· XLS file · Web view2016-12-19 · 6/30/2016. Arial" 0 Commerce Commission Information Disclosure Template Arial" 0 Arial" 0 Arial" 0 . 1. Commerce Commission Transpower Information

Commerce Commission Transpower Information Disclosure Template

Tab name: CoverSheet 05/09/2023

Transpower Information Disclosure Schedules F1-6, G1-8, SO1with additional schedules added by Transpower

Disclosure Year (year ended) 42551 -1409d mmmm yyyy

28th February 2014


Tab name: Table of Contents 05/09/2023

TRANSPOWER INFORMATION DISCLOSURETable of Contents

ComplianceDirectors' Certificate (dated 19 October 2016) Transpower-inserted tabDirectors' Certificate (dated 14 December 2016) Transpower-inserted tabAssurance Report (dated 16 December 2016) Transpower-inserted tab

Financial InformationF1 Value of the Regulatory Asset Base (RAB Roll Forward)F1b Value of the Regulatory Asset Base (RAB Roll Forward) - IPP/GAAP amounts and adjusting calculations Transpower-inserted tab

F2 Operating Expenditure (Opex): ActualsF3 Base Capital Expenditure (Base Capex): CommissionedF4 Actuals v Forecasts (Opex and Base Capex)F5 Major Capital Expenditure (Major Capex)TP1 ROI and profit calculations required by paragraphs 8.6 to 8.13 Transpower-inserted tabTP2 Major project costs required by paragraph 8.19.1 Transpower-inserted tabTP3 Major project timing required by paragraph 8.19.2 Transpower-inserted tabTP4 Fully commissioned project details required by paragraph 8.20 Transpower-inserted tabTP5 Related party transactions Transpower-inserted tabF6 Transmission Revenue (Actual Totals and Detail)TP6 Investment contracts Transpower-inserted tabGrid Management InformationG1 CircuitsG2 Grid Demand and InjectionG3 Grid Exit Point (GXP) Connection Capacity and Demand (Actual and Forecast)G4 Quality of Supply: Grid Outputs and Performance MeasuresG5 Quality of Supply: Interconnection AssetsG6 Asset Health, Age and Changes See note belowG7 Asset Management Maturity Assessment Tool (AMMAT) See note belowG8 AMMAT Results Summary See note belowSystem OperatorSO1. System Operator

Note: The Information Disclosure Determination requires that Schedules G6, G7 and G8 are published "in or as a companion to the integrated transmission plan", which had a publication deadline of 30 September 2016. We have obtained an exemption from the Commerce Commission allowing us to publish these schedules in this document together with the bulk of the Information Disclosures, which had a publication deadline of 21 October 2016. We published our integrated transmission plan on 8 September 2016.


Tab name: Revision History 05/09/2023

TRANSPOWER INFORMATION DISCLOSURE SCHEDULESRevision History

Revision Date Description of Revision / Changes 1 28/02/2014 Determination issued


Tab name: Guidelines 05/09/2023

Disclosure Template Guidelines

Disclosure Template Guidelines for Information EntryThese templates have been prepared for use byTranspower when making disclosures under the Transpower Information Disclosure Determination 2014.

Data Entry Cells and Calculated Cells

Inserting Additional RowsThe templates for schedules F3, F6,G3, and SO1 may require additional rows to be inserted in tables marked 'include additional rows if needed' or similar. Additional rows must be inserted in the body of the tables and must not be inserted directly above the first row or below the last row of a table. This is to ensure that entries made in the new row

Overwriting of sample data

Asset Management Maturity Assessment Tool (AMMAT)The instructions for completing the Asset Management Maturity Assessment Tool (G7. AMMAT) are contained in a separate sheet that follows The AMMAT Results(G8) sheet self populates from the assessment tool (G7)

Explanantion of Special terms used in Templates

Term Template Explananation of Term Network Divestiture expenditure F2 Expenditure associated with the divestment of transpower assets to connected parties forecast expenditure f6 The phased expenditure included in the MCP submissionEnvironment G4 Environment - lightning, storms, earthquakes, high wind, snow, ice, tree contact, bird contact or fouling, etc.Equipment G4 Equipment related – caused by inadequate design, installation, or maintenance, or by ageing or wear and tear.Human error G4

Miscellaneous G4 Not known. (Mainly transient line faults with no positive cause or evidence found.)Not Known G4 Miscellaneous – unplanned causes not covered by the above and including non-Transpower human interference.Transpower Planned G4 Outages planned for maintenance, replacement or refurbishment, as well as for new construction.Significant Events G4 Significant events are those events resulting in more than 1.0 system minute of non-supply.Underlying Events G4 Underlying events are those resulting in supply interruptions totalling 1.0 system minute or less. system minutes G4

Asset G5 Branch name from node to node e.g. ASY-SBKIndex Measures for Asset Category G5 The performance target for each category Asset Category G5 high level branch type e.g. interconnection transformer branches or interconnecting circuit branches Sub Category G5

G6

Asset Additions G6

Asset Disposal G6

Asset Divestments G6 Divestment of Transpower assets to connected parties Forecast from Expenditure Proposal for Reset Period G6

Data entered into this workbook may be entered only into the data entry cells. Data entry cells are the bordered, unshaded areas (white cells) in each template. Data should not be entered into the workbook outside a data entry cell.

In some cases, where the information for disclosure is able to be ascertained from disclosures elsewhere in the workbook, such information is disclosed in a calculated cell. The formulas in a calculated cell should not be overwritten.

In templates G3, G4, and G5 there is sample data in Italics. This sample data has been included to illustrate the data that is expected to be populated. The sample data should be overwritten with the actual data

The majority of terms are either self explanantory or are defined in other determinations. However, there are a small number of terms that have specific meanings and the explanantion of them is shown below

Human Element– initiated by an action by Transpower staff or service providers (although inadequate design or other factors may be an underlying cause).

A system minute is defined as the energy in megawatt-minutes not supplied from the system to consumers divided by the system maximum demand in megawatts for the year in question.

sub category of the high level branch type (Asset Category) e.g. 220/110 kV interconnecting transformers and associated equipment

Asset Replacement/Refurbishment /Development/Enhancement of Existing Assets

work on an asset that is providing an existing service. For example reconductoring, replacement of existing transformers , tower painting , outdoor to indoor conversionsNew asset that is providing a service that did not previously exist. For example a new transmission line, new substation etc. This is has the same meaning as the Transpower IMs but excludes the assets that are divested to connected parties, as these are recorded under "Asset Divestments"

Forecast expenditure and/or quantities that were either recorded in the Regulatory Control Period Expenditure Proposal or supporting documents, or were used asa basis for producing the data in the reset proposal.


Tab name: AMMAT instructions 05/09/2023

Asset Management Maturity Assessment Tool (AMMAT) Asset Management Maturity Assessment Tool (AMMAT) Asset Management Maturity Assessment Tool (AMMAT)

Introduction Definitions Guidance for completing the AMMAT

Key

Cells to be completed.

Assessment information

Business TranspowerAssessment Date 4/29/2011Assessment Year 2011Assessor E. Xample

Version History

Version Date Comment0.2 29/04/11 Pre-draft tool for review by Commerce Commission.0.3 24/05/11 Draft tool for review by Commission.0.4 08/06/11 Revised draft with updated question set.1.0 29/07/11 Draft final version2 27/09/11 Final version

Terms and conditions

Copyright

Disclaimer

Footnotes1.

• Structure, capability and authority; and• Competency and training. Asset Management

Systematic and coordinated activities and practices through which an organisation optimally and sustainably manages its assets and asset systems, their associated performance, risks, expenditures over their lifecycles for the purpose of achieving its organisational strategic plan.

Organisational strategic planOverall long-term plan for the organisation that is derived from, and embodies, its vision, mission, values, business policies, stakeholder requirements, objectives and the management of its risks. – Note. Some organisations call this Corporate Plan, Corporate Strategic Plan or Business Plan.

Asset Management PolicyPrinciples and mandated requirements derived from and consistent with the organisational strategic plan, providing a framework for the development and implementation of the asset management strategy and the setting of the asset management objectives.

Asset Management StrategyLong-term optimised approach to management of the assets, derived from, and consistent with, the organisational strategic plan and the asset management policy. - Note 1. The asset management strategy converts the objectives of the organisational strategic plan and the asset management policy into a high-level, long-term action plan for the assets and/or the asset management system. - Note 2. The high-level long-term action plans for the assets and the asset management objectives are normally the outputs of the asset management strategy. These elements together form the basis for developing more specific and detailed asset management plans

Asset Management InformationMeaningful data relating to assets and asset management. - Note. Examples of asset management information include asset registers, drawings, contracts, licenses, legal, regulatory and statutory documents, policies, standards, guidance notes, technical instructions, procedures, operating criteria, asset performance and condition data, or all asset management records.

Asset Management Information systemSystem for the storage, processing and transmission of asset management information.

Appoint a co-ordinatorAppointing a coordinator who will be responsible for all matters concerning the assessment, including: - Organising the people within the organisation, who will be acting as respondents to the questions; - Arranging for all information to be captured within the AMMAT; - Reporting to the organisation on the results of the assessment; and - Determine the scope of the asset management system that it wishes to assess.

Plan the assessment processConsider the form the assessment process will take. - In this context, the principal formats are generally taken to be interviews, facilitated groups/panels or a combination of the two;

Arrange for appropriate outsourced service providers and stakeholders, to act as respondents during the assessment exercise;

Provide appropriate pre-assessment communication (and training where appropriate) to ensure that, as a minimum, the proposed respondents are aware of the AMMAT process and the part within it that they are being asked to play.

Identify which questions are to be asked of which respondents.

Cells to be completedThe only cells which should be populated when completing the 'AMMAT' worksheet are as follows: - 'User guidance': This column can be used to provide guidance on a specific question to a user of the AMMAT. - 'Evidence - Summary': This column should be used to enter the information/evidence used to support the assessed rating. - 'Score': The appropriate maturity rating should be entered here. Values 0 - 4.

The AMMAT comprises questions and guidance from the PAS 55 Assessment Methodology (PAM) which is published by the Institute of Asset Management1.

The IAM PAS 55:2008 Assessment Methodology and associated guidelines, maturity scale and tool are copyright of the Institute of Asset Management.the use of the IAM PAS 55:2008 Assessment Methodology and associated guidelines, maturity scale and tool however caused.

www.theiam.org

http://www.theiam.org/


Tab name: Directors' certificate 19 Oct 05/09/2023

Directors' Certificate


Tab name: Directors' certificate 14 Dec 05/09/2023

Directors' Certificate


Tab name: Assurance report 16 Dec 05/09/2023

Assurance Report






Tab name: F1. RAB 05/09/2023

Transpower Disclosure Date ###

SCHEDULE F1: VALUE OF THE REGULATORY ASSET BASE (RAB ROLL FORWARD) - Information Disclosure version Disclosure Year (year ended) ###

ref

5 F1(i): Value of Regulatory Asset Base (RAB Roll Forward)6 RAB RAB RAB RAB RAB7 CY-4 CY-3 CY-2 CY-1 CY8 ($M) ($M) ($M) ($M) ($M)9 Opening RAB value - - - 4,483.9 4,608.7 = 99.4% of the IPP RAB

10 plus Value of found assets - - 11 less Value of disposed assets 43.4 10.7 12 less Value of lost assets - - 13 less Total depreciation 216.7 231.2 14 plus Value of commissioned assets (including acquired assets and costs incurred after an asset is first commissioned) 384.9 204.8 15 plus Adjustment to opening RAB resulting from change in cost allocation16 Closing RAB value - - - 4,608.7 4,571.6 = 99.4% of the IPP RAB1718 F1(ii): Unallocated Regulatory Asset Base19 Unallocated RAB Unallocated RAB Unallocated RAB Unallocated RAB Unallocated RAB20 CY-4 CY-3 CY-2 CY-1 CY21 ($M) ($M) ($M) ($M) ($M)22 Unallocated opening RAB value 4,522.7 4,645.5 23 plus Found assets - 24 less Asset disposals 43.4 10.7 25 less Lost Assets - 26 less Total depreciation 228.1 243.6 27 plus Assets commissioned 394.4 214.7 28 Unallocated closing RAB value - - - 4,645.5 4,606.0 2930 Result of cost allocation ratio (opening values) - - - 99% 99%31

32 F1(iii): Disclosure by Asset Category

33

HVDC Lines Easements Intangibles IST (comms) Pseudo Assets Total

34 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)35 Opening RAB value (CY) 1,410.1 1,812.6 616.9 102.3 286.8 70.6 180.4 60.9 68.3 4,608.7

opening balance reallocation 19.2 - (19.2) - - - - - - - 37 plus Found assets - - - - - - - - - - 38 less Asset disposals 5.6 2.7 0.2 0.1 - 0.1 1.7 0.3 - 10.7 39 less Lost Assets - - - - - - - - - - 40 less Total depreciation 64.3 59.2 33.9 3.9 0.6 23.3 24.8 12.8 8.4 231.2 41 plus Assets commissioned 66.0 81.7 7.6 2.9 1.7 23.8 9.4 11.5 - 204.8 42 less Adjustment to opening RAB resulting from change in cost allocation - 43 Closing RAB value (CY) 1,425.3 1,832.4 571.3 101.3 287.9 70.9 163.3 59.3 59.9 4,571.6 44

46 F1(iv): Found Assets

47


48 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)49 RAB value (CY) - 50 Unallocated RAB value (CY) - 51

52 F1(v): Asset Disposals

53


54 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)

55 RAB Asset Sales - Related Party (CY) - - - - - - - - - - 56 RAB Asset Sales - Regulated Supplier (CY) - 0.1 - - - - - - - 0.1 57 RAB Asset Sales - Other (CY) 0.2 0.7 - - - - 0.1 0.3 - 1.3 58 RAB Asset Disposals (CY) 5.4 2.0 0.2 0.1 - 0.1 1.5 0.0 - 9.2 59 Unallocated RAB Asset Sales - Related party (CY) - 60 Unallocated RAB Asset Sales - Regulated Supplier (CY) - 0.1 - - - - - - - 0.1 61 Unallocated RAB Asset Sales - Other (CY) 0.2 0.7 - - - - 0.1 0.3 - 1.3 62 Unallocated RAB Asset Disposals (CY) 5.4 2.0 0.2 0.1 - 0.1 1.5 0.0 - 9.2 63

64 F1(vi): Lost Assets

65



70 F1(vii): Depreciation

71


72 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)73 Depreciation on the RAB (CY) 64.3 59.2 33.9 3.9 0.6 23.3 24.8 12.8 8.4 231.2 74 Depreciation on the unallocated RAB (CY) 64.3 59.2 33.9 3.9 0.6 35.7 24.8 12.8 8.4 243.6 75

76 F1(viii): Value of Commissioned Assets

77HVDC Lines Easements Intangibles IST (comms) Pseudo Assets Total

78 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)79 RAB value (CY) 66.0 81.7 7.6 2.9 1.7 23.8 9.4 11.5 - 204.8 80 Unallocated RAB value (CY) 66.0 81.7 7.6 2.9 1.7 33.7 9.4 11.5 - 214.7 818283

These are the categories that align with the asset categories in our audited financial statements. The numbers below are the subset of the numbers in our financial statements which relate to our regulated transmission (HVAC/HVDC) line of business. Business Support below equates to the category called Administration Assets in our financial statements and IST (comms) below equates to the category called Software. Different definitions of Business Support and IST apply in Schedules F3 and F4.

HVAC Substations

HVAC Lines and Transmission

cables

HVDC Substations and

Submarine cables

Business Support

Note: We have completed all major activities on the HVDC Pole 3 project and the HVDC synchronous condenser project. We have also closed out the majority of these projects into the fixed asset register. Subsequent to this close out we have reviewed the assets created by these projects. As a result of this review we have increased the value of the underlying assets that relate to the Synchronous Condensers, and reduced the underlying assets that relate to the HVDC link. For the purposes of our RAB the synchronous condenser assets are shared 50:50 between HVDC and HVAC customers. This reallocation has been reflected in the above adjustment to the RAB opening balances.

