N6	Y*	Y*	Y	N

- (c) The following table shows how the connection assets at and between N1, N2, N3, N4 and N6 are “shared” between customers A, B, C, D and E:

connection assets	sharing
at N1	shared between A and B, apart from A- or B-specific connection assets
at N2	shared between A, B and C
at N3	shared between A, B and C, apart from C-specific connection assets
at N4	shared between A, B, C and D, apart from D-specific connection assets
at N6	shared between A, B, C, D and E, apart from E-specific connection assets
in link N1-N2	shared between A and B
in link N2-N3	shared between A, B and C
in link N3-N4	shared between A, B and C
in link N2-N4	shared between A, B and C
in link N4-N6	shared between A, B, C and D

Figure 10

23 Discretion to Classify and Reclassify as Connection Asset

(1) Despite anything else in this transmission pricing methodology, Transpower may classify or (subject to subclause (2)) reclassify any grid asset that would otherwise be an interconnection asset as a connection asset if Transpower determines—
- (a) the grid asset provides or will provide transmission services to 1 or more customers of a type and nature typically provided by connection assets; and
- (b) the grid asset does not provide or will not provide any material transmission services of a type and nature typically provided by interconnection assets; and
- (c) it is reasonable in all the circumstances to classify or reclassify the grid asset as a connection asset.
(2) Transpower must not reclassify a grid asset as a connection asset under subclause (1) retrospectively.
(3) Transpower must—
- (a) before classifying or reclassifying a grid asset as a connection asset under subclause (1), consult with all customers who will be connected to the grid asset. This consultation may occur either before or after the start of the first pricing year; and
- (b) notify those customers of Transpower’s decision whether or not to classify or reclassify the grid asset as a connection asset under subclause (1).
(4) A customer referred to in subclause (3) may, within 20 days of Transpower notifying the customer of Transpower’s decision, refer Transpower’s decision under subclause (1) to an independent expert for review.
(5) The independent expert’s decision will be binding on Transpower and the customer, and will have effect as if Transpower had made the decision itself, except that the customer may not refer the decision to an independent expert again.
(6) The costs of the independent expert must be met by the customer unless the independent expert decides Transpower’s decision was unreasonable, in which case Transpower may be required to meet all or some of the costs of the independent expert, as determined by the independent expert.

Part C Connection Charges

24 Calculation of Connection Charges

(1) Only customers connected to connection assets pay connection charges.
(2) A customer’s annual connection charge for a connection asset, connection location and pricing year (CC) is calculated as follows:

CC = ((A + FA + M + O) × CA) − RBT

where

A

is the asset component for the connection asset and pricing year calculated under clause 26

FA

is the customer’s funded asset component for the connection asset and pricing year calculated under clause 28

M

is the maintenance component for the connection asset and pricing year calculated under clause 30

O

is the operating component for the connection asset and pricing year calculated under clause 31

CA

is the customer’s connection customer allocation for the connection asset, connection location and pricing year

RBT

is the customer’s funded asset rebate for the connection asset, connection location and pricing year calculated under clause 29.

(3) A customer’s annual connection charge for a connection location and pricing year (ACC) is calculated as follows:

where

CC_a

is the customer’s annual connection charge for connection asset a for the connection location and pricing year.

(4) A customer’s annual connection charge for a connection transmission alternative and pricing year (TACC) is calculated as follows:

where

TAC

is the TA opex for the connection transmission alternative and preceding financial year, less any contribution to the TA opex under investment agreements

ACC_l

is the customer’s annual connection charge for connection location 1 and the previous pricing year, where connection location l is a connection location that would be connected by a connection asset for which the connection transmission alternative is an alternative

ACC_l total

is the total of all customers’ annual connection charges for connection location 1 and the previous pricing year.

(5) A customer’s monthly connection charge for a pricing year (MCC) is calculated—
- (a) for a connection location, as follows:

where

ACC

is the customer’s annual connection charge for the connection location and pricing year; and

(b) for a connection transmission alternative, as follows:

where

TACC

is the customer’s annual connection charge for the connection transmission alternative and pricing year.

(6) Connection charges are calculated for each pricing year before the start of the pricing year.
(7) A connection charge may be adjusted, including during a pricing year, under clauses 76 to 80 if there is a connection charge adjustment event.

25 Start of Connection Charges

Except as otherwise required under any relevant transmission agreement, Transpower must start the connection charges for a connection investment from the connection investment’s start pricing year. To avoid doubt, this clause does not apply to charges under an investment agreement.

Clause 25: amended, on 31 July 2023, by clause 6 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

26 Asset Component

(1) Subject to subclause (2), Transpower may designate a connection asset, or an actual or notional part of a connection asset, as anticipatory for a pricing year if—
- (a) the connection asset or part of the connection asset was commissioned at or after the start of the first pricing year; and
- (b) Transpower determines that the connection asset or part of the connection asset is not likely to be required during the pricing year by the customers connected to the connection asset.
(2) Once Transpower has designated a notional part of a connection asset as anticipatory for a pricing year under subclause (1), Transpower must not designate a greater notional part of the connection asset or the whole connection asset as anticipatory for any subsequent pricing year.
(3) A connection asset or part of a connection asset designated as anticipatory for a pricing year under subclause (1) is an anticipatory connection asset for the pricing year. If the anticipatory connection asset is part of a larger connection asset then, for the purposes of this clause 26 and clause 27, the larger connection asset is treated as two separate connection assets for the pricing year, being the anticipatory connection asset and the part of the larger connection asset that is not anticipatory for the pricing year.
(4) Whether or not a connection asset or part of a connection asset is an anticipatory connection asset for a pricing year must be determined by Transpower having regard to the extent to which—
- (a) the customers connected to the connection asset have agreed to fund the connection asset under investment agreements; and
- (b) the connection asset is likely to be required to meet the requirements of the customers connected to the connection asset and cover reasonable grid contingencies during the pricing year.
(5) Half of the capital cost of an anticipatory connection asset is recovered through the asset component of connection charges. The other half of the capital cost of the anticipatory connection asset is recovered through benefit-based charges for the relevant anticipatory BBI (see clause 27).
(6) The asset component of the connection charge for a connection asset and pricing year (A) allocates a portion of the capital cost of all connection assets to the connection asset, and is calculated as follows:

A = (ARR × RC) + (DARR × RC′)

where

ARR

is the connection asset return rate for the pricing year calculated under subclause (7)

RC

is—

(a) 0 if the connection asset is an investment agreement asset or anticipatory connection asset; or
(b) otherwise, the replacement cost of the connection asset at the end of the preceding financial year

DARR

is the discounted connection asset return rate for the pricing year calculated under subclause (8)

RC′

is—

(a) 0 if the connection asset is an anticipatory connection asset; or
(b) otherwise, the replacement cost of the connection asset at the end of the preceding financial year (even if the connection asset is an investment agreement asset).

(7) The connection asset return rate for a pricing year (ARR) is calculated as follows:

where

r

is Transpower’s PQ WACC (pre-tax) for the pricing year

V_total

is the total closing RAB value of all connection assets for the preceding financial year

V_{total anticipatory}

is the part of V_total attributable to anticipatory connection assets, as determined by Transpower

D_total

is total depreciation of all connection assets other than investment agreement assets during the preceding financial year, excluding accelerated depreciation

D_{total anticipatory}

is the part of D_total attributable to anticipatory connection assets, as determined by Transpower

RC_total

is the total replacement cost of all connection assets other than investment agreement assets and anticipatory connection assets at the end of the preceding financial year.

(8) The discounted connection asset return rate for a pricing year (DARR) is calculated as follows:

where

r

is Transpower’s PQ WACC (pre-tax) for the pricing year

V_{total anticipatory}

is the part of the total closing RAB value of all connection assets for the preceding financial year attributable to anticipatory connection assets, as determined by Transpower

D_{total anticipatory}

is the part of total depreciation of all connection assets other than investment agreement assets during the preceding financial year, excluding accelerated depreciation, attributable to anticipatory connection assets, as determined by Transpower

RC′_total

is the total replacement cost of all connection assets (including connection assets that are investment agreement assets) other than anticipatory connection assets at the end of the preceding financial year.

Clause 26(4)(a) and (b): amended, on 31 July 2023, by clause 7 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

27 Anticipatory BBIs

(1) The benefit-based charges for anticipatory BBIs recover the part of the capital cost of anticipatory connection assets that is not recovered through the asset component of connection charges, specifically half of that capital cost.
(2) For each anticipatory connection asset for a pricing year there is deemed to be a commissioned BBI (an anticipatory BBI) for the pricing year (only for the purpose of recovering half of the capital cost of the anticipatory connection asset)—
- (a) that comprises the anticipatory connection asset; and
- (b) that has a covered cost for the pricing year (CVC) calculated as follows:

CVC = ((r × V_anticipatory) + D_anticipatory) × 0.5

where

r

is Transpower’s PQ WACC (pre-tax) for the pricing year

V_anticipatory

is the part of the total closing RAB value for the preceding financial year attributable to the anticipatory connection asset, as determined by Transpower

D_anticipatory

is the part of total depreciation during the preceding financial year, excluding accelerated depreciation, attributable to the anticipatory connection asset, as determined by Transpower; and

- (c) for which the start pricing year is the pricing year; and
- (d) for which a customer’s individual NPB is calculated under the simple method, subject to the modifications in subclause (3) and even if the anticipatory BBI’s deemed covered cost for the pricing year under paragraph (b) is more than the base capex threshold as defined in the Transpower Capex IM.
(3) The modifications referred to in paragraph 2(d) are as follows:
- (a) If Transpower determines the anticipatory BBI is primarily to allow for a future increase in offtake, the anticipatory BBI’s regional customer groups are limited to regional supply groups:
- (b) If Transpower determines the anticipatory BBI is primarily to allow for a future increase in injection, the anticipatory BBI’s regional customer groups are limited to regional demand groups.

28 Funded Asset Component

(1) The funded asset component of the connection charge ensures that non-contributing customers pay part of the capital cost of funded assets through their connection charges.
(2) A customer’s funded asset component for a connection asset is 0 unless—
- (a) the connection asset is a funded asset; and
- (b) the customer is, but for the funded asset component, a non-contributing customer for the funded asset; and
- (c) there is, in respect of the customer, at least one prior contributing customer who has a non-zero connection customer allocation for the funded asset.

Clause 28(2)(b) amended, on 17 June 2024, by clause 6(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

Clause 28(2)(c) inserted, on 17 June 2024, by clause 6(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

(3) Subject to subclauses (4) and (5), a non-contributing customer’s funded asset component for a funded asset and pricing year (FA) is calculated as follows:

where

TF

is the total amount paid, or expected to be paid, towards the capital cost of the funded asset under all investment agreements

EL_remain

is the remaining economic life of the funded asset at the end of the pricing year during which the non-contributing customer connected to the funded asset

EL_total

is the total economic life of the funded asset, including any part of it that has elapsed.

(4) The non-contributing customer’s funded asset component for the funded asset applies for 10 consecutive pricing years only, starting with the pricing year after the pricing year during which the non-contributing customer connected to the funded asset.
(5) If the non-contributing customer agrees with 1 or more prior contributing customers to contribute towards the capital cost of a funded asset—
- (a) subclause (3) applies to the funded asset subject to that agreement; and
- (b) the agreement is deemed to be an investment agreement for the funded asset (even if Transpower is not a party to it).

29 Funded Asset Rebate

(1) A non-contributing customer’s funded asset component for a funded asset and pricing year is rebated to each prior contributing customer for the funded asset in respect of the non-contributing customer.
(2) A customer’s funded asset rebate for a connection asset and pricing year is 0 unless—
- (a) the connection asset is a funded asset; and
- (b) a non-contributing customer pays a funded asset component for the funded asset and pricing year; and
- (c) the customer is a prior contributing customer for the funded asset in respect of the non-contributing customer.
(3) Subject to subclause (4), prior contributing customer c’s funded asset rebate of non-contributing customer i’s funded asset component for a connection location and pricing year (RBT_c) is calculated as follows:

where

FA_i

is non-contributing customer i’s funded asset component for the funded asset and pricing year

CA_i

is non-contributing customer i’s connection customer allocation for the funded asset, connection location and pricing year

CA_c

is prior contributing customer c’s connection customer allocation for the funded asset, connection location and pricing year

CA_prior total

is the total of all prior contributing customers’ (including prior contributing customer c’s) connection customer allocations for the funded asset, connection location and pricing year.

(4) Subclause (3) applies subject to any agreement of the type referred to in subclause 28(5).

30 Maintenance Component

(1) The maintenance component of the connection charge for a connection asset and pricing year (M) allocates to the connection asset a portion of Transpower’s total maintenance costs for all connection assets, and is calculated as follows:

M = MC × (1 − ICR_maint)

where

MC

is the maintenance cost component for the connection asset and pricing year calculated under subclause (2)

ICR_maint

is the percentage of the maintenance cost for the connection asset and pricing year expected to be recovered by Transpower under investment agreements, expressed as a decimal and no more than 1.

(2) The maintenance cost component for the connection asset and pricing year (MC) is—
- (a) if the connection asset is located at a station, the station maintenance cost component for the pricing year calculated under subclause (3); or
- (b) if the connection asset is a line, the line maintenance cost component for the pricing year calculated under subclause (5).
(3) The station maintenance cost component for the connection asset and pricing year (MC_station) is calculated as follows:

MC_station = MRR_station × RC

where

MRR_station

is the station maintenance recovery rate for the pricing year calculated under subclause (4)

RC

is the replacement cost of the connection asset at the end of the preceding financial year.

(4) The station maintenance recovery rate for a pricing year (MRR_station) is calculated as follows:

where

AMC_{station total}

is the average over the preceding 4 financial years of Transpower’s maintenance costs for all connection assets located at stations

RC_{station total}

is the total replacement cost of all connection assets located at stations at the end of the preceding financial year.

(5) The line maintenance cost component is calculated using a line maintenance recovery rate that depends on the line type. The different line types (all AC) used are—
- (a) 220kV or higher voltage tower lines; and
- (b) other tower lines; and
- (c) pole lines; and
- (d) underground cable lines.
(6) The line maintenance cost component for the connection asset and pricing year (MC_line) is calculated as follows:

MC_line = MRR_line t × L

where

MRR_line t

is the line maintenance recovery rate for the connection asset’s line type t and the pricing year calculated under subclause (7)

L

is the line length (in km) of the connection asset at the end of the preceding financial year.

(7) Subject to subclause (8), the line maintenance recovery rate for lines of type t and a pricing year (MRR_{line t}) is calculated as follows:

where

AMC_{line t total}

is the average over the preceding 4 financial years of Transpower’s maintenance costs for all connection assets that are lines of type t

L_t total

is the total line length (in km) of all connection assets that are lines of type t at the end of the preceding financial year.

(8) Transpower may estimate the line maintenance recovery rate for underground cable lines if Transpower determines it has insufficient data to carry out the calculation in subclause (7) for underground cable lines.

31 Operating Component

(1) The operating component of the connection charge for a connection asset and pricing year (O) allocates to the connection asset a portion of Transpower's total operating costs for all AC assets, and is calculated as follows:

O = OC × (1 - ICR_op)

where

OC

is the operating cost component for the connection asset and pricing year calculated under subclause (2)

ICR_op

is the percentage of the operating cost for the connection asset and pricing year expected to be recovered by Transpower under investment agreements, expressed as a decimal and no more than 1.

(2) The operating cost component for the connection asset and pricing year (OC) is calculated as follows:

OC = ORR × (S - (0.1 × S_cust))

where

ORR

is the operating recovery rate for the pricing year calculated under subclause (3)

S

is the number of switches that are part of the connection asset at the end of the preceding financial year

S_cust

is the number of switches that are part of the connection asset and operated by a customer at the end of the preceding financial year.

(3) The operating recovery rate for the pricing year (ORR) is calculated as follows:

where

OC_{switch total}

is Transpower’s total operating costs for all AC switches over the preceding financial year

S_total

is the total number of AC switches at the end of the preceding financial year

S_{cust total}

is the total number of AC switches that are operated by a customer at the end of the preceding financial year.

32 Connection Customer Allocations

(1) Subject to subclause (5) and clause 33, a customer’s connection customer allocation for a connection asset, connection location and pricing year (CA₁) is calculated as follows if the connection asset is—
- (a) for 1 connection location only; and
- (b) not a mixed connection asset:

where

AMDIC

is the total of the customer’s AMDC and AMIC at the connection location for the pricing year

AMDIC_total

is the total of all customers’ AMDCs and AMICs at the connection location for the pricing year.

(2) Subject to subclause (5) and clause 33, a customer’s connection customer allocation for a connection asset, connection location and pricing year (CA₂₊) is calculated as follows if the connection asset is—
- (a) for 2 or more connection locations, being the set of connection locations L; and
- (b) not a mixed connection asset:

where

AMDIC

is the total of the customer’s AMDC and AMIC at the connection location for the pricing year

AMDIC_L total

is the total of all customers’ AMDCs and AMICs at all connection locations in the set of connection locations L for the pricing year.

(3) Subject to subclauses (4) and (5) and clause 33, a customer’s connection customer allocation for a connection asset, connection location and pricing year (CA_mixed) is calculated as follows if the connection asset is a mixed connection asset:

where

AMDIC

is the total of the customer’s AMDC and AMIC at the connection location for the pricing year

C

is the capacity of the connection asset at the end of CMP A for the pricing year.

(4) If the sum of all customers’ connection customer allocations for a mixed connection asset and pricing year is greater than 1, Transpower must scale down all of the connection customer allocations on a pro rata basis so that they sum to 1.
(5) If a connection asset is—
- (a) an investment agreement asset provided under an investment agreement with a customer; and
- (b) for more than 1 connection location, or for 1 connection location at which there is more than 1 customer,
then the calculation of the connection customer allocations for the connection asset and connection locations is subject to any provisions in the investment agreement that alter the customer’s connection customer allocation for the connection asset and connection locations.
(6) The following table shows the connection customer allocations for the connection assets that are part of the connection links in figure 10 above (based on the AMDC and AMIC quantities shown in figure 10):

Table

33 De-rating

(1) This clause 33 applies if both of the following conditions are satisfied:
- (a) a customer (the notifying customer) has notified Transpower in writing that—
  - (i) the notifying customer’s assets at a connection location have been de-rated; or
  - (ii) embedded plant connected to the notifying customer’s assets at a connection location have been de-rated and the de-rating is large:
- (b) Transpower is reasonably satisfied the notified de-rating or large de-rating has occurred.
(2) In this clause 33, a relevant pricing year is—
- (a) the first pricing year that starts at least 6 months (or such shorter period as Transpower may determine is practicable) after the date the conditions in subclause (1) are first satisfied; and
- (b) a subsequent pricing year if the date the conditions in subclause (1) are first satisfied is within CMP A for the pricing year.
(3) Transpower must, for each relevant pricing year, calculate connection charges for the connection location by—
- (a) estimating the notifying customer’s future AMDC and AMIC for the connection location taking into account—
  - (i) the reduced capacity of the connecting customer’s assets or the embedded plant (as the case may be); and
  - (ii) any available historical information about the notifying customer’s offtake and injection at the connection location; and
- (b) capping the notifying customer’s AMDC and AMIC for the connection location and relevant pricing year at the notifying customer’s estimated future AMDC and AMIC for the connection location.

34 Replacement Costs

(1) Transpower must review, including update as appropriate, the replacement costs it uses to calculate connection charges no later than 5 years after the start of the first pricing year and, after that, at intervals of no more than 5 years.
(2) Transpower’s first review of replacement costs under subclause (1) may occur before the start of the first pricing year.
(3) Subject to subclause (4), Transpower must consult with all customers who pay connection charges on any update to replacement costs under subclause (1) before updating the replacement costs.
(4) Transpower is not required to consult on an update to replacement costs under subclause (1) if Transpower determines—
- (a) the update is technical and non-controversial; or
- (b) there is widespread support for the update among customers; or
- (c) there has been adequate prior consultation on the update so that all relevant views of customers have been considered.
(5) Before Transpower’s first review of replacement costs under subclause (1) is completed, the replacement cost of a connection asset commissioned before 1 July 2006 is calculated by multiplying the connection asset’s unadjusted replacement cost by the replacement cost adjustment factor.
(6) If Transpower does not have a replacement cost for a connection asset, Transpower must use the replacement cost available to Transpower for the closest equivalent of the connection asset, as determined by Transpower, for the purposes of calculating connection charges for the connection asset.

Part D Benefit-based Charges

General

35 Calculation of Benefit-based Charges

(1) Subject to subclauses 84(7) and 85(6) and clause 88, only beneficiaries pay benefit-based charges, and only for the BBIs of which they are beneficiaries.
(2) A beneficiary’s annual benefit-based charge for a BBI and pricing year (BBC) is calculated as follows:

𝐵𝐵𝐶 = 𝐶𝐶 × 𝐶𝐴

where

CC

is the BBI’s covered cost for the pricing year

CA

is the beneficiary’s BBI customer allocation for the BBI.

(3) A beneficiary's monthly benefit-based charge for a BBI and pricing year (MBBC) is calculated as follows:

where

BBC

is the beneficiary’s annual benefit-based charge for the BBI and pricing year.

(4) Benefit-based charges are calculated for each pricing year before the start of the pricing year.
(5) A benefit-based charge may be—
- (a) adjusted, including during a pricing year, under clauses 81 to 91 if there is a benefit-based charge adjustment event; and
- (b) adjusted under clause 96 if the relevant BBI is subject to reassignment.

36 Start of Benefit-based Charges

Transpower must start the benefit-based charges for a BBI from the BBI’s start pricing year. To avoid doubt, this clause does not apply to charges under an investment agreement.

Clause 36: replaced, on 31 July 2023, by clause 8 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

37 Expenditure on Existing BBIs

(1) Subject to subclause (4) and (5), Transpower must treat a refurbishment investment or replacement investment in respect of an existing post-2019 BBI as—
- (a) part of the existing post-2019 BBI, in which case the refurbishment investment or replacement investment will increase the covered cost of the post-2019 BBI but will not change its BBI customer allocations; or
- (b) a separate post-2019 BBI; or
- (c) part of an existing post-2019 BBI referred to in paragraph (b), in which case the refurbishment investment or replacement investment will increase the covered cost of the post-2019 BBI but will not change its BBI customer allocations.
(2) Subject to subclause (4) and (5), Transpower must treat a refurbishment investment or replacement investment commissioned after 23 July 2019 in respect of an Appendix A BBI as—
- (a) a separate post-2019 BBI; or
- (b) part of an existing post-2019 BBI referred to in paragraph (a), in which case the refurbishment investment or replacement investment will increase the covered cost of the post-2019 BBI but will not change its BBI customer allocations.
(3) Subject to subclause (5), Transpower must treat an enhancement investment commissioned after 23 July 2019 in respect of an existing BBI as a separate post-2019 BBI.
(4) Transpower must not treat a refurbishment investment or replacement investment as part of an existing post-2019 BBI under subclause (1) or (2) if Transpower determines the refurbishment investment or replacement investment is likely to have—
- (a) different beneficiaries than the existing post-2019 BBI; or
- (b) a materially different distribution of NPB than the existing post-2019 BBI.
(5) If a refurbishment investment, replacement investment or enhancement investment referred to in subclause(1), (2) or (3) is an exempt post-2019 investment—
- (a) Transpower must not treat the refurbishment investment, replacement investment or enhancement investment as, or as part of, a post-2019 BBI; and
- (b) if the refurbishment investment, replacement investment or enhancement investment is in respect of an Appendix A BBI, Transpower must treat the refurbishment investment, replacement investment or enhancement investment as part of the Appendix A BBI, in which case the refurbishment investment, replacement investment or enhancement investment will increase the covered cost of the Appendix A BBI but will not change its BBI customer allocations.

38 Assumptions Book

(1) Transpower must publish, and may from time to time publish updates to, an assumptions book.
(2) The assumptions book must not contain any assumptions or methodologies that are inconsistent with this Code.
(3) Subject to subclause (4), Transpower must consult with all customers on the assumptions book or any update to it before publishing the assumptions book or update.
(4) Transpower is not required to consult on an update to the assumptions book if Transpower determines—
- (a) the update is technical and non-controversial; or
- (b) there is widespread support for the update among customers; or
- (c) there has been adequate prior consultation on the update so that all relevant views of customers have been considered.
(5) Except as otherwise stated in this transmission pricing methodology, the assumptions book is not binding on Transpower or any independent expert.
(6) Transpower must review the content of the assumptions book and consider whether any of the content is appropriate for incorporation in this transmission pricing methodology by way of a review under clause 12.85 of this Code no later than 7 years after its date of publication and, after that, at intervals of no more than 7 years.
(7) The assumptions book may be part of the same document in which the reassignment practice manual or prudent discount practice manual is contained.

Covered Cost

39 Covered Cost

(1) A BBI’s covered cost for a pricing year (CC) is calculated as follows:

where

D_a

is depreciation of asset a for the preceding financial year, where asset a is an asset comprised in the BBI, excluding accelerated depreciation

C_a

is the capital charge for asset a and the preceding financial year calculated under subclause (2)

T_a

is the sum of—

(a) Transpower’s depreciation tax loss (positive value) or gain (negative value) for asset a and the preceding financial year calculated under subclause (3); and
(b) income tax on the capital charge for asset a and the preceding financial year calculated under subclause (5)

AO

is the attributed opex component for the BBI and pricing year calculated under subclause 40(1).

(2) The capital charge for an asset and financial year (C) is calculated—
- (a) if the asset had an opening RAB value for the financial year, as follows:

C = r x V

where

r

is Transpower’s PQ WACC (vanilla) at the start of the financial year

V

is, subject to subclause 7, the opening RAB value for the asset and financial year; or

- (b) if the asset was commissioned during the financial year, as follows:

where

V

is, subject to subclause (7), the asset’s value of commissioned asset

r

is Transpower’s PQ WACC (vanilla) at the start of the financial year

m

is the month of the financial year during which the asset was commissioned (for example, m = 3 for September).

(3) Transpower’s depreciation tax loss or gain for an asset and financial year (Tdep) is calculated as follows:

where

r

is the corporate tax rate, as defined in the Transpower IMs, at the start of the financial year

AD

is depreciation of the asset during the financial year, excluding accelerated depreciation

TD

is tax depreciation of the asset during the financial year, excluding accelerated depreciation

I

is notional interest for the asset and financial year calculated under subclause (4).

(4) Notional interest for an asset and financial year (I) is calculated as follows:

I = V × L × CD

where

V

is, subject to subclause (7), the opening RAB value for the asset and financial year

L

is leverage, as defined in the Transpower IMs, at the start of the financial year

CD

is the estimated cost of debt used under the Transpower IMs to calculate Transpower's PQ WACC (vanilla) applicable at the start of the financial year.

(5) Income tax on the capital charge for an asset and financial year (T_inc) is calculated as follows:

where

r

is the corporate tax rate, as defined in the Transpower IMs, at the start of the financial year

C

is the capital charge for the asset and financial year calculated under subclause (2).

(6) [Revoked]
(7) If the asset referred to in subclause (2) or (4)—
- (a) has been written-down; and
- (b) is comprised in a BBI that, as at the start of the relevant financial year, does not meet the requirements of subparagraph (b)(i), (b)(ii) or (b)(iii) of the definition of eligible BBI in clause 3; and
- (c) the circumstances justifying the write-down of the asset would otherwise justify reassignment of the BBI (excluding subparagraph 104(2)(b)(ii)),
Transpower must carry out the calculation under subclause (2) or (4) for the asset as if the asset had not been written-down.
(8) This clause 39 is subject to clause 40A.

Clause 39(1) and (3): amended, on 31 July 2023, by clause 9(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 39(6): revoked, on 31 July 2023, by clause 9(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 39(8): inserted, on 31 July 2023, by clause 9(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

40 Attributed Opex Component

(1) The attributed opex component for a BBI and pricing year (AO) is calculated as follows:

where

D_a

is depreciation of asset a for the preceding financial year, where asset a is an asset comprised in the BBI, excluding accelerated depreciation

AOR

is the attributed opex ratio for the pricing year calculated under subclause (3)

HVDC

is—

(a) if the BBI comprises 1 or more transmission investments in the HVDC link, an allocation of HVDC opex for the preceding financial year as determined by Transpower subject to subclause (2); or
(b) otherwise, 0

TA

is—

(a) if the BBI comprises 1 or more interconnection transmission alternatives, TA opex for the interconnection transmission alternatives and preceding financial year, less any contribution to the TA opex under investment agreements; or
(b) otherwise, 0

MCP

is MCP opex for the BBI and preceding financial year.

(2) HVDC opex for a financial year must be fully allocated to 1 or more BBIs that comprise a transmission investment in the HVDC link, unless there are no such BBIs.
(3) The attributed opex ratio for a pricing year during an RCP (AOR) is calculated as follows:

where

OC

is the allowance for operating costs, as defined in the Transpower IMs, for the RCP

PC

is the allowance for pass-through costs, as defined in the Transpower IMs, for the RCP

RC

is the allowance for recoverable costs, as defined in the Transpower IMs, for the RCP

HVDC

is forecast HVDC opex for the RCP

TA

is the allowance for TA opex for the RCP, to the extent it is included in any of the above allowances

MCP

is the allowance for MCP opex for the RCP, to the extent it is included in any of the above allowances

FD

is an amount of operating costs attributable to Transpower assets that are fully depreciated at the start of the RCP, as determined by Transpower

D

is the allowance for depreciation for the RCP.

(4) The value of AOR in subclause (3) is—
- (a) calculated for the whole of the RCP; and
- (b) only re-calculated if any of the relevant allowances are reset by the Commission during the RCP.
(5) This clause 40 is subject to clause 40A.

Clause 40(1): amended, on 31 July 2023, by clause 10(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 40(5): inserted, on 31 July 2023, by clause 10(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

40A

Commissioned Assets Not Asseted

An asset that—
- (a) is comprised in a BBI; and
- (b) was commissioned at or before the end of the financial year preceding the pricing year for which Transpower is calculating the BBI’s covered cost; and
- (c) is not asseted at the time of that calculation,
must be ignored for the purposes of calculating the BBI’s covered cost for the pricing year.

Clause 40A: inserted, on 31 July 2023, by clause 11 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

41 Covered Cost of Anticipatory BBI

To avoid doubt, clauses 39 and 40 do not apply to an anticipatory BBI, the deemed covered cost of which is calculated under paragraph 27(2)(b).

BBI Customer Allocations

42 BBI Customer Allocations for Appendix A BBIs

(1) Subject to paragraph 75(5)(a), for each Appendix A BBI—
- (a) the starting beneficiaries are the Appendix A beneficiaries for the Appendix A BBI; and
- (b) the starting BBI customer allocations are the Appendix A allocations for the Appendix A BBI.
(2) To avoid doubt, for each Appendix A BBI—
- (a) the Appendix A beneficiaries are based on the Schedule 1 beneficiaries of the Appendix A BBI; and
- (b) the Appendix A allocations are based on the Schedule 1 allocations for the Appendix A BBI,
in each case adjusted as Transpower determined necessary to account for changes to and affecting customers before and after the Authority published the 2020 guidelines.

43 BBI Customer Allocations for Post-2019 BBIs

(1) A customer’s BBI customer allocation for a post-2019 BBI (CA) is calculated as follows:

where

NPB

is the customer’s individual NPB for the post-2019 BBI

NPB_total

is the total of all customers’ individual NPBs for the post-2019 BBI.

(2) Subject to subclauses (3) and (4A), a customer’s individual NPB for a post-2019 BBI is calculated under a standard method or the simple method as follows:

type	sub-type	method
post-2019 BBI expected to be high-value when fully commissioned	resiliency BBI	resiliency method
	otherwise	price-quantity method
post-2019 BBI expected to be low-value when fully commissioned	none	simple method

(2A) If Transpower’s expectation as to whether a post-2019 BBI will be high-value or low-value when fully commissioned changes before—
- (a) the post-2019 BBI’s final investment decision date; or
- (b) for a post-2019 BBI with a final investment decision date before the start of the first pricing year, the date the post-2019 BBI is commissioned,
Transpower may, but is not obliged to, change the method it applies to calculate customers’ BBI customer allocations for the post-2019 BBI from a standard method to the simple method or vice versa in accordance with subclause (2). However, Transpower must not change the method if Transpower has already notified one or more customers of their benefit-based charges for the post-2019 BBI and its start pricing year under their transmission agreements.
(3) For the purpose of calculating customers’ BBI customer allocations for a high-value intervening BBI and its start pricing year, Transpower may apply the simple method if Transpower determines it is necessary to do so to ensure there is sufficient time for Transpower to complete a robust process for calculating the BBI's BBI customer allocations under the standard method, including consultation under clause 15.
(4) If Transpower applies the simple method under subclause (3) for a high-value intervening BBI, Transpower must carry out a wash-up of transmission charges in the pricing year after the BBI’s start pricing year so that no customer is under or over-charged benefit-based charges for the BBI and start pricing year as a result of Transpower applying the simple method under subclause (3). The wash-up must include time value of money adjustments using Transpower’s ID WACC (pre-tax).
(4A) If Transpower—
- (a) expects a post-2019 BBI to be high-value when fully commissioned; and
- (b) expects one or more interconnection investments comprised in the post-2019 BBI to become connection investments within 3 years of the post-2019 BBI’s full commissioning date; and
- (c) would not expect the post-2019 BBI to be high-value when fully commissioned if those interconnection investments were excluded from the post-2019 BBI on its full commissioning date,
Transpower must apply the simple method to calculate customers’ BBI customer allocations for the post-2019 BBI.
(5) If a post-2019 BBI is a tested investment, the assumptions and other inputs (including the factual, counterfactual, modelled constraints and scenarios) Transpower uses in applying a standard method to the post-2019 BBI must be as consistent as reasonably practicable with the assumptions and other inputs used in applying the investment test to the post-2019 BBI, except—
- (a) as otherwise stated in this transmission pricing methodology; or
- (b) to the extent Transpower determines such alignment would not produce BBI customer allocations that are broadly proportionate to positive NPB from the post-2019 BBI, in which case Transpower may use different assumptions and other inputs provided they do not contradict what Transpower determines were its key drivers for proceeding with its investment in the post-2019 BBI as at the post-2019 BBI’s final investment decision date.
(6) To avoid doubt, the order of the provisions of this transmission pricing methodology specifying the standard methods and simple method do not necessarily reflect the order in which Transpower will carry out the steps specified in those provisions when Transpower applies the relevant standard method or simple method.

Clause 43(2): amended, on 31 July 2023, by clause 12(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 43(2A): inserted, on 31 July 2023, by clause 12(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 43(4A): inserted, on 31 July 2023, by clause 12(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Standard Method: Price-quantity Method

44 Overview of Price-quantity Method

(1) Clauses 44 to 55 apply—
- (a) to the price-quantity method only; and
- (b) only to those post-2019 BBIs to which Transpower applies the price-quantity method in accordance with subclause 43(2).
(2) Under the price-quantity method—
- (a) regional NPB is calculated for a regional customer group as any of the following:
  - (i) market regional NPB under clauses 49 to 52:
  - (ii) ancillary service regional NPB under clause 53:
  - (iii) reliability regional NPB under clause 54:
  - (iv) other regional NPB under clause 55; and
- (b) subject to subclauses (3) and 55(2), Transpower may—
  - (i) calculate market regional NPB for a market BBI; and
  - (ii) calculate ancillary service regional NPB for an ancillary service BBI; and
  - (iii) calculate reliability regional NPB for a reliability BBI; and
  - (iv) calculate or estimate other regional NPB for a market BBI, ancillary service BBI or reliability BBI; and
- (c) individual NPB is calculated for each customer in a regional customer group with positive regional NPB.
(3) Under the price-quantity method, Transpower must—
- (a) always calculate at least 1 of market regional NPB, ancillary service regional NPB or reliability regional NPB for a post-2019 BBI; and
- (ab) calculate market regional NPB for a market BBI if Transpower determines it is necessary to do so to produce BBI customer allocations for the market BBI that are broadly proportionate to positive NPB from the market BBI; and
- (b) calculate ancillary service regional NPB for an ancillary service BBI if Transpower determines it is necessary to do so to produce BBI customer allocations for the ancillary service BBI that are broadly proportionate to positive NPB from the ancillary service BBI; and
- (c) calculate reliability regional NPB for a reliability BBI if Transpower determines it is necessary to do so to produce BBI customer allocations for the reliability BBI that are broadly proportionate to positive NPB from the reliability BBI.

Clause 44(2)(b): replaced, on 1 March 2024, by clause 4(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) (No 2) 2023.

Clause 44(3)(ab): inserted, on 1 March 2024, by clause 4(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2024.

45 Factual and Counterfactual

(1) Transpower must determine a BBI’s factual and counterfactual.
(2) Transpower must apply the following principles to determine the BBI’s counterfactual unless Transpower determines applying these principles does not produce a reasonably likely future grid state:
- (a) if a transmission investment comprised in the BBI is an enhancement investment, the counterfactual must include the transmission investment not being made:
- (b) if a transmission investment comprised in the BBI is a replacement investment or compliance investment, the counterfactual must include the immediate decommissioning of the relevant grid asset or transmission alternative without replacement:
- (c) if a transmission investment comprised in the BBI is a refurbishment investment, the counterfactual must include leaving the relevant grid asset or transmission alternative in operation without refurbishment until it reaches replacement state and then immediately decommissioning it without replacement.

46 Scenarios

(1) Transpower must determine a BBI’s scenarios and probability weightings for the scenarios. A market BBI’s market scenarios must include variations in load growth, generation expansion and hydrology.
(2) Transpower must apply the same scenarios in a BBI’s factual and counterfactual, unless the BBI is a market BBI that is expected to influence materially generating plant investment decisions, in which case Transpower may apply different generation expansion market scenarios in the BBI’s factual and counterfactual.
(3) If a market scenario for a BBI includes a customer ceasing to be a customer, the market scenario must not be applied in the BBI’s factual or counterfactual in respect of the customer. To avoid doubt, this means the present value of regional NPB for a regional customer group for the BBI of which the customer is a member may be different for the customer than for all other customers who are members of the regional customer group.

47 Individual NPB

A customer’s individual NPB for a BBI (NPB) is calculated as follows:

where

PVRNPB_g

is the present value of regional NPB for regional customer group g calculated under clause 48, where regional customer group g is a regional customer group for the BBI—

(a) that has a positive present value of regional NPB; and
(b) of which the customer is a member

IRA_g

is the value of the customer’s intra-regional allocator for regional customer group g

IRA_g total

is the total of the values of all customers’ intra-regional allocators for regional customer group g.

48 Present Value of Regional NPB

(1) Subject to subclause (2), the present value of a regional customer group’s regional NPB (PVRNPB) is calculated as follows:

where

RNPB_n

is the regional customer group’s market regional NPB, ancillary service regional NPB, reliability regional NPB or other regional NPB (as the case may be) for year n of the BBI’s standard method calculation period

r

is the BBI’s standard method rate.

(2) As an alternative to the calculation under subclause (1), Transpower may calculate a regional customer group’s market regional NPB, ancillary service regional NPB, reliability regional NPB or other regional NPB (as the case may be) for each year of the BBI’s standard method calculation period on a present value basis, provided that the method of calculating present value is consistent with the method in subclause (1).

49 Modelling for Market Regional NPB

(1) This clause 49 applies to modelling for calculating market regional NPB for a market BBI.
(2) Transpower must determine the market BBI’s investment grids.
(3) Transpower must use a wholesale market model to model the prices, quantities and changes in prices and quantities in the wholesale market for electricity between the market BBI’s factual and counterfactual under its market scenarios and based on its investment grids. The modelling must cover each year of the market BBI’s standard method calculation period.
(4) The illustrative wholesale market models in figures 11 and 12 below show alternative modelled prices, quantities and changes in prices and quantities for a notional market BBI, market scenario and year of the market BBI’s standard method calculation period (assuming no adjustments under subclause (6)). The effect of the market BBI is modelled as a change in the supply curve from S (counterfactual) to S′ (factual). P_max is consumers’ estimated cost of self-supply for electricity or alternative energy.

Figure 11

Figure 12

(5) In carrying out the modelling under this clause 49, Transpower may model embedded plant as if it were grid-connected. If Transpower does this, the modelled market benefits and disbenefits in respect of the plant must be attributed to the relevant host customer, not the owner of the plant.
(6) Transpower may adjust prices in the modelling under this clause 49 if, and to the extent, Transpower determines it is appropriate to do so to moderate the sensitivity of modelled prices and changes in prices to modelling assumptions and other inputs, or otherwise with the objective of ensuring the BBI customer allocations for the market BBI are broadly proportionate to positive NPB from the market BBI.

50 Modelled Regions and Regional Customer Groups

(1) Transpower must determine the market BBI’s modelled regions as follows and based on the outcomes of the modelling under clause 49:
- (aa) Transpower must determine the market BBI’s modelled regions based on the outcomes of the modelling under clause 49 except to the extent Transpower determines basing the modelled regions on those outcomes would not support the objective in paragraph (d):
- (a) a modelled region must be a set of either GXPs or GIPs:
- (b) the expected price or quantity changes, if any, at all GXPs or GIPs in a modelled region must be in the same direction:
- (c) a region meeting the requirements of paragraphs (a) and (b) may comprise more than 1 modelled region if the market benefits or disbenefits accruing at different GXPs or GIPs in the region—
  - (i) are of a materially different magnitude; or
  - (iii) occur under different market scenarios:
- (d) Transpower must determine the market BBI’s modelled regions with the objective of ensuring the BBI customer allocations for the market BBI are broadly proportionate to positive NPB from the market BBI.
(2) Transpower must determine the market BBI’s regional customer groups as follows and based on the outcomes of the modelling under clause 49:
- (a) subject to paragraph (b) and subclauses 51(7) and 52(9), the market BBI’s regional customer groups are as follows:

type of regional customer group	modelled region	regional customer group
regional demand group	a region defined by a set of GXPs	subject to subclause (4), all offtake customers in the modelled region
regional supply group	a region defined by a set of GIPs	all injection customers in the modelled region

- (b) there may be more than 1 regional demand group or regional supply group for the same modelled region, each comprising different offtake customers or injection customers (as the case may be), if Transpower determines it is necessary to have more than 1 regional demand group or regional supply group for the modelled region to produce BBI customer allocations for the market BBI that are broadly proportionate to positive NPB from the market BBI, having regard to the attributes of the offtake customers or injection customers (including whether the offtake customers or injection customers currently exist in the modelled region).
(3) To avoid doubt—
- (a) the market BBI may have 1 or more future regional customer groups, which may be regional demand groups, regional supply groups or a combination of both; and
- (b) a regional customer group that is not a future regional customer group may, in future, include offtake customers or injection customers who do not currently exist in the relevant modelled region.
(4) An offtake customer is not a member of a regional demand group for the market BBI in respect of its grid-connected battery storage if the market BBI’s market regional NPB is calculated under clause 52.

Clause 50(1)(aa): inserted, on 1 March 2024, by clause 5(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2024.

Clause 50(1)(b): amended, on 1 March 2024, by clause 5(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2024.