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support


Tab name: F1b. IPP RAB 05/09/2023


SCHEDULE F1b: GAAP VALUE OF THE REGULATORY ASSET BASE (RAB ROLL FORWARD) Disclosure Year (year ended) ###

Since 1 July 2015 the fixed assets in our IPP RAB are stated at their GAAP values. Under IM clause 2.2.9 any non-GAAP adjustments to our RAB (i.e. those arising during RCP1) were amalgamated into a single pseudo asset on that date. This new pseudo asset will depreciate over 31 years.

ref

6 F1b(i): Value of Regulatory Asset Base (RAB Roll Forward)7 RAB RAB RAB RAB RAB8 CY-4 CY-3 CY-2 CY-1 CY9 ($M) ($M) ($M) ($M) ($M)

10 Opening RAB value - - - 4,510.7 4,635.7 11 plus Value of found assets - - 12 less Value of disposed assets 43.4 10.7 13 less Value of lost assets - - 14 less Total depreciation 217.8 232.4 15 plus Value of commissioned assets (including acquired assets and costs incurred after an asset is first commissioned) 386.1 206.0 16 plus Adjustment to opening RAB resulting from change in cost allocation17 Closing RAB value - - - 4,635.7 4,598.7 1819 F1b(ii): Unallocated Regulatory Asset Base20 Unallocated RAB Unallocated RAB Unallocated RAB Unallocated RAB Unallocated RAB21 CY-4 CY-3 CY-2 CY-1 CY22 ($M) ($M) ($M) ($M) ($M)23 Unallocated opening RAB value 4,549.5 4,672.5 24 plus Found assets - 25 less Asset disposals 43.4 10.7 26 less Lost Assets - 27 less Total depreciation 229.2 244.7 28 plus Assets commissioned 395.5 216.0 29 Unallocated closing RAB value - - - 4,672.5 4,633.1 3031 Result of cost allocation ratio (opening values) - - - 99% 99%32

33 F1b(iii): Disclosure by Asset Category

34


35 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)36 Opening RAB value (CY) 1,414.4 1,825.4 623.7 102.8 287.2 71.2 181.5 61.2 68.3 4,635.7

opening balance reallocation 19.2 - (19.2) - - - - - - - 38 plus Found assets - - - - - - - - - - 39 less Asset disposals 5.6 2.7 0.2 0.1 - 0.1 1.7 0.3 - 10.7 40 less Lost Assets - - - - - - - - - - 41 less Total depreciation 64.5 59.5 34.2 3.9 0.6 23.5 24.9 12.9 8.4 232.4 42 plus Assets commissioned 66.4 82.2 7.7 3.0 1.7 23.9 9.5 11.6 - 206.0 43 less Adjustment to opening RAB resulting from change in cost allocation - 44 Closing RAB value (CY) 1,429.9 1,845.4 577.9 101.8 288.4 71.5 164.4 59.6 59.9 4,598.7 45

47 F1b(iv): Found Assets

48



53 F1b(v): Asset Disposals

54


55 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)

56 RAB Asset Sales - Related Party (CY) - 57 RAB Asset Sales - Regulated Supplier (CY) - 0.1 - - - - - - - 0.1 58 RAB Asset Sales - Other (CY) 0.2 0.7 - - - - 0.1 0.3 - 1.3 59 RAB Asset Disposals (CY) 5.4 2.0 0.2 0.1 - 0.1 1.5 0.0 - 9.2 60 Unallocated RAB Asset Sales - Related party (CY) - 61 Unallocated RAB Asset Sales - Regulated Supplier (CY) - 0.1 - - - - - - - 0.1 62 Unallocated RAB Asset Sales - Other (CY) 0.2 0.7 - - - - 0.1 0.3 - 1.3 63 Unallocated RAB Asset Disposals (CY) 5.4 2.0 0.2 0.1 - 0.1 1.5 0.0 - 9.2 64

65 F1b(vi): Lost Assets

66



71 F1b(vii): Depreciation

72


73 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)74 Depreciation on the RAB (CY) 64.5 59.5 34.2 3.9 0.6 23.5 24.9 12.9 8.4 232.4 75 Depreciation on the unallocated RAB (CY) 64.5 59.5 34.2 3.9 0.6 35.9 24.9 12.9 8.4 244.7 76

77 F1b(viii): Value of Commissioned Assets

78HVDC Lines Easements Intangibles IST (comms) Pseudo Assets Total

79 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)80 RAB value (CY) 66.4 82.2 7.7 3.0 1.7 23.9 9.5 11.6 - 206.0 81 Unallocated RAB value (CY) 66.4 82.2 7.7 3.0 1.7 33.9 9.5 11.6 - 216.0 828384

This schedule is included to help the reader understand schedule F1. Schedule F1 gives the value of the RAB for the purposes of Information Disclosure - i.e. including the effect of the cap on IDC required by IM clause 2.2.7(2)(b). Transpower recognises the economic impact of this cap by making an adjustment directly to revenue. That avoids the compliance burden of having to maintain two separate and very slightly different asset registers (RAB and GAAP). This schedule is therefore the RAB (=GAAP) that Transpower uses for its Individual Price Path (IPP) calculations. IDC cap adjustment workings are included from row 85.

These are the categories that align with the asset categories in our audited financial statements. The numbers below are the subset of the numbers in our financial statements which relate to our regulated transmission (HVAC/HVDC) line of business. Business Support below equates to the category called Administration Assets in our financial statements and IST (comms) below equates to the category called Software. Different definitions of Business Support and IST apply in Schedules F3 and F4.

HVAC Substations


cables


Submarine cables

Business Support

Note: We have completed all major activities on the HVDC Pole 3 project and the HVDC synchronous condenser project. We have also closed out the majority of these projects into the fixed asset register. Subsequent to this close out we have reviewed the assets created by these projects. As a result of this review we have increased the value of the underlying assets that relate to the Synchronous Condensers, and reduced the underlying assets that relate to the HVDC link. For the purposes of our RAB the synchronous condenser assets are shared 50:50 between HVDC and HVAC customers. This reallocation has been reflected in the above adjustment to the RAB opening balances.

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

HVAC Substations


cables


Submarine cables

Business Support

Q41

John Findlay: $6.4m of this depreciation relates to the old pseudo asset that originates from the start of RCP1. That asset is fully depreciated at the end of 2015/16.


Tab name: F1b. IPP RAB 05/09/2023

2011/12 2012/13 2013/14 2014/15 2015/16

Memo 1: IDC cap adjustments CY-4 CY-3 CY-2 CY-1 CY($M) ($M) ($M) ($M) ($M)

IDC in excess of the cap under IM 2.2.7(2)(b) (0.1) (19.0) (8.4) (1.1) (1.3)Impact on the amount capitalised in the year (1.3)Impact on the RAB closing balance for each year (26.9) (27.0) (27.1)Impact on depreciation for the year (note: there's no depreciation in the year of commissioning in RCP1) (1.1)


($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)

Average depreciation rate 3.10% 2.60% 3.30% 3.30% 0.00% 20.00% 8.30% 20.00%

Commissioning in 2011/12 168.3 48.9 21.9 37.9 11.2 20.6 29.8 6.7 345.2 allocation of the IDC cap excess in 2011/12 (0.1) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.1)

Adjusted commissioning 168.2 48.8 21.9 37.9 11.2 20.5 29.8 6.7 345.1

Commissioning in 2012/13 137.7 673.2 414.6 27.9 17.2 30.5 33.1 18.0 1,352.2 allocation of the IDC cap excess in 2012/13 (1.9) (9.4) (5.8) (0.4) (0.2) (0.4) (0.5) (0.3) (19.0)

Adjusted commissioning 135.8 663.7 408.8 27.5 16.9 30.1 32.6 17.7 1,333.2





Commissioning in 2015/16 66.4 82.2 7.7 3.0 1.7 23.9 9.5 11.6 - 206.0 allocation of the IDC cap excess in 2015/16 (0.4) (0.5) (0.0) (0.0) (0.0) (0.1) (0.1) (0.1) (1.3)


Total depreciation (CY) 64.5 59.5 34.2 3.9 0.6 23.5 24.9 12.9 8.4 232.4 adjustment to depreciation in relation to accumulated IDC adjustments (0.1) (0.4) (0.2) (0.0) - (0.2) (0.1) (0.1) (1.1)Adjusted depreciation (CY) 64.3 59.2 33.9 3.9 0.6 23.3 24.8 12.8 8.4 231.2

Value of the IDC 'excess' using the specific asset depreciation ratesAsset value of the IDC excess at the end of 2011/12 (0.1) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.1)Asset value of the IDC excess at the end of 2012/13 (2.0) (9.5) (5.8) (0.4) (0.2) (0.4) (0.5) (0.3) (19.1)Asset value of the IDC excess at the end of 2013/14 (4.0) (12.9) (6.9) (0.5) (0.4) (0.7) (1.1) (0.3) (26.9)Asset value of the IDC excess at the end of 2014/15 (4.3) (12.8) (6.8) (0.5) (0.4) (0.6) (1.1) (0.3) (27.0)Asset value of the IDC excess at the end of 2015/16 (4.6) (13.0) (6.6) (0.5) (0.5) (0.6) (1.0) (0.3) (27.1)

HVAC Substations


cables


Submarine cables

Business Support

D122

John Findlay: From 1 July 2015 the RAB also recognises depreciation in the year of commissioning. Commissioning is taken to be mid-year here.


Tab name: F2.Opex 05/09/2023


SCHEDULE F2: OPERATING EXPENDITURE (OPEX): ACTUAL Disclosure Year (year ended) ###

ref

5 F2(i): Operating Expenditure (Actual Totals)6 CY-4 CY-3 CY-2 CY-1 CY7 ($M) ($M) ($M) ($M) ($M)8 Grid - maintenance projects - - - 20.6 20.0 9 Grid - routine maintenance - - - 81.6 80.8

10 IST - grid - - - 26.7 23.7 11 IST - business support - - - 14.2 15.0 12 Corporate - - - 102.2 111.8 13 Total operating expenditure - - - 245.3 251.2 1415 Comprising:16 HVAC operating expenditure 227.1 230.8 17 HVDC operating expenditure 18.3 20.4 18

19 F2(ii): Operating Expenditure (Actual Details)20 CY-4 CY-3 CY-2 CY-1 CY21 ($M) ($M) ($M) ($M) ($M)

22 Grid Maintenance Projects - Transmission TL Tower 6.1 5.9

23 Grid Maintenance Projects - Transmission TL Conductor 5.9 4.1

24 Grid Maintenance Projects - Transmission TL Foundation 2.4 2.5

25 Grid Maintenance Projects - Transmission TL Insulators - -

26 Grid Maintenance Projects - Transmission TL Pole 0.8 0.7

27 Grid Maintenance Projects - Transmission TL Access - -

28 Grid Maintenance Projects - AC Stations ACS Buildings & Grounds 1.6 0.8

29 Grid Maintenance Projects - AC Stations ACS Power Transformers 0.6 5.0

30 Grid Maintenance Projects - AC Stations ACS Outdoor Circuit Breakers 0.1 -

31 Grid Maintenance Projects - AC Stations ACS Indoor Switchgear 0.2 0.1

32 Grid Maintenance Projects - HVDC Stations HVDC 0.8 0.5

33 Grid Maintenance Projects - Other MP Other 2.2 0.3

34 Total grid - maintenance projects - - - 20.6 20.0

35

36 Grid Routine Maintenance RM Stations 41.6 42.5

37 Grid Routine Maintenance RM Transmission Lines 30.9 21.9

38 Grid Routine Maintenance RM HVDC 4.1 11.5

39 Grid Routine Maintenance RM Operating 0.8 0.5

40 Grid Routine Maintenance RM Training 4.3 4.4

41 Grid Routine Maintenance RM Contractor Transition - -

42 Total grid - routine maintenance - - - 81.6 80.8

43

44 IST Grid IST Grid IT Asset Management 1.2 1.9

45 IST Grid IST Grid IT Transmission System Plan 3.1 3.2

46 IST Grid IST Grid IT Telecommunications Services 21.1 17.1

47 IST Grid IST Grid IT Network Services 1.3 1.5

48 Total IST - grid - - - 26.7 23.7

49

50 IST Business Support IST Business Support IT Corporate services 4.7 5.1

51 IST Business Support IST Business Support IT ICT Shared Services 7.2 7.2

52 IST Business Support IST Business Support IT Security Services 2.2 2.6

53 Total IST - business support - - - 14.2 15.0

54

55 Corporate Corporate CS Departmental Corporate 44.2 43.8

56 Corporate Corporate CS Departmental Grid 27.8 33.2

57 Corporate Corporate Grid Operating Services Costs (GOS) 7.2 8.3

58 Corporate Corporate Reseach and Development (R&D) - -

59 Corporate Corporate Investigations 7.5 9.7

Corporate Corporate Demand response platform 0.8

61 Corporate Corporate Insurance 13.3 14.0

62 Corporate Corporate Ancillary Services 2.1 1.9

63 Total Corporate - - - 102.2 111.8

64

65 F2(iii): Network Divestiture Expenditure66 CY-4 CY-3 CY-2 CY-1 CY67 ($M) ($M) ($M) ($M) ($M)

68 Network divestiture expenses - -

69

70 F2(iv): Other Disclosures71 CY-4 CY-3 CY-2 CY-1 CY72 ($M) ($M) ($M) ($M) ($M)73 Third party insurance allowance 16.6 14.8

74 Self-insurance allowance - 3.0

75 Note: we have stated the CPI-adjusted amount for each of these allowances

76


Tab name: F3. Base Capex 05/09/2023


SCHEDULE F3: BASE CAPITAL EXPENDITURE (BASE CAPEX): ACTUAL COMMISSIONED Disclosure Year (year ended) ###

ref

5 F3(i): Base Capex (Actual Commissioned Totals)6 CY-4 CY-3 CY-2 CY-1 CY7 ($M) ($M) ($M) ($M) ($M)8 Grid - refurbishment and replacement - - - 229.8 138.6 9 Grid - enhancement and development - - - 4.9 1.6

10 IST - - - 72.4 31.0 11 Business support - - - 10.2 1.2 12 Total base capex commissioned - - - 317.4 172.2 1314 Comprising:15 HVAC base capex commissioned 289.4 168.8 16 HVDC base capex commissioned 28.0 3.4 17

18 F3(ii): Base Capex (Actual Commissioned by Asset Type)19 CY-4 CY-3 CY-2 CY-1 CY20 ($M) ($M) ($M) ($M) ($M)

21 Grid refurbishment and replacement AC Stations ACS Power Transformers 33.0 6.7

22 Grid refurbishment and replacement AC Stations ACS Outdoor to Indoor Conv 27.7 26.7

23 Grid refurbishment and replacement AC Stations ACS Buildings & Grounds-Seismic 8.4 2.0

24 Grid refurbishment and replacement AC Stations ACS Buildings & Grounds 15.5 5.7

25 Grid refurbishment and replacement AC Stations ACS Outdoor Circuit Breakers 10.6 2.8

26 Grid refurbishment and replacement AC Stations ACS Indoor Switchgear 4.1 0.8

27 Grid refurbishment and replacement AC Stations ACS Capacitors and Reactors - -

28 Grid refurbishment and replacement AC Stations ACS Structures & Buswork 0.0 6.9

29 Grid refurbishment and replacement AC Stations ACS Instrument Transformers 3.4 4.2

30 Grid refurbishment and replacement AC Stations ACS Disconnectors & E/S 0.4 0.0

31 Grid refurbishment and replacement AC Stations ACS Other Station Equipment 0.7 -

32 Grid refurbishment and replacement AC Stations ACS Power Cables - -

33 Grid refurbishment and replacement AC Stations ACS Dynamic Reactive 24.1 1.6

34 Grid refurbishment and replacement Protection and Metering SA Metering 0.1 0.0

35 Grid refurbishment and replacement Protection and Metering SA BZ Protection 1.9 1.6

36 Grid refurbishment and replacement Protection and Metering SA Line Protection 7.8 5.8

37 Grid refurbishment and replacement Protection and Metering SA Transformer Protection 3.5 1.9

38 Grid refurbishment and replacement Protection and Metering SA Batteries & DC Systems 0.9 1.7

39 Grid refurbishment and replacement Protection and Metering SA Feeder Protection 1.8 (0.0)

40 Grid refurbishment and replacement Protection and Metering SA Substation Mgmt Systems 9.7 6.1

41 Grid refurbishment and replacement HVDC Stations HVDC 4.2 2.1

42 Grid refurbishment and replacement Transmission Lines TL Paint 33.2 32.1

43 Grid refurbishment and replacement Transmission Lines TL Tower 0.3 -

44 Grid refurbishment and replacement Transmission Lines TL Foundation 2.2 1.6

45 Grid refurbishment and replacement Transmission Lines TL Grillage 16.7 9.1

46 Grid refurbishment and replacement Transmission Lines TL Conductor 2.9 8.1

47 Grid refurbishment and replacement Transmission Lines TL Pole 10.6 6.3

48 Grid refurbishment and replacement Transmission Lines TL Insulators 6.3 4.2

49 Grid refurbishment and replacement Transmission Lines TL Access (0.0) 0.6

50 Total grid refurbishment and replacement - - - 229.8 138.6

51

52 Grid enhancment and development CP_VAR_RN_00_00 VAR- Corridor Management progr 1.9 1.2

53 Grid enhancment and development CP_ISL_DR_00_00 ISL Substation Fire Protection 0.9 0.1

54 Grid enhancment and development CP_ISL_DU_00_00 ISL-Standby Generator - Diesel 0.4 0.0

55 Grid enhancment and development CP_THI_04_00_00 THI- Special Protection Scheme 0.3 0.0

56 Grid enhancment and development CP_VAR_TV_00_00 USI Reliability Sln - stage 1 0.3 -

57 Grid enhancment and development CP_TIM_48_00_00 TIM 110kV T5&T8 o/load protect 0.3 (0.0)

58 Grid enhancment and development CP_BPD_02_00_00 BPD-WTK O-load Protect Scheme 0.2 -

59 Grid enhancment and development CP_ROX_60_00_00 ROX 220kV Bus Split SPS 0.2 -

60 Grid enhancment and development CP_ROX_58_00_00 ROX 220kV Bus Split SPS - Inv 0.2 -

61 Grid enhancment and development CP_BPD_01_00_00 BPD-WTK Overload Scheme - Inv 0.1 - CP_HWB_AP_00_00 HWB T4 220/110/11kV 250 MVA Tx 0.2