51 Calculation of Market Regional NPB based on Quantity

(1) Transpower must calculate market regional NPB for a market BBI under this clause 51 if—
- (a) Transpower determines, based on the outcomes of the modelling under clause 49 and taking into account the market BBI’s market scenarios and their probability weightings determined by Transpower under clause 46(1), that most of the positive market regional NPB for the market BBI’s regional supply groups relates to new large generating plant for which, at the time Transpower makes its determination under this paragraph, the proponent has not made its final decision to proceed with its investment in the plant; or
- (b) subclause 52(1) does not apply.
(2) To avoid doubt, paragraph (1)(a) does not require Transpower to have determined the market BBI’s regional supply groups before making the determination under that paragraph.
(3) For each regional customer group, market scenario and year of the market BBI’s standard method calculation period, the expected market benefit (positive value) or disbenefit (negative value) is calculated based on—
- (a) the modelling under clause 49; and
- (b) the period or periods during which the market BBI is modelled to generate its primary market benefits, as determined by Transpower (the periods of benefit),
- as follows:
- (c) for a regional demand group, quantities in the counterfactual are positive if there are alleviated prices for the regional demand group during the periods of benefit and negative if there are exacerbated prices for the regional demand group during the periods of benefit:
- (d) for a regional supply group, quantities in the counterfactual are positive if there are exacerbated prices for the regional supply group during the periods of benefit and an increase being positive and a decrease being negative, the sum being the expected market benefit or disbenefit. negative if there are alleviated prices for the regional supply group during the periods of benefit:
- (e) subject to subclause (4), for a regional demand group or regional supply group, the positive or negative quantities under paragraph (c) or (d) (as appropriate) are summed with the changes in quantities between the factual and counterfactual during all periods.
(4) In applying paragraph (3)(e), Transpower must adjust the changes in quantities as it determines necessary to ensure the market benefit or disbenefit attributable to modelled changes in injection and offtake for grid-connected battery storage is not double-counted.
(5) To avoid doubt, any alleviated prices or exacerbated prices outside the periods of benefit are ignored when applying paragraphs (3)(c) and (3)(d).
(6) Subject to subclause (7), a regional customer group’s market regional NPB for a year of the market BBI’s standard method calculation period (MRNPB) is calculated as follows:

where

EMBD_s

is the expected market benefit (positive value) or disbenefit (negative value) for the regional customer group and year for market scenario s, where market scenario s is a market scenario for the market BBI, but excluding any expected market benefit or disbenefit attributable to a future customer or future large plant unless the regional customer group is a future regional customer group

W_s

is the probability weighting for market scenario s determined by Transpower under clause 46(1).

(7) If a customer has injection and offtake at the same connection location, Transpower may, in carrying out the calculation under subclause (6), set off the customer’s expected market disbenefit from its injection or offtake at the connection location against the customer’s expected market benefit from its offtake or injection at the connection location. If Transpower does this, Transpower must assign the customer and the customer’s net expected market benefit to either the regional demand group or regional supply group for the modelled region in which the connection location is located (but not to both) depending on the regional customer group for which the customer has the higher present value net expected market benefit over the market BBI’s standard method calculation period (each present value calculated consistently with clause 48).
(8) To avoid doubt, subject to subclause (7), expected market benefits and disbenefits are not summed between different regional customer groups.
(9) If necessary for calculating the BBI customer allocations for the market BBI, Transpower must determine the dollar value of each regional customer group’s market regional NPB for each year of the market BBI’s standard method calculation period.

Clause 51(9): amended, on 1 March 2024, by clause 6 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2024.

52 Calculation of Market Regional NPB based on Price and Quantity

(1) Transpower must calculate market regional NPB for the market BBI under this clause 52 if—
- (a) paragraph 51(1)(a) does not apply; and
- (b) Transpower determines, based on the outcomes of the modelling under clause 49 and taking into account the market BBI’s market scenarios and their probability weightings determined by Transpower under clause 46(1), that—
  - (i) most of the positive market regional NPB for the market BBI’s regional customer groups derives from consumers avoiding having to pay their estimated cost of self-supply for electricity or alternative energy during peak demand periods; or
  - (ii) calculating market regional NPB for the market BBI under clause 51 would not produce BBI customer allocations that are broadly proportionate to positive NPB from the market BBI.
(2) To avoid doubt, subparagraph (1)(b)(i) does not require Transpower to have determined the market BBI’s regional customer groups before making the determination under that subparagraph.
(3) For a regional demand group, market scenario and year of the market BBI’s standard method calculation period, the expected market benefit or disbenefit is equal to—
- (a) the modelled change in consumer benefit for the regional demand group in the wholesale market for electricity (a positive change being a market benefit and a negative change being a market disbenefit); plus
- (b) the modelled change in loss and constraint excess received by customers in the regional demand group as a result of the change in consumer benefit other than through the settlement of FTRs (a positive change being a market benefit and a negative change being a market disbenefit), unless—
  - (i) Transpower has adjusted modelled price outcomes under subclause 49(6); or
  - (ii) the market BBI is a high-value intervening BBI.
(4) For a regional supply group, market scenario and year of the market BBI’s standard method calculation period, the expected market benefit or disbenefit arising is equal to—
- (a) the modelled change in producer benefit for the regional supply group in the wholesale market for electricity (a positive change being a market benefit and a negative change being a market disbenefit); plus
- (b) the modelled change in loss and constraint excess received by customers in the regional supply group as a result of the change in producer benefit other than through the settlement of FTRs (a positive change being a market benefit and a negative change being a market disbenefit), unless—
  - (i) Transpower has adjusted modelled price outcomes under subclause 49(6); or
  - (ii) the market BBI is a high-value intervening BBI.
(5) In applying paragraph (4)(a), Transpower must model offtake of grid-connected battery storage as a production cost for injection from the grid-connected battery storage.
(6) In the illustrative wholesale market model in figure 11 above—
- (a) the expected market benefit or disbenefit for the regional demand group is equal to the modelled change in consumer benefit, being:

factual	counterfactual	change in consumer benefit
a + b + c	a	b + c

- (b) the expected market benefit or disbenefit for the regional supply group is equal to the modelled change in producer benefit, being:

factual	counterfactual	change in producer benefit
d + e	b + d	e - b

(7) In the illustrative wholesale market model in figure 12 above—
- (a) the expected market benefit or disbenefit for the regional demand group is equal to the modelled change in consumer benefit, being:

factual	counterfactual	change in consumer benefit
a + b + c	0	a + b + c

- (b) the expected market benefit or disbenefit for the regional supply group is equal to the modelled change in producer benefit, being:

factual	counterfactual	change in producer benefit
d + e + f	a + d	e + f - a

(8) Subject to subclause (9), a regional customer group’s market regional NPB for a year of the market BBI’s standard method calculation period (MRNPB) is calculated as follows:

where

EMBD_s

is the expected market benefit (positive value) or disbenefit (negative value) for the regional customer group and year for market scenario s, where market scenario s is a market scenario for the market BBI, but excluding any expected market benefit or disbenefit attributable to a future customer or future large plant unless the regional customer group is a future regional customer group

W_s

is the probability weighting for market scenario s determined by Transpower under clause 46(1).

(9) If a customer has injection and offtake at the same connection location, Transpower may, in carrying out the calculation under subclause (8), set off the customer’s expected market disbenefit from its injection or offtake at the connection location against the customer’s expected market benefit from its offtake or injection at the connection location. If Transpower does this, Transpower must assign the customer and the customer’s net expected market benefit to either the regional demand group or regional supply group for the modelled region in which the connection location is located (but not to both) depending on the regional customer group for which the customer has the higher present value net expected market benefit over the market BBI’s standard method calculation period (each present value calculated consistently with clause 48).
(10) To avoid doubt, subject to subclause (9), expected market benefits and disbenefits are not summed between different regional customer groups.

53 Ancillary Service Regional NPB

(1) This clause 53 applies to calculating ancillary service regional NPB for an ancillary service BBI (if Transpower decides to calculate ancillary service regional NPB for the ancillary service BBI).
(2) Transpower must model changes in prices and quantities in the wholesale market for the relevant specified ancillary service between the ancillary service BBI’s factual and counterfactual under its market scenarios. The modelling must cover each year of the ancillary service BBI’s standard method calculation period.
(3) Transpower must determine the ancillary service BBI’s modelled regions and regional customer groups as follows:

specified ancillary service	type of regional customer group	modelled region	regional customer group
instantaneous reserve (by island)	regional demand group	none	none
instantaneous reserve (by island)	regional supply group	island	all grid-connected generators in the modelled region except in respect of generating plant with capacity equal to or less than the value of INJ_D in clause 8.59 of this Code
frequency keeping	regional demand group	New Zealand	all direct consumers in the modelled region
frequency keeping	regional supply group	none	none
voltage support (by zone)	regional supply group	none	none
voltage support (by zone)	regional demand group	zone	all connected asset owners in the modelled region

(4) To avoid doubt—
- (a) the ancillary service BBI may have 1 or more future regional customer groups, which may be regional demand groups, regional supply groups or a combination of both; and
- (b) a regional customer group that is not a future regional customer group may, in future, include grid-connected generators, direct consumers or connected asset owners who do not currently exist in the relevant modelled region.
(5) For a regional customer group, market scenario and year of the ancillary service BBI’s standard method calculation period, the expected market benefit or disbenefit is equal to the modelled change in the allocable cost of the specified ancillary service (a negative change being a market benefit and a positive change being a market disbenefit).
(6) A regional customer group’s ancillary service regional NPB for a year of the ancillary service BBI’s standard method calculation period (ASRNPB) is calculated as follows:

where

EASBD_s

is the expected market benefit (positive value) or disbenefit (negative value) for the regional customer group and year for market scenario s, where market scenario s is a market scenario for the ancillary service BBI, but excluding any expected market benefit or disbenefit attributable to a future customer or future large plant unless the regional customer group is a future regional customer group

W_s

is the probability weighting for market scenario s determined by Transpower under clause 46(1).

(7) To avoid doubt, expected market benefits and disbenefits are not summed between different regional customer groups.

54 Reliability Regional NPB

(1) This clause 54 applies to calculating reliability regional NPB for a reliability BBI (if Transpower decides to calculate reliability regional NPB for the reliability BBI).
(2) Transpower must use a system limit model to model changes in expected curtailed energy between the reliability BBI’s factual and counterfactual under its outage scenarios. The modelling must cover each year of the reliability BBI’s standard method calculation period.
(3) The illustrative system limit model in figure 13 below shows, for a notional reliability BBI, outage scenario, market scenario and year of the reliability BBI’s standard method calculation period, the effect of the reliability BBI. The effect of the reliability BBI is modelled as a change in the system limit from S (counterfactual) to S′ (factual), which reduces the value of X (percentage of year t supply, demand or active power transfer is at or more than the system limit). The modelled change in expected curtailed energy for the year (ΔECE_z) is calculated as follows:

ΔECE_z = CE × P_z × ΔP_x

where

CE

is Transpower’s estimate of curtailed energy caused by the outage scenario occurring in the market scenario

P_z

is Transpower’s estimate of the probability of the outage scenario occurring during the year

ΔP_x

is the change in the value of X in figure 13 between the counterfactual and factual.

Figure 13

(4) Transpower must determine the reliability BBI’s modelled regions and regional customer groups as follows and based on the outcomes of the modelling under subclause (2):
- (a) subject to paragraph (b), the reliability BBI’s modelled regions and regional customer groups are as follows:

type of regional customer group	modelled region	regional customer group
regional demand group	a region defined by a set of GXPs at which there is expected to be a change in unserved energy in the same direction if an outage scenario for the reliability BBI occurs	all offtake customers in the modelled region except in respect of grid-connected battery storage
regional supply group	a region defined by a set of GIPs at which there is expected to be a change in unsupplied energy in the same direction if an outage scenario for the reliability BBI occurs	all injection customers in the modelled region

- (b) there may be more than 1 regional demand group or regional supply group for the same modelled region, each comprising different offtake customers or injection customers (as the case may be), if Transpower determines it is necessary to have more than 1 regional demand group or regional supply group for the modelled region to produce BBI customer allocations for the reliability BBI that are broadly proportionate to positive NPB from the reliability BBI, having regard to the attributes of the offtake customers or injection customers (including whether the offtake customers or injection customers currently exist in the modelled region).
(5) To avoid doubt—
- (a) the reliability BBI may have 1 or more future regional customer groups, which may be regional demand groups, regional supply groups or a combination of both; and
- (b) a regional customer group that is not a future regional customer group may, in future, include offtake customers or injection customers who do not currently exist in the relevant modelled region.
(6) For each regional customer group, market scenario and year of the reliability BBI’s standard method calculation period, the expected reliability benefit or disbenefit (ERBD) is calculated as follows:

where

ΔECE_z

is the modelled change in expected curtailed energy for the regional customer group and outage scenario z, where outage scenario z is an outage scenario for the reliability BBI, calculated under subclause (3)

VL

is—

(a) if the regional customer group is a regional demand group, the reliability BBI’s VOLL; or
(b) if the regional customer group is a regional supply group, a value of lost generation determined by Transpower.

(7) A regional customer group’s reliability regional NPB for a year of the reliability BBI’s standard method calculation period (RRNPB) is calculated as follows:

where

ERBD_s

is the expected reliability benefit (positive value) or disbenefit (negative value) for the regional customer group and year for market scenario s, where market scenario s is a market scenario for the reliability BBI, but excluding any expected reliability benefit or disbenefit attributable to a future customer or future large plant unless the regional customer group is a future regional customer group

W_s

is the probability weighting for market scenario s determined by Transpower under clause 46(1).

(8) To avoid doubt—
- (a) expected reliability benefits and disbenefits are not summed between different regional customer groups; and
- (b) all regional demand groups, and all members of a regional demand group, are assumed to have the same value of unserved energy, being the reliability BBI’s VOLL; and
- (c) all regional supply groups, and all members of a regional supply group, are assumed to have the same value of unsupplied energy, being the value of lost generation determined by Transpower under subclause (5).

55 Other Regional NPB

(1) This clause 55 applies to calculating or estimating other regional NPB for a market BBI, ancillary service BBI or reliability BBI (if Transpower decides to calculate or estimate other regional NPB for the BBI).
(2) Transpower must only calculate or estimate other regional NPB for a BBI if all of the following criteria are satisfied:
- (a) Transpower reasonably expects positive other regional NPB for the BBI to be received—
  - (i) directly by 1 or more existing customers, whether in their capacities as customers or otherwise; or
  - (ii) by the majority of embedded plant owners connected to a host customer’s local network or grid-connected plant, whether in their capacities as embedded plant owners or otherwise:
- (b) Transpower determines the other regional NPB will be a material part of total positive regional NPB for the BBI:
- (c) Transpower determines the dollar value of the other regional NPB can be calculated or estimated to a reasonable level of certainty without Transpower incurring disproportionate cost.
(3) Transpower must determine the BBI’s modelled regions and regional customer groups as follows:

type of regional customer group	modelled region	regional customer group
regional demand group	a region in which other regional NPB is expected to arise from the BBI	all offtake customers in the modelled region expected to receive the other regional NPB
regional supply group		all injection customers in the modelled region expected to receive the other regional NPB

(4) To avoid doubt, the BBI customer allocations for a BBI are not adjusted merely because other regional NPB for the BBI arises or is discovered after the starting BBI customer allocations for the BBI have been calculated.

Standard Method: Resiliency Method

56 Overview of Resiliency Method

(1) Clauses 56 to 58 apply—
- (a) to the resiliency method only; and
- (b) only to those post-2019 BBIs to which Transpower applies the resiliency method in accordance with subclause 43(2).
(2) Under the resiliency method—
- (a) there is 1 modelled region and 1 regional customer group; and
- (b) regional NPB for the regional customer group is assumed to be positive and is not calculated; and
- (c) individual NPB is calculated for each customer in the regional customer group.

57 Individual NPB

A customer’s individual NPB for the resiliency BBI is equal to the value of the customer’s intra-regional allocator for the regional customer group.

58 Modelled Region and Regional Customer Group

Transpower must determine a resiliency BBI’s modelled region and regional customer group as follows:

type of regional customer group	modelled region	regional customer group
regional demand group	the island in which the risk of cascade failure is mitigated	all offtake customers in the modelled region except in respect of grid-connected battery storage
regional demand group	a region in which the risk of the HILP event is mitigated
regional supply group	none	none

Simple Method

59 Overview of Simple Method

(1) Clauses 59 to 64 apply—
- (a) to the simple method only; and
- (b) only to—
  - (i) those low-value post-2019 BBIs to which Transpower applies the simple method in accordance with subclause 43(2); and
  - (ii) those high-value intervening BBIs to which Transpower applies the simple method in accordance with subclause 43(3); and
  - (iii) those high-value post-2019 BBIs to which Transpower applies the simple method in accordance with subclause 43(4A); and
  - (iv) anticipatory BBIs.
(2) Under the simple method—
- (a) regional NPB is calculated for a regional customer group in respect of an investment region based on the extent to which the regional customer group is deemed to contribute to total offtake and injection in, or electricity flow to or from, the investment region, either as—
  - (i) a regional customer group in the investment region; or
  - (ii) a regional demand group in another modelled region that imports electricity from the investment region directly or indirectly; or
  - (iii) a regional supply group in another modelled region that exports electricity to the investment region directly or indirectly; and
- (b) individual NPB is calculated for each customer in a regional customer group with positive regional NPB in respect of the investment region.
(3) To avoid doubt, a BBI may have more than 1 investment region depending on where the transmission investments comprised in the BBI are located.

Clause 59(1)(b)(iii): replaced, on 17 June 2024, by clause 7 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

60 Simple Method Periods

(1) Subject to subclause (2), the simple method periods are—
- (a) the period starting on 24 July 2019 and ending at the end of the fourth pricing year after the first pricing year; and
- (b) each period of 5 pricing years immediately following the end of the previous simple method period.
(2) Transpower may start a new simple method period to coincide with the start of an RCP.

61 Individual NPB

(1) A customer’s individual NPB for a BBI in an investment region (NPB) is calculated as follows:

where

RNPB_g

is regional NPB for regional customer group g, where regional customer group g is a regional customer group for the BBI—

(a) that has positive regional NPB in respect of the investment region; and
(b) of which the customer is a member

SMF_g

is the customer’s simple method factor for regional customer group g.

(2) A customer’s simple method factor for a simple method period and regional customer group of which the customer is a member (SMF) is calculated as follows:

where

IRA

is the value of the customer’s intra-regional allocator for the simple method period and regional customer group

IRA_total

is the total of the values of all customers’ intra-regional allocators for the simple method period and regional customer group.

(3) If a benefit-based charge adjustment event in any of paragraphs 81(1)(b) to 81(1)(j) occurs between the end of CMP C for a simple method period and the start of the simple method period, Transpower must apply subclause (6) to calculating all customers’ simple method factors for the simple method period as if the benefit-based charge adjustment event occurred during the simple method period.
(4) The values of RNPB_g and SMF_g under subclause (1) are those that apply when the BBI is commissioned, and Transpower must use those values to calculate each customer's individual NPB and starting BBI customer allocation for the BBI. To avoid doubt, the BBI customer allocations for the BBI do not change merely because—
- (a) there are different values of regional NPB for a subsequent simple method period; or
- (b) there are different simple method factors, individual NPBs and starting BBI customer allocations for a subsequent simple method period; or
- (c) new or re-calculated simple method factors, individual NPBs and starting BBI customer allocations for a simple method period are calculated or re-calculated under paragraph (6)(a) or published under paragraph 64A(c).
(5) [Revoked]
(6) If a benefit-based charge adjustment event in any of paragraphs 81(1)(b) to 81(1)(j) occurs, Transpower must—
- (a) calculate or re-calculate (as the case may be and to the extent affected by the benefit-based charge adjustment event) all customers’ simple method factors, individual NPBs and starting BBI customer allocations for the current simple method period, using estimated values for the customers’ intra-regional allocators to the extent necessary; and
- (b) subject to this subclause (6), apply the new or re-calculated starting BBI customer allocations to each BBI commissioned during the simple method period after the new or re-calculated starting BBI customer allocations are published under paragraph 64A(c).

Clause 61(4): replaced, on 31 July 2023, by clause 13(1) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 61(5): revoked, on 31 July 2023, by clause 13(2) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 61(6): replaced, on 31 July 2023, by clause 13(3) of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

62 Modelled Regions

(1) The modelled regions are the connection regions and HVDC link.
(2) [Revoked]
(3) Transpower must review, including update as appropriate, the modelled regions (other than the HVDC link) for each simple method period before the start of the simple method period.
(4) Transpower must determine the connection regions for a simple method period by—
- (a) determining high-voltage grid connection regions on either side of the HVDC link; and
- (b) isolating prevailing directional electricity flows on interconnection branches in the high-voltage grid (excluding the HVDC link) over CMP C for the simple method period and determining high-voltage grid connection regions on either side of the interconnection branches on which those electricity flows occur; and
- (c) determining a low-voltage grid connection region on the low-voltage grid side of each interconnection transformer branch containing an interconnecting transformer connecting the low-voltage grid to a high-voltage grid connection region; and
- (d) if a low-voltage grid connection region is connected to more than 1 high-voltage grid connection region, determining separate low-voltage grid connection regions on either side of the minimum transfer interconnection branch within the low-voltage grid connection region, so that each of the separate low-voltage grid connection regions is connected to only 1 high-voltage grid connection region; and
- (e) for a low-voltage connection region connected to 1 high-voltage connection region by more than 1 interconnection branch, determining separate low voltage grid connection regions on either side of the minimum transfer interconnection branch within the low-voltage grid connection region if electricity flow on that branch is low relative to total electricity flows between interconnecting transformers in the low-voltage grid connection region; and
- (f) incorporating—
  - (i) the branches referred to in paragraph (b) in both relevant connection regions in proportion to the electricity flows on those branches into each connection region; and
  - (ii) the branches referred to in paragraph (c), including the interconnecting transformers, in the relevant low-voltage grid connection region; and
  - (iii) the branches between low-voltage connection regions referred to in paragraphs (d) and (e) in both relevant low-voltage connection regions in half parts.
(5) Transpower—
- (a) is not required to (but may) assess electricity flows over the entire high-voltage grid under paragraph (4)(b); and
- (b) may amalgamate geographically adjacent connection regions for a simple method period if—
  - (i) the connection regions have the same voltage; and
  - (ii) 1 or more of the connection regions contains significantly fewer market nodes than the average number of market nodes contained in all connection regions.

Clause 62(2): revoked, on 31 July 2023, by clause 14 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

63 Regional Customer Groups

Subject to subclause 27(3), the regional customer groups are as follows:

type of regional customer group	modelled region	regional customer group
regional demand group	a connection region	all offtake customers in the modelled region
regional supply group	a connection region	all injection customers in the modelled region

64 Regional NPB

(1) [Revoked]
(2) Regional NPB for a regional customer group in respect of an investment region for a simple method period (RNPB) is calculated as follows:

where

SMC_t

is the regional customer group’s simple method contribution in respect of the investment region for trading period t, where trading period t is a trading period during CMP C for the simple method period

W_t

is a weighting for trading period t determined by Transpower

F

is—

(a) if the regional customer group is a regional demand group, the demand factor for the simple method period; or
(b) if the regional customer group is a regional supply group, 1.

(3) The calculation under subclause (2) must be carried out for all trading periods during CMP C for the simple method period for which Transpower determines it has access to reliable values for the variables in subclause (7).
(4) The demand factor for a simple method period (DF) is calculated as follows:

where

RNPB_s total

is total regional NPB for all regional supply groups in respect of all investment regions for the simple method period calculated under subclause (2)

RNPB_d total

is total regional NPB for all regional demand groups in respect of all investment regions for the simple method period calculated under subclause (2) but without multiplying by the demand factor.

(5) Figure 14 below illustrates how, given the generalised electricity flow state depicted (connection region A to B to C)—
- (a) the beneficiaries of a BBI located in 1 of the connection regions (being the investment region) are identified; and
- (b) a regional customer group’s simple method contribution in respect of the investment region is calculated for a trading period during which, on average, the electricity flow state prevailed.

Figure 14

(6) In figure 14 above—
- (a) the beneficiaries of a BBI in connection region A (being the investment region) are deemed to be—
  - (i) the customers in the regional demand group and regional supply group in connection region A; and
  - (ii) the customers in the regional demand groups in connection regions B and C, which import electricity from the investment region directly or indirectly; and
- (b) the beneficiaries of a BBI in connection region B (being the investment region) are deemed to be—
  - (i) the customers in the regional demand group and regional supply group in connection region B; and
  - (ii) the customers in the regional supply group in connection region A, which exports electricity to the investment region directly; and
  - (iii) the customers in the regional demand group in connection region C, which imports electricity from the investment region directly; and
- (c) the beneficiaries of a BBI in connection region C (being the investment region) are deemed to be—
  - (i) the customers in the regional demand group and regional supply group in connection region C; and
  - (ii) the customers in the regional supply groups in connection regions A and B, which export electricity to the investment region directly or indirectly.
(7) In figure 14 above, a regional customer group’s simple method contribution in respect of the investment region (being either connection region A, B or C) for a trading period is calculated in accordance with the relevant formula in figure 14,

where

G_x

is total injection at all connection locations in connection region x for the trading period

L_x

is total offtake at all connection locations in connection region x for the trading period

F_{x_y}

is electricity flow from connection region x to connection region y for the trading period.

Clause 64(1): revoked, on 31 July 2023, by clause 15 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

64A

Publication of Simple Method Information

Transpower must—

(a) publish the modelled regions, regional NPB for each modelled region, starting BBI customer allocations and all inputs to the calculation of the starting BBI customer allocations for the first simple method period before the start of the first pricing year; and
(b) publish the modelled regions, regional NPB for each modelled region, starting BBI customer allocations and all inputs to the calculation of the starting BBI customer allocations for each subsequent simple method period before the start of the subsequent simple method period; and
(c) if Transpower calculates or re-calculates the simple method factors, individual NPBs and starting BBI customer allocations for a simple method period under paragraph 61(6)(a), publish the new or re-calculated starting BBI customer allocations and all inputs to their calculation or re-calculation.

Clause 64A: inserted, on 31 July 2023, by clause 16 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Intra-regional Allocators

65 Intra-regional Allocators

(1) Subject to subclause (2), the intra-regional allocator for a regional customer group under the price-quantity method is as follows:

type of BBI	type of regional customer group	intra-regional allocator	subclause
peak BBI	regional supply group	mean historical annual injection	f
peak BBI	regional demand group	mean historical coincident peak offtake	(7), (8)
non-peak BBI	regional supply group	mean historical annual injection	f
non-peak BBI	regional demand group	mean historical annual offtake	e

(2) The intra-regional allocator for an ancillary service regional customer group under the price-quantity method is as follows:

specified ancillary service	type of ancillary service regional customer group	intra-regional allocator	subclause
instantaneous reserve	regional supply group	mean historical annual injection	f
frequency keeping	regional demand group	mean historical annual offtake	e
voltage support	regional demand group	mean peak kVar	(9)

(3) The intra-regional allocator for the regional customer group under the resiliency method is mean historical annual offtake (see subclause (5)).
(4) The intra-regional allocator for a regional customer group under the simple method is as follows:

type of regional customer group	intra-regional allocator	subclause
regional supply group	mean historical annual injection	(11)
regional demand group	mean historical annual offtake	(10)

(5) Subject to subclause (13), if a regional customer group for a BBI under a standard method has a mean historical annual offtake intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (including part capacity years expressed as a decimal) during CMP B for the relevant BBI for which the pre-existing customer was a member of the regional customer group

TO_n

is the pre-existing customer’s total offtake at all connection locations in the regional customer group’s modelled region during capacity year n of CMP B for the BBI.

(6) Subject to subclause (13), if a regional customer group for a BBI under a standard method has a mean historical annual injection intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (including part capacity years expressed as a decimal) during CMP B for the relevant BBI for which the pre-existing customer was a member of the regional customer group

TI_n

is the pre-existing customer’s total injection at all connection locations in the regional customer group’s modelled region during capacity year n of CMP B for the BBI.

(7) Subject to subclause (13), if a regional customer group for a BBI under a standard method has a mean historical coincident peak offtake intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (rounded up to the nearest whole capacity year) during CMP B for the relevant BBI during which the pre-existing customer was a member of the regional customer group, each such capacity year being capacity year n

T_n

is the number of peak offtake trading periods for the regional customer group’s modelled region and capacity year n during which the pre-existing customer was a member of the regional customer group, each such peak offtake trading period being peak offtake trading period t

TO_t

is the pre-existing customer’s total offtake at all connection locations in the regional customer group’s modelled region for peak offtake trading period t.

(8) A modelled region’s peak offtake trading periods for a capacity year are the T trading periods during the capacity year that have the highest total offtake (across all offtake customers) at all connection locations in the modelled region, where T is a number of trading periods between 1 and 100 published in the assumptions book for the purposes of this subclause.
(9) Subject to subclause (13), if a regional customer group for a BBI under a standard method has a mean peak kVar intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (rounded up to the nearest whole capacity year) during CMP B for the relevant BBI for which the pre-existing customer was a member of the regional customer group

NPK_n

is the pre-existing customer’s nominated peak kVar for the regional customer group’s modelled region and capacity year n of CMP B for the BBI.

(10) Subject to subclause (13), if a regional customer group for a BBI under the simple method has a mean historical annual offtake intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (including part capacity years expressed as a decimal) during CMP C for the relevant simple method period for which the pre-existing customer was a member of the regional customer group

TO_n

is the pre-existing customer’s total offtake at all connection locations in the regional customer group’s modelled region during capacity year n of CMP C for the simple method period.

(11) Subject to subclause (13), if a regional customer group for a BBI under the simple method has a mean historical annual injection intra-regional allocator, the value of a pre-existing customer’s intra-regional allocator for the regional customer group, where the pre-existing customer is a member of the regional customer group, (IRA) is calculated as follows:

where

N

is the number of capacity years (including part capacity years expressed as a decimal) during CMP C for the relevant simple method period for which the pre-existing customer was a member of the regional customer group

TI_n

is the pre-existing customer’s total injection at all connection locations in the regional customer group’s modelled region during capacity year n of CMP C for the simple method period.

(12) Subclause (13) applies if—
- (a) one or more specified pre-start adjustment events for a BBI under a standard method and a pre-existing customer occurred during CMP B for the BBI; or
- (b) one or more specified pre-start adjustment events for a BBI under the simple method and a pre-existing customer occurred during CMP C for the relevant simple method period.
(13) If this subclause applies under subclause (12), Transpower must estimate the value of the pre-existing customer’s intra-regional allocator under clause 66 as if the pre-existing customer were a recent customer, but also taking into account the full impact of the specified pre-start adjustment events.

66 Recent Customers

The value of a recent customer’s intra-regional allocator for a regional customer group is estimated under paragraph 83(3)(a) as if the recent customer were a new customer joining the regional customer group, but also taking into account any available historical information about the recent customer’s mean historical annual injection, mean historical annual offtake or mean historical coincident peak offtake (as the case may be).

67 Notional IRA Value

If a regional customer group is a future regional customer group, Transpower must determine a value of the intra-regional allocator for a notional pre-existing customer who accounts for all of the future regional customer group’s market regional NPB, being the notional IRA value for the future regional customer group.

Part E Residual Charges

68 Calculation of Residual Charges

(1) Only load customers pay residual charges.
(2) A load customer’s annual residual charge for a pricing year (ARC) is calculated as follows:

ARC = AMDR × RCR

where

AMDR

is the load customer’s AMDR for the pricing year

RCR

is the residual charge rate for the pricing year calculated under clause 74.

(3) A load customer’s monthly residual charge for a pricing year (MRC) is calculated as follows:

where

where ARC is the load customer’s annual residual charge for the pricing year.

(4) Residual charges are calculated for each pricing year before the start of the pricing year.
(5) A residual charge may be re-calculated, including during a pricing year, under clauses 92 to 95 if there is a residual charge adjustment event.

69 Anytime Maximum Demand (Residual)

(1) A load customer’s AMDR for pricing year n (AMDR_n) is—
- (a) 0 if the load customer became a customer at or after the start of financial year n-4; or
- (b) calculated as follows if the load customer became a customer before the start of financial year n-4 and at or after the start of financial year n-8:

where

m

is the financial year during which the load customer became a customer

AMDR_baseline

is the load customer’s AMDR baseline calculated or estimated under clause 70; or

(c) otherwise, calculated as follows:

AMDR_c = AMDR_baseline × RCAF_n

where

AMDR_baseline

is the load customer’s AMDR baseline calculated or estimated under clause 70

RCAF_n

is the load customer’s RCAF for pricing year n.

70 Anytime Maximum Demand (Residual) Baseline

(1) Subject to subclause 72(1), a pre-existing load customer’s AMDR baseline (AMDR_baseline) is calculated as follows:

where

where MGD_ln is the pre-existing load customer’s maximum gross demand for connection location 1 and financial year n.

(2) A recent load customer’s AMDR baseline—
- (a) is estimated by Transpower as if the recent load customer’s assets were fully operational from the start of CMP D and taking into account—
  - (i) the type and capacity of the recent load customer’s assets; and
  - (ii) the AMDR baselines for any other load customers with assets of the same or a similar type as the recent load customer’s assets; and
  - (iii) any available information about the recent load customer’s maximum gross demand, but excluding any contribution to the recent load customer’s maximum gross demand from the charging or discharging of large battery storage other than the battery storage’s energy losses; and
- (b) may be re-estimated by Transpower under clause 73.

71 Residual Charge Adjustment Factor

(1) A load customer’s RCAF for pricing year n (RCAF_n) is calculated as follows:

where

LATGE_n

is the load customer’s lagged average total gross energy for pricing year n calculated under subclause (2)

ATGE_baseline

is the load customer’s average total gross energy baseline calculated or estimated under subclause (4) or (5).

(2) A load customer’s lagged average total gross energy for pricing year n (LATGEn) is calculated as follows:

where

F_m

is—

(a) if—
- (i) the load customer is a pre-existing load customer; and
- (ii) there has been one or more reduction events for the load customer that occurred after the end of financial year m, the reduction event adjustment factor for the load customer and financial year m calculated under subclause (3); or
(b) otherwise, 1

TGE_m

is—

(a) if—
- (i) the load customer is a pre-existing load customer; and
- (ii) there has been one or more reduction events for the load customer that occurred during financial year m,
- ATGE_after as defined in subclause (3), immediately after the most recent such reduction event; or
(b) otherwise, the load customer’s total gross energy for financial year m.

(3) The reduction event adjustment factor for a load customer and financial year m (REAF_m) is calculated as follows:

where

ATGE_after

is the load customer’s average total gross energy baseline immediately after the reduction under subclause 72(2) for the latest reduction event that occurred after the end of financial year m

ATGE_before

is the load customer’s average total gross energy baseline immediately before the reduction under subclause 72(2) for the earliest reduction event that occurred after the end of financial year m.

(4) Subject to subclause 72(2), a pre-existing load customer’s average total gross energy baseline (ATGE_baseline) is calculated as follows:

where

where TGE_n is the pre-existing load customer’s total gross energy for financial year n.

(5) A recent load customer’s average total gross energy baseline—
- (a) is estimated by Transpower as if the recent load customer’s assets were fully operational from the start of CMP D and taking into account—
  - (i) the type and capacity of the recent load customer’s assets; and
  - (ii) the total gross energy baselines for any other load customers with assets of the same or a similar type as the recent load customer’s assets; and
  - (iii) any available information about the recent load customer’s total gross energy,
  - but excluding any contribution to the recent load customer’s total gross energy from the charging or discharging of large battery storage other than the battery storage’s energy losses; and
- (b) may be re-estimated by Transpower under clause 73.
(6) To avoid doubt, a load customer’s RCAF for a pricing year is only calculated if the load customer’s AMDR for the pricing year is calculated under clause 69(1)(c).

Clause 71(2): amended, on 22 March 2023, by clause 4 of the Electricity Industry Participation Code Amendment (Residual Charge Adjustment Factor) 2023.

Clause 71(2): replaced, on 31 July 2023, by clause 17 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 71(3): amended, on 22 March 2023, by clause 4 of the Electricity Industry Participation Code Amendment (Residual Charge Adjustment Factor) 2023.

Clause 71(3): replaced, on 31 July 2023, by clause 17 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

72 Reduction Events

(1) Transpower may reduce a pre-existing load customer’s AMDR baseline by an amount determined by Transpower—
- (a) if a reduction event for the pre-existing load customer has occurred or Transpower determines will occur; and
- (b) to the extent the impact of the reduction event is not fully captured in the calculation of the pre-existing load customer’s AMDR baseline under subclause 70(1).
(2) If Transpower reduces an AMDR baseline under subclause (1), Transpower must also reduce the pre-existing load customer’s average total gross energy baseline to the extent necessary to be consistent with the reduction in the pre-existing customer’s AMDR baseline, as determined by Transpower.
(3) To avoid doubt, the time when a reduction event occurred or will occur is determined by Transpower.

73 Re-estimating for Recent Load Customers

(1) Transpower may re-estimate either or both of a recent load customer’s AMDR baseline and average total gross energy baseline—
- (a) when information is available to Transpower about the recent load customer’s maximum gross demand or total gross energy when the recent load customer’s assets are fully operational, but may only re-estimate each of the recent load customer’s AMDR baseline and average total gross energy baseline under this paragraph once; or
- (b) if Transpower determines information relevant to Transpower’s estimate of the recent load customer’s AMDR baseline or average total gross energy baseline provided to Transpower by or on behalf of the recent load customer was false or misleading.
(2) To avoid doubt, the purpose of a re-estimation under subclause a is to correct any material under- or over-estimation in Transpower’s estimate of the recent load customer’s AMDR baseline or average total gross energy baseline.

74 Residual Charge Rate

The residual charge rate for a pricing year (RCR) is calculated as follows:

where

RR

is residual revenue for the pricing year

AMDR_total

is the total of all customers’ AMDR for the pricing year.

Part F Adjustments

General

75 Adjustment Events

(1) Subject to subclauses (4) and (5), an adjustment event is deemed to have occurred on the date Transpower has actual knowledge, and is reasonably satisfied, that the adjustment event has occurred, regardless of when the adjustment event actually occurred.
(2) Except as otherwise stated in this transmission pricing methodology, if an adjustment event occurs, Transpower must adjust relevant transmission charges from the date of the adjustment event, if necessary on a pro rata basis for the event pricing year depending on when the adjustment event occurred during the event pricing year.
(3) If adjustment events affecting the same transmission charge occur simultaneously, Transpower must determine an order in which the adjustment events will be deemed to have occurred for the purpose of adjusting the transmission charge.
(4) Subject to subclauses (6) and (7), if a pre-start adjustment event for a post-2019 BBI has occurred, Transpower must treat the pre-start adjustment event as a benefit-based charge adjustment event that occurred or will occur at the start of the post-2019 BBI’s start pricing year and—
- (a) if Transpower determines it is reasonably practicable to do so, factor the pre-start adjustment event into its calculation of relevant transmission charges from the start of the post-2019 BBI’s start pricing year; or
- (b) otherwise, process the pre-start adjustment event as a benefit-based charge adjustment event during the start pricing year.
(5) Subject to subclauses (6) to (8), if a pre-commencement adjustment event has occurred, Transpower must treat the pre-commencement adjustment event as an adjustment event that occurred or will occur at the start of the first pricing year and—
- (a) if Transpower determines it is reasonably practicable to do so, factor the pre-commencement adjustment event into its calculation of relevant transmission charges from the start of the first pricing year; or
- (b) otherwise, process the pre-commencement adjustment event as an adjustment event during the first pricing year.
(6) Unless a pre-start adjustment event or pre-commencement adjustment event is a SSCGU, Transpower is not required to (but may) factor the pre-start adjustment event or pre-commencement adjustment event into its calculation of regional NPB under paragraph (4)(a) or (5)(a).
(7) Neither subclause (4) nor (5) applies to a pre-start adjustment event or pre-commencement adjustment event that is a specified pre-start adjustment event to which subclause 65(13) applies.
(8) Subclause (5)—
- (a) does not apply to a pre-commencement adjustment event for an Appendix A BBI that—
  - (i) occurred on or before 10 June 2020 (being the date the Authority published the 2020 guidelines); or
  - (ii) is reflected in Appendix A through an adjustment of the type referred to in subclause 42(2); and
- (b) subject to paragraph (a), applies to a benefit-based charge for an Appendix A BBI despite the starting beneficiaries and starting BBI customer allocations for the Appendix A BBI specified in Appendix A.

Connection Charges

76 Connection Charge Adjustment Events

(1) The following events are connection charge adjustment events:
- (a) a customer (the connecting customer) connects at a connection location at which the customer is not already connected;
- (b) a customer (the disconnecting customer) disconnects from a connection location;
- (c) a customer (the vendor) sells or otherwise transfers all or part of its business that constitutes it as a customer at a connection location to another party (the purchaser);
- (d) Transpower decides to voluntarily under-recover the connection charges for a connection asset, connection location or connection transmission alternative.
(2) Transpower must not voluntarily under-recover the connection charge for a connection asset, connection location or connection transmission alternative if the effect of doing so would be to increase residual revenue for any pricing year.
(3) To avoid doubt, a vendor’s sale or other transfer of all or part of its business that constitutes it as a customer at a connection location to a purchaser is treated as the connection charge adjustment event in paragraph (1)(c) and not the connection charge adjustment event in paragraph (1)(a) or (1)(b).

77 Connection Charge Adjustment Event: Connecting Customer

(1) This clause 77 applies in the case of the connection charge adjustment event in paragraph 76(1)(a).
(2) In this clause 77, a relevant pricing year is the event pricing year and the pricing year after the event pricing year.
(3) Transpower must, for each relevant pricing year—
- (a) determine whether the connecting customer will be treated as an offtake customer or injection customer at the connection location; and
- (b) estimate the connecting customer’s AMDC or AMIC (as applicable depending on Transpower’s determination under paragraph (a) for the connection location, taking into account—
  - (i) the type and capacity of the connecting customer’s assets; and
  - (ii) AMDC or AMIC (as the case may be) for any other customers with assets of the same or a similar type as the new customer’s assets connected at the connection location; and
- (c) calculate or re-calculate (as the case may be) all customers’ connection customer allocations for the connection location to account for the connecting customer’s AMDC or AMIC estimated under paragraph (b); and
- (d) calculate or re-calculate (as the case may be) all customers’ connection charges for the connection location based on the customers’ connection customer allocations calculated under paragraph (c); and
- (e) calculate or re-calculate (as the case may be) all customers’ connection charges for any relevant connection transmission alternative—
  - (i) to account for the connecting customer’s annual connection charge for the connection location calculated under paragraph (d); and
  - (ii) assuming that annual connection charge applied for the previous pricing year.
(4) Transpower must start the connecting customer’s monthly connection charges calculated under paragraph (3)(d) or (3)(e) as soon as reasonably practicable. The connecting customer’s monthly connection charges may include an adjustment as necessary to ensure the connecting customer pays its full connection charges for the connection location or connection transmission alternative from the date the connecting customer connected at the connection location.
(5) Transpower is not required to (but may) start any other customer’s monthly connection charges re-calculated under paragraph (3)(d) or (3)(e) during, or from the start of, an exempt pricing year for the customer. However, any over-recovery of annual connection charges for the connection location or connection transmission alternative and exempt pricing year resulting from the start of the connecting customer’s monthly connection charges for the connection location or connection transmission alternative must be rebated, as appropriate, to the other customers by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

78 Connection Charge Adjustment Event: Disconnecting Customer

(1) This clause 78 applies in the case of the connection charge adjustment event in paragraph 76(1)(b).
(2) Transpower—
- (a) must make the disconnecting customer’s connection customer allocations (and the inputs to their calculation) and connection charges for the connection location and any relevant connection transmission alternative 0; and
- (b) must not increase—
  - (i) any other customer’s connection charges for the connection location or connection transmission alternative and event pricing year; or
  - (ii) any other transmission charges for the event pricing year,
- as a consequence of applying paragraph (a).