63 Grid enhancment and development Other 0.1 0.1

64 Total grid enhancement and development - - - 4.9 1.6

65 *Insert additional rows and update calculation of totals as needed

67 IST Transmission Systems IT SCADA/RTS 3.1 15.7

68 IST Transmission Systems IT Time Series 2.4 (0.0)

69 IST Transmission Systems IT Transmission Systems Plan 0.2 (0.0)

70 IST Transmission Systems IT Meter Data Management 1.5 0.3

71 IST Asset Management Systems IT Asset Management 6.6 1.4

72 IST Asset Management Systems IT Spatial & Drawings 2.0 0.3

73 IST Asset Management Systems IT Outage Management 1.0 0.9

74 IST Network Services IT Communication Services 0.1 0.1

75 IST Telecommunications IT Shared Comms Infrastructure 2.9 2.9

76 IST Telecommunications IT Subst Comms Infrastructure 12.7 0.9

77 IST Corporate Systems IT Stakeholder Management 0.1 0.6

78 IST Corporate Systems IT Corp Info & Doc Mgmt 1.1 (0.0)

79 IST Corporate Systems IT Safety - 0.5

80 IST Corporate Systems IT Risk/Audit Management 0.2 0.0

81 IST Corporate Systems IT Finance 2.9 0.2

82 IST Corporate Systems IT Human Resources 0.6 (0.0)

83 IST Corporate Systems IT Portfolio Planning - 0.2

84 IST IST Shared Services IT Enabling Infrastructure 7.0 3.5

85 IST IST Shared Services IT Service Management 1.7 0.7


Tab name: F3. Base Capex 05/09/2023

86 IST IST Shared Services IT Workforce Mobility 1.7 (0.0)

87 IST IST Shared Services IT Data Centre 13.9 1.7

88 IST Security Services IT Security Infrastructure 10.6 1.0

89 Total IST - - - 72.4 31.0

90

91 Business support Office buildings and facilities BS Office buildings and facilities 5.6 0.0

92 Business support Minor Fixed Assets BS Vehicles 2.4 (0.0)

93 Business support Minor Fixed Assets BS Office Equipment 1.9 0.0

94 Business support Spares and inventory BS Mobile Substation 0.0 -

95 Business support Properties BS Strategic Properties -

96 Business support Other BS Other 0.3 1.2

97 Total business support - - - 10.2 1.2

98


Tab name: F4. Actuals vs Forecasts 05/09/2023

Transpower Disclosure Date ###SCHEDULE F4: COMPARISON OF FORECASTS FOR OPEX AND BASE CAPEX COMMISSIONING Disclosure Year (year ended) ###

ref45 F4(i): Opex6 CY CY CY7 Actual Forecast* Variance8 ($M) ($M) % 9 Grid - maintenance projects 20.0 26.3 -24% note 1

10 Grid - routine maintenance 80.8 77.9 4%11 IST - grid 23.7 33.2 -28% note 212 IST - business support 15.0 16.4 -9%13 Corporate 111.8 114.7 -3%14 Total operating expenditure 251.2 268.5 -6%15 *CPI-adjusted allowance16 F4(ii): Base Capex Commissioned17 CY CY CY18 Actual Forecast* Variance19 ($M) ($M) % 20 Grid - replacement and refurbishment 138.6 175.7 -21% note 321 Grid - enhancement and development 1.6 6.7 -77% note 422 IST 31.0 42.8 -28% note 523 Business support 1.2 3.1 -62%24 Total base capex commissioned 172.2 228.3 -25%25 *CPI-adjusted allowance2627 The base capex expenditure adjustment is $nil28 The base capex annual policies and processes adjustment is $nil29 No base capex projects have been the subject of any major capex proposals in the year3031 Opex variance explanations3233 note 1:

3435 note 2:

3637 Base capex variance explanations3839 note 3:

4041 note 4: Review of the investment need resulting in lower expenditure.4243 note 5:

4445

46

Improved prioritisation of lines project works and improved condition assessment information leading to de-scoping of planned project works have resulted in lower maintenance projects spend.

We have rationalised our fibre lease contracts and negotiated lower prices for continuing leases; we have reduced operating costs associated with communications and control equipment by phasing out legacy 24 volt batteries and increased the use of remote monitoring; we have been able to rent fewer data centre server racks than anticipated, saving on rental costs and energy costs.

We are implementing a more risk-informed asset management approach that prioritises work based on asset condition and consequences of failure. Implementing this new approach has contributed to a temporary dip in output for 2015/16.

The maintain contributors to the variance are completion of two fewer outdoor to indoor switchyard conversions ($7m), savings on New Plymouth to Stratford reconductoring ($5m) as result of competitive wiring contract price & substantial reduction in the requirement for foundation strengthening work. The Wilton substation bus rationalisation will be completed in 2016/17 ($7m) rather than 2015/16.

Lower spend on the TransGO fibre network ($5.6m) due to volume of migration work completed in 2014/15 and a delay to the Westcoast fibre route planned for 2015/16 ($4m). This was partially offset by later completion of the SCADA upgrade originally planned for the end of RCP1 (+$6m).


Tab name: F5. Major Capex Projects 05/09/2023

Transpower Disclosure Date 42551 -1409d mmmm yyyy

SCHEDULE F5: MAJOR CAPITAL EXPENDITURE (MAJOR CAPEX) Disclosure Year (year ended) 42551 -1409d mmmm yyyy

ref

5 F5(i): Major Capex Projects (Summary): Approved But Not Yet Commissioned6

7 Initial Project Approvals Amendments to Approved Projects

8

Approved MCP Outputs Recovery Scheme P50 P50 Approved MCP Outputs

9 Project Name ($M) ($M) ($M) ($M) ($M) ($M)

10 Bunnythorpe-Haywards Reconductoring 161.0 n/a Capex 2014 to 2020 151.0 End 2025 2020

11 Clutha Upper Waitaki Lines Programme 196.9 n/a Capex 2012 to 2017 147.2 n/a 2017

Upper North Island Dynamic Reactive Support 98.2 12.0 Capex and recoverable costs 2011 to 2015 103.4 n/a 2015

Lower South Island Reliability 62.4 n/a Capex 2012 to 2015 55.7 n/a 2015

Upper South Island Grid Upgrade 2.8 n/a Capex Mid 2014 2.6 End 2018 Mid 2014 8.0 n/a Capex 6.6 - 2018/19

Wanganui-Stratford Transmission 44.1 n/a Capex 2011 42.3 n/a 2011

16

17 F5(ii): Major Capex Projects (Detail): Approved But Not Yet Commissioned*18

*Insert additional tables as required for projects

19 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total

20 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)21 Project name Bunnythorpe-Haywards Reconductoring Forecast Expenditure - 2.4 8.0 19.5 28.2 29.5 27.5 22.9 11.7 1.3 151.0 22 Actual Expenditure 0.9 0.6 1.8 5.6 18.5 27.3 23 Variance (0.9) (0.6) 0.7 2.4 1.0 28.2 29.5 27.5 22.9 11.7 1.3 - - 123.7 24

25 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total26 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)27 Project name Clutha Upper Waitaki Lines Programme Forecast Expenditure 35.1 22.4 47.3 41.3 0.6 0.6 - 147.2 28 Actual Expenditure 2.9 4.2 13.9 14.0 9.1 44.1 29 Variance 32.2 18.2 33.4 27.3 (8.5) 0.6 - - - - - - - 103.1 3031 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total32 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)33 Project name Upper North Island Dynamic Reactive Support Forecast Expenditure (capex plus recoverable costs) 77.8 25.7 - - 103.4 34 Actual Expenditure (capex plus recoverable costs) 14.7 21.6 17.1 0.4 0.3 54.1 35 Variance 63.0 4.0 (17.1) (0.4) (0.3) - - - - - - - - 49.3 3637 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total38 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)39 Project name Lower South Island Reliability Forecast Expenditure 2.5 11.6 20.6 21.1 55.7 40 Actual Expenditure 1.9 5.1 5.6 0.8 0.5 13.8 41 Variance 0.6 6.5 15.0 20.3 (0.5) - - - - - - - - 41.9 4243 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total44 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)45 Project name Upper South Island Grid Upgrade Forecast Expenditure 0.1 1.1 0.4 1.7 1.7 1.7 6.6 46 Actual Expenditure - 0.1 1.1 0.4 0.0 1.6 47 Variance - - - (0.0) 1.7 1.7 1.7 - - - - - - 5.0 4849 CY-4 + previous CY-3 CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 Total50 ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M)51 Project name Wanganui-Stratford Transmission Forecast Expenditure 42.3 42.3 52 Actual Expenditure 20.4 1.1 0.1 0.1 2.0 23.7 53 Variance 21.9 (1.1) (0.1) (0.1) (2.0) - - - - - - - - 18.6 5455

56 F5(iii): Future Major Capex Projects Under Consideration: Not Yet Approved57

58 Project Name Project Description Purpose/Benefits of Project59 None606162636465

66 F5(iv): Commissioned Major Capex Projects 67 Value of Commissioned Assets Commissioning Dates Project Outputs

68 Project Name Project DescriptionApproved Date Actual Date

69

North Auckland and Northland Project (NAaN) 333.6 418.9 378.7 352.9 (66.0)

70 Project Outputs

71

See tab TP4 See tab TP4 See tab TP4 See tab TP4 See tab TP4 See tab TP4 See tab TP4

7374

Major Capex Allowance

Max. Recoverable

costsCommissioning

Date(s)Approval Expiry

DateCompletion

date Assumption

Major Capex Allowance

Max. Recoverable

costsRecovery Scheme

Approval Expiry Date

Completion Date

Assumption

(1) Procuring, installing and commissioning Zebra ACSR conductor on the Bunnythorpe – Haywards A and B lines and decommissioning the existing conductor. (2) Works on the foundations and towers to enable the Zebra conductor to be operated at 75C. (3) Procuring, constructing and commissioning substation facilities to facilitate the above connections and equipment. (4) Obtaining property rights and environmental approvals required for these works. (5) Installing alternative conductor technologies on a short section to evaluate its performance in coastal climatic conditions.

(1) Converting the Roxburgh to Livingstone section of the Roxburgh – Islington 220kV line to a duplex conductor configuration. (2) Converting the Aviemore – Livingstone 220kV line to a duplex conductor configuration. (3) Converting the Aviemore – Benmore 220kV line to a duplex conductor configuration. (4) Converting the Roxburgh to Clyde section of the Roxburgh – Twizel 220kV line to a duplex conductor configuration. (5) Thermally upgrading the Cromwell – Twizel section of the Roxburgh–Twizel 220kV line to a 75°C rating.

(1) Install load monitoring equipment in the upper North Island region. (2) Install software enhancements to improve dynamic stability calculations. (3) Undertake a range of demand-side initiatives in the upper North Island region. (4) Install and commission a Reactive Power Controller (RPC) for the upper North Island region. (5) Install and commission a reactive support device in Auckland. (6) Install and commission a reactive support device in Northland. (7) Procure, construct and commission substation facilities to facilitate the above connections and equipment. (8) Obtain property rights and environmental approvals required for these works. (9) Carry out any additional minor works and activities required to facilitate the above.

(1) Procuring, constructing and commissioning of works to tee off both circuits of the North Makarewa–Three Mile Hill line build a 2 km double circuit line to Gore substation, and connect this line to two new 220/110 kV interconnecting transformers; replace the existing 220/110 kV interconnecting transformers at Roxburgh and Invercargill; install a 50% compensation series capacitor on one circuit of the North Makarewa–Three Mile Hill line at Three Mile Hill; install appropriate shunt capacitors to support voltage; install Special Protection Schemes on the 220 kV to manage security of supply during low storage at Manapouri; and install Special Protection Schemes as an interim measure on the 110 kV network until the new build is completed. (2) Procuring, constructing and commissioning substation facilities to facilitate the above connections and equipment. (3) Decommissioning and dismantling components of existing connections, circuits and substations made redundant by these works. (4) Obtaining designations, easements, resource consents and property purchases for these works.

(1) A new 220 kV bus coupler and associated switchgear at Islington substation. The bus coupler and switchgear are incorporated into the Christchurch Reactive Power Controller scheme. (2) An additional discriminating zone (zone F) for the Islington 220 kV bus bar protection. (3) 10 load monitoring units installed in substations in the Upper South Island. (4) Solution study reports on two different configurations for Orari switching station, including cost estimates within +/- 30%. (5) The initial stage of a detailed solution for the preferred Orari switching station configuration. (6) An area stage report of the transmission line route selection process, being the initial step in obtaining the required designation/consents.

The additional outputs are: (1) undertaking preliminary processes substation, lines and site planning necessary for obtaining designations and easements necessary for Orari and Rangitata switching stations; (2) obtaining designations for substations at the two sites, and any transmission line realignments at each site; (3) purchasing land at Rangitata for the second switching station; (4) purchasing easements for any transmission line realignments at each site; and (5) transferring the final costs of land (after subdivision of land not required for transmission services) and easements required for the two switching stations and line realignments at Orari and Rangitata, to the regulatory asset base.

(1) Procuring, installing and commissioning Nobelium AAAC conductor on the Stratford–Waverley–Wanganui 110kV transmission line. (2) Procuring, constructing and commissioning substation facilities to facilitate the above connections and equipment. (3) Obtaining property rights and environmental approvals required for these works. (4) Any additional minor works and activities required to facilitate the above.

Estimated cost ($M)

Estimated Start Date

Estimated Commissioning

Date

Expected (P50) ($M)

MCA (P90) ($M)

Adjusted MCA ($M)

Actual Cost ($M)

Variance v P90 ($M)

Material Change in

Value? (y/n)Variance

(months)Material

Change in Date? (y/n)

Variance to approved

outputs? (y/n)Material

Variance? (y/n)

Before this project the only electricity supply to west Auckland, the North Shore and on to Northland (the NAaN area) was through one double circuit line from Otahuhu to Henderson. The NAaN project provides a parallel route and creates a high capacity (220 kV) ring around the main Auckland isthmus adding diversity and capacity to North Auckland and Northland. It also provides two new direct grid connections into the Vector distribution network, one in Auckland city centre at Hobson Street and one on the North Shore at Wairau Road.

The project primarily involved the installation of a new 220 kV single underground circuit comprising three 600 MVA cables underground from Pakuranga to Penrose substations and, underground and via the harbour bridge, from Penrose to Albany via two new substations at Hobson Street and Wairau Road.

Yes, compared to the P90. See tab

TP4.


Tab name: TP1. ROI and profit 05/09/2023


Return on Investment (ROI) and Profit calculations Disclosure Year (year ended) ###under paragraphs 8.6 to 8.13 of the Transpower Information Disclosure Determination 2014

ROI (vanilla) 8.57% Vanilla ROI calculated as required by Clause 8.6Cost of debt (ID) 5.11%ROI (post-tax) 7.94% Post-tax ROI calculated as required by Clause 8.7

ROI (vanilla) 8.57% per clause 8.667th percentile vanilla WACC (IPP version) 7.19% this is the WACC used for the purposes of calculating revenue for the disclosure year

Difference 1.38%

Reconciliation from the regulatory WACC to our ROI (clause 8.10.2)

7.19%Effect of permanent voluntary revenue reductions -0.20%Contribution from incentives 1.35%Transpower's actual ROI 8.34%

Double counted TCSD in the ID tax calculation 0.02%Elements missing from the ID ROI formula 0.11%Difference due to the ID RAB having a lower value than the IPP RAB 0.07%Other differences 0.01%

8.57%

Comparison required by Clause 8.8.3ROI (vanilla) 8.57% per clause 8.667th percentile vanilla WACC (ID version) 6.41%

Difference 2.16%

Comparison required by Clause 8.9.3ROI (post-tax) 7.94% per clause 8.767th percentile post-tax WACC (ID version) 5.78%

Difference 2.16%

Clause 8.10.1 and clause 8.10.3This difference (2.16%) has the same components as those described under Clause 8.10.2 above, but with the added difference that the ID vanilla WACC rate is different from the IPP vanilla WACC rate.The more useful comparison (being the added difference) is between67th percentile vanilla WACC (IPP version) 7.19%67th percentile vanilla WACC (ID version) 6.41%

Difference 0.78% of this difference 0.73% is due to ID having a lower risk free rate and 0.05% due to ID having a lower debt premiumas above 1.38%

as above (8.8.3) 2.16%

Comparison required by Clause 8.8.2ROI (vanilla) 8.57% per clause 8.6Mid-point vanilla WACC (ID version) 5.95%

Difference 2.62%

Comparison required by Clause 8.9.2ROI (post-tax) 7.94% per clause 8.7Mid-point post-tax WACC (ID version) 5.32%

Difference 2.62% see above

Regulatory profit/loss before taxRevenue 917,769,580 Operating expenditure - 251,244,801 Pass-through costs - 16,085,431 Recoverable costs - 1,131,381 Depreciation (tax depreciation and write-offs) - 348,701,519 TCSD - 3,160,037 double counted in Notional Interest until the rules are correctedRegulatory profit/loss before tax 297,446,411 Disclosure required by Clause 8.11Notional interest (IM clause 2.3.1(3)(a)) - 126,655,212

170,791,200 Tax 47,821,536

Regulatory profit/loss before tax including EV account movement 338,555,636 Disclosure required by Clause 8.12

Regulatory profit/loss after tax including EV account movement 279,223,517 Disclosure required by Clause 8.13

WORKINGS

Quantities specified in Attachment A1 Amount (A) Factor (B) A x B

$ $Opening RAB value 4,608,716,763 - 1.000 - 4,608,716,763 Revenue 917,769,580 0.956 876,961,694

204,756,412 - 0.942 - 192,849,531

Tranpower's ROI (clauses 8.6 and 8.7)

Specified in Transpower's cost of capital determination for the disclosure year 2016

A comparison of our ROI to the WACC used to calculate our revenue (clause 8.8.4)

67th percentile vanilla WACC (IPP version)

Vanilla ROI calculated under clause 8.6

this difference (also see below) is the same as those calculated above, but with the added difference of 0.46%, being the difference between the mid-point and 67th percentile WACCs

Using revenue cash timing specified in the ID determination

ΣVCA


Tab name: TP1. ROI and profit 05/09/2023

Operating expenditure 251,244,801 - 0.960 - 241,156,957 Operating costs - dismantling costs 13,835,203 - 0.960 - 13,279,700 Pass-through costs 16,085,431 - 0.960 - 15,439,577 Recoverable costs 1,131,381 - 0.960 - 1,085,954 Regulatory tax allowance 47,821,536 - 0.960 - 45,901,432 Disposed asset proceeds 5,388,770 0.960 5,172,403 Term Credit Spread Differential 3,160,037 - 0.960 - 3,033,157 Other regulated income 0.960 - Adjusted closing RAB value 4,571,610,578 0.921 4,210,918,761 Closing EV account balance (asset = +ve) 49,609,445 0.960 47,617,554 Opening EV account balance (asset = +ve) 20,010,803 - 0.960 - 19,207,340

ROI (goal seek cell D110 to zero by changing cell C110) 8.57% 0

Value of commissioned assets $ days $ $ IPP RABJuly 2,552,715 16.5 2,543,249 2,568,601 August 2,814,490 47.5 2,784,548 2,832,005 September 7,878,849 77.5 7,742,554 7,927,880 October 7,577,939 108.5 7,395,051 7,625,098 November 5,742,246 138.5 5,565,937 5,777,981 December 11,895,589 169.5 11,450,146 11,969,617 January 4,655,551 200.5 4,450,049 4,684,523 February 10,114,074 228.5 9,606,866 10,177,015 March 35,333,038 259.5 33,327,688 35,552,921 April 25,316,018 289.5 23,718,432 25,473,563 May 45,553,035 320.5 42,381,516 45,836,518 June 45,322,868 350.5 41,883,497 45,604,919

204,756,412 266.1 192,849,531 206,030,643 ID RAB commissioning as a proportion of the IPP RAB commissioning 99.38% -


Tab name: TP2. Major project costs 05/09/2023


SCHEDULE TP2: PARTIALLY COMPLETED MAJOR PROJECTS: COSTS Disclosure Year (year ended) ###

ref

5 Updated cost forecasts for partially completed major projects

6

78 ($M) ($M) ($M) ($M) (%) (Y or N)9 Bunnythorpe-Haywards Reconductoring 161.0 124.7 151.0 (26.3) (17.4) Y

10 Clutha Upper Waitaki Lines Programme 196.9 44.6 147.2 (102.6) (69.7) Y 11 98.2 51.4 91.4 (40.0) (43.8) Y 12 Lower South Island Reliability 62.4 31.6 55.6 (24.0) (43.2) Y 13 Upper South Island Grid Upgrade 8.0 6.6 6.6 - - N 14 Wanganui-Stratford Transmission 44.1 25.7 42.3 (16.6) (39.2) Y 15 570.6 284.6 494.1 (209.5) (42.4)1617 (1) 'Material' has been specified in our Information Disclosure Determination as being greater than 10% or $10m.18 (2) Excluding amounts in relation to demand response initiatives 1920 Bunnythorpe-Haywards Reconductoring

21

23 Clutha Upper Waitaki Lines Programme24

2526 Upper North Island Dynamic Reactive Support

272829 Lower South Island Reliability Transmission Investment

303132 Wanganui-Stratford Transmission Investment

3334 Other savings against forecast included $2.3 million on procurement and $4.8 million on property.353637 Updated cost forecasts for partially completed non-transmission solution projects38

39Variance Variance

40 ($M) ($M) ($M) (%) (Y or N)41 12.0 3.5 (8.5) -71% Y 4243 (3) The demand response component of this project44

4546

Major capex allowance

Current forecast expected cost

Original forecast expected costs

Variance in the expected cost

Variance in the expected cost Material (1)

Upper North Island Dynamic Reactive Support (2)

The forecast cost of the this project is reduced mainly in the reduction in the costs of reconductoring. Section 1 which has been completed, has helped refine this reduction, which was due to efficiencies and competitive contracting. This is able to be carried forward to the other remaining four sections. In addition the design has been refined - in particular we have replaced a significant number of tower raises with mid-span earthworks. These are a cheaper method of dealing with clearance issues, but were not able to be quantified until negotiated with landowners. We also have had nil drawdown of contingency for Section 1 and incurred lower IDC than budgeted.

The main reason for reduction on the programme forecast cost is that three of the five projects of the CUWLP programme are not being progressed at this stage, as the system need is not manifest (with the on-going uncertainty ref the Tiwai Aluminium Smelter). Two of the projects have been commisioned.

The reduction in costs from the original budget can be attributed to two main factors. The first being for the Marsden and Penrose STATCOMs where the main contract for design, supply and installation was lower than budgeted due to contract efficiencies with HVDC and foreign exchange benefit. The second main factor has been a reduction in the forecast for the Auckland Reactive Power Controller where alternative solution approaches have been evaluated to provide outcomes at a cost $28.3 million below the original budget estimate.

The expected cost in the approval includes $16.7 million for a 220 kV series capacitor at Three Mile Hill that is now not expected to be required until 2020 or later. This cost is excluded from the forecast end cost and we will review it before completing all remaining components of the project, and prepare a variation to the regulatory approval for the project and close it out. Other savings include the cost of two transformers and a pair of shunt capacitors being less than the forecast, and having successfully avoided draw down of $4 million of the contingencies allowance to date.

Construction costs were forecast to be $25.8 million including contingencies. Successful management of most construction risks meant that there was limited draw-down of contingencies and actual construction costs were $16 million. This also reflects a successful procurement strategy of awarding all line sections to a single contractor.

Maximum recoverable cost

Current forecast total cost Material (1)

Upper North Island Dynamic Reactive Support (3)

The allowance for demand side initiatives under this programme is $12.0m, which includes any necessary spending on capex, but with no restriction on the capex/opex split. The total costs claimed as 'non-transmission solution recoverable costs' is unchanged since last year (the last year of RCP1) because since the start of RCP2 we have a specific controllable opex allowance for Demand Side Response initiatives. The apparent variance of $8.5m includes $3.6m which was spent on the demand response management system (i.e. capital spending). The remaining under-spend arose because we were able to procure demand response at a lower cost than had been anticipated.


Tab name: TP3. Major project timing 05/09/2023


SCHEDULE TP3: PARTIALLY COMPLETED MAJOR PROJECTS: TIMING Disclosure Year (year ended) ###

ref

5 Updated timing forecasts for partially completed major projects

6

7Current forecast commissioning

8 (date or date range) (date or date range) (Y or N)9 Bunnythorpe-Haywards Reconductoring 2014 to 2020 2014 to 2020 N

10 Clutha Upper Waitaki Lines Programme 2012 to 2017 2014 to 2016 Y 11 Upper North Island Dynamic Reactive Support 2011 to 2015 2011 to 2018 Y 12 Lower South Island Reliability 2012 to 2015 April 2018 Y 13 Upper South Island Grid Upgrade 2018/19 2018/19 N 14 Wanganui-Stratford Transmission 2011 December 2017 Y 1516 (1) 'Material' has been specified in our Information Disclosure Determination as being greater than 3 months171819 Clutha Upper Waitaki Lines Programme

20

22 Upper North Island Dynamic Reactive Support

23

25 Lower South Island Reliability Transmission Investment

262728 Wanganui-Stratford Transmission Investment

2930 Substation work at Stratford and Waverly has been completed, but work at Hawera is scheduled to be competed by December 2017 so that we can minimise disruption and avoid major outages.31

Forecast commissioning at approval Material (1)

With three sections of the works not being progressed at this time as discussed in the cost variance explanation, the second of the two completed projects was commissioned in June 2016. We have not forecast a commissioning date for the sections of the work which are on hold.

The upper North Island reactive power equipment was installed and commissioned in 2013. The final component of the program (Auckland Reactive Power Controller) was deferred in order to carry out an assessment into an alternative solution, which has now been agreed with the Commerce Commission, providing a forecast cost saving of $28.3 million. The programme is now forecast to be complete in June 2018.

The forecast end date has been revised to 1st April 2018 due to delays in securing the designation and easements to construct a 2.25 km long 220 kV double circuit line from the 220 kV North Makarewa – Three Mile Hill A line to Gore Substation, for the new 220/110 kV interconnection at Gore. The designation over the chosen line route was obtained in late 2013. However, efforts to acquire easements through negotiations were not successful due to the 3 landowners' unwillingness to grant easements and strong preference of an outright sale of their farms to Transpower. Easements are now being pursued through the compulsory acquisition process under the Public Works Act and this process is being undertaken by Land Information New Zealand (LINZ) on behalf of the Crown.

Commissioning of individual lines sections was phased more slowly than originally forecast to better manage outages and to fit with contractor resourcing. The first, second and third sections were completed in 2010, early 2012 and 2013.


Tab name: TP4. NAaN close-out report 05/09/2023


SCHEDULE TP4: FULLY-COMMISSIONED PROJECT CLOSE-OUT REPORTS Disclosure Year ###

ref

5 Report in relation to the North Auckland and Northland project67 Project description

89

10 Variance Material?11 Commissioned values $'m $'m $'m12 Project costs, excluding the customer-funded Hobson Street and Wairau Road GXPs 352.9 333.6 19.3 Yes 13

15 Project outputs and related commissioning dates Actual date Approved date Variance Material?

16

No 12/16/2013 2014 No n/a

17

No 2/27/2014 2014 No n/a

18

No 1/17/2016 2014 Yes Yes

19

4. Dismantling components of existing connections and substations made redundant by these works. No 1/17/2016 2014 Yes Yes

20

5. Obtaining designations, easements, resource consents and property purchases for these works. No 2014 Yes Yes

21

No 1/17/2016 2014 Yes Yes

2223 Lessons learnt

2425

2627 Cost efficiencies $'m Assumptions28 None that can be quantified - n/a2930 Major capex over-spend adjustment $'m31 Allowance at approval (P90) 418.932 Allowance adjusted for the disparity between forecast and actual CPI and FX rates 378.733 Forecast final end cost 352.934 Excess amount -35 Over-spend adjustment -3637 Commissioning date variance explanations

383940 Commissioned value variance explanation

414243 Project output variance explanation44 n/a4546

Before this project the only electricity supply to west Auckland, the North Shore and on to Northland (the NAaN area) was through one double circuit line from Otahuhu to Henderson. The NAaN project provides a parallel route and creates a high capacity (220 kV) ring around the main Auckland isthmus adding diversity and capacity to North Auckland and Northland. It also provides two new direct grid connections into the Vector distribution network, one in Auckland city centre at Hobson Street and one on the North Shore at Wairau Road.

The project primarily involved the installation of a new 220 kV single underground circuit comprising three 600 MVA cables underground from Pakuranga to Penrose substations and, underground and via the harbour bridge, from Penrose to Albany via two new substations at Hobson Street and Wairau Road.

Forecast final end cost

Expected (P50) cost at

approval

Variance to approved outputs

1. Procuring, constructing, commissioning and operating a connection between Pakuranga and Penrose substations that: - is capable of 220 kV operation; and - has a winter cyclic rating of around 600 MVA.

2. Procuring, constructing, commissioning and operating a connection between Penrose substation, Hobson Street substation, Wairau Road substation and Albany substation that: - is capable of 220 kV operation; and - has a winter cyclic rating of around 600 MVA

3. Procuring, constructing, commissioning and operating substation facilities at Pakuranga, Penrose and Albany substations to facilitate the above connections.

Anticipated completion by

Nov 2016

6. Any additional minor works and activities required to facilitate the above or manage the reliability risks of higher than expected demand or longer than expected construction times.

Regulatory Approval The NAaN project was one of the first projects subject to individual regulatory approval and the first involving a distribution business directly (Vector in this case). Experience gained through this process has influenced how we work with a distribution business to engage with our regulator and industry participants regarding investment cases.

Commercial TermsThe cable contracts provided for substantial payment linked to cable delivery rather than installation. This was designed to match the contractor’s cash flow and limit the financing costs, thus giving a lower overall cost. The result of this was that on one of the two contracts, it removed an incentive for the poorly performing installation contractor. On future contracts these conflicting requirements would need to be carefully considered to get the balance right.

Selection of ContractorsOne of the cables contracts was let to a consortium of three contractors, each being jointly and severally liable, and each providing a different skill set. This proved not to be a success as the Consortium lacked overall leadership and internal conflict became an issue affecting performance.

Stakeholder ManagementWe had a dedicated Communications Manager reporting directly to the Project Director and this was a great success. The project had the potential for adverse impacts in a number of areas, both physical and reputational, and having a resource focussed on this enabled us to take ownership and manage the outcomes proactively.

Estimated value

Commissioning dates were affected by delays in completing the required works at Penrose substation. The delays were caused by the October 2014 fire event, installation challenges for the 220 kV Ring Bus Cable during November 2015 to Apil 2015. Discovery of asbestos contamination inside the old Penrose control and relay room in March 2015 resulted in further delays to the commissioning of NAaN Stage 3 comprising 220 kV Ring Bus Cable and 220 kV Bus Zone Protection. Completion of easements’ registration on the titles remains pending due to delays caused by Vector Limited, the grantor of easements.

The cost increase of 6% against the P50 expected cost at approval, arises principally from additional unforeseen costs in relation to cabling and general costs increases caused by the delayed commissioning.


Tab name: TP5. Related party transactions 05/09/2023


SCHEDULE TP5: RELATED PARTY TRANSACTIONS Disclosure Year (year ended) ###

ref56 Transactions with key management personnel7 The Group did not conduct any business with key personnel.89 Key management personnel compensation

10 Key personnel received the following compensation for their services to the Group.

12 $m13 Directors' fees 0.514 Other key management personnel 4.615 Defined contribution schemes 0.21617 There were no termination payments to key management personnel in 2016.18 There was no long term compensation paid to key management personnel.1920 Transactions with other parts of Transpower $m21 Risk Reinsurance Limited 12.522 Transpower procures insurance services from a captive insurance company, Risk Reinsurance Limited.232425 Some directors of the company may be directors or officers of other companies or organisations with26 which Transpower may transact. 2728 All transactions are carried out at on an "arm's length" basis.29


Tab name: F6. Revenues 05/09/2023


SCHEDULE F6: REGULATED REVENUE Disclosure Year (year ended) ###Regulated revenue is received in Pricing Years, ending on 31 March each year. For example, the pricing year corresponding to the 30 June 2015 disclosure year is the pricing year ended 31 March 2015. All revenue numbers here are stated in pricing years, except where indicated.

ref

5 F6(i): Regulated Electricity Transmission Revenue 6 CY-4 CY-3 CY-2 CY-1 CY

7 ($M) ($M) ($M) ($M) ($M)8 HVAC - Interconnection (excl. EV) 497.3 559.5 640.8 688.0 664.5 9 HVAC - NEA and PDA income 2.0 1.9 4.8 6.4 6.7

10 HVAC - Connection (excl.EV) 119.3 125.7 136.7 130.5 127.1 11 HVAC - EV adjustment (50.3) (12.2) (65.7) (28.2) (32.2)12 HVDC (excl. EV) 70.5 104.4 129.0 131.4 121.0 13 HVDC - NEA and PDA income - - - - - 14 HVDC - EV adjustment 14.3 24.4 33.5 13.1 28.9 15 Other regulated transmission revenue * 8.8 3.2 1.6 2.6 1.8

16 Total regulated electricity transmission revenue 661.8 806.8 880.8 943.8 917.8

* "other regulated transmission revenue" is principally the sale of scrap metal to a variety of scrap metal merchants19

20 F6(ii): Regulated Revenue21

20 Total Revenue (CY)

21

TOTAL ($M)

22 Distributor 582.4 3.8 86.3 3.1 - 675.6 (28.2) 0.7 648.1 30,775,576 1,277,810 23 Direct Connect 81.9 - 9.6 - - 91.5 (4.0) - 87.5 7,251,571 346,726 24 Generator 0.2 2.8 31.2 117.9 - 152.1 (0.0) 28.2 180.3 68,144 37,755,897

Other * 1.8 1.8 1.8 25 Grand Total 664.5 6.7 127.1 121.0 1.8 921.0 (32.2) 28.9 917.8 38,095,292 39,380,433 26

* "other" relates to our other regulated revenue - principally scrap metal merchants32

33

34 F6(iii): Customer Charges 35 The customer charges shown must include all charges irrespective of the form of the contract

36 note: location "(blank)" relates to the wash-up for each customer under the TPM Actual amount received in the year Amount notified to customers prior to the pricing year Amount notified to customers prior to the pricing year

37 Current Year Charges (CY) Current Year +1 (CY+1) Charges Current Year +2 (CY+2) Charges

38

Customer Code Customer Name Location Code Location Name Connection Charge HVDC Charge Total Charges Connection Charge HVDC Charge Total Charges HVDC Charge Total Charges