79 Connection Charge Adjustment Event: Sale of Business

(1) This clause 79 applies in the case of the connection charge adjustment event in paragraph 76(1)(c).
(2) In this clause 79, a relevant pricing year is the event pricing year and the pricing year after the event pricing year.
(3) Transpower must, for a sale of part of the vendor’s business and for each relevant pricing year—
- (a) determine an apportionment between the vendor and purchaser of the vendor’s connection customer allocations (and the inputs to their calculation) for the connection location, taking into account the size and nature of the transferred business; and
- (b) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s connection charges for the connection location based on the apportionment of the vendor’s connection customer allocations under paragraph (a); and
- (c) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s connection charges for any relevant connection transmission alternative—
  - (i) to account for the vendor’s and purchaser’s annual connection charges for the connection location calculated under paragraph (b); and
  - (ii) assuming those annual connection charges applied for the previous pricing year.
(4) Transpower must, for a sale of all of the vendor’s business and for each relevant pricing year—
- (a) attribute all of the vendor’s connection customer allocation (and the inputs to its calculation) for the connection location to the purchaser; and
- (b) calculate or re-calculate (as the case may be) the purchaser’s connection charges for the connection location based on the attribution of the vendor’s connection customer allocation under paragraph (a); and
- (c) calculate or re-calculate (as the case may be) the purchaser’s connection charge for any relevant connection transmission alternative—
  - (i) to account for the purchaser’s annual connection charges for the connection location calculated under paragraph (b); and
  - (ii) assuming those annual connection charges applied for the previous pricing year.
(5) Transpower must start the purchaser’s monthly connection charges calculated under paragraph (3)(b), (3)(c), (4)(b) or (4)(c) as soon as reasonably practicable. The purchaser’s monthly connection charges may include an adjustment as necessary to ensure the purchaser pays its full connection charges for the connection location or connection transmission alternative from the date of the transfer.
(6) Transpower is not required to (but may) start the vendor’s monthly connection charges calculated under paragraph (3)(b) or (3)(c) during, or from the start of, an exempt pricing year for the vendor. However, any over-recovery of annual connection charges for the connection location or connection transmission alternative and exempt pricing year resulting from the start of the purchaser’s monthly connection charges for the connection location or connection transmission alternative must be rebated to the vendor by way of an adjustment to its transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

80 Connection Charge Adjustment Event: Voluntary Under-recovery

(1) This clause 80 applies in the case of the connection charge adjustment event in paragraph 76(1)(d).
(2) In this clause 80, a relevant pricing year is a pricing year for which Transpower decided to voluntarily under-recover the connection charges for the connection asset, connection location or connection transmission alternative.
(3) Transpower must, for each relevant pricing year, calculate or re-calculate (as the case may be) all customers’ connection charges for the connection asset, connection location or connection transmission alternative to account for the amount of the voluntary under-recovery of the connection charges.
(4) If Transpower decides to voluntarily under-recover the connection charges for the connection asset, connection location or connection transmission alternative and a relevant pricing year during, or within 1 month of the start of, the relevant pricing year, Transpower is not required to (but may) start customers’ monthly connection charges calculated under subclause (3) during, or from the start of, the relevant pricing year. However, any over-recovery of annual connection charges for the connection asset, connection location or connection transmission alternative and relevant pricing year (accounting for the voluntary under-recovery) must be rebated, as appropriate, to the customers by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the relevant pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

Benefit-based Charges

81 Benefit-based Charge Adjustment Events

(1) The following events are benefit-based charge adjustment events:
- (a) a BBI suffers material damage:
- (b) a new customer connects to the grid:
- (c) a customer (the exiting customer) ceases to be a customer:
- (d) an existing customer (the connecting or disconnecting customer) connects plant to, or disconnects plant from, the grid:
- (e) large embedded plant is connected to, or large embedded plant is disconnected from, a host customer’s (the connecting or disconnecting customer’s) local network or grid-connected plant:
- (f) there is a substantial sustained increase by a customer’s (the increasing customer’s) existing grid-connected plant:
- (g) there is a substantial sustained increase by existing large embedded plant connected to a host customer’s (the increasing customer’s) local network or grid-connected plant:
- (h) a distributor (the connecting distributor) connects its local network at a grid point of connection (new grid point of connection) to which the connecting distributor was not connected immediately before connecting its local network at the new grid point of connection:
- (i) the point of connection for existing large plant changes:
- (j) a customer (the vendor) sells or otherwise transfers all or part of its business that constitutes it as a beneficiary of a BBI to another party (the purchaser):
- (k) Transpower decides to voluntarily under-recover a BBI’s covered cost:
- (l) there is a SSCGU.
(2) Transpower must not voluntarily under-recover a BBI’s covered cost if the effect of doing so would be to increase residual revenue for any pricing year.
(3) For the purposes of paragraphs (1)(d) and (1)(e)—
- (a) a large upgrade of existing plant is treated as the connection of large plant equivalent in size to the upgrade; and
- (b) a large de-rating of existing plant is treated as the disconnection of large plant equivalent in size to the de-rating; and
- (c) a series of incremental upgrades or de-ratings of existing plant is treated as a large upgrade or large de-rating (as the case may be) if the incremental upgrades or de-ratings would constitute a large upgrade or large de-rating if undertaken at the same time.
(4) For the purposes of paragraphs (1)(f) and (1)(g), whether the increase in electricity consumed or generated by the large plant is a substantial sustained increase in respect of a BBI must be assessed against the average annual electricity consumption or generation by the large plant explicitly or implicitly included in the current value of the increasing customer’s intra-regional allocator for its regional customer group and the BBI.
(5) To avoid doubt, the benefit-based charge adjustment events in paragraphs (1)(a) and (1)(k) do not result in any change to the relevant BBI’s BBI customer allocations.
(6) The benefit-based charge adjustment event in paragraph (1)(i) is treated as the benefit-based charge adjustment events in one or both of paragraphs (1)(d) and (1)(e) (depending on the previous and new point of connection) occurring in respect of the same large plant, provided that clause 85 will not apply except as specified in clause 88.
(7) To avoid doubt, a vendor’s sale or other transfer of all or part of its business that constitutes it as a beneficiary of a BBI to a purchaser is treated as the benefit-based charge adjustment event in paragraph (1)(j) and not the benefit-based charge adjustment event in paragraph (1)(b) or (1)(c).
(8) Any of the benefit-based charge adjustment events in paragraphs (1)(b) to (1)(j) may also be a SSCGU, in which case both clause 91 and clause 83, 84, 85, 86, 87 or 88 (as applicable depending on the benefit-based charge adjustment event) will apply. However, clause 83, 84, 85, 86, 87 or 88 will apply to a relevant BBI described in paragraph 91(2)(a) only in respect of pricing years before the SSCGU’s start pricing year.
(9) For the purposes of subclauses 84(5), 84(6), 85(4) and 85(5) (which relate to continuing BBIs)—
- (a) the Bunnythorpe-Haywards Appendix A BBI is deemed to have a commissioning date of 9 May 2015; and
- (b) the post-2019 CUWLP investment is deemed to have a commissioning date of 1 January 2021; and
- (c) if the commissioning date of any other high-value intervening BBI is not known to Transpower, the high-value intervening BBI is deemed to have a commissioning date determined by Transpower.

82 Benefit-based Charge Adjustment Event: Material Damage

(1) This clause 82 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(a).
(2) In this clause 82, a relevant pricing year is—
- (a) the event pricing year; and
- (b) each subsequent pricing year for which a write-down due to the material damage is not reflected in the RAB values or values of commissioned asset used to calculate the BBI’s covered cost for the pricing year.
(3) Subject to subclause (4), Transpower must, for each relevant pricing year—
- (a) reduce the BBI’s covered cost by an amount determined by Transpower to reflect a reasonable write-down of the BBI due to the material damage; and
- (b) calculate or re-calculate (as the case may be) all beneficiaries’ benefit-based charges for the BBI based on the reduction of the BBI’s covered cost under paragraph (a).
(4) If a beneficiary (the causing beneficiary) caused, or contributed to the cause of, the material damage, subclause (3) does not apply to the causing beneficiary’s benefit-based charge for the BBI.
(5) Transpower is not required to (but may) start a beneficiary’s monthly benefit-based charge calculated under paragraph (3)(b) during, or from the start of, an exempt pricing year for the beneficiary. However, any over-recovery of the BBI’s covered cost for the exempt pricing year (accounting for the material damage) must be rebated, as appropriate, to the beneficiaries (other than any causing beneficiary) by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.
(6) Transpower must not increase any transmission charges for the event pricing year as a consequence of applying subclause (3).

83 Benefit-based Charge Adjustment Event: New Customer

(1) This clause 83 applies in the case of the benefit-based charge adjustment event in paragraph (81)(1)(b).
(2) The new customer—
- (a) is a beneficiary of each post-2019 BBI (a relevant post-2019 BBI) that has positive regional NPB for a regional customer group of which the new customer is expected to be a member (a relevant regional customer group for the relevant post-2019 BBI); and
- (b) may be a beneficiary of 1 or more of the Appendix A BBIs.
(3) Transpower must, for each relevant post-2019 BBI—
- (a) estimate the value of the new customer’s intra-regional allocator for each relevant regional customer group as if the new customer’s assets were fully operational and taking into account—
  - (i) the type and capacity of the new customer’s assets; and
  - (ii) the values of the intra-regional allocators for any other customers with assets of the same or a similar type as the new customer’s assets; and
- (b) subject to subclause (4) and applying subclause (13) if required, calculate the new customer’s individual NPB for the relevant post-2019 BBI—
  - (i) under clause 47, 57 or 61 (as applicable depending on the method used to calculate beneficiaries’ BBI customer allocations for the relevant post-2019 BBI); and
  - (ii) based on the value of the new customer’s intra-regional allocator for each relevant regional customer group estimated under paragraph (a), but excluding the value of the new customer’s intra-regional allocator from the denominator of the formula in clause 47 or subclause 61(2) (as applicable) unless the regional customer group had no members immediately before the new customer joined it; and
- (c) calculate the new customer’s BBI customer allocation for the relevant post-2019 BBI based on the new customer’s individual NPB for the relevant post-2019 BBI calculated under paragraph (b), but excluding the value of the new customer’s individual NPB from the denominator of the formula in subclause 43(1); and
- (d) scale down all beneficiaries’ (including the new customer’s) BBI customer allocations for the relevant post-2019 BBI by a factor (F) calculated as follows:

where

CA

is the new customer’s BBI customer allocation for the relevant post-2019 BBI calculated under paragraph (c); and

- (e) calculate or re-calculate (as the case may be) all beneficiaries’ benefit-based charges for the relevant post-2019 BBI based on the beneficiaries’ BBI customer allocations calculated under paragraph (d).
(4) If the new customer is in a future regional customer group for a relevant BBI, Transpower must calculate the new customer’s individual NPB for the relevant BBI under paragraph (3)(b) in respect of the future regional customer group by using the future regional customer group's notional IRA value in the denominator of the formula in clause 47.
(5) The following tables illustrate the application of subclause (3) to a new customer (customer E) entering regional customer group Y for a post-2019 BBI under the price-quantity method where regional customer group Y is not a future regional customer group:

Before

regional customer group	beneficiary	regional NPB	intra-regional allocator	individual NPB	BBI customer allocation
X	A	60	1	20	18.18%
X	B	60	2	40	36.36%
Y	C	50	3	30	27.27%
Y	D	50	2	20	18.18%

Transition (paragraphs (3)(a) to (3)(c))

regional customer group	beneficiary	regional NPB	intra-regional allocator	individual NPB	BBI customer allocation
X	A	60	1	20	18.18%
X	B	60	2	40	36.36%
Y	C	50	3	30	27.27%
	D		2	20	18.18%
	E		1 (estimated)	1/5 × 50 = 10	10/110 = 9.09%

After (paragraph (3)(d)

regional customer group	beneficiary	regional NPB	intra-regional allocator	individual NPB	BBI customer allocation (scaled by 1/1.0909)
X	A	60	1	20	16.67%
X	B	60	2	40	33.33%
Y	C	50	3	30	25.00%
	D		2	20	16.67%
	E		1 (estimated)	10	8.33%

(5A) Subclause (5C) applies to the new customer’s benefit-based charges for post-2019 BBIs under the simple method if—

BBC₍₃₎_total > SMBC

where

BBC₍₃₎ _total

is the new customer’s total benefit-based charges for relevant post-2019 BBIs under the simple method if calculated under subclause (3)

SMBC

is the new customer’s simple method BBC cap.

(5B) Subject to subclause (9A), the new customer’s simple method BBC cap (SMBC) is calculated as follows:

where

E

is Transpower’s estimate of the value of the new customer’s intra-regional allocator for the relevant regional customer group under paragraph 83(3)(a)

J

is the number of customers of the same type as the new customer (generator or connected asset owner)—

(a) at the new customer’s connection location; or
(b) if there are no such customers at the new customer’s connection location, at the connection location electrically closest to the new customer’s connection location at which there is 1 or more such customers, as determined by Transpower,

each such customer being customer j

BBC_{j total}

is customer j’s total annual benefit-based charges for BBIs under the simple method for the current pricing year and regional customer group in which customer j’s connection location is located

E_j

is the value of customer j’s intra-regional allocator for the current simple method period and regional customer group in which customer j’s connection location is located.

(5C) If this subclause applies under subclause (5A), Transpower must, instead of applying the new customer’s benefit-based charges for the relevant post-2019 BBIs under the simple method calculated under subclause (3)—
- (a) attribute part of the new customer’s simple method BBC cap to each investment region in respect of which the relevant regional customer group has positive regional NPB as follows:

where

SMBC_region

is the part of the new customer’s simple method BBC cap attributed to the investment region

SMBC

is the new customer’s simple method BBC cap

BBC₍₃₎

is the part of the new customer’s annual benefit-based charges for the relevant post-2019 BBIs under the simple method attributed to the investment region if calculated under paragraph 83(3)(e)

BBC_{(3) total}

is the new customer’s total annual benefit-based charges for the relevant BBIs under the simple method if calculated under paragraph 83(3)(e); and

- (b) calculate the new customer’s BBI customer allocation for each relevant post-2019 BBI (CA) as follows:

where

SMBC_region

is the part of the new customer’s simple method benefit cap attributed to the investment region in which the relevant post-2019 BBI is located under paragraph (a)

CC_{region total}

is the total covered cost of all relevant post-2019 BBIs under the simple method located in the investment region for the current pricing year; and

- (c) scale down all beneficiaries’ (including the new customer’s) BBI customer allocations for each relevant post-2019 BBI by a factor (F) calculated as follows:

where

CA

is the new customer’s BBI customer allocation for the relevant post-2019 BBI calculated under paragraph (b); and

- (d) calculate or re-calculate (as the case may be) all beneficiaries’ benefit-based charges for each relevant post-2019 BBI based on the beneficiaries’ BBI customer allocations calculated under paragraph (c).
(6) Transpower must, for each Appendix A BBI—
- (a) subject to subclause (9A), calculate the new customer’s BBI customer allocation for the Appendix A BBI (CA) as follows:

where

E

is Transpower’s estimate of the new customer’s average annual offtake or injection at the new customer’s connection location when the new customer’s assets are fully operational

J

is the number of Appendix A customers of the same type as the new customer (generator or connected asset owner)—

(i) at the new customer’s connection location; or
(ii) if there are no such Appendix A customers at the new customer’s connection location, at the connection location electrically closest to the new customer’s connection location at which there is 1 or more such Appendix A customers, as determined by Transpower,

each such Appendix A customer being Appendix A customer j

BF_j

is Appendix A customer j’s benefit factor for the Appendix A BBI and the new customer’s connection location (or the electrically closest connection location, as the case may be) (which may be zero); and

- (b) scale down all beneficiaries’ (including the new customer’s) BBI customer allocations for the Appendix A BBI by a factor (F) calculated as follows:

where

CA

is the new customer’s BBI customer allocation for the Appendix A BBI calculated under paragraph (a); and

- (c) calculate or re-calculate (as the case may be) all beneficiaries’ benefit-based charges for the Appendix A BBI based on the beneficiaries’ BBI customer allocations calculated under paragraph (b).
(7) An Appendix A customer’s benefit factor for an Appendix A BBI and connection location (BF) is calculated as follows:

where

CA

is the part of the Appendix A customer’s Appendix A allocation for the Appendix A BBI attributable to the connection location (which may be 0)

E

is—

(a) if the Appendix A customer is a Schedule 1 customer, and subject to subclause (7A), the Appendix A customer’s average annual offtake (for a connected asset owner) or injection (for a generator) at the connection location over CMP D, being the period the Authority used to calculate the Schedule 1 allocations, adjusted as necessary to take account of any adjustments of the type referred to in subclause 42(2); or

(b) otherwise, the estimate of the Appendix A customer’s average annual offtake (for a connected asset owner) or injection (for a generator) at the connection location over CMP D used to calculate the Appendix A customer’s Appendix A allocation for the Appendix A BBI.

(7A) This subclause applies to an Appendix A customer and connection location if—
- (a) paragraph (a) of the definition of variable E in subclause (7) applies to the calculation of the Appendix A customer’s benefit factors for the connection location; and
- (b) the Appendix A customer—
  - (i) is or was a connected asset owner at the connection location and had average annual injection at the connection location over CMP D that was greater than its average annual offtake at the connection location over CMP D; or
  - (ii) is or was a generator at the connection location and had average annual offtake at a connection location over CMP D that was greater than its average annual injection at the connection location over CMP D.
If this subclause applies, Transpower must—
- (c) if the Appendix A customer is or was a connected asset owner at the connection location—
  - (i) use the Appendix A customer’s average annual injection at the connection location over CMP D as the value of variable E in subclause (7), instead of its average annual offtake at the connection location over CMP D; and
  - (ii) treat the Appendix A customer as a generator at the connection location for the purposes of calculations under paragraph (6)(a); and
- (d) if the Appendix A customer is or was a generator at the connection location—
  - (i) use the Appendix A customer’s average annual offtake at the connection location over CMP D as the value of variable E in subclause (7), instead of its average annual injection at the connection location over CMP D; and
  - (ii) treat the Appendix A customer as a connected asset owner at the connection location for the purposes of calculations under paragraph (6)(a).
(8) For the purposes of the calculation under paragraph (6)(a), if the new customer’s assets are battery storage—
- (a) the new customer must be treated as a generator and not a connected asset owner; and
- (b) variable E must be Transpower’s estimate of the new customer’s average annual injection at the new customer’s connection location when the new customer’s battery storage is fully operational.
(9) The following tables illustrate the application of subclause (6) to a new customer (beneficiary E) for an Appendix A BBI, where the incumbent beneficiaries are all Appendix A customers and the benefit factors for beneficiaries B and C are used in the calculation in subclause (6)(a):

B

beneficiary	benefit factor	average annual offtake/injection	BBI customer allocation
A	0.1818	100	18.18%
B	0.1818	200	36.36%
C	0.0909	300	27.27%
D	0.0455	400	18.18%

Transition (paragraph (6)(a))

beneficiary	benefit factor	average annual offtake/injection	BBI customer allocation
A	0.1818	100	18.18%
B	0.1818	200	36.36%
C	0.0909	300	27.27%
D	0.0455	400	18.18%
E	(0.1818 + 0.0909)/2 = 0.1364	250 (estimated)	0.1364 × 250 = 34.10%

After (paragraph (6)(b))

beneficiary	benefit factor	annual offtake/injection	BBI customer allocation (scaled by 1/1.341)
A	0.1818	100	13.56%
B	0.1818	200	27.11%
C	0.0909	300	20.34%
D	0.0455	400	13.56%
E	0.1364	250 (estimated)	25.43%

(9A) Despite subclause (5B) and paragraph (6)(a), Transpower may exclude from the calculation under subclause (5B) or paragraph (6)(a) (as the case may be) any other customer's generating plant, consuming plant or local network that is not reasonably comparable to the new customer's generating plant, consuming plant or local network, whether by reason of different expected operating modes or otherwise.
(10) Transpower must start the new customer’s monthly benefit-based charges calculated under paragraph (3)(e) or (6)(c) as soon as reasonably practicable. The new customer’s monthly benefit-based charges may include an adjustment as necessary to ensure the new customer pays its full benefit-based charge for each BBI from the date the new customer connected to the grid.
(11) Transpower is not required to (but may) start any other beneficiary’s monthly benefit-based charges re-calculated under paragraph (3)(e) or (6)(c) during, or from the start of, an exempt pricing year for the beneficiary. However, any over-recovery of the benefit-based charge for a BBI and exempt pricing year resulting from the start of the new customer’s monthly benefit-based charge for the BBI must be rebated, as appropriate, to the other beneficiaries by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.
(12) Subclause (13) applies if the new customer is expected to be a member of a regional customer group under the simple method that—
- (a) had no members during CMP C for the relevant simple method period; and
- (b) has regional NPB of 0 in respect of at least one investment region for the relevant simple method period (each a zero RNPB investment region).
(13) If this subclause applies under subclause (12), Transpower must, for the purposes of the calculation under paragraph (3)(b), calculate regional NPB for the regional customer group in respect of each zero RNPB investment region (RNPB) as follows:

where, subject to subclause (14)

RNPB_{type total}

is—

(a) if the regional customer group is a regional demand group, the total of all other regional demand groups’ regional NPBs in respect of all investment regions for the simple method period; or
(b) if the regional customer group is a regional supply group, the total of all other regional supply groups’ regional NPBs in respect of all investment regions for the simple method period

I

is the number of investment regions for the simple method period

IRA_{type total}

is—

(a) if the regional customer group is a regional demand group, the total of all customers’ intra-regional allocator values for all other regional demand groups for the simple method period; or
(b) if the regional customer group is a regional supply group, the total of all customers’ intra-regional allocator values for all other regional supply groups for the simple method period

IRA

is the value of the customer’s intra-regional allocator estimated under paragraph 83(3)(a)

RNPB_{inv total}

is the total of all other regional customer groups’ regional NPBs in respect of the zero RNPB investment region for which RNPB is being calculated

RNPB_total

is the total of all other regional customer groups’ regional NPBs in respect of all zero RNPB investment regions.

(14) The other regional customer groups referred to in the definitions of variables RNPB_{type total}, RNPB_{inv total} and RNPB_total in subclause (13) exclude regional customer groups with no members.

Clause 83(3)(a)(ii): amended, on 10 April 2024, by clause 5(1) of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

Clause 83(5): amended, on 10 April 2024, by clause 5(2) of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

Clause 83(5A), (5B) and (5C): inserted, on 10 April 2024, by clause 5(3) of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

Clause 83(6)(a): amended, on 10 April 2024, by clause 5(4) of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

Clause 83(7): amended, on 31 July 2023, by clause 18 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 83(7A): inserted, on 31 July 2023, by clause 18 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Clause 83(9A): inserted, on 10 April 2024, by clause 5(5) of the Electricity Industry Participation Code Amendment (Benefit-based Charge Adjustment Event: New Customer) 2024.