39 ALPE Alpine Energy ABY Albury 0.7 0.0 0.3 1.0 0.6 0.3 0.3 1.2 0.6 0.1 0.2 0.9 40 ALPE Alpine Energy BPD Bells Pond 0.0 0.3 0.1 0.4 0.0 0.4 - 0.1 0.5 0.0 0.4 - 0.1 0.5 41 ALPE Alpine Energy STU Studholme 0.3 0.8 0.0 1.1 0.3 0.8 - 0.0 1.1 0.3 0.9 - 0.0 1.2 42 ALPE Alpine Energy TIM Timaru 0.5 6.3 1.5 8.3 0.5 6.6 - 1.5 8.6 0.5 6.9 - 1.3 8.7 43 ALPE Alpine Energy TKA Tekapo A 0.2 0.3 0.5 0.2 0.4 - 0.6 0.2 0.3 - 0.6 44 ALPE Alpine Energy TMK Temuka 1.1 2.8 0.1 4.0 1.0 2.7 - 0.1 3.8 1.0 4.4 - 0.1 5.5 45 ALPE Alpine Energy TWZ Twizel 0.2 0.2 0.4 0.2 0.2 - 0.4 0.2 0.3 - 0.5 46 BUEL Buller Electricity ORO Orowaiti Tee 0.6 0.7 0.0 1.3 0.5 0.5 0.0 0.9 0.8 0.5 0.0 1.3 47 BUEL Buller Electricity WPT Westport 1.1 0.6 1.8 1.0 0.7 - 1.8 - 48 BUEL Buller Electricity (blank) (blank) 0.0 0.0 - - 49 CHBP Centralines WPW Waipawa 0.8 2.0 2.8 0.8 2.1 - 2.9 0.8 2.3 - 3.1 50 COUP Counties Power BOB Bombay 0.5 6.6 0.2 7.3 0.5 8.0 - 0.4 8.9 0.5 7.7 - 0.3 8.5 51 COUP Counties Power GLN Glenbrook 0.5 2.6 3.1 0.5 2.8 - 3.2 0.5 3.3 - 3.7 52 COUP Counties Power (blank) (blank) (0.0) (0.0) - - 53 CTCT Contact Energy CYD Clyde 1.3 18.4 0.0 19.7 1.4 - 18.7 20.0 1.3 - 18.5 19.8 54 CTCT Contact Energy NPL New Plymouth - - - - - - - - - 55 CTCT Contact Energy OKI Ohaaki 1.4 0.0 1.4 0.6 0.0 - 0.6 1.4 - - 1.4 56 CTCT Contact Energy OTA Otahuhu A 0.1 0.0 0.0 0.2 0.1 0.0 - 0.0 0.1 - - - - 57 CTCT Contact Energy OTC Otahuhu B 0.0 0.0 - - - - - - - - 58 CTCT Contact Energy PPI Poihipi 0.4 0.0 0.2 0.6 0.4 0.0 - 0.2 0.7 0.4 - - 0.0 0.5 59 CTCT Contact Energy ROX Roxburgh 0.3 12.8 13.1 0.3 - 13.1 13.4 0.3 - 13.4 13.7 60 CTCT Contact Energy SFD Stratford 0.2 0.0 0.3 0.6 0.2 - - 0.3 0.6 0.2 - - 0.3 0.6 61 CTCT Contact Energy THI Te Mihi 0.6 0.0 2.5 3.0 0.6 0.0 - 2.5 3.1 0.6 - - 2.0 2.6 62 CTCT Contact Energy WHI Whirinaki 0.1 0.0 0.1 0.1 0.0 - 0.1 0.1 0.0 - 0.1 63 CTCT Contact Energy WRK Wairakei 0.1 0.1 0.1 - - 0.1 0.1 - - 0.1 64 CTCT Contact Energy (blank) (blank) 0.1 0.1 - - 65 DUNE Aurora Energy CML Cromwell 0.2 2.2 0.4 2.8 0.3 2.6 - 0.4 3.3 0.3 3.1 - 0.3 3.7 66 DUNE Aurora Energy CYD Clyde 0.3 0.0 0.6 1.0 0.3 0.1 0.5 0.9 0.3 0.0 0.4 0.8 67 DUNE Aurora Energy FKN Frankton 1.5 4.1 0.2 5.8 1.4 5.1 - 0.2 6.7 1.4 5.7 - 0.2 7.3 68 DUNE Aurora Energy HWB Halfway Bush 1.0 5.6 0.8 7.4 0.9 5.8 0.8 7.5 1.0 6.9 0.6 8.5 69 DUNE Aurora Energy SDN South Dunedin 1.5 6.1 0.1 7.6 1.5 6.6 - 0.1 8.2 1.5 7.0 - 0.2 8.7 70 DUNE Aurora Energy (blank) (blank) (0.0) (0.0) - - 71 EASH Electricity Ashburton ASB Ashburton 0.9 3.6 0.1 1.3 5.8 0.9 4.1 0.0 1.3 6.3 0.9 9.8 0.0 1.2 12.0 72 EAST Eastland Network TUI Tuai 0.3 5.2 0.1 5.6 0.3 5.7 - 0.1 6.1 0.3 5.9 - 0.1 6.3 73 EAST Eastland Network (blank) (blank) 0.0 (0.0) (0.0) - - 74 EAST Eastland Network GIS Gisborne 0.0 0.0 - - 75 ESLL Electricity Southland CML Cromwell 0.0 0.0 0.0 0.0 0.0 0.0 76 ESLL Electricity Southland FKN Frankton 0.1 0.2 0.0 0.3 0.1 0.3 - 0.0 0.4 0.1 0.4 - 0.0 0.5 77 GENE Genesis Energy HLY Huntly 0.3 0.0 0.3 0.3 - - 0.0 0.3 0.3 - - 0.3 78 GENE Genesis Energy RPO Rangipo 1.4 1.4 1.4 - - 1.4 1.4 - - 1.4 79 GENE Genesis Energy TKA Tekapo A 1.4 0.0 1.2 2.5 1.2 - 1.2 2.4 1.2 - 1.2 2.4 80 GENE Genesis Energy TKB Tekapo B 0.6 7.0 7.7 0.7 - 7.2 7.8 0.7 - 7.0 7.6 81 GENE Genesis Energy TKU Tokaanu 1.4 0.0 1.5 1.5 - - 0.0 1.6 1.5 - - 1.5 82 GENE Genesis Energy TUI Tuai 0.2 0.2 0.2 - - 0.2 0.2 - - 0.2 83 GENE Genesis Energy (blank) (blank) (0.0) (0.0) - - 84 HAWK Unison Networks FHL Fernhill 0.5 4.8 5.4 0.5 5.0 - 5.5 0.6 5.4 - 5.9 85 HAWK Unison Networks OKI Ohaaki - - - - - - - - - 86 HAWK Unison Networks OWH Owhata 0.8 1.3 2.0 0.7 1.3 - 2.0 0.8 1.4 - 2.1 87 HAWK Unison Networks RDF Redclyffe 0.4 6.0 0.9 7.3 0.4 5.9 - 1.0 7.3 0.4 6.4 - 0.6 7.4 88 HAWK Unison Networks ROT Rotorua 1.4 5.1 6.5 1.5 5.1 - 6.5 1.5 4.9 - 0.0 6.4 89 HAWK Unison Networks TRK Tarukenga 0.1 0.8 0.2 1.1 0.1 0.8 - 0.0 0.9 0.1 0.8 - 0.0 1.0 90 HAWK Unison Networks WRK Wairakei 1.0 0.0 1.0 1.1 - - 0.2 1.3 1.1 0.0 - 0.2 1.3 91 HAWK Unison Networks WTU Whakatu 1.3 8.2 0.1 9.5 1.3 8.7 - 0.0 10.0 1.4 9.2 - 0.0 10.6 92 HAWK Unison Networks (blank) (blank) 0.0 0.0 - - 93 HORO Electra MHO Mangahao 0.6 0.4 1.0 1.4 0.6 - 2.0 1.3 0.9 - 2.2 94 HORO Electra PRM Paraparaumu 0.4 5.7 0.7 6.8 0.4 6.1 - 0.7 7.2 0.4 6.4 - 0.7 7.5 95 HORO Electra (blank) (blank) - - - -

96 HRZE EDG Edgecumbe 0.7 1.0 1.7 0.9 0.0 - 0.9 0.9 0.0 - 0.9

97 HRZE KAW Kawerau 0.4 1.2 1.6 0.4 1.4 - 1.8 0.4 2.0 - 2.3

98 HRZE TKH Te Kaha 1.3 0.1 1.4 1.0 0.1 - 1.1 1.0 0.1 - 1.1

HVAC - Interconnection (excl. EV) ($M)

NEA and PDA income ($M)

HVAC - Connection (excl.EV) ($M)

HVDC (excl. EV) ($M)

Sum of Other regulated

transmission revenue ($M)

Sum of Total Revenue excl. EV

adj($M)

HVAC - EV adjustment ($M)

HVDC - EV adjustment ($M)

Sum of Offtake quantities (MWH)

Sum of Injection quantities (MWH)

Interconnection Charge

NEA and PDA charges

Investment Contract Charges


NEA and PDA charges


Connection Charge


NEA and PDA charges


Horizon Energy Distribution





99 HRZE WAI Waiotahi 1.0 0.8 1.9 0.9 0.9 - 1.9 0.9 1.1 - 2.1

100 HRZE (blank) (blank) (0.0) (0.0) - -

101 KIWI HWA Hawera 0.1 0.0 0.1 0.1 - - 0.0 0.1 0.1 - - 0.0 0.2

102 KUPE HWA Hawera 0.1 0.9 0.3 1.3 0.1 0.9 - 0.3 1.3 0.1 0.7 - 0.3 1.1

103 MARL Marlborough Lines BLN Blenheim 0.6 6.4 0.5 7.5 0.6 6.7 - 0.5 7.8 0.6 7.0 - 0.4 8.0 104 MELT MEL (Te Apiti) WDV Woodville 0.1 0.0 0.1 0.1 0.0 - 0.1 0.1 0.0 - 0.1 105 MELW MEL(Westwind) WWD West Wind 0.3 0.0 0.7 1.0 0.3 0.0 - 0.7 1.0 0.1 0.0 - 0.6 0.7 106 MERI Meridian Energy AVI Aviemore 0.1 10.2 10.4 0.1 - 10.4 10.5 0.1 - 9.4 9.6 107 MERI Meridian Energy BEN Benmore 0.2 22.3 0.1 22.6 0.2 - 22.7 0.1 23.0 0.2 - 21.2 0.1 21.5 108 MERI Meridian Energy MAN Manapouri 13.1 36.9 0.1 50.2 13.8 - 37.5 0.1 51.4 13.8 - 39.8 0.1 53.6 109 MERI Meridian Energy OHA Ohau A 1.2 11.8 12.9 1.2 - 12.0 13.2 1.2 - 11.2 12.4 110 MERI Meridian Energy OHB Ohau B 0.1 9.5 9.6 0.1 - 9.6 9.8 0.1 - 9.1 9.2 111 MERI Meridian Energy OHC Ohau C 0.1 9.4 9.6 0.1 - 9.6 9.7 0.1 - 9.0 9.2 112 MERI Meridian Energy TWZ Twizel 0.1 0.1 0.0 0.2 0.1 0.1 - 0.0 0.2 0.1 0.1 - 0.2 113 MERI Meridian Energy WTK Waitaki 0.8 4.2 5.0 0.8 - 4.2 5.1 0.8 - 4.0 4.8 114 MERI Meridian Energy (blank) (blank) (0.0) (0.0) - -

115 METH MNI Motunui 0.5 0.7 1.1 0.5 0.7 - 1.1 0.5 0.7 - 1.2

116 MPOW ASY Ashley 0.6 0.8 0.5 1.8 0.6 0.9 - 0.7 2.3 0.6 1.3 - 0.7 2.6

117 MPOW CUL Culverden 0.9 1.2 0.0 2.2 0.9 1.2 - 0.0 2.1 0.9 1.9 - - 2.8

118 MPOW KAI Kaiapoi 0.7 2.7 0.4 3.8 0.7 2.9 - 0.4 4.0 0.7 2.6 - 0.4 3.7

119 MPOW SBK Southbrook 0.4 4.2 4.7 0.5 4.5 - 4.9 0.5 4.7 - 0.4 5.6

120 MPOW WPR Waipara 0.3 1.1 0.1 1.4 0.3 0.9 - 0.1 1.2 0.3 1.1 - 0.1 1.4

121 MPOW (blank) (blank) (0.0) 0.1 0.1 - -

122 MRPL Mighty River Power ARA Aratiatia 0.6 0.6 0.7 - - 0.7 0.7 - - 0.7 123 MRPL Mighty River Power ARI Arapuni 0.3 0.3 0.3 - - 0.3 0.3 - - 0.3 124 MRPL Mighty River Power ATI Atiamuri 0.1 0.1 0.1 - - 0.1 0.1 - - 0.1 125 MRPL Mighty River Power HAM Hamilton 0.0 0.0 - - 126 MRPL Mighty River Power KPO Karapiro 0.8 0.8 0.8 - - 0.8 0.1 - - 0.1 127 MRPL Mighty River Power MTI Maraetai 1.3 1.3 1.3 - - 1.3 1.3 - - 1.3 128 MRPL Mighty River Power OHK Ohakuri 0.1 0.1 0.1 - - 0.1 0.1 - - 0.1 129 MRPL Mighty River Power WKM Whakamaru 0.2 0.2 0.2 - - 0.2 0.2 - - 0.2 130 MRPL Mighty River Power WPA Waipapa 0.7 0.7 0.7 - - 0.7 0.7 - - 0.7 131 MRPL Mighty River Power (blank) (blank) - - - -

132 NAPA NAP Nga Awa Purua 0.4 0.0 0.4 0.8 0.9 0.0 - 0.4 1.3 0.4 - - 0.4 0.8

133 NELS Nelson Electricity STK Stoke 0.1 1.0 0.1 1.2 0.1 1.1 - 0.1 1.3 0.1 1.2 - 0.1 1.4 134 NPOW Northpower BRB Bream Bay 1.7 3.9 5.6 1.7 4.3 - 6.0 1.7 5.1 - 6.8 135 NPOW Northpower MPE Maungatapere 0.3 10.4 0.1 10.8 0.3 10.7 - 0.1 11.1 0.3 11.8 - 0.1 12.2 136 NPOW Northpower MTO Maungaturoto 0.4 1.4 1.8 0.5 1.6 - 2.1 0.5 1.8 - 2.2 137 NPOW Northpower (blank) (blank) 0.0 0.1 0.1 - -

138 NTRG NAP Nga Awa Purua 0.3 0.0 0.5 0.8 0.6 - - 0.5 1.1 0.3 - - 0.5 0.8

139 NZAS NZ Aluminium Smelter TWI Tiwai 1.3 63.0 64.3 1.3 65.9 - 67.2 1.3 71.2 - 72.5 140 NZST New Zealand Steel GLN Glenbrook 2.3 5.0 0.1 7.3 2.3 1.8 - 0.1 4.1 2.4 3.0 - 0.1 5.4 141 NZST New Zealand Steel (blank) (blank) (0.0) (0.0) - - 142 ORON Orion New Zealand APS Arthurs Pass 0.2 0.0 0.2 0.2 0.0 - 0.2 0.2 0.0 - 0.2 143 ORON Orion New Zealand BRY Bromley 1.9 13.4 0.8 16.0 1.9 15.2 - 0.8 17.9 2.0 13.3 - 0.8 16.1 144 ORON Orion New Zealand CLH Castle Hill 0.1 0.0 0.2 0.1 0.0 - 0.2 0.1 0.0 - 0.2 145 ORON Orion New Zealand COL Coleridge 0.1 0.0 0.2 0.1 0.0 - 0.2 0.1 0.0 - 0.2 146 ORON Orion New Zealand HOR Hororata 0.5 1.4 0.0 2.0 0.5 1.6 - 0.0 2.1 0.5 3.0 - 0.0 3.5 147 ORON Orion New Zealand ISL Islington 1.8 47.8 0.5 50.1 1.8 48.7 - 0.5 51.0 1.9 47.9 - 0.3 50.0 148 ORON Orion New Zealand KBY Kimberley 0.0 0.4 1.1 1.5 0.0 0.4 - 1.0 1.5 0.0 0.9 - 1.0 2.0 149 ORON Orion New Zealand (blank) (blank) 0.0 0.0 - - 150 ORON Orion New Zealand MLN Middleton 0.0 0.0 - - 151 PANP WHI Whirinaki 1.0 4.0 5.1 1.0 2.5 - 3.5 1.1 3.3 - 4.3 152 POCO Powerco BPE Bunnythorpe 0.8 8.3 0.1 9.2 0.8 9.6 - 0.1 10.5 0.8 9.8 - 0.0 10.6 153 POCO Powerco BRK Brunswick 0.6 2.8 3.4 0.6 3.1 - 3.7 0.6 2.9 - 3.5 154 POCO Powerco CST Carrington St 0.5 5.0 0.7 6.2 0.5 5.7 - 0.6 6.8 0.5 5.0 - 0.6 6.0 155 POCO Powerco GYT Greytown 0.5 0.9 1.4 0.5 1.1 - 1.5 0.5 1.2 - 1.7 156 POCO Powerco HIN Hinuera 1.0 3.8 4.8 1.0 3.8 - 4.8 0.8 4.2 - 5.0 157 POCO Powerco HUI Huirangi 0.4 1.5 1.9 0.4 1.3 - 0.9 2.6 0.4 2.5 - 0.9 3.8 158 POCO Powerco HWA Hawera 0.5 1.0 0.3 1.8 0.6 0.1 - 0.3 0.9 0.6 0.6 - 0.3 1.5 159 POCO Powerco KIN Kinleith 1.3 5.5 6.8 1.3 5.7 - 7.0 1.3 5.8 - 7.2 160 POCO Powerco KMO Kaitimako 0.1 1.8 0.4 2.3 0.1 2.1 - 0.4 2.6 0.1 2.1 - 0.4 2.6 161 POCO Powerco KPU Kopu 2.4 4.1 0.0 6.5 2.3 4.4 - 0.0 6.7 2.4 4.7 - 0.2 7.3 162 POCO Powerco LTN Linton - 0.8 4.9 - 0.0 5.7 0.9 4.8 - 0.0 5.7 163 POCO Powerco MGM Mangamaire 0.4 0.9 1.3 0.5 1.0 - 1.5 0.5 1.2 - 1.6 164 POCO Powerco MST Masterton 0.4 4.1 0.7 5.1 0.4 4.5 - 0.7 5.5 0.4 4.8 - 0.7 5.8 165 POCO Powerco MTM Mt Maunganui 0.2 6.1 1.0 7.2 0.2 6.7 - 0.9 7.8 0.2 7.1 - 0.9 8.3 166 POCO Powerco MTN Marton 0.4 1.6 1.9 0.4 1.6 - 2.0 0.4 1.7 - 2.1 167 POCO Powerco MTR Mataroa 0.3 0.7 1.0 0.3 0.7 - 1.0 0.3 0.7 - 1.0 168 POCO Powerco NPL New Plymouth 0.4 1.8 2.1 0.4 2.0 - 2.4 0.4 2.0 - 2.4 169 POCO Powerco OKN Ohakune 0.1 0.2 0.2 0.1 0.2 - 0.3 0.1 0.2 - 0.3 170 POCO Powerco OPK Opunake 1.1 0.7 1.8 1.1 0.7 - 1.8 1.1 0.8 - 1.9 171 POCO Powerco PAO Piako 0.3 2.5 1.3 4.0 0.3 2.9 - 1.4 4.5 0.2 3.7 - 1.4 5.3 172 POCO Powerco SFD Stratford 0.4 2.2 2.6 0.4 2.3 - 2.7 0.5 2.4 - 2.9 173 POCO Powerco TGA Tauranga 1.1 6.1 1.4 8.6 1.0 7.1 - 1.3 9.4 1.0 7.8 - 1.3 10.1 174 POCO Powerco TMI Te Matai 0.5 2.6 0.3 3.3 0.5 3.1 - 0.2 3.8 0.5 3.5 - 0.2 4.2 175 POCO Powerco WGN Wanganui 0.4 2.6 3.0 0.4 2.6 - 3.0 0.5 3.2 - 3.6 176 POCO Powerco WHU Waihou 1.0 2.5 3.6 1.0 2.5 - 3.5 1.0 2.6 - 3.6 177 POCO Powerco WKO Waikino 1.3 3.3 4.6 1.2 3.4 - 4.6 1.3 3.6 - 4.9 178 POCO Powerco WVY Waverley 0.2 0.4 0.6 0.2 0.3 - 0.6 0.2 0.4 - 0.6 179 POCO Powerco (blank) (blank) (0.0) 0.0 0.0 - - 180 POCO Powerco LIN Linton 0.8 4.4 0.0 5.2 - - 181 POWN PowerNet BAL Balclutha 1.1 2.3 3.4 1.0 2.6 - 3.6 1.0 2.6 - 3.7 182 POWN PowerNet EDN Edendale 0.2 1.6 1.8 0.2 1.1 - 0.1 1.4 0.3 1.2 - 0.0 1.5 183 POWN PowerNet GOR Gore 0.6 2.7 3.3 0.6 2.8 - 3.4 0.6 3.0 - 3.6 184 POWN PowerNet HWB Halfway Bush 0.1 0.6 0.1 0.8 0.1 0.6 - 0.1 0.8 0.1 0.8 - 0.2 1.0 185 POWN PowerNet INV Invercargill 0.4 8.2 0.6 9.3 0.4 9.1 - 0.6 10.2 0.4 9.5 - 0.6 10.5 186 POWN PowerNet NMA North Makarewa 0.8 3.5 1.8 6.1 0.8 3.8 1.8 6.4 0.8 3.4 1.5 5.7 187 POWN PowerNet NSY Naseby 0.6 1.5 0.0 0.1 2.2 0.6 1.9 0.0 0.1 2.6 0.6 2.3 0.0 0.0 2.9 188 POWN PowerNet (blank) (blank) 0.0 0.0 0.0 - -