Clause 83(13): amended, on 17 June 2024, by clause 8 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

84 Benefit-based Charge Adjustment Event: Exiting Customer

(1) This clause 84 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(c).
(2) The exiting customer ceases to be a beneficiary of each BBI (a relevant BBI) of which the exiting customer was a beneficiary immediately before ceasing to be a customer.
(3) Subject to subclause (7), Transpower—
- (a) must, for each relevant BBI—
  - (i) make the exiting customer’s BBI customer allocation and benefit-based charge for the relevant BBI 0; and
  - (ii) scale up all remaining beneficiaries’ BBI customer allocations for the relevant BBI by a factor (F) calculated as follows:

where

CA

is the exiting customer’s BBI customer allocation for the relevant BBI immediately before it was set to 0 under subparagraph (i); and

- - (iii) re-calculate all remaining beneficiaries’ benefit-based charges for the relevant BBI based on the remaining beneficiaries’ BBI customer allocations calculated under subparagraph (ii); and
- (b) must not increase—
  - (i) the remaining beneficiaries’ benefit-based charges for the relevant BBI and event pricing year; or
  - (ii) any other transmission charges for the event pricing year, as a consequence of applying subparagraph (a)(i).
(4) The following tables illustrate the application of subclause c to a customer (customer D) exiting regional customer group Y for a post-2019 BBI that is not a resiliency BBI:

Before

regional customer group	beneficiary	regional NPB	intra-regional allocator	individual NPB	BBI customer allocation
X	A	60	1	20	16.67%
X	B	60	2	40	33.33%
Y	C	50	3	30	25.00%
	D		2	20	16.67%
	E		1	10	8.33%

After (subparagraphs (3)(a)(i) and (3)(a)(ii))

regional customer group	beneficiary	regional NPB	intra-regional allocator	individual NPB	BBI customer allocation (scaled by 1/0.8333)
X	A	60	1	20	20.00%
X	B	60	2	40	40.00%
Y	C	50	3	30	30.00%
	D		2	20	0%
	E		1	10	10.00%

(5) In subclauses (6) and (7), a continuing BBI is any of the following BBIs:
- (a) the Bunnythorpe Haywards Appendix A BBI if—
  - (i) the exiting customer was a beneficiary of the Bunnythorpe Haywards Appendix A BBI immediately before ceasing to be a customer; and
  - (ii) the Bunnythorpe Haywards Appendix A BBI was commissioned less than 10 years before the date the exiting customer ceased to be a customer:
- (b) a post-2019 BBI—
  - (i) which is not an anticipatory BBI; and
  - (ii) of which the exiting customer was a beneficiary immediately before ceasing to be a customer; and
  - (iii) in the case of a post-2019 BBI under a standard method or a high-value intervening BBI under the simple method, commissioned or deemed to have been commissioned less than 10 years before the date the exiting customer ceased to be a customer; and
  - (iv) in the case of any other post-2019 BBI under the simple method, commissioned during a simple method period that started less than 12.5 years before the date the exiting customer ceased to be a customer, provided that Transpower must treat all such BBIs commissioned during that simple method period in an investment region as a single continuing BBI in that investment region with a covered cost equal to the aggregate of all such BBIs’ covered costs.
(6) Subclause (7) applies to a continuing BBI until—
- (a) in the case of the Bunnythorpe Haywards Appendix A BBI, a post-2019 BBI under a standard method or a high-value intervening BBI under the simple method, the start of the first pricing year that starts at least 10 years after the continuing BBI’s commissioning date or deemed commissioning date; and
- (b) in the case of any other post-2019 BBI under the simple method, the start of the first pricing year that starts at least 12.5 years after the start of the simple method period during which the continuing BBI was commissioned.
(7) If this subclause applies to a continuing BBI under subclause (6) and a related entity of the exiting customer is a customer after the exiting customer ceases to be a customer—
- (a) subparagraphs (3)(a)(ii) and (3)(a)(iii) do not apply; and
- (b) the exiting customer’s benefit-based charge for the continuing BBI must be attributed (by way of increase) to the related entity in its capacity as a customer. If there is more than 1 related entity, this subclause applies to a related entity determined by Transpower; and
- (c) Transpower must start the related entity’s monthly benefit-based charges attributed under paragraph (b) as soon as reasonably practicable. The related entity’s monthly benefit-based charges may include an adjustment as necessary to ensure the related entity pays its full attributed benefit-based charge for the continuing BBI from the date the exiting customer ceased to be a customer.

Clause 84(5) & (6): replaced, on 17 June 2024, by clause 9 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

85 Benefit-based Charge Adjustment Event: Large Plant Connected or Disconnected

(1) Subject to subclause 81(6), this clause 85 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(d) or 81(1)(e).
(2) Transpower must, for a connecting customer—
- (a) comply with clause 83 as if the large plant had been connected to the grid by a separate new customer (the notional new customer) at—
  - (i) if the large plant is connected to the grid, the connection location where the large plant is connected; or
  - (ii) if the large plant is connected to the connecting customer’s local network, the connection location electrically closest to the large plant’s electrically closest point of connection to the local network, as determined by Transpower; or
  - (iii) if the large plant is connected to the connecting customer’s grid-connected plant, the connection location where the grid-connected plant is connected; and
- (b) attribute (by way of increase) the notional new customer’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for each relevant post-2019 BBI and Appendix A BBI to the connecting customer.
(3) Subject to subclause (6), Transpower must, for a disconnecting customer—
- (a) comply with clause 84 (without regard to subclauses 84(5) to 84(7)) as if the large plant had been disconnected from the grid by a separate exiting customer (the notional exiting customer) at—
  - (i) if the large plant was connected to the grid, the connection location where the large plant was connected; or
  - (ii) if the large plant was connected to the disconnecting customer’s local network, the connection location electrically closest to the large plant’s electrically closest point of connection to the local network before the large plant was disconnected, as determined by Transpower; or
  - (iii) if the large plant was connected to the disconnecting customer’s grid-connected plant, the connection location where the grid-connected plant is connected; and
- (b) attribute (by way of reduction) the notional exiting customer’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for each relevant BBI to the disconnecting customer, provided that the minimum value of the disconnecting customer’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for each relevant BBI is 0.
(4) In subclauses (5) and (6), a continuing BBI is any one of the following BBIs:
- (a) the Bunnythorpe Haywards Appendix A BBI if—
  - (i) the exiting customer was a beneficiary of the Bunnythorpe Haywards Appendix A BBI immediately before ceasing to be a customer; and
  - (ii) the Bunnythorpe Haywards Appendix A BBI was commissioned less than 10 years before the date the exiting customer ceased to be a customer:
- (b) a post-2019 BBI—
  - (i) which is not an anticipatory BBI; and
  - (ii) of which the notional exiting customer was a beneficiary immediately before the disconnection of the large plant; and
  - (iii) in the case of a post-2019 BBI under a standard method or a high-value intervening BBI under the simple method, commissioned or deemed to have been commissioned less than 10 years before the date the large plant was disconnected; and
  - (iv) in the case of any other post-2019 BBI under the simple method, commissioned during a simple method period that started less than 12.5 years before the date the large plant was disconnected, provided that Transpower must treat all such BBIs commissioned during that simple method period in an investment region as a single continuing BBI in that investment region with a covered cost equal to the aggregate of all such BBIs’ covered costs.
(5) Subclause (6) applies to a continuing BBI until—
- (a) in the case of the Bunnythorpe Haywards Appendix A BBI or a post-2019 BBI under a standard method or a high-value intervening BBI under the simple method, the start of the first pricing year that starts at least 10 years after the continuing BBI’s commissioning date or the deemed commissioning date; and
- (b) in the case of any other post-2019 BBI under the simple method, the start of the first pricing year that starts at least 12.5 years after the start of the simple method period during which the continuing BBI was commissioned.
(6) If this subclause applies to a continuing BBI under subclause (5) and the large plant owner or a related entity of the large plant owner (relevant person) is a customer after the disconnection of the large plant—
- (a) subparagraphs 84(3)(a)(ii) and 84(3)(a)(iii) do not apply; and
- (b) the notional exiting customer’s benefit-based charge for the continuing BBI must be attributed (by way of increase) to the relevant person in its capacity as a customer. If there is more than 1 relevant person, this subclause applies to—
  - (i) the large plant owner; or
  - (ii) if the large plant owner is not a customer after the disconnection of the large plant, a related entity determined by Transpower; and
- (c) Transpower must start the relevant person’s monthly benefit-based charges attributed under paragraph (b) as soon as reasonably practicable. The relevant person’s monthly benefit-based charges may include an adjustment as necessary to ensure the relevant person pays its full attributed benefit-based charge for the continuing BBI from the date the large plant was disconnected.

Clause 85(4) & (5): replaced, on 17 June 2024, by clause 10 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Related Amendments) 2024.

86 Benefit-based Charge Adjustment Event: Substantial Sustained Increase

(1) This clause 86 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(f) or 81(1)(g).
(2) Transpower must—
- (a) comply with clause 83 as if the substantial sustained increase were attributable to plant connected to the grid by a separate new customer (the notional new customer) at—
  - (i) if the substantial sustained increase is in electricity consumed or generated by grid-connected plant, the connection location where the grid-connected plant is connected; or
  - (ii) if the substantial sustained increase is in electricity consumed or generated by large embedded plant connected to the increasing customer’s local network, the connection location electrically closest to the large embedded plant’s electrically closest point of connection to the local network, as determined by Transpower; or
  - (iii) if the substantial sustained increase is in electricity consumed or generated by large embedded plant connected to the increasing customer’s grid-connected plant, the connection location where the grid-connected plant is connected; and
- (b) attribute the notional new customer’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for each relevant post-2019 BBI and Appendix A BBI to the increasing customer.

87 Benefit-based Charge Adjustment Event: Distributor Connection at Grid Point of Connection

(1) This clause 87 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(h).
(2) In this clause 87, a relevant BBI is a BBI that has at least 1 regional customer group with positive regional NPB that the connecting distributor became a member of by connecting at the new grid point of connection (and of which the connecting distributor was not a member immediately before connecting at the new grid point of connection).
(3) Transpower must for each relevant BBI (and no other BBIs)—
- (a) comply with clause 83 as if a local network had been connected at the new grid point of connection by a separate new distributor (the notional new distributor), provided that the estimate of the notional new distributor’s intra-regional allocators must take into account any expected reduction in the connecting distributor’s offtake or injection at grid points of connection in other modelled regions as a result of the connection of the connecting customer’s local network at the new grid point of connection (with any such reduction to be set off against the estimate of the notional new distributor’s offtake or injection at the new grid point of connection); and
- (b) attribute the notional new distributor’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for each relevant BBI to the connecting distributor.

Clause 87 Heading: amended, on 31 July 2023, by clause 19 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

88 Benefit-based Charge Adjustment Event: Changed Point of Connection

(1) This clause 88 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(i).
(2) Transpower must—
- (a) apply subclauses 85(2) and 85(3) to calculate the notional new customer’s and notional exiting customer’s BBI customer allocations; and
- (b) identify the BBIs of which both the notional new customer and notional exiting customer are beneficiaries (the relevant BBIs).
(3) If the notional new customer’s BBI customer allocation for a relevant BBI is equal to or more than the notional exiting customer’s BBI customer allocation for the relevant BBI, Transpower must—
- (a) apply paragraph 85(2)(b) for the connecting customer and relevant BBI; and
- (b) apply paragraph 85(3)(b) for the disconnecting customer and relevant BBI (without regard to subclause 85(5)).
(4) If the notional exiting customer’s BBI customer allocation for a relevant BBI is more than the notional new customer’s BBI customer allocation for the relevant BBI, Transpower must—
- (a) apply paragraph 85(2)(b) for the connecting customer and relevant BBI, but by attributing to the connecting customer the notional exiting customer’s BBI customer allocation (and the inputs to its calculation) and benefit-based charge for the relevant BBI instead of the notional new customer’s; and
- (b) apply paragraph 85(3)(b) for the disconnecting customer and relevant BBI (without regard to subclause 85(5)).

89 Benefit-based Charge Adjustment Event: Sale of Business

(1) This clause 89 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(j).
(2) Transpower must, for a sale of part of the vendor’s business—
- (a) determine an apportionment between the vendor and purchaser of the vendor’s BBI customer allocation (and the inputs to its calculation) for the BBI taking into account the size and nature of the transferred business; and
- (b) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s benefit-based charges for the BBI based on the apportionment of the vendor’s BBI customer allocation under paragraph (a); and
- (c) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s cap recovery charge and prudent discount recovery charges for the event pricing year to account for—
  - (i) the vendor’s and purchaser’s annual benefit-based charges calculated under paragraph (b); and
  - (ii) any annual residual charge for the vendor or purchaser calculated under subclause 94(2) or 94(3) in respect of the same sale of business.
(3) Transpower must, for a sale of all of the vendor’s business—
- (a) attribute the vendor’s BBI customer allocation (and the inputs to its calculation) for the BBI to the purchaser; and
- (b) calculate or re-calculate (as the case may be) the purchaser’s benefit-based charge for the BBI based on the attribution of the vendor’s BBI customer allocation under paragraph (a); and
- (c) calculate or re-calculate (as the case may be) the purchaser’s cap recovery charge and prudent discount recovery charges for the event pricing year to account for—
  - (i) the purchaser’s annual benefit-based charge calculated under paragraph (b); and
  - (ii) any annual residual charge for the vendor or purchaser calculated under clause 94(2) or 94(3) in respect of the same sale of business.
(4) Transpower must start the purchaser’s monthly benefit-based charge calculated under paragraph (2)(b) or (3)(b) as soon as reasonably practicable. The purchaser’s monthly benefit-based charge may include an adjustment as necessary to ensure the purchaser pays its full benefit-based charge for the BBI from the date of the transfer.
(5) Transpower is not required to (but may) start the vendor’s monthly benefit-based charge calculated under paragraph (2)(b) during, or from the start of, an exempt pricing year for the vendor. However, any over-recovery of the annual benefit-based charge for the BBI and exempt pricing year resulting from the start of the purchaser’s monthly benefit-based charge for the BBI must be rebated to the vendor by way of an adjustment to its transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

90 Benefit-based Charge Adjustment Event: Voluntary Under-recovery

(1) This clause 90 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(k).
(2) In this clause 90, a relevant pricing year is a pricing year for which Transpower decided to voluntarily under-recover the BBI’s covered cost.
(3) Transpower must, for each relevant pricing year, calculate or re-calculate (as the case may be) all beneficiaries’ benefit-based charges for the BBI to account for the amount of the voluntary under-recovery of the BBI’s covered cost.
(4) If Transpower decides to voluntarily under-recover the BBI’s covered cost for a relevant pricing year during, or within 1 month of the start of, the relevant pricing year, Transpower is not required to (but may) start beneficiaries’ monthly benefit-based charges calculated under subclause (3) during, or from the start of, the relevant pricing year. However, any over-recovery of the BBI’s covered cost for the relevant pricing year (accounting for the voluntary under-recovery) must be rebated, as appropriate, to the beneficiaries by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the relevant pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

91 Benefit-based Charge Adjustment Event: SSCGU

(1) This clause 91 applies in the case of the benefit-based charge adjustment event in paragraph 81(1)(l).
(2) Transpower must—
- (a) determine which post-2019 BBIs, if any, satisfy all of the following conditions (the relevant BBIs):
  - (i) the post-2019 BBI is expected to be high-value at the start of the SSCGU’s start pricing year:
  - (ii) the distribution of regional NPB for the post-2019 BBI is likely to have changed materially as a result of the SSCGU, compared to the distribution of regional NPB for the post-2019 BBI immediately before the SSCGU:
  - (iii) the SSCGU was not a market scenario used to calculate the existing BBI customer allocations for the post-2019 BBI; and
- (b) for each relevant BBI, re-calculate beneficiaries’ BBI customer allocations as if the relevant BBI were a new high-value post-2019 BBI for which—
  - (i) the standard method calculation period starts on the date of the SSCGU; and
  - (ii) the final investment decision date is the date of the SSCGU.
(3) In carrying out the re-calculation under paragraph b.ii, Transpower may use—
- (a) a different standard method than was used to calculate the existing BBI customer allocations for the relevant BBI; or
- (b) different factual, counterfactual, investment grids, system limits, scenarios, modelled regions and regional customer groups than were used to calculate the existing BBI customer allocations for the relevant BBI.
(4) From the SSCGU’s start pricing year, Transpower must calculate beneficiaries’ benefit-based charges for each relevant BBI based on the beneficiaries’ BBI customer allocations for the relevant BBI re-calculated under paragraph (2)(b).

Residual Charges

92 Residual Charge Adjustment Events

(1) The following events are residual charge adjustment events:
- (a) a customer (the exiting load customer) ceases to be a customer:
- (b) a customer (the vendor) sells or otherwise transfers all or part of its business that constitutes it as a load customer to another party (the purchaser):
- (c) Transpower decides to voluntarily under-recover residual revenue.
(2) Transpower must not voluntarily under-recover residual revenue for a pricing year if the effect of doing so would be to increase residual revenue for any other pricing year.
(3) To avoid doubt, a vendor’s sale or other transfer of all or part of its business that constitutes it as a load customer to a purchaser is treated as the residual charge adjustment event in paragraph (1)(b) and not the residual charge adjustment event in paragraph (1)(a), and the purchaser is not treated as a new load customer.

93 Residual Charge Adjustment Event: Exiting Load Customer

(1) This clause 93 applies in the case of the residual charge adjustment event in paragraph 92(1)(a).
(2) Transpower—
- (a) must make the exiting load customer’s AMDR and residual charge 0; and
- (b) must not increase—
  - (i) any other load customer’s residual charge for the event pricing year; or
  - (ii) any other transmission charges for the event pricing year,
- as a consequence of applying paragraph (a).

94 Residual Charge Adjustment Event: Sale of Business

(1) This clause 94 applies in the case of the residual charge adjustment event in paragraph 92(1)(b).
(2) Transpower must, for a sale of part of the vendor’s business—
- (a) determine an apportionment between the vendor and purchaser of the vendor’s AMDR (and the inputs to its calculation) taking into account the size and nature of the transferred business; and
- (b) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s residual charges based on the apportionment of the vendor’s AMDR under paragraph (a) (but not any change in residual revenue that may have occurred during the event pricing year); and
- (c) calculate or re-calculate (as the case may be) the vendor’s and purchaser’s cap recovery charge and prudent discount recovery charges for the event pricing year to account for—
  - (i) the vendor’s and purchaser’s annual residual charges calculated under paragraph (b); and
  - (ii) any annual benefit-based charges for the vendor or purchaser calculated under subclause 89(2) or 89(3) in respect of the same sale of business.
(3) Transpower must, for a sale of all of the vendor’s business—
- (a) attribute the vendor’s AMDR (and the inputs to its calculation) to the purchaser; and
- (b) calculate or re-calculate (as the case may be) the purchaser’s residual charge based on the attribution of the vendor’s AMDR under paragraph (a); and
- (c) calculate or re-calculate (as the case may be) the purchaser’s cap recovery charge and prudent discount recovery charges for the event pricing year to account for—
  - (i) the purchaser’s annual residual charges calculated under paragraph (b); and
  - (ii) any annual benefit-based charges for the vendor or purchaser calculated under subclause 89(2) or 89(3) in respect of the same sale of business.
(4) Transpower must start the purchaser’s monthly residual charge calculated under paragraph (2)(b) or (3)(b) as soon as reasonably practicable. The purchaser’s monthly residual charge may include an adjustment as necessary to ensure the purchaser pays its full residual charge from the date of the transfer.
(5) Transpower is not required to (but may) start the vendor’s monthly residual charge calculated under paragraph (2)(b) during, or from the start of, an exempt pricing year for the vendor. However, any over-recovery of residual revenue for the exempt pricing year resulting from the start of the purchaser’s monthly residual charge must be rebated to the vendor by way of an adjustment to its transmission charges—
- (a) if reasonably practicable, at the end of the exempt pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

95 Residual Charge Adjustment Event: Voluntary Under-recovery

(1) This clause 95 applies in the case of the residual charge adjustment event in paragraph 92(1)(c).
(2) In this clause 95, a relevant pricing year is a pricing year for which Transpower decided to voluntarily under-recover residual revenue.
(3) Transpower must, for each relevant pricing year, calculate or re-calculate (as the case may be) all load customers’ residual charges for the discounted pricing year to account for the amount of the voluntary under-recovery of residual revenue.
(4) If Transpower decides to voluntarily under-recover residual revenue for a relevant pricing year during, or within 1 month of the start of, the relevant pricing year, Transpower is not required to (but may) start load customers’ monthly residual charges calculated under subclause (3) during, or from the start of, the relevant pricing year. However, any over-recovery of residual revenue for the relevant pricing year (accounting for the voluntary under-recovery) must be rebated, as appropriate, to load customers by way of an adjustment to their transmission charges—
- (a) if reasonably practicable, at the end of the relevant pricing year; or
- (b) otherwise, as soon as reasonably practicable during the next pricing year.

Part G Reassignment

96 Effect of Reassignment

If an eligible BBI is reassigned, Transpower must, from the reassignment’s start pricing year—
- (a) reduce the eligible BBI’s covered cost by the eligible BBI’s reassignment amount; and
- (b) calculate beneficiaries’ benefit-based charges for the eligible BBI based on the reduction of the eligible BBI’s covered cost under paragraph (a).

97 Reassignment Amount

The reassignment amount for a reassigned eligible BBI (RA) is calculated as follows:

RA = CC × (1 − RF)

where

CC

is the eligible BBI’s covered cost

RF

is the eligible BBI's reassignment factor.

98 Eligibility for Reassignment

(1) Before or as soon as reasonably practicable after the start of a pricing year, Transpower must publish—
- (a) a list of BBIs that satisfy paragraph (a) of the definition of eligible BBI in clause 3 as at the start of the pricing year; and
- (b) identify which of the listed BBIs are post-2019 BBIs that satisfy subparagraph (b(i) of the definition of eligible BBI in clause 3 as at the start of the pricing year.
(2) The reassignment threshold (RT) for a pricing year is—
- (a) $5 million for the first pricing year; and
- (b) calculated as follows for each pricing year after the first pricing year:

where

CPI

is the average of the quarterly CPIs for the preceding financial year

CPI_base

is the average of the quarterly CPIs for the most recent complete financial year before the start of the first pricing year.

(3) If there is a base adjustment to CPI, the calculation in paragraph (2)(b) is to include an equivalency adjustment to eliminate the impact of the base adjustment.

99 Reassignment Application

(1) If an eligible person wishes for a BBI to be reassigned, the eligible person must submit to Transpower a written application for reassignment that meets the requirements of subclause (2).
(2) An application for reassignment must—
- (a) contain all of the information described in the relevant application requirements; and
- (b) contain reasonable evidence that the conditions for reassignment in this transmission pricing methodology are met; and
- (c) be accompanied by an independent verification of the application.
(3) The eligible person must provide Transpower with any additional information Transpower determines is necessary to enable it to assess the application.

100 Application Screening and Publication

(1) Transpower must reject an application for reassignment without assessing the application further if, when Transpower receives the application—
- (a) the applicant is not an eligible person; or
- (b) the BBI to which the application relates is not an eligible BBI.
(2) Transpower may reject an eligible person’s application for reassignment without assessing the application further—
- (a) under subclause 14(1); or
- (b) if an eligible person has previously applied for reassignment on substantially the same basis as the new application and Transpower—
  - (i) rejected the previous application; and
  - (ii) determines there has not been a change in circumstances since its decision on the previous application that materially increases the likelihood of the new application being approved.
(3) Transpower is not required to consult on any decision to reject an application under subclause (1), (2) or 14(1).
(4) Unless Transpower rejects an application under subclause (1), (2) or 14(1), and subject to clause 106, Transpower must publish the application and any information the eligible person provides to Transpower under subclause 99c.

101 Assessment

(1) In assessing an eligible person’s application for reassignment, Transpower—
- (a) is not obliged to use the information the eligible person provided in or in support of the application; and
- (b) may use any other information relevant to the application.
(2) Transpower must approve the application if Transpower determines that—
- (a) the eligible BBI to which the application relates has a BBI reassignment factor of less than 0.8; and
- (b) the circumstances causing the BBI reassignment factor to be less than 0.8—
  - (i) are reasonably likely to persist for at least 5 years after they occurred; and
  - (ii) have not resulted, and are not reasonably likely to result, in a write-down of assets comprised in the BBI.
(3) Otherwise, Transpower must reject the application.

102 Forecast Peak Loading and Reassignment Factors

(1) The forecast loading period for an eligible BBI the subject of a reassignment application is the period starting on the date Transpower receives the application and ending on the later of—
- (a) 10 years after the date Transpower receives the application; and
- (b) if the eligible BBI is a post-2019 BBI to which subparagraph (b)(i) of the definition of eligible BBI in clause 3 does not apply, 20 years after the eligible BBI’s commissioning date.
(2) Forecast peak loading for a transmission investment comprised in the eligible BBI is the expected future peak electrical loading of the transmission investment over the eligible BBI’s forecast loading period, as determined by Transpower.
(3) The investment reassignment factor for a transmission investment comprised in the eligible BBI is the proportion of the transmission investment’s total replacement cost (adjusted proportionately for any previous write-down of assets comprised in the transmission investment) Transpower determines it would incur to replace the transmission investment with a transmission investment—
- (a) of the same type; and
- (b) with a service potential sufficient to meet the forecast peak loading and reasonable grid contingencies, but no more.
(4) The BBI reassignment factor for the eligible BBI (BRF) is calculated as follows:

where

CC_total

is the eligible BBI’s covered cost for the pricing year during which the application for reassignment was received

CC_i

is the part of the eligible BBI’s covered cost for the pricing year during which the application for reassignment was received attributable to transmission investment i, where transmission investment i is a transmission investment comprised in the eligible BBI

IRF_i

is transmission investment i’s investment reassignment factor.

(5) Transpower may publish in the reassignment practice manual, for 1 or more types of transmission investment in, or in relation to, interconnection assets, information about the relationship between the transmission investment’s forecast peak loading and its investment reassignment factor, which may include 1 or more methods of calculating the investment reassignment factor as a function of forecast peak loading.

103 Consultation on Draft Decision

(1) Subject to subclause 100(3), Transpower must consult with all customers on its draft decision to approve or reject an eligible person’s application for reassignment.
(2) Subject to clause106, Transpower’s consultation under subclause (1) must include the information specified in paragraphs 105(a), 105(b) and 105(c) for the draft decision.

104 Decision and Independent Review

(1) If Transpower decides to approve an eligible person’s application for reassignment, Transpower may approve a different BBI reassignment factor than sought in the application.
(2) Transpower must notify the eligible person whether Transpower approves or rejects the application. Transpower’s notice must include the information specified in paragraphs 105(a), 105(b) and 105(c).
(3) The eligible person may, within 60 days of Transpower notifying the eligible person of Transpower’s decision on the application, refer any aspect of Transpower’s decision to an independent expert for review.
(4) The independent expert’s decision will be binding on Transpower and the eligible person, and will have effect as if Transpower had made the decision itself, except that the eligible person may not refer the decision to an independent expert again.
(5) The costs of the independent expert must be met by the eligible person unless the independent expert decides an aspect of Transpower’s decision under review was unreasonable, in which case Transpower may be required to meet all or some of the costs of the independent expert, as determined by the independent expert.

105 Decision to be Published

Subject to clause 106, as soon as reasonably practicable after the reassignment confirmation date, Transpower must publish—
- (a) its decision to approve or reject the eligible person’s application for reassignment; and
- (b) if Transpower approves the application, the eligible BBI and its BBI reassignment factor; and
- (c) Transpower’s analysis supporting its decision, including any material departures from the assumptions and methodologies in the reassignment practice manual and the reasons for those departures; and
- (d) any report prepared by an independent expert relating to the reassignment.

106 Commercially Sensitive Information

(1) Subject to subclause (2), Transpower is not obliged to publish or otherwise disclose any information under subclause 100(4) or 103(2) or clause 105 if—
- (a) the eligible person identifies the information as commercially sensitive; and
- (b) Transpower determines the disclosure of the information would be likely to commercially disadvantage the eligible person or any other person, in a material manner.
(2) Transpower must always publish under subclause 103(2) and clause 105 at least—
- (a) its draft decision or decision (as the case may be) to approve or reject the eligible person’s application for reassignment; and
- (b) if the application is approved, the eligible BBI and its BBI reassignment factor.

107 Reversal for Increased Forecast Peak Loading

(1) Transpower must fully or partially reverse a reassignment if—
- (a) Transpower determines that the forecast peak loading of 1 or more of the transmission investments comprised in the relevant BBI have increased such that the BBI’s BBI reassignment factor has increased; and
- (b) Transpower determines that the circumstances causing the BBI reassignment factor to have increased are reasonably likely to persist for at least 5 years after they occurred; and
- (c) at the time of the reversal, the total closing RAB value of all assets comprised in the BBI for the most recent complete financial year is at least the reassignment threshold.
(2) If Transpower proposes to fully or partially reverse the reassignment—
- (a) clause 103 applies as if that clause applied to Transpower’s draft decision to reverse the reassignment;
- (b) Transpower must publish its decision on the reversal, including—
  - (i) the BBI’s new BBI adjustment factor; and
  - (ii) Transpower’s analysis supporting its decision, including any material departures from the assumptions and methodologies in the reassignment practice manual and the reasons for those departures;
- (c) an eligible person for the BBI may, within 60 days of Transpower publishing its decision on the reversal, refer any aspect of Transpower’s decision to an independent expert for review, in which cases subclauses 104(4) and 104(5) apply; and
- (d) clauses 105 and 106 apply as if those clauses applied to Transpower’s decision on the reversal and the eligible person referred to in paragraph 106(1)(a) were any eligible person who referred Transpower’s decision to an independent expert under paragraph (c).
(3) If Transpower determines that the BBI’s BBI reassignment factor is 0.8 or more, Transpower must fully reverse the reassignment.
(4) To avoid doubt, all references to the BBI’s BBI reassignment factor in this clause 107 refer to the BBI reassignment factor calculated by reference to the replacement costs of the transmission investments comprised in the BBI without any adjustment for their investment reassignment factors for the current reassignment of the BBI.
(5) A full or partial reversal of reassignment under this clause 107 will have effect from the first pricing year that starts at least 6 months (or such shorter period as Transpower may determine is practicable) after the reassignment confirmation date.

108 Reversal for Subsequent Write-Down

(1) Transpower must fully reverse a reassignment if the circumstances causing the relevant BBI reassignment factor to be less than 0.8 result in a write-down of assets comprised in the relevant BBI.
(2) A reversal of reassignment under subclause (1) will have effect from the first pricing year that starts after the end of the financial year during which the write-down occurred.

109 Application Fees, Application Requirements and Reassignment Practice Manual

(1) Transpower must publish the application requirements and the application fees, if any, for reassignment applications by the start of the first pricing year. Transpower may publish updates to the application requirements and application fees from time to time.
(2) Transpower may from time to time publish, and publish updates to, a reassignment practice manual.
(3) The reassignment practice manual must not contain any assumptions or methodologies that are inconsistent with this Code.
(4) Subject to subclause (5), Transpower must consult with all customers on the reassignment practice manual or any update to it before publishing the reassignment practice manual or update.
(5) Transpower is not required to consult on an update to the reassignment practice manual if Transpower determines—
- (a) the update is technical and non-controversial; or
- (b) there is widespread support for the update among customers; or
- (c) there has been adequate prior consultation on the update so that all relevant views of customers have been considered.
(6) The reassignment practice manual is not binding on Transpower or any independent expert.
(7) Transpower must review the content of the reassignment practice manual and consider whether any of the content is appropriate for incorporation in this transmission pricing methodology by way of a review under clause 12.85 of this Code no later than 7 years after its date of publication and, after that, at intervals of no more than 7 years.
(8) The reassignment practice manual may be part of the same document in which the assumptions book or prudent discount practice manual is contained.

Part H Transitional Price Cap

110 Cap and Cap Condition

(1) Despite anything else in this transmission pricing methodology, a capped customer’s transmission charges for each pricing year preceding pricing year 2038 must be reduced by the minimum amount necessary (if any) to ensure the cap condition is satisfied for the capped customer and pricing year.
(2) The cap condition for a pricing year is:

CC - IC₁₉ - HVDC₁₉ ≤ DC

where

CC

is a capped customer’s capped charges for the pricing year

IC₁₉

is the capped customer’s annual interconnection charge for pricing year 2019 under the previous transmission pricing methodology

HVDC₁₉

is the capped customer’s annual HVDC charge for pricing year 2019 under the previous transmission pricing methodology

DC

is the capped customer’s difference cap for the pricing year.

(3) The cap condition is applied, and the difference cap is calculated, subject to any applicable prudent discount or previous discount that applies or applied at the relevant time.
(4) [Revoked]
(5) The cap condition applies at the start of a pricing year only. The cap condition is not applied again, and difference caps are not re-calculated, if there is an adjustment to transmission charges during the pricing year.
(6) Despite anything else in this clause 110, the cap condition must not result in Transpower recovering less than recoverable revenue for a pricing year. If Transpower determines it is necessary to do so, Transpower may reduce all capped customers’ cap reductions for a pricing year on a pro rata basis to ensure Transpower recovers recoverable revenue for the pricing year (but not more than recoverable revenue for the pricing year).

Clause 110(4): revoked, on 31 July 2023, by clause 20 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

111 Difference Cap

(1) A capped customer’s difference cap for pricing year n (DC_n) is calculated as follows:

DC_n = NEB₁₉ x (0.035 + (0.02 ×N) + ∆CPI_n + ∆TGE_n)

where

NEB₁₉

is the capped customer’s notional electricity bill for pricing year 2019 calculated under subclause (2)

N

is—

0 if the capped customer is a distributor; or

the greater of 0 and n-2024 if the capped customer is a direct consumer

∆CPI_n

is the proportionate change in CPI for pricing year n calculated under subclause (3)

∆TGE_n

is the proportionate increase (if any) in the capped customer’s total gross energy for pricing year n calculated under subclause (5).

(2) A capped customer’s notional electricity bill for pricing year 2019 (NEB19) is calculated as follows:

NEB₁₉ = LC₁₉ + ( P₁₉ x TGE₁₉ )

where

LC₁₉

is—

(a) if the capped customer is a distributor, the capped customer’s “total line charge revenue” for pricing year 2019, as disclosed in the capped customer’s Report on Billed Quantities and Line Charge Revenues (Schedule 8) under the EDB ID determination for its disclosure year ended 31 March 2020; or
(b) if the capped customer is a direct consumer, the capped customer’s total annual transmission charges for pricing year 2019 under the previous transmission pricing methodology

P₁₉

is the volume weighted average of final prices at the capped customer’s connection locations during CMP G, using gross energy per trading period for weighting

TGE₁₉

is the capped customer’s total gross energy for pricing year 2019, being—

(a) if the capped customer is a distributor, the capped customer’s “electricity entering system for supply to consumers’ connection points” for pricing year 2019, as disclosed in the capped customer’s Report on Network Demand (Schedule 9e) under the EDB ID determination for its disclosure year ended 31 March 2020; or
(b) if the capped customer is a direct consumer, as determined by Transpower.

(3) Subject to subclause (4), the proportionate change in CPI for pricing year n (ΔCPI_n) is calculated as follows:

where

CPI_n-2

is the average of the quarterly CPIs for pricing year n-2

CPI₁₉

is 1041.75, being the average of the quarterly CPIs for pricing year 2019.

(4) If there is a base adjustment to CPI, the calculation in subclause (3) is to include an equivalency adjustment to eliminate the impact of the base adjustment.
(5) The proportionate increase (if any) in a capped customer’s total gross energy for pricing year n (ΔTGEn) is calculated as follows:

where

TGE_n-2

is the capped customer’s total gross energy for pricing year n-2, being—

(a) if the capped customer is a distributor, the capped customer’s “electricity entering system for supply to consumers’ connection points” for pricing year n2, as disclosed in the capped customer’s Report on Network Demand (Schedule 9e) under the EDB ID determination for its disclosure year ended 31 March of year n-1; or
(b) if the capped customer is a direct consumer, as determined by Transpower.

TGE₁₉

is as defined in subclause (2) for the capped customer.

112 Cap Recovery Charge

(1) Only customers who do not receive a cap reduction for a pricing year pay a cap recovery charge for the pricing year.
(2) A customer’s annual cap recovery charge for a pricing year (ACRC) is calculated as follows:

where

CR_total

is the total of all customers’ cap reductions for the pricing year

CRRC

is the customer’s cap recovery-relevant charges for the pricing year

CRRC_total

is the total of all customers’ cap recovery-relevant charges for the pricing year, excluding cap-recovery relevant charges for customers who receive a cap reduction for the pricing year.

(3) A customer’s monthly cap recovery charge for a pricing year (MCRC) is calculated as follows:

where

ACRC

is the customer’s annual cap recovery charge for the pricing year.

(4) Except as otherwise stated in this transmission pricing methodology, cap recovery charges—
- (a) are calculated at the start of a pricing year only; and
- (b) are not re-calculated during a pricing year if there is an adjustment to other transmission charges during the pricing year.

Clause 112: replaced, on 31 July 2023, by clause 21 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

Part I Prudent Discount Policy

General

113 Effect of Prudent Discount Agreements

Despite anything else in this transmission pricing methodology, a prudent discount recipient’s transmission charges are subject to its prudent discount agreement.

114 Prudent Discount Applications

(1) If a customer wishes to receive a prudent discount, the customer must submit to Transpower a written application for the prudent discount that meets the requirements of subclause (2).
(2) The application must—
- (a) contain all of the information described in the relevant application requirements; and
- (b) contain reasonable evidence that the conditions for obtaining the prudent discount in this transmission pricing methodology are met; and
- (c) include at least the level of detail a prudent board of directors of a company would reasonably expect when assessing an investment proposal for the alternative project proposed in the application; and
- (d) be accompanied by an independent verification of the application.
(3) The customer must provide Transpower with any additional information Transpower determines is necessary to enable it to assess the application.

115 Application Screening and Publication

(1) Transpower must reject an application for a prudent discount without assessing the application further if the applicant is not a customer.
(2) Transpower may reject a customer’s application for a prudent discount without assessing the application further—
- (a) under subclause 14(1); or
- (b) if a customer has previously applied for a prudent discount on substantially the same basis as the new application and Transpower—
  - (i) rejected the previous application; and
  - (ii) determines there has not been a change in circumstances since its decision on the previous application that materially increases the likelihood of the new application being approved.
(3) Transpower is not required to consult on any decision to reject an application under subclause (1), (2) or 14(1).
(4) Unless Transpower rejects an application under subclause (1), (2) or 14(1), and subject to clause 125, Transpower must publish the application and any information the customer provides to Transpower under subclause 114(3).

116 Assessment

(1) In assessing a customer’s application for a prudent discount, Transpower—
- (a) is not obliged to use the information the customer provided in or in support of the application, but must not assess an alternative project that is not the alternative project proposed in the application; and
- (b) may use any other information relevant to the application.
(2) In assessing whether the alternative project would provide the same or a substantially similar level of service to the customer as the transmission services it currently receives, Transpower must consider—
- (a) access to electricity, including access to security of supply; and
- (b) electricity quality, reliability and security; and
- (c) any other service measures for transmission services Transpower determines are relevant.

117 Calculation of Alternative Project Costs

(1) The alternative project costs for an alternative project are the capital, operating, maintenance and overhead costs of the alternative project, as would be incurred by:
- (a) the customer, in the case of an inefficient bypass prudent discount; or
- (b) an efficient transmission services provider, in the case of a stand-alone cost prudent discount.
(2) For the purposes of calculating the alternative project costs—
- (a) the value of any increase or decrease in electrical losses that would result from the alternative project must be included as an operating cost of the alternative project (with a decrease being treated as a negative cost); and
- (b) an efficient transmission services provider is assumed not to have any of Transpower’s historic statutory rights in respect of works or activities.

118 Assessment of Commercial Viability

(1) The alternative project proposed in a customer’s application for a prudent discount is only commercially viable if it is reasonably likely that:

where

PVAPC

is the present value of the alternative project costs for the alternative project calculated under subclause (2)

PVATC

is the present value of the customer’s avoided charges calculated under subclause (2)

(2) In calculating the present values under subclause (1) (PV), Transpower must use the formula:

where

A_n

are the alternative project costs or avoided charges (as the case may be) for year n of the relevant prudent discount calculation period

r

is the relevant prudent discount rate, which must be pre-tax if the cash flows being discounted are pre-tax and post-tax if the cash flows being discounted are post-tax.

(3) To avoid doubt—
- (a) the calculation under subclause (2) does not assume the alternative project is fully amortised over the prudent discount calculation period; and
- (b) any residual value of the alternative project at the end of the prudent discount calculation period is ignored in the calculation under subclause (2).

Clause 118(1) and (2): amended, on 31 July 2023, by clause 22 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

119 Consultation on Draft Decision

(1) Subject to subclause 115(3), Transpower must consult with all customers on its draft decision to approve or reject a customer’s application for a prudent discount.
(2) Subject to clause 125, Transpower’s consultation under subclause (1) must include—
- (a) the information specified in paragraphs 124(a) and 124(c) and subparagraph 124(b)(i) for the draft decision; and
- (b) if Transpower proposes to approve the application, the terms of the proposed prudent discount agreement specified in subparagraphs 125(2)(b)(ii), 125(2)(b)(iii) and 125(2)(b)(iv).

120 Decision and Independent Review

(1) If Transpower decides to approve a customer’s application for a prudent discount, Transpower may—
- (a) approve different terms of the prudent discount than sought in the application, including a different amount of the prudent discount; and
- (b) approve the application subject to reasonable conditions.
(2) Transpower must notify the customer whether Transpower approves or rejects the application. Transpower’s notice must include—
- (a) the information specified in paragraphs 124(a) and 124(c) and subparagraph 124(b)(i); and
- (b) if Transpower approves the application, the terms of the proposed prudent discount agreement specified in subparagraphs 125(2)(b)(ii), 125(2)(b)(iii) and 125(2)(b)(iv).
(3) The customer may, within 60 days of Transpower notifying the customer of Transpower's decision on the application, refer any aspect of Transpower’s decision to an independent expert for review.
(4) The independent expert’s decision will be binding on Transpower and the customer, and will have effect as if Transpower had made the decision itself, except that the customer may not refer the decision to an independent expert again.
(5) The costs of the independent expert must be met by the customer unless the independent expert decides an aspect of Transpower’s decision under review was unreasonable, in which case Transpower may be required to meet all or some of the costs of the independent expert, as determined by the independent expert.

121 Prudent Discount Agreement

(1) If Transpower approves a customer’s application for a prudent discount, Transpower must promptly offer a prudent discount agreement to the customer.
(2) The prudent discount agreement must provide for—
- (a) the prudent discount agreement to be of no effect unless and until all of the conditions precedent of Transpower’s approval (if any) are satisfied; and
- (b) the customer to pay Transpower an annuity, calculated under clause 123, in monthly instalments; and
- (c) Transpower to calculate the customer’s transmission charges in accordance with clause 132 or 137, as applicable; and
- (d) Transpower to have the right to terminate the prudent discount agreement immediately if any condition subsequent of Transpower’s approval is not, or ceases to be, satisfied; and
- (e) the customer to have the right to terminate the prudent discount agreement at the start of a pricing year by notifying Transpower at least 6 months before the start of the pricing year.
(3) The term of the prudent discount agreement must be the same as the relevant prudent discount calculation period, subject to—
- (a) satisfaction of all conditions precedent of Transpower’s approval (if any); and
- (b) earlier termination in accordance with the terms of the prudent discount agreement.
- To avoid doubt, the term of the prudent discount agreement must start on the prudent discount’s start pricing year, subject to satisfaction of all conditions precedent of Transpower’s approval (if any).
(4) The annuity payable to Transpower by a customer under a prudent discount agreement is deemed to be a charge payable to Transpower under this transmission pricing methodology for transmission services provided to the customer.