189 PTNP NPL New Plymouth 0.0 0.0 0.0 0.0 0.0 - 0.0 0.0 0.0 - 0.0

190 RAYN Dongwha Patinna BDE Brydone 0.2 0.7 0.9 0.2 0.8 - 0.9 0.2 0.9 - 1.1 191 SCAN Scanpower DVK Dannevirke 0.4 1.2 0.2 1.8 0.4 1.3 - 0.2 1.8 0.4 1.4 - 0.2 1.9 192 SCAN Scanpower WDV Woodville 0.3 0.3 0.1 0.6 0.3 0.3 - 0.1 0.6 0.3 0.3 - 0.1 0.7



Fonterra Todd Cogeneration

Origin Energy Resources

Methanex New Zealand

MainPower New Zealand






Nga Awa Purua Joint Venture

Ngatamariki Geothermal

Pan Pac Forest Products

Port Taranaki New Plymouth



193 SCGL SWN Southdown - 0.1 - - 0.1 0.0 0.0 - 0.1

194 SENZ BDE Brydone 0.0 0.0 0.0 0.0 0.0 0.0 - 0.0 0.0 0.0 0.0 - 0.0 0.0

195 SGGP Southern Generation MAT Matahina - - - - - 0.2 0.2 196 SHPK Southpark Utilities PEN Penrose 0.0 0.0 0.0 0.1 0.0 0.0 - 0.0 0.1 0.0 0.0 - 0.0 0.1 197 TAPP Norske Skog Tasman KAW Kawerau 1.2 0.8 2.0 1.2 - - 0.8 2.0 1.2 - - 0.7 2.0 198 TASM Network Tasman KIK Kikiwa 0.1 0.2 0.3 0.1 0.2 - 0.3 0.1 0.2 - 0.3 199 TASM Network Tasman MCH Murchison 0.2 0.2 0.4 0.2 0.2 - 0.4 0.2 0.2 - 0.4 200 TASM Network Tasman STK Stoke 1.3 9.7 0.3 11.4 1.4 10.9 - 0.3 12.6 1.4 10.2 - 0.2 11.8 201 TBOP Nova Energy KPA Kaponga 0.3 0.3 0.3 - - 0.3 0.3 - - 0.3 202 TBOP Nova Energy MAT Matahina 0.2 0.2 - - - 0.2 0.2 - 203 TBOP Nova Energy MKE McKee 0.0 0.0 0.2 0.2 0.0 0.0 - 0.2 0.2 0.0 0.0 - 0.2 0.2 204 TOPE Top Energy KOE Kaikohe 1.2 4.0 5.2 1.1 4.5 - 5.6 1.1 4.6 - 5.6 205 TOPE Top Energy (blank) (blank) (0.0) (0.0) - - 206 TRNZ KiwiRail BPE Bunnythorpe 0.4 0.1 0.5 0.4 0.1 - 0.5 0.4 0.1 - 0.5 207 TRNZ KiwiRail HAM Hamilton 0.4 0.1 0.5 0.4 0.1 - 0.4 0.4 0.1 - 0.5 208 TRNZ KiwiRail PEN Penrose 0.1 0.0 0.2 0.1 0.2 - 0.4 0.1 0.5 - 0.6 209 TRNZ KiwiRail SWN Southdown 0.1 0.0 0.5 0.6 0.1 0.4 - 0.5 1.0 0.1 0.4 - 0.5 1.0 210 TRNZ KiwiRail TMN Taumarunui 0.5 0.2 0.6 0.5 0.1 - 0.6 0.5 0.1 - 0.6 211 TRNZ KiwiRail TNG Tangiwai 0.5 0.1 0.6 0.5 0.1 - 0.6 0.5 0.0 - 0.5 212 TRUS TrustPower ARG Argyle 0.1 0.0 0.5 0.6 0.1 - 0.5 0.6 0.1 - 0.5 0.5 213 TRUS TrustPower BWK Berwick 1.8 1.8 - - - 1.8 1.8 - - - 1.8 1.8 214 TRUS TrustPower COL Coleridge 0.0 1.8 1.9 0.1 - 1.8 1.9 0.1 - 2.0 2.0 215 TRUS TrustPower HWA Hawera - - - - - - - - - 216 TRUS TrustPower MAT Matahina 0.8 0.8 - - - 0.8 0.8 - - - 0.8 0.8 217 TRUS TrustPower MTM Mt Maunganui 0.0 0.0 0.0 0.0 - 218 TRUS TrustPower ROT Rotorua - - - - - - - - - 219 VECT Vector ALB Albany 1.1 22.5 0.4 24.0 1.1 23.1 - 0.4 24.6 1.1 23.3 - 0.4 24.8 220 VECT Vector HEN Henderson 0.5 11.1 0.3 11.9 0.5 13.3 - 0.3 14.0 0.5 12.8 - 0.3 13.6 221 VECT Vector HEP Hepburn Road 1.0 13.9 0.3 15.2 1.0 13.9 - 0.3 15.1 1.0 15.6 - 0.3 16.9 222 VECT Vector HOB Hobson 0.7 0.9 4.2 5.8 0.7 3.7 - 3.5 7.9 0.7 3.8 - 3.5 8.0 223 VECT Vector LFD Lichfield 0.0 0.3 0.3 0.0 0.2 - 0.2 0.0 0.5 - 0.6 224 VECT Vector MNG Mangere 0.6 13.8 0.6 15.0 0.6 12.0 - 0.6 13.1 0.6 11.8 - 0.6 13.0 225 VECT Vector OTA Otahuhu A 0.8 6.3 0.1 7.2 0.8 6.7 - 0.1 7.6 0.9 6.3 - 0.1 7.3 226 VECT Vector PAK Pakuranga 1.4 13.5 0.4 15.3 1.4 14.2 - 0.5 16.1 1.4 15.1 - 0.5 17.0 227 VECT Vector PEN Penrose 2.0 37.5 1.3 40.8 2.0 33.1 - 1.1 36.2 2.0 48.3 - 1.2 51.5 228 VECT Vector ROS Mt Roskill 0.7 17.8 0.6 19.1 0.7 18.1 - 0.5 19.4 0.8 18.2 - 0.5 19.5 229 VECT Vector SVL Silverdale 0.6 7.7 1.3 9.6 0.6 8.3 - 1.2 10.2 0.7 9.0 - 1.2 10.8 230 VECT Vector SWN Southdown 3.5 3.5 - - 231 VECT Vector TAK Takanini 1.2 11.0 12.2 1.2 11.4 - 12.5 1.2 12.0 - 13.2 232 VECT Vector WEL Wellsford 0.3 3.1 0.0 3.5 0.3 3.4 - 0.0 3.8 0.4 3.7 - 0.0 4.1 233 VECT Vector WIR Wiri 1.2 8.2 0.2 9.7 1.2 8.8 - 0.1 10.2 1.3 9.6 - 0.1 11.0 234 VECT Vector WRD Wairau Road 0.7 5.6 3.1 9.3 0.5 6.9 - 3.1 10.5 0.5 7.5 - 3.1 11.1 235 VECT Vector (blank) (blank) 0.0 0.0 - -

236 VWEN CPK Central Park 1.9 17.2 0.1 19.2 1.9 18.4 - 0.1 20.3 1.4 18.9 - 0.1 20.4

237 VWEN GFD Gracefield 1.2 6.0 7.2 1.2 6.5 - 7.6 1.2 6.5 - 7.7

238 VWEN HAY Haywards 0.7 3.2 3.9 0.7 3.5 - 4.1 0.7 3.6 - 4.3

239 VWEN KWA Kaiwharawhara 0.5 3.1 0.7 4.2 0.5 3.2 - 0.6 4.3 0.4 3.3 - 0.6 4.4

240 VWEN MLG Melling 1.4 5.9 7.3 1.4 6.3 - 7.7 1.5 6.5 - 8.0

241 VWEN NGA Ngauranga - 0.0 - - 0.0 0.0 - - 0.0

242 VWEN PNI Pauatahanui 0.5 1.9 2.4 1.1 2.0 - 3.0 1.1 2.0 - 3.1

243 VWEN TKR Takapu Road 0.6 9.0 0.3 9.8 0.5 9.6 - 0.3 10.4 0.5 10.1 - 0.3 10.9

244 VWEN UHT Upper Hutt 0.3 3.0 0.2 3.5 0.3 3.2 - 0.2 3.7 0.3 3.3 - 0.2 3.9

245 VWEN WIL Wilton 1.4 3.8 0.1 5.3 1.6 2.8 - 0.1 4.5 1.6 3.8 - 0.1 5.5

246 WAIP Waipa Networks CBG Cambridge 0.7 3.3 0.1 4.0 0.7 3.7 - 0.1 4.5 0.6 4.1 - 0.1 4.7 247 WAIP Waipa Networks TMU Te Awamutu 1.1 3.1 0.0 4.3 1.0 3.4 - 0.0 4.4 0.6 3.6 - 0.8 5.0 248 WATA Network Waitaki BPT Blackpoint 0.1 0.2 0.4 - - - 0.2 0.2 0.4 - - - 0.2 0.2 0.4 249 WATA Network Waitaki OAM Oamaru 0.8 3.0 3.8 0.6 3.2 - 3.8 0.6 3.2 - 3.8 250 WATA Network Waitaki TWZ Twizel 0.2 0.1 0.3 0.2 0.2 - 0.4 0.2 0.2 - 0.4 251 WATA Network Waitaki WTK Waitaki 0.1 0.2 0.0 0.4 0.2 0.1 - 0.1 0.4 0.2 0.2 - 0.1 0.4 252 WELE WEL Networks HAM Hamilton 1.1 14.6 0.4 16.0 1.1 15.2 - 0.3 16.6 1.1 16.3 - 0.3 17.7 253 WELE WEL Networks HLY Huntly 0.2 2.2 0.7 3.1 0.2 2.3 - 0.7 3.2 0.2 2.3 - 0.7 3.2 254 WELE WEL Networks MER Meremere 0.3 0.0 0.4 0.3 - - 0.3 0.3 - - 0.3 255 WELE WEL Networks TWH Te Kowhai 0.5 0.9 1.4 2.9 0.5 4.8 - 1.4 6.7 0.5 2.2 - 1.3 4.1 256 WELE WEL Networks WES Western Rd - - - - - - - - - 257 WELE WEL Networks (blank) (blank) (0.0) (0.0) - - 258 WIND Tararua Wind Power TWC Tararua 0.1 0.0 0.3 0.4 0.1 0.0 - 0.3 0.4 0.1 0.0 - 0.3 0.4

259 WNST TNG Tangiwai 1.1 3.1 4.2 1.1 2.7 - 3.7 1.1 2.9 - 4.0

260 WPOW Westpower ATU Atarau 0.1 0.0 0.1 0.1 0.0 - 0.1 0.1 0.0 - 0.1 261 WPOW Westpower DOB Dobson 0.3 0.5 0.0 0.8 0.3 0.4 0.0 0.7 0.3 0.4 0.0 0.8 262 WPOW Westpower GYM Greymouth 0.0 0.2 0.1 0.3 0.0 0.3 0.1 0.4 0.0 0.2 0.1 0.3 263 WPOW Westpower HKK Hokitika 0.2 0.2 0.1 0.5 0.1 0.1 0.1 0.4 0.1 0.5 0.1 0.7 264 WPOW Westpower KUM Kumara - - - - - - - - - 265 WPOW Westpower OTI Otira 0.2 0.0 0.2 0.2 0.0 - 0.2 0.2 0.0 - 0.2 266 WPOW Westpower RFN Reefton 0.0 0.8 0.0 0.8 0.0 0.9 - 0.9 0.0 0.5 - 0.6 267 WPOW Westpower (blank) (blank) 0.0 0.0 - - 268 WTOM The Lines Company HTI Hangatiki 0.9 2.1 3.0 0.8 2.2 - 3.1 0.5 2.6 - 3.1 269 WTOM The Lines Company NPK National Park 0.3 0.4 0.7 0.3 0.4 - 0.7 0.3 0.4 - 0.7 270 WTOM The Lines Company OKN Ohakune 0.1 0.4 0.6 0.2 0.5 - 0.7 0.2 0.5 - 0.6 271 WTOM The Lines Company ONG Ongarue 0.3 0.2 0.5 0.3 0.2 - 0.5 0.3 0.1 - 0.5 272 WTOM The Lines Company TKU Tokaanu 0.1 0.6 0.7 0.1 0.7 - 0.8 0.1 0.7 - 0.8 273 - - 274 TOTAL 127.1 632.3 149.9 6.7 41.8 957.8 128.4 662.1 152.3 3.3 41.4 987.4 127.0 715.1 149.2 3.3 40.2 1,034.8 275 note: location "(blank)" relates to the wash-up for each customer under the TPM

276 F6(iv): Other Regulated Income (excl Asset Disposals)277 Note: this section states the revenue received in the disclosure year (ended on 30 June 201 HVAC HVDC278 Total Income Distributors Generators Direct Connects Generators Other279 Type of Income ($M) ($M) ($M) ($M) ($M) ($M)

280 (1.0) (1.0)

281 Other miscellaneous items (0.2) (0.2)282 Insurance proceeds (0.5) (0.5)283 TOTAL (1.7) - - - - (1.7)

284 *Insert additional rows and update calculation of totals as needed

Southdown Cogeneration

Solid Energy New Zealand

Wellington Electricity Lines










Winstone Pulp International

Scrap metal proceeds (125 items averaging $8k each)



285

286 F6(v): Asset Disposals

288 Total Income/(Loss) Disposal Value

289 Asset ($M) ($M)290 Islington (1.4) 1.4

291 Otahuhu (1.0) 1.0

292 Wanganui (0.3) 0.3

293 Transpower House (0.2) 0.3

294 Penrose (1.1) 1.1

295 South Island Control Centre (0.2) 0.2

296 NICC, Hamilton (0.2) 0.2

297 Takapu Road (0.2) 0.2

298 New Plymouth - Stratford A (0.2) 0.2

299 Benmore DC (0.2) 0.2

300 Benmore -Haywards A (0.1) 0.1

301 Hepburn Road (0.5) 0.5

302 Ashley (0.1) 0.1

303 Bunnythorpe - Haywards (0.6) 0.6

304 Mangahao - Paekakariki (0.7) 0.7

305 Bombay (0.1) 0.1

306 Edgecumbe (0.1) 0.1

307 Clyde (0.1) 0.1

308 Ohinewai (0.1) 0.1

309 Silverdale Radio Hut (0.1) 0.1

310 Henderson (0.1) 0.1

311 Huirangi (0.1) 0.1

312 Glenbrook-Deviation A (0.1) 0.1

313 Mt Threave (0.1) 0.1

314 Hairini-Tauranga A (0.1) 0.1

315 Halfway Bush (0.1) 0.1

316 Te Weraiti (0.1) 0.1

317 Roxburgh (0.1) 0.1

318 Huntly (0.1) 0.1

319 Blenheim-Stoke A 0.0 0.6

320 Bombay Radio 0.9 0.1

321 Maungatapere 0.1 0.1

322 Transpower Warehouse (0.1) 0.1

323 Locations < $50k NBV 1.8 1.6

324 TOTAL (5.1) 10.5 325

326 F6(vi): Asset Divestments327 Amounts stated are in the year to 30 June 2016328 Party Asset Divested to Disposal Value

329 ($M)330 Mainpower Ashley Deviation Line 0.1 331

332 TOTAL 0.1

333

There are too many assets to list individually. The total number of non-zero asset disposals was 1432 with an average NBV at disposal of $7,364. Assets have been grouped by location, showing those locations with an aggregate NBV at disposal over $50,000.