122 Back-dated Prudent Discounts

(1) This clause 122 back-dates the start pricing year for a back-dated prudent discount and provides for a wash-up of the prudent discount recipient's transmission charges as necessary to give effect to that back-dating.
(2) The start pricing year for a back-dated prudent discount is the first pricing year.
(3) If a back-dated prudent discount is not reflected in the transmission charges for the back-dated prudent discount’s start pricing year or any later pricing year during the term of the relevant prudent discount agreement (a relevant pricing year), Transpower must carry out a wash-up of the prudent discount recipient’s transmission charges for each relevant pricing year so that the prudent discount recipient is not over-charged transmission charges for the relevant pricing years. The wash-up—
- (a) must be carried out in the earliest practicable pricing year; and
- (b) must include a time value of money adjustment using Transpower’s ID WACC (pre-tax); and
- (c) must not include a wash-up of transmission charges for any customer who is not the prudent discount recipient.
(4) To avoid doubt, there is no wash-up under subclause (3) for a relevant pricing year if all conditions precedent of Transpower’s approval of the back-dated prudent discount (if any) are not satisfied before or during the relevant pricing year.

123 Calculation of Annuity

The annuity under a prudent discount agreement (AN) is levelised and calculated as follows:

where

N

is the number of years in the relevant prudent discount calculation period, with each such year being year n

PVAPC

is the present value of the alternative project costs for the relevant alternative project calculated under subclause 118(2)

r

is the relevant prudent discount rate, which must be pre-tax if the present value of the alternative project costs for the alternative project is pre-tax and post-tax if the present value of the alternative project costs for the alternative project is post-tax.

124 Decision to be Published

Subject to clause 125, as soon as reasonably practicable after the prudent discount confirmation date, Transpower must publish—
- (a) its decision to approve or reject the customer’s application for the prudent discount; and
- (b) if Transpower approves the application—
  - (i) any conditions of its approval; and
  - (ii) a copy of the relevant prudent discount agreement; and
- (c) its analysis supporting its decision, including any material departures from the assumptions and methodologies in the prudent discount practice manual and the reasons for those departures; and
- (d) any report prepared by an independent expert relating to the prudent discount.

125 Commercially Sensitive Information

(1) Subject to subclause (2), Transpower is not obliged to publish any information under subclause 115(4) or 119(2) or clause 124 if—
- (a) the customer identifies the information as commercially sensitive; and
- (b) Transpower determines the disclosure of the information would be likely to commercially disadvantage the customer or any other person, in a material manner.
(2) Transpower must always publish under subclause 119(2) and clause 124 at least—
- (a) its draft decision or decision (as the case may be) to approve or reject the customer’s application for the prudent discount; and
- (b) if Transpower approves the application—
  - (i) reasonable details of the alternative project and alternative project costs; and
  - (ii) the annuity under the prudent discount agreement and details of how it was calculated; and
  - (iii) details of how the prudent discount recipient’s transmission charges will be calculated under the prudent discount agreement; and
  - (iv) the term of the prudent discount agreement.

126 Application Fees, Application Requirements and Prudent Discount Practice Manual

(1) Transpower must publish the application requirements and the application fees, if any, for prudent discount applications by the start of the first pricing year. Transpower may publish updates to the application requirements and application fees from time to time.
(2) Transpower must publish, and may from time to time publish updates to, a prudent discount practice manual.
(3) The prudent discount practice manual must not contain any assumptions or methodologies that are inconsistent with this Code.
(4) Subject to subclause (5), Transpower must consult with all customers on the prudent discount practice manual or any update to it before publishing the prudent discount practice manual or update.
(5) Transpower is not required to consult on an update to the prudent discount practice manual if Transpower determines—
- (a) the update is technical and non-controversial; or
- (b) there is widespread support for the update among customers; or
- (c) there has been adequate prior consultation on the update so that all relevant views of customers have been considered.
(6) The prudent discount practice manual is not binding on Transpower or any independent expert.
(7) Transpower must review the content of the prudent discount practice manual and consider whether any of the content is appropriate for incorporation in this transmission pricing methodology by way of a review under clause 12.85 of this Code no later than 7 years after its date of publication and, after that, at intervals of no more than 7 years.
(8) The prudent discount practice manual may be part of the same document in which the assumptions book or reassignment practice manual is contained.

Inefficient Bypass Prudent Discount

127 Purpose of Inefficient Bypass Prudent Discount

The purpose of an inefficient bypass prudent discount is to help ensure this transmission pricing methodology does not provide incentives for a customer to invest in an alternative project that would allow a customer to reduce its own transmission charges, by bypassing existing grid assets, while increasing total economic costs.

128 Multiple Benefitting Customers

If there is more than 1 benefitting customer for an application for an inefficient bypass prudent discount—
- (a) all references to the applicant customer or prudent discount recipient in clauses 113 to 132 and 138 are deemed to include every benefitting customer; and
- (b) without limiting paragraph (a)—
  - (i) the commercial viability test in clause 118 must be applied using the total avoided charges of all benefitting customers; and
  - (ii) the inefficiency test in subclause 130(2) must be applied using Transpower’s costs of providing transmission services to all benefitting customers; and
- (c) the highest prudent discount rate across the benefitting customers applies to the application.

Clause 128(b)(i): amended, on 31 July 2023, by clause 23 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

129 Assessment of Equivalence, Feasibility and Commercial Viability

Transpower must assess whether the alternative project for an inefficient bypass prudent discount—

(a) would provide the customer with the same or a substantially similar level of service as the transmission services the customer currently receives from the grid assets the alternative project would bypass; and
(b) is technically feasible using present day technology and construction methods, including that it is feasible for the customer to obtain the necessary resource consents and property rights for the alternative project; and
(c) is operationally feasible, including that the alternative project is compliant with applicable asset owner performance obligations, technical codes and any other requirements in Part 8 of this Code; and
(d) is otherwise consistent with GEIP; and
(e) is commercially viable under clause 118.

Clause 129(e): amended, on 31 July 2023, by clause 24 of the Electricity Industry Participation Code Amendment (Transmission Pricing Methodology Amendments) 2023.

130 Assessment whether the Alternative Project is Inefficient

(1) If Transpower determines the alternative project for an inefficient bypass prudent discount satisfies all of the criteria in clause 129, Transpower must assess whether the alternative project is inefficient under subclause (2)
(2) The alternative project is only inefficient if it is reasonably likely that—

PVAPC > (PVTC_{no ap} - PVTC_ap)

where

PVAPC

is the present value of the capital, operating, maintenance and overhead costs of the alternative project, including, but not limited to, the alternative project costs

PVTC_{no ap}

is the present value of Transpower’s capital, operating, maintenance and overhead costs of providing transmission services to the customer at the required service levels, including the cost of future transmission investments, without the alternative project calculated under subclause (3)

PVTC_ap

is the present value of Transpower’s capital, operating, maintenance and overhead costs of providing transmission services to the customer at the required service levels, including the cost of future transmission investments, with the alternative project calculated under subclause (3).

(3) In calculating the present values under subclause (2) (PV), Transpower must use the formula:

where

C_n

is the relevant costs for year n of the relevant prudent discount calculation period

r

is the relevant prudent discount rate, which must be pre-tax if the cash flows being discounted are pre-tax and post-tax if the cash flows being discounted are post-tax.

131 Approval or Rejection of Inefficient Bypass Prudent Discount Application

(1) Transpower must approve a customer’s application for an inefficient bypass prudent discount if Transpower determines—
- (a)the alternative project for the application satisfies all of the criteria in clause 129; and
- (b)the alternative project is inefficient under subclause 130(2).
(2) Otherwise, Transpower must reject the application.

132 Impact on Transmission Charges

A prudent discount agreement for an inefficient bypass prudent discount must provide for Transpower to calculate the prudent discount recipient’s transmission charges during the term of the prudent discount agreement as if the relevant alternative project had been implemented, assuming none of its alternative project costs would be recovered through transmission charges.

Stand-alone Cost Prudent Discount

133 Purpose of Stand-alone Cost Prudent Discount

The purpose of a stand-alone cost prudent discount is to help ensure this transmission pricing methodology does not result in a customer paying transmission charges that exceed the efficient stand-alone cost of the transmission services the customer currently receives. A stand-alone cost prudent discount achieves this by replacing the prudent discount recipient’s connection charges, benefit-based charges and residual charge with an annuity under a prudent discount agreement equal to the alternative project costs of an efficient stand-alone investment.

134 Assessment of Equivalence, Feasibility and Commercial Viability

(1) Transpower must assess whether the alternative project for a stand-alone cost prudent discount—
- (a) is an efficient stand-alone investment that would provide the customer with the same or a substantially similar level of service as the transmission services the customer currently receives; and
- (b) subject to subclause (2), is technically feasible using present day technology and construction methods; and
- (c) is operationally feasible, including that the alternative project is compliant with applicable asset owner performance obligations, technical codes and any other requirements in Part 8 of this Code; and
- (d) is otherwise consistent with GEIP; and
- (e) is commercially viable under clause 118.
(2) The alternative project is technically feasible even if it is not feasible to obtain any or all of the necessary resource consents and property rights for the alternative project, provided that the alternative project is technically feasible in all other respects. In calculating the alternative project costs, Transpower must use estimates of the likely cost of obtaining any resource consents and property rights that are not feasible to obtain based on the cost of obtaining broadly equivalent resource consents and property rights for feasible activities in feasible locations.
(3) In calculating the alternative project costs, Transpower must value any optimised grid that forms part of the alternative project in a way that accounts for depreciation according to the age of the part of the existing grid that is optimised.
(4) To avoid doubt, Transpower must carry out the assessment under subclause (1) on a single customer basis.

135 Assessment of Efficient Stand-alone Investment

(1) An efficient stand-alone investment is an investment in the grid, 1 or more transmission alternatives, or a combination of both that an efficient transmission services provider would make to supply transmission services solely to the customer who has applied for a stand-alone cost prudent discount, assessed by—
- (a) using the existing grid, existing transmission alternatives and the customer’s existing grid points of connection as a starting point; and
- (b) applying optimisation tests to the grid and transmission alternatives to identify, in the single-customer hypothetical, stranded grid assets and transmission alternatives, excess capacity in grid assets and transmission alternatives, and other grid and transmission alternative over-engineering.
(2) The efficient stand-alone investment does not need to be in the same location or follow the same route as the existing grid or existing transmission alternatives.

136 Approval or Rejection of Stand-alone Cost Prudent Discount Application

(1) Transpower must approve a customer’s application for a stand-alone cost prudent discount if Transpower determines the alternative project for the application satisfies all of the criteria in subclause 134(1).
(2) Otherwise, Transpower must reject the application.

137 Impact on Transmission Charges

A prudent discount agreement for a stand-alone cost prudent discount—
- (a) must provide for the prudent discount recipient’s connection charges, benefit-based charges and residual charge to be 0 during the term of the prudent discount agreement; and
- (b) must not provide for a change to any other transmission charge.

Prudent Discount Recovery

138 Prudent Discount Recovery Charges

(1) The amount of a prudent discount is recovered by Transpower through—
- (a) BBI prudent discount recovery charges, which—
  - (i) recover the part of the amount of the prudent discount deemed to relate to discounted BBIs; and
  - (ii) are paid by the beneficiaries of the discounted BBIs other than the prudent discount recipient; and
- (b) residual prudent discount recovery charges, which
  - (i) recover the part of the amount of the prudent discount not recovered by BBI prudent discount recovery charges (if any); and
  - (ii) are paid by the load customers other than the prudent discount recipient.
(2) Subject to subclause (4), customer c’s BBI prudent discount recovery charge for discounted BBI b and a pricing year (BPDScb), where customer c is a beneficiary of discounted BBI b and not the prudent discount recipient, is calculated as follows:

where

PD

is the amount of the relevant prudent discount for the pricing year

BBC_{recipient b}

is the prudent discount recipient’s annual benefit-based charge for discounted BBI b and the pricing year without the prudent discount

BBC_{recipient k}

is the prudent discount recipient’s annual benefit-based charge for discounted BBI k for the pricing year without the prudent discount, where discounted BBI k is a discounted BBI for the prudent discount (including discounted BBI b)

RC_recipient

is—

(a) if the prudent discount includes any discount to the prudent discount recipient’s residual charge or connection charges, the prudent discount recipient’s annual residual charge for the pricing year without the prudent discount; or
(b) otherwise, 0

BBC_cb

is customer c’s annual benefit-based charge for discounted BBI b and the pricing year

BBC_jb

is customer j’s annual benefit-based charge for discounted BBI b and the pricing year, where customer j is a beneficiary of discounted BBI b and not the prudent discount recipient (including customer c).

(3) Subject to subclause (4), customer c’s residual prudent discount recovery charge for a prudent discount and pricing year (RPDSc), where customer c is a load customer and not the prudent discount recipient, is calculated as follows:

where

PD

is the amount of the prudent discount for the pricing year

BPDS

is the part of the amount of the prudent discount to be recovered through BBI prudent discount recovery charges for the pricing year

RC_c

is customer c’s annual residual charge for the pricing year

RC_j

is customer j’s annual residual charge for the pricing year, where customer j is not the prudent discount recipient (including customer c).

(4) The minimum value of a BBI prudent discount recovery charge or residual prudent discount recovery charge is 0.
(5) A customer’s annual prudent discount recovery charge for a pricing year (APDRC) is the sum of the customer’s BBI prudent discount recovery charges and residual prudent discount recovery charges for the pricing year.
(6) A customer’s monthly prudent discount recovery charge for a pricing year (MPDRC) is calculated as follows:

where

APDRC

is the customer’s annual prudent discount recovery charge for the pricing year.

(7) Except as otherwise stated in this transmission pricing methodology, prudent discount recovery charges—
- (a) are calculated at the start of a pricing year only; and
- (b) are not re-calculated during a pricing year if there is an adjustment to other transmission charges during the pricing year.

Appendix A

BBIs and Starting BBI Customer Allocations

A

Customer	Bunnythorpe Haywards	HVDC	LSI Reliability	LSI Renewables	NIGU	UNIDRS	Wairakei Ring
Alpine Energy Ltd	3.09%	0.86%	1.50%	2.99%	0.30%	0.30%	0.24%
Aurora Energy Ltd	5.67%	1.57%	0.91%	4.50%	0.30%	0.30%	0.27%
Beach Energy Resources NZ (Holdings) Ltd	0.03%	0.07%	0.10%	0.08%	0.03%	0.03%	0.04%
Buller Electricity Ltd	0.26%	0.08%	0.08%	0.19%	0.01%	0.01%	0.01%
Centralines Ltd	0.07%	0.21%	0.24%	0.17%	0.05%	0.05%	0.01%
Contact Energy Ltd	2.09%	12.58%	24.11%	0.09%	5.92%	5.92%	21.38%
Counties Energy Ltd	0.31%	1.06%	1.09%	0.85%	2.62%	2.62%	1.42%
Daiken Southland Ltd	0.27%	0.09%	1.39%	0.28%	0.02%	0.02%	0.02%
EA Networks Ltd	1.69%	0.51%	0.76%	1.72%	0.26%	0.26%	0.15%
Eastland Network Ltd	0.17%	0.35%	0.57%	0.41%	0.05%	0.05%	0.00%
Electra Ltd	2.60%	0.55%	0.65%	0.45%	0.11%	0.11%	0.09%
Genesis Energy Ltd	1.21%	3.24%	0.00%	0.03%	3.65%	3.65%	7.69%
GTL Energy (New Zealand) Pty Ltd	0.00%	0.00%	0.01%	0.00%	0.00%	0.00%	0.00%
Horizon Energy Distribution Ltd	0.23%	0.24%	0.37%	0.43%	0.04%	0.04%	0.00%
KiwiRail Holdings Ltd	0.03%	0.07%	0.11%	0.08%	0.20%	0.20%	0.12%
Mainpower New Zealand Ltd	3.19%	0.88%	1.29%	2.96%	0.24%	0.24%	0.20%
Manawa Energy Ltd	0.00%	0.65%	0.00%	0.01%	0.16%	0.16%	1.15%
Marlborough Lines Ltd	2.02%	0.45%	0.87%	1.88%	0.15%	0.15%	0.13%
Mercury NZ Ltd	0.70%	0.06%	0.09%	0.07%	6.80%	6.80%	10.73%
Mercury SPV Ltd	0.38%	0.02%	0.00%	0.00%	0.25%	0.25%	0.00%
Meridian Energy Ltd	0.23%	33.80%	1.11%	0.05%	7.32%	7.32%	0.00%
Methanex New Zealand Ltd	0.03%	0.06%	0.09%	0.07%	0.03%	0.03%	0.04%
Nelson Electricity Ltd	0.28%	0.06%	0.12%	0.23%	0.02%	0.02%	0.02%
Network Tasman Ltd	3.04%	0.71%	1.35%	2.58%	0.20%	0.20%	0.17%
Network Waitaki Ltd	1.12%	0.36%	0.53%	2.17%	0.13%	0.13%	0.08%
New Zealand Aluminium Smelters Ltd	21.91%	7.27%	2.14%	23.72%	1.60%	1.60%	1.62%
New Zealand Steel Ltd	0.30%	0.51%	0.97%	0.85%	2.46%	2.46%	1.34%
Nga Awa Purua Joint Venture	0.00%	0.00%	0.00%	0.00%	0.97%	0.97%	8.06%
Ngatamariki Geothermal Ltd	0.01%	0.00%	0.00%	0.00%	0.59%	0.59%	4.89%
Norske Skog Tasman Ltd	0.00%	0.00%	0.00%	0.00%	0.18%	0.18%	2.48%
Northpower Ltd	0.66%	1.13%	2.17%	1.79%	5.96%	5.96%	2.92%
Nova Energy Ltd	0.04%	0.00%	0.00%	0.00%	0.03%	0.03%	0.00%
OMV NZ Production Ltd	0.04%	0.10%	0.14%	0.12%	0.04%	0.04%	0.06%
Orion New Zealand Ltd	18.12%	4.90%	7.20%	14.77%	1.14%	1.14%	1.00%
Pan Pac Forest Product Ltd	0.34%	0.47%	0.77%	0.70%	0.10%	0.10%	0.00%
Powerco Ltd	4.00%	6.27%	8.60%	6.73%	1.90%	1.90%	3.61%
Powernet Ltd	5.35%	1.38%	10.60%	6.36%	0.38%	0.38%	0.35%
Scanpower Ltd	0.05%	0.15%	0.17%	0.12%	0.03%	0.03%	0.03%
Southern Generation GP Ltd	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Southpark Utilities Ltd	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Tararua Wind Power Ltd	0.26%	0.01%	0.00%	0.00%	0.16%	0.16%	0.00%
The Lines Company Ltd	0.16%	0.36%	0.47%	0.37%	0.18%	0.18%	0.49%
Todd Generation Taranaki Ltd	0.49%	0.18%	0.00%	0.03%	0.52%	0.52%	0.00%
Top Energy Ltd	0.00%	0.24%	0.00%	0.00%	1.08%	1.08%	0.52%
Unison Networks Ltd	0.63%	1.34%	2.20%	1.61%	0.16%	0.16%	0.00%
Vector Ltd	5.48%	10.79%	19.06%	14.45%	51.10%	51.10%	24.57%
Waipa Networks Ltd	0.25%	0.59%	0.82%	0.64%	0.33%	0.33%	1.02%
Waverley Wind Farm Ltd	0.23%	0.01%	0.00%	0.00%	0.15%	0.15%	0.00%
WEL Networks Ltd	0.51%	1.13%	1.82%	1.41%	1.13%	1.13%	2.38%
Wellington Electricity Lines Ltd	11.76%	4.25%	4.93%	3.23%	0.83%	0.83%	0.66%
Westpower Ltd	0.40%	0.09%	0.18%	0.46%	0.04%	0.04%	0.03%
Whareroa Co-generation Ltd	0.10%	0.03%	0.00%	0.00%	0.02%	0.02%	0.00%
Winstone Pulp International Ltd	0.16%	0.29%	0.43%	0.36%	0.07%	0.07%	0.00%

Schedule 12.5

cls 12.119 and 120

Availability and reliability index measures

Asset type	Asset category		Planned unavailability	Unplanned unavailability	Number of planned interruptions	Planned unserved energy MWh	Number of unplanned interruptions	Unplanned unserved energy MWh
Interconnection transformer branches	220/110 kV interconnecting transformers and associated equipment		1.56%	0.06%	0.03	0.10	0.02	0.72
	220/066 kV interconnecting transformers and associated equipment		0.66%	0.02%	0.00	0.00	0.00	0.00
	110/066 kV interconnecting transformers and associated equipment		2.25%	0.02%	0.00	0.00	0.00	0.00
Interconnection circuit branches	220 kV interconnection circuit branches and associated line end equipment		0.88%	0.05%	0.00	0.00	0.13	9.87
	110 kV interconnection circuit branches and associated line end equipment		1.67%	0.07%	0.08	0.50	0.28	10.45
	66 kV interconnection circuit branches and associated line end equipment		1.25%	0.08%	0.14	0.46	1.31	1.88
Shunt assets	Capacitor banks and associated equipment	High (220kV- 66kV)	0.81%	1.33%	0.00	0.00	0.02	0.03
	Capacitor banks and associated equipment	Low (33kV- 11kV)	0.81%	1.33%	0.00	0.00	0.02	0.03
	Reactors and associated equipment		1.33%	0.31%	0.00	0.00	0.00	0.00
	Synchronous condensers and associated equipment		2.00%	1.00%	0.00	0.00	0.00	0.00
	Dynamic reactive power compensation devices and associated equipment		0.82%	0 .04%	0.00	0.00	0.00	0.00
	Filter banks and associated equipment		1.03%	1.71%	0.00	0.00	0.00	0.00
HVDC Link Pole 2	One category including associated equipment		1.27%	0.51%	0.00	0.00	0.20	0.85

Compare: Electricity Governance Rules 2003 schedule F6A part F

Schedule 12.5 Table, column 2, row 11: amended, on 1 May 2025, by clause 24 of the Electricity Industry Participation Code Amendment (Common Quality Related Amendments) 2025.

Schedule 12.6

cl 1.1

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Electricity Industry Participation Code 2010