Description of Assets Divested


Tab name: TP6. Investment contracts 05/09/2023

Investment Contracts (new contracts in the disclosure yearTranspower Disclosure Date ###under paragraph 10 of the Transpower Information Disclosure Determination 2014 Disclosure Year (year ended) ###

Customer Name Contract Title Brief Description Electrical Capacity Contract Signed Date

Alpine Energy Timaru Additional 11 kV Feeders Installation of four new 11 kV feeders and associated feeder protection 11 kV 8/18/2015 $ 873,100

Network Waitaki Waitaki 11 kV Switchgear Modifications Installation of 11 kV feeder protection & intertip relay, modify existing T28 protection, remove interlock scheme 11 kV 8/10/2015 $ 658,632

Contract Budget / Estimated build

cost


Tab name: G1. System Statistics 05/09/2023


SCHEDULE G1: TRANSMISSION SYSTEM STATISTICS Disclosure Year (year ended ###Note: The data used for the current year (2015/16) disclosures has been improved and so the prior year numbers have been restated to be consistent with the current year.

ref

5 G1(i): Circuit Information Transmission System Statistics67 System length by operating voltage (kV) CY-1 (km) CY (km)8 Total 16,743.0 16,734.0 9 350kV (HVDC) 1,225.0 1,225.0

10 0 kV (HVDC earth electrode) 35.0 35.0 11 220kV (HVAC) 9,193.0 9,188.0 12 110kV (HVAC) 5,501.0 5,498.0 13 66/50kV (HVAC) (Includes leased assets) 789.0 788.0 1415 Circuit length of overhead electric lines by operating voltage (kV)16 Total 16,589.0 16,580.0 17 350kV (HVDC) 1,145 1,145 18 0 kV (HVDC earth electrode) 35 35 19 220kV (HVAC) 9,137 9,132 20 110kV (HVAC) 5,484 5,481 21 66/50kV (HVAC) (includes leased assets) 788 787

23 Route length of overhead electric lines by operating voltage (kV)24 Total 11,062.5 11,056.0 25 350kV (HVDC) 572 572 26 0 kV (HVDC earth electrode) 12 12 27 220kV (HVAC) 5,914 5,914 28 110kV (HVAC) 4,122 4,122 29 66/50kV (HVAC) (includes leased assets) 443 436

31 Circuit length of HVAC underground transmission cable by operating voltage (kV)32 Total 74.0 74.0 33 350kV (HVDC) - - 34 220kV (HVAC) 56 56 35 110kV (HVAC) 17 17 36 66kV (HVAC) 1 1

38 Total length of HVDC submarine cable by operating voltage (kV)39 Total 121.0 121.0 40 350kV (HVDC) 121 121 4142 CY (Quantity)43 HVAC Substation/Switching Station 169 169 44 HVDC Convertor stations 2 2 45 HVDC Electrode stations 2 2 46 HVDC Cable transition stations 2 2 47 HVAC Cable transition stations 29 29 48 Interconnecting Transformer Banks ( 66 kV and above) 57 57 49 Supply Transformer Banks ( 66 kV and above) 266 265 50 Dynamic Reactive power Static (SVCs and STATCOMs) 10 10 51 Dynamic Reactive power Synchronous Condensers 8 8 52 Capacitor Banks (HVAC System) 58 84 53 AC filter Banks (HVDC) 14 14 54 Series and Shunt reactors 145 134 55 Outdoor Circuit Breakers ( 66 kV and above) 1,149 1,174 56 Outdoor Circuit Breakers (33,22,11kV) 320 326 57 Indoor Circuit Breakers ( 66 kV and above) 73 75 58 Indoor Circuit Breakers (33,22,11kV) 827 924 59

CY-1 (Quantity)


Tab name: G2. Grid Demand and Injection 05/09/2023


SCHEDULE G2: GRID DEMAND AND INJECTION Disclosure Year (year ended) ###

ref

5 G2(i): Demand and Injection6 CY-4 CY-3 CY-2 CY-1 CY7 Energy Volume (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)8 Generators (Injection) 38,003.00 37,983.95 9 GXP-EDBs (offtake) 30,715.47 30,581.29

10 GXP-direct connects (Offtake) 7,261.83 7,338.37 11 HVDC flows north 3,191.72 3,219.31 12 HVDC flows south 155.80 139.02 13 HVDC Losses 121.38 116.05 14 AC System Losses 1,116.43 1,198.65 The 2014/15 (CY-1) number has been restated

15CY-4 CY-3 CY-2 CY-1 CY

17 Maximum peak demand (MW) (MW) (MW) (MW) (MW) (MW)18 Generators (Injection) 6,276.95 6,283.61 see note below

19 GXP-EDBs (offtake) 5,546.56 5,499.99 20 GXP-direct connects (Offtake) 924.20 914.32 21 HVDC flows north 1,077.71 985.37 22 HVDC flows south 503.30 495.83 23 HVDC Losses 60.30 50.76 24 AC System Losses 235.24 263.89 The 2014/15 (CY-1) number has been restated 25

26Note: the Maximum Peak Demand figure for Generators (Injection) is not the same as the System Maximum Demand (SMD) figure that we use for the purposes of network performance reporting. SMD also includes injection from generators which are embedded through a distribution network connection.

Transpower Disclosure Date 42551 -1409d mmmm yyyy

SCHEDULE G3: GRID EXIT POINT (GXP) CONNECTION CAPACITY AND DEMAND (ACTUAL AND FORECAST) Disclosure Year (year en 42551 -1409d mmmm yyyy

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5 G3(i): Current Connection Capacity vs Actual and Forecast Demand

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7Forecast Demand (MVA)

8 GXP Name / Region Name CY CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 Comments on Capacity 9 Bream Bay Yes 53 55 56 56 56 57 57 57 58 58 58 No issues

10 Kaikohe Yes 65 88 89 90 90 91 91 92 93 93 94 No issues

11 Maungatapere Yes 100 125 127 129 131 133 135 137 139 141 143 No issues

12 Maungaturoto Yes 18 19 19 20 20 20 21 21 21 22 22 No issues

13 Wellsford Yes 34 35 35 36 36 37 38 38 39 39 40 14 Yes 154 146 147 149 150 152 153 154 156 157 159 No issues

15 Yes 117 180 180 180 180 180 180 180 180 180 180 No issues

16 Yes 12 14 14 15 15 - - - - - - Load shifting to 110 kV bus in 2021

17 Yes 119 91 98 105 111 133 140 147 154 161 168 No issues

18 Yes 68 68 69 70 71 71 72 73 74 75 75 No issues

19 Glenbrook - NZ Steel (Dirty bus) Yes 124 116 116 116 116 116 116 116 116 116 116 No issues

20 Henderson No 130 151 159 168 177 186 196 205 214 224 234 21 Hepburn Rd Yes 133 157 158 158 159 159 160 161 161 162 163 No issues

22 Hobson Street Yes 73 135 143 146 149 152 155 158 161 164 167 No issues

23 No 131 124 126 129 132 134 137 140 142 145 148 24 Yes 60 28 28 28 28 28 28 28 28 28 28 No issues

25 Meremere Yes 3 6 6 6 6 6 6 6 6 6 6 No issues

26 No 131 132 132 132 132 132 132 132 132 132 132 27 Yes 118 72 72 72 72 72 72 72 72 72 72 No issues

28 Mt Roskill 110 kV - Liverpool St feeder Yes - - - - - - - - - - - No issues

29 Otahuhu No 64 72 73 73 73 73 74 74 74 75 75 30 Pakuranga Yes 144 155 155 155 156 156 156 157 157 157 157 No issues

31 Yes 48 52 52 52 53 53 53 53 54 54 54 No issues

32 Yes 277 317 320 323 326 329 331 334 337 340 343 No issues

33 Yes 386 135 143 146 149 152 155 158 161 164 167 No issues

34 Silverdale Yes 83 96 98 99 101 102 103 105 106 108 109 No issues

35 Takanini No 115 124 124 124 124 124 124 124 124 124 124 36 Wiri Yes 85 97 98 99 101 102 104 105 107 108 110 37 Cambridge No 40 45 45 46 47 47 48 49 50 50 50 38 Yes 35 41 42 42 43 43 43 44 44 45 45 39 No 137 148 150 151 153 154 156 158 159 161 161 40 Hamilton NZR Yes 13 7 7 7 7 7 7 7 7 7 7 No issues

41 Hangatiki No 37 43 44 44 45 46 46 47 48 48 48 42 Hinuera No 44 51 52 33 33 33 34 34 34 35 35 43 Huntly Yes 28 28 28 29 29 29 29 29 29 29 29 No issues

44 Yes 82 84 84 84 84 84 84 84 84 84 84 No issues

45 No 19 21 21 21 21 21 22 22 22 22 22 46 Kopu Yes 52 53 54 55 55 56 57 58 59 60 60 47 Lichfield Yes 9 17 17 17 18 18 18 18 18 18 18 No issues

48 Piako Yes 36 42 42 43 44 45 46 47 48 48 48 No issues

49 Putaruru Yes - - - 20 20 20 20 20 21 21 21 New GXP planned for 2019

50 Te Awamutu No 47 41 41 41 42 42 42 42 42 43 43 51 Te Kowhai Yes 105 97 97 98 98 99 100 100 101 102 102 No issues

52 Waihou No 37 53 54 55 56 57 57 58 59 60 60 53 Waikino No 34 39 40 40 41 42 42 43 43 44 44 54 Edgecumbe No 63 66 67 68 69 69 70 70 72 72 72 55 Kaitimako Yes 26 24 24 30 30 30 31 31 32 32 32 No issues

56 Kawerau Horizon Yes 19 20 20 20 20 20 20 20 20 20 20 No issues

57 Kawerau T6-T9 Yes 27 47 47 47 47 47 47 47 47 47 47 No issues

58 Kawerau – T11 and T14 Yes 79 78 78 78 78 78 78 78 78 78 78 No issues

59 Matahina Yes - 17 17 17 17 17 17 17 17 17 17 No issues

60 Yes 67 71 70 71 53 53 56 56 59 59 59 No issues

61 Owhata No 14 15 15 15 15 15 15 15 15 15 15 62 Yes 29 31 32 32 32 32 33 33 33 33 33 63 Yes 45 51 51 51 52 52 52 52 53 53 53 64 No 12 10 10 10 11 11 11 11 11 11 11 The load at Tarukenga is supplied through a single 110/11 kV, 20 MVA supply transformer.

65 No 30 32 32 28 28 28 29 29 30 30 30 66 Yes 83 73 74 76 77 77 80 80 83 83 83 No issues

67 Te Kaha No 1 3 3 3 3 3 3 3 3 3 3 The load at Te Kaha is supplied through a single 50 kV transmission circuit and a single 50/11 kV, 5 MVA supply transformer.

68 Te Matai Yes 32 37 41 41 62 62 64 64 65 65 65 69 Waiotahi Yes 10 13 13 13 13 13 14 14 14 14 14 70 No 101 113 108 109 110 111 112 113 115 116 117 71 Bunnythorpe NZR Yes 11 7 7 7 7 7 7 7 7 7 7 No issues

72 Dannevirke Yes 13 13 13 13 13 13 13 13 14 14 14 No issues

73 Linton Yes 62 65 73 74 75 76 77 78 79 80 81 74 Mangahao No 46 40 41 41 41 41 41 42 42 42 42 75 Mangamaire Yes 15 19 19 19 20 20 20 20 20 20 20 No issues

76 Marton Yes 16 19 19 19 20 20 20 21 21 21 22 77 Mataroa No 7 8 8 8 8 8 8 8 8 8 8 The load at Mataroa is supplied through a single 110/33 kV, 30 MVA supply transformer.

78 National Park No 6 7 7 7 7 7 7 7 7 7 7 The load at National Park is supplied through a single 110/33 kV, 15 MVA supply transformer.

79 Ohakune No 10 11 11 12 12 12 12 12 12 13 13 The load at Ohakune is supplied through a single 110/33 kV, 20MVA supply transformer.

80 Ongarue No 9 10 10 11 11 11 11 11 11 11 12 The load at Ongarue is supplied through a single 110/33 kV, 20MVA supply transformer.

81 Yes 38 40 41 41 41 41 42 42 42 42 42 No issues

82 Tangiwai NZR Yes 12 10 10 10 10 10 11 11 11 11 11 No issues

83 Tokaanu No 9 11 11 11 11 11 11 11 11 12 12 The load at Tokaanu is supplied through a single 220/33 kV, 20MVA supply transformer.

84 Waipawa Yes 20 21 21 21 21 21 21 21 21 21 21 No issues

85 Wairakei Yes 44 32 32 33 33 33 33 34 34 34 34 No issues

86 Woodville Yes 3 3 3 3 3 3 3 3 3 3 3 No issues

87 Brunswick No 39 47 47 47 48 48 49 49 50 50 53 88 Carrington Street Yes 54 51 53 79 81 83 85 87 88 90 99 89 Hawera Yes 39 32 32 33 33 33 33 34 34 35 36 90 Hawera (Kupe) No 9 11 11 11 11 11 11 11 11 11 11 A single 110/33 kV, 30 MVA supply transformer supplies the Origin Energy Resources Kupe load, resulting in no n-1 security.

91 Huirangi No 36 62 63 64 64 65 66 67 67 68 72 The peak load at Huirangi is forecast to exceed the transformers’ n-1 summer capacity by 2 MW in 2016, increasing to approximately 13 MW in 2031. Operational measures will be used to prevent transformer overloading.

92 Kaponga Yes - 5 5 5 5 5 5 5 5 5 5 No issues

93 Motunui Yes 9 11 11 11 11 11 11 11 11 11 11 No issues

94 New Plymouth Yes 19 24 25 - - - - - - - - Load to transfer to Carrington Street in 2019

Megawatt (MW) and megavar (MVA) values are nearly equal, with MW slightly lower than MVA. We reported MW (real power) values instead of MVA (apparent power) as this reflects the real power drawn by the customer load. The MVA (apparent power) values incorporate both the MW (real power) drawn by the customer load and the reactive power component (MVar) that reflects how the voltage is supported to deliver the real power. In the comments on capacity we have taken into consideration the effect of the reactive power (MVar) on the real power (MW) that can be delivered.

Firm Capacity

The peak load at Wellsford is forecasted to exceed the transformers’ n 1 winter capacity by 1 MW in 2024, increasing to approximately 5 MW in 2031. Both supply transformers at Wellsford have an expected end-of-life within the next five years. We will discuss with Vector the rating and timing for the replacement transformers.

Albany 33 kVAlbany 110 kV -Wairau RoadBombay 33 kVBombay 110 kVGlenbrook 33 kV (clean bus)

The peak load at Henderson is forecast to exceed the transformers’ n 1 winter capacity by approximately 9 MW in 2016, increasing to approximately 146 MW in 2031. The transformers’ capacity is limited by a bus section, circuit breaker and disconnector.There is a project underway to convert the Henderson 33 kV outdoor switchgear to an indoor switchboard. This will raise the n-1 limit but will not resolve the issue.

Mangere 33 kV The peak load at Mangere is forecast to exceed the transformers’ n-1 winter capacity by 11 MW in 2016, increasing to approximately 51 MW in 2031. The transformers’ capacity is limited by a protection equipment limit. We are investigating the option of increasing the protection limits on these transformers.

Mangere 110 kV

Mt Roskill 22 kV The peak load at Mount Roskill is forecast to exceed the transformers’ n-1 winter capacity by 6 MW in 2016, and this is not expected to change over the forecast period. The transformers’ capacity is limited by a circuit breaker limit on the 50 MVA transformer and protection relay limits on the 70 MVA transformers.

Mt Roskill 110 kV - Kingsland feeder

The peak load at Otahuhu is forecast to exceed the n-1 winter capacity by 14 MW in 2016, increasing to approximately 19 MW in 2031. The transformers’ capacity is limited by LV cable ratings, followed by a transformer bushings limit . We will discuss options to increase firm capacity with Vector, which include:

Penrose 22 kVPenrose 33 kVPenrose 110 kV - Liverpool Street

The peak load at Takanini is forecast to exceed the transformers’ n-1 winter capacity by 3 MW in 2016, increasing to approximately 6 MW in 2031. The transformers’ capacity is limited by protection equipment limit, followed by the circuit breaker (137 MVA) and 33 kV bus (137 MVA) limits. The peak load at Wiri will exceed the transformers’ summer n-1 capacity by approximately 1 MW in 2021, increasing to approximately 16 MW in 2031. The transformers’ capacity is limited by protection equipment limit.Resolving the protection equipment limits will delay the overload issues. We will discuss future supply options with Vector, including:The peak load at Cambridge is forecast to exceed the transformers’ n 1 winter capacity by approximately 2 MW in 2016, increasing to approximately 13 MW in 2031. The transformers’ capacity is limited by the Cambridge–T3 protection limit. Resolving the protection limit will reduce the forecast overload, but will not resolve the issue. We will discuss the options to increase the supply transformers’ firm capacity with Waipa Networks.

Hamilton 11 kV The peak load at Hamilton 11 kV is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2018, increasing to 7 MW by 2031. WEL Networks is capable of significant load shifting between Hamilton and Te Kowhai. The total load will not exceed the combined supply transformer firm capacity at Hamilton and Te Kowhai within the forecast period.

Hamilton 33 kV The peak load at Hamilton 33 kV is forecast to exceed the transformers’ n-1 winter capacity by approximately 21 MW in 2016, increasing to 50 MW by 2031. WEL Networks is capable of significant load shifting between Hamilton and Te Kowhai. The total load will not exceed the combined supply transformer firm capacity at Hamilton and Te Kowhai within the forecast period.

The peak load at Hangatiki is forecast to exceed the transformers’ n-1 summer capacity by 24 MW in 2016, increasing to 34 MW by 2031. We are discussing longer-term options with The Lines Company, such as replacing the existing transformers with two 50-60 MVA supply transformers. The peak load at Hinuera is forecast to exceed the transformers’ n-1 winter capacity by approximately 15 MW in 2016. In the short-term, load may be transferred within the Powerco network from Hinuera to Waihou and/or Piako to resolve this issue. Powerco is planning to increase transmission security in the Hinuera area with a new grid exit point near Putaruru.

Kinleith 11 kVKinleith 33 kV The peak 33 kV load at Kinleith is forecast to exceed the 20 MVA transformer’s installed capacity by approximately 1 MW in 2016, increasing to approximately 3 MW in 2031. We are discussing options with Powerco and Carter Holt Harvey that include replacing the 20 MVA transformer

with a 40 MVA transformer.The peak load at Kopu is forecast to exceed the transformers’ n-1 capacity by approximately 1 MW in 2020, increasing to 10 MW by 2031. The transformers’ firm capacity is limited by protection limits. Resolving the protection limit will delay the firm capacity issue to 2028. We will discuss options to increase the supply transformers’ n 1 capacity with Powerco closer to this time.

The peak load at Te Awamutu is forecast to exceed the transformers’ n-1 capacity by approximately 3 MW in 2016, increasing to approximately 6 MW in 2031. The transformers’ capacity is limited by protection equipment. Resolving the protection limit will provide sufficient firm capacity within the forecast period.

The peak load at Waihou is forecast to exceed the transformers’ firm winter capacity by approximately 12 MW in 2016, increasing to approximately 25 MW in 2031. In the short-term the issue can be managed operationally by shifting load to other grid exit points, and swapping a transformer unit with an on-site spare unit.The peak load at Waikino is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2016, increasing to approximately 10 MW in 2031. In the short-term, operational measures can be used to manage this issue. We will discuss with Powerco the options to increase the supply transformers’ firm capacity.The peak load at Edgecumbe is forecast to exceed the transformers’ n-1 winter capacity by approximately 4 MW in 2016, increasing to approximately 15 MW in 2031. The two supply transformers have an expected end-of-life within the forecast period. The overload can be managed operationally until the transformers are replaced.

Mt Maunganui 33 kVThe peak load at Owhata is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW from 2016, increasing to approximately 6 MW in 2031. In the short term, the issue can be managed operationally. In the long term upgrading transformer capacity will resolve the issue.

Rotorua 11 kV The Rotorua 11 kV peak load is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW from 2029 remaning at the same level until 2031. In the short term, the issue can be managed operationally. In the medium to long-term, Unison is expected to permanently shift load from Rotorua to Owhata, with both 11 kV and 33 kV feeders.

Rotorua 33 kV The Rotorua 33 kV peak load is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW from 2029, increasing to 3 MW in 2031. In the short term, the issue can be managed operationally. In the medium to long-term, Unison is expected to permanently shift load from Rotorua to Owhata, with both 11 kV and 33 kV feeders.

Tarukenga 11 kVTauranga 11 kV The peak load on the Tauranga 11 kV bus is forecast to exceed the transformers’ firm winter capacity by approximately 3 MW in 2016 increasing to 4 MW in 2031. The transformers’ capacity is limited by low voltage cables, protection and metering limits, and the series reactors.

A possible option is to limit the load or to transfer additional load to Kaitimako.Tauranga 33 kV

The peak load at Te Matai is forecast to exceed the transformers’ firm winter capacity by approximately 3 MW in 2018increasing to 31 MW in 2031. The issue will be managed operationally in the short term. We will discuss with Powerco the timing and rating of replacement transformers. The transformers also supply Te Kaha’s load via an 11/50 kV step-up transformer at Waiotahi. The combined peak load at Waiotahi and Te Kaha is forecast to exceed the Waiotahi transformers’ firm winter capacity by approximately 1 MW in 2017, increasing to 3 MW in 2031. ALso, the load at Waithai is supplied through a single 110 kV transmission circuit.

Bunnythorpe 33 kV The peak load at Bunnythorpe is forecast to exceed the transformers’ firm winter capacity by approximately 19 MW in 2016 increasing to 30 MW in 2031. Powerco can transfer load within the distribution system to Linton following a contingency. Longer-term options include a third 120 MVA 220/33 kV supply transformer at Bunnythorpe.

The peak load at Linton is forecast to exceed the transformers’ firm winter capacity by approximately 1 MW in 2025, increasing to approximately 8 MW in 2031. We are committed to replacing the 82 MVA transformer with a 120 MVA transformer, which will address the supply transformer capacity issue.The peak load at Mangahao is forecast to exceed the transformers’ firm winter capacity by approximately 7 MW in 2016, increasing to approximately 10 MW in 2031. If Mangahao generates at 10 MW or more, this issue can be delayed beyond the forecast period. The supply transformer overload is managed operationally as Mangahao generation is usually available during peak load periods.

The peak load at Marton is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2019, increasing to approximately 4 MW in 2031. The transformers’ capacity is limited by metering equipment, followed by an LV bushing limit (24 MVA) and a protection limit (25 MVA). Resolving the metering equipment limit will solve the transformers’ firm capacity issue within the forecast period.

Tangiwai 11 kV

The peak load at Brunswick is forecast to exceed the transformer’s continuous capacity by approximately 1 MW in 2018, increasing to approximately 7 MW in 2031. Also, The load at Brunswick is supplied through a single 220/33 kV, 20MVA supply transformer.We are discussing longer-term future supply options with Powerco, one of which is to install a second supply transformer to provide firm security.The peak load at Carrington Street is forecast to exceed the firm winter capacity by approximately 18 MW in 2019 increasing to 40 MW in 2031. The transformers’ capacity is limited by their 33 kV equipment.In the short-term, the overload can be managed operationally. Resolving the 33 kV equipment limits will resolve the issue for the forecast period and beyond. The peak load at Hawera is forecast to exceed the transformers’ n-1 winter capacity by 1 MW in 2023, increasing to approximately 3 MW in 2031 . The transformers’ capacity is limited by a 33 kV bus section limit.The interim solution is to close the 33 kV bus coupler and supply the Powerco load from the remaining Hawera supply transformer and the single Kupe supply transformer.

95 Opunake Yes 12 12 12 12 12 12 13 13 13 13 14 No issues

96 No 27 30 30 31 31 32 32 33 34 34 37 97 Taumarunui Yes 11 12 12 12 12 12 12 12 12 12 13 No issues

98 Wanganui No 48 51 52 52 53 54 55 55 56 57 61 99 Waverley No 5 5 6 6 6 6 6 6 6 7 7 A single 110/11 kV, 10 MVA transformer supplies load at Waverley resulting in no n-1 security.

100 Fernhill No 55 59 59 60 61 61 62 62 63 64 64 101 Redclyffe Yes 74 69 69 70 70 71 72 72 73 73 74 No issues

102 Tuai Yes 57 63 65 66 68 70 71 73 75 76 78 No issues

103 Whakatu Yes 90 89 90 91 91 92 93 94 94 95 96 No issues

104 Whirinaki Yes 77 83 83 83 83 83 83 83 83 83 83 No issues

105 Yes 23 27 27 28 28 28 28 28 28 28 29 No issues

106 Yes 157 167 168 169 170 171 172 172 173 174 175 No issues

107 Gracefield Yes 61 65 66 66 66 66 67 67 67 68 68 No issues

108 Greytown Yes 12 14 14 14 15 15 15 15 15 16 16 No issues

109 No 19 21 21 21 21 21 21 21 21 22 22 110 No 19 20 20 20 20 20 20 20 20 20 20 111 Kaiwharawhara No 35 41 41 41 42 42 42 43 43 43 44 112 Masterton Yes 44 30 31 31 31 31 31 31 31 31 32 No issues

113 No 27 39 39 39 39 39 39 40 40 40 40 114 Yes 34 49 49 50 51 51 52 52 53 53 54 No issues

115 Paraparaumu Yes 62 24 24 24 25 25 25 25 26 26 26 116 Pauatahanui No 21 79 80 81 81 82 83 84 85 86 86 117 Takapu Rd Yes 92 102 102 103 103 104 104 104 105 105 106 No issues

118 Upper Hutt Yes 31 33 34 34 35 35 36 36 37 38 38 119 Wilton Yes 55 61 61 62 62 62 63 63 63 64 64 No issues

120 Blenheim Yes 70 75 77 78 79 81 82 84 85 86 88 No issues

121 Yes 129 138 140 141 143 145 147 149 151 153 155 122 No 154 26 27 27 28 29 30 30 31 32 33 123 Arthur's Pass No 0 0 0 0 0 0 0 0 0 0 0 A single 66/11 kV, 3 MVA transformer supplies load at Arthur’s Pass, resulting in no n-1 security. The lack of n-1 security can be managed operationally.

124 Atarau Yes 1 1 1 1 1 1 1 1 1 1 1 No issues

125 Castle Hill No 1 1 2 6 6 6 6 6 6 6 6 A single 66/11 kV, 3.75 MVA transformer supplies load at Castle Hill, resulting in no n-1 security. The lack of n-1 security can be managed operationally.

126 Dobson Yes 8 10 10 10 10 10 11 11 11 11 11 No issues

127 Greymouth Yes 15 15 16 16 16 17 17 17 18 18 18 No issues

128 Hokitika Yes 18 17 17 18 19 19 19 20 20 20 20 No issues

129 Kikiwa No 3 4 4 4 4 4 4 4 4 4 4 130 Kumara Yes 12 2 2 2 2 2 2 2 2 2 2 No issues

131 Murchison Yes 3 3 3 3 3 3 3 3 3 3 3 No issues

132 Otira Yes 1 1 1 1 2 2 2 2 2 2 2 Otira is supplied by a single 66/11 kV, 2.5 MVA transformer, resulting in no n-1 security. Additionally, load growth is forecast to exceed the transformer rating by Winter 2021.

133 Reefton Yes 10 8 8 9 9 9 9 9 9 10 10 No issues

134 Robertson Street Yes 10 13 13 13 13 14 14 14 14 15 15 135 Westport Yes 9 - - - - - - - - - - No issues

136 Ashburton 33 kV Yes 29 9 - - - - - - - - - Load to transfer to 66 kV bus from 2017

137 Ashburton 66 kV Yes 151 196 208 210 212 214 216 218 220 222 222 No issues

138 Ashley Yes 17 16 16 16 16 16 16 16 16 16 16 No issues

139 Bromley 66 kV Yes 200 159 159 160 160 161 161 192 192 313 313 140 Coleridge No 0 0 1 1 1 1 1 1 1 1 1 A single 66/11 kV, 2.5 MVA three phase supply transformer supplies the load at Coleridge, resulting in no n-1 security.

141 Culverden 33 kV No 22 25 26 26 27 28 29 30 30 31 31 142 Culverden 66 kV Yes 10 13 13 13 13 13 13 13 13 14 14 No issues

143 Hororata 33 kV No 20 27 23 22 23 23 23 23 23 23 23 144 Hororata 66 kV Yes 29 34 30 27 27 27 27 28 28 28 28 No issues

145 Islington 33 kV Yes 77 83 84 85 85 86 87 88 89 89 89 No issues

146 Islington 66 kV Yes 465 511 519 527 535 543 551 529 537 425 425 No issues

147 Kaiapoi Yes 30 32 33 33 33 34 34 35 35 36 36 148 Kimberley Yes 16 18 22 22 22 22 22 22 22 22 22 No issues

149 Southbrook 33 kV Yes 43 24 24 25 25 26 27 27 28 28 28 No issues

150 Southbrook 66 kV Yes 46 24 25 25 26 27 27 28 28 29 29 No issues

151 Waipara 33 kV No 10 9 9 9 9 10 10 10 10 10 10 A single 66/33 kV, 16 MVA transformer supplies load at Waipara resulting in no n-1 security.

152 Waipara 66 kV Yes 10 12 12 12 12 12 12 12 13 13 13 No issues

153 Albury No 4 5 5 5 5 8 8 8 8 8 8 154 Bells Pond No 11 23 26 28 20 20 20 20 21 21 21 Bells Pond has a single 110 kV circuit with a hard-tee connection to Oamaru–Waitaki–2 circuit, resulting in no n-1 security.

155 Black Point No 11 15 18 18 18 18 18 18 18 18 18 Black Point has a single 110 kV circuit with a hard-tee connection to the Oamaru–Waitaki–1 circuit, resulting in no n-1 security.

156 Oamaru Yes 43 48 49 49 50 50 51 51 52 52 53 157 St Andrews Yes - - - - 21 38 39 40 40 41 41 St Andrews represents a possible future GXP between Studholme and Timaru from 2020

158 Studholme No 14 14 20 20 21 21 21 21 21 21 21 159 Tekapo A No 4 6 6 6 6 6 7 7 7 7 7 160 Temuka No 80 70 80 82 83 85 86 87 89 90 92 161 Timaru Yes 64 73 73 74 74 72 72 73 73 74 74 No issues

162 Twizel Yes 8 12 13 14 14 15 15 15 15 15 15 No issues

163 Waitaki Yes 10 8 8 8 8 8 8 8 8 9 9 No issues

164 Balclutha Yes 30 29 29 29 29 29 30 30 30 30 30 No issues

165 Brydone Yes 10 10 10 10 11 11 11 11 11 11 11 No issues

166 Clyde Yes 9 10 10 10 10 10 10 10 10 10 11 No issues

167 Cromwell Yes 32 35 36 37 39 40 41 43 44 45 46 168 Edendale No 29 36 36 37 38 38 39 40 40 41 42 169 Frankton Yes 59 65 66 68 69 70 72 73 74 76 77 170 Gore Yes 30 32 33 33 34 34 35 35 36 36 37

171 Yes 8 7 7 - - - - - - - - Load transfer to 33 kV bus

172 No 95 89 75 82 83 83 84 84 85 85 86 173 Yes 48 58 58 58 59 59 59 60 60 60 60 No issues

174 Invercargill Yes 96 100 101 101 102 102 103 103 104 104 105 The peak load at Invercargill is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2025, increasing to approximately 4 MW in 2031. Recalibrating the metering parameters at Invercargill will solve the issue within the forecast period.

175 Naseby Yes 31 33 34 34 35 35 36 37 37 38 38 176 North Makarewa Yes 67 53 54 55 56 57 58 59 60 60 61 No issues

177 South Dunedin Yes 73 81 96 97 97 97 98 98 99 99 99 No issues

178 Tiwai Yes 591 596 596 596 596 596 596 596 596 596 596 No issues

179180 GXPs Total 8,976 9,120 9,248 9,347 9,465 9,572 9,685 9,779 9,885 9,983 10,078 181 *Insert additional rows and update calculation of totals as needed182

183 G3(ii): Current Connection Capacity vs Actual and Forecast Injection184185

Grid Injection point (generator location if embedded)Forecast Injection (MVA)

186 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 Comments on Capacity 187 Bream Bay (Marsden Diesel) 9 9 9 9 9 9 9 9 9 9 9 188 Kaikohe (Ngawha) 27 27 27 27 27 27 27 27 27 27 27 189 Maungatapere (Wairua) 5 5 5 5 5 5 5 5 5 5 5 190 Albany (Rosedale) 3 3 3 3 3 3 3 3 3 3 3 191 Bombay (Hampton Downs Landfill) 7 7 7 7 7 7 7 7 7 7 7 192 Bombay (Greymouth power co., Contact Energy) 2 2 2 2 2 2 2 2 2 2 2

Stratford 33 kV The peak load at Stratford already exceeds the transformers’ n-1 summer capacity and the overload is forecast to increase to approximately 12 MW by 2031. The transformers’ winter capacity is limited by the LV meter accuracy limit.Resolving the meter accuracy limit will solve the issue beyond the forecast period.

The peak load at Wanganui already exceeds the transformers’ firm winter capacity and the overload is forecast to increase to approximately 39 MW in 2031. The transformers’ capacity is limited by the transformer LV bushing limit.In the short term, limited load can be shifted to Brunswick. We will discuss with Powerco the appropriate rating and timing for the replacement transformers.

The peak load at Fernhill already exceeds the transformers’ n-1 summer winter capacity by approximately 25 MW, and the overload is forecast to increase to approximately 35 MW in 2031 . The transformers’ capacity is limited by the rating of the LV bushings limits (36 MVA), 33 kV overhead bus (37 MVA), and LV meter accuracy limit (41 MVA).

Central Park 11 kVCentral Park 33 kV

Haywards 11 kV The Haywards 11 kV peak load is forecast to exceed the transformers’ capacity by approximately 1 MW in 2016, increasing to approximately 2 MW in 2031. We are discussing future supply options with Wellington Electricity. The short-term solution is to manage the load operationally. A possible long-term option is to replace the supply transformers with two new 110/33/11 kV, 60/30/30 MVA transformers, providing firm security to both the 11 kV and 33 kV buses.Haywards 33 kV The Haywards 33 kV peak load is forecast to exceed the transformer’s capacity by approximately 1 MW in 2029 remaining at this level to 2031. See Haywards 11 kV entry for solution to both 11 kV and 33 kV buses.The total peak load is forecast to exceed the transformers’ n-1 winter and summer capacities by approximately 6 MW in 2016, increasing to approximately 11 MW in 2031. The transformers’ capacity is limited by the 11 kV circuit breaker owned by Wellington Electricity.Wellington Electricity considers the issue can be managed operationally by transferring excess load to other grid exit points through the distribution network.

Melling 11 kV Melling 11 kV load is forecast to exceed the transformers’ n-1 winter capacity by 2 MW in 2016, increasing to approximately 4 MW in 2031. The transformers’ capacity is limited by HV protection equipment.Resolving the protection limit will solve the transformers’ firm winter capacity issue until 2031.

Melling 33 kVThe peak load at Paraparaumu is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2020, increasing to approximately 11 MW in 2031. The supply transformers are limited by the metering accuracy limit.Resolving the meter accuracy limit will provide sufficient n-1 capacity for the forecast period.The peak load at Pauatahanui is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2016, increasing to approximately 5 MW in 2031. In the short-term, the lack of firm capacity for the transformers can be managed operationally. In the longer term, increase in the supply transformers’ capacity will be required.

The peak load at Upper Hutt is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2026, increasing to approximately 3 MW in 2031. The transformers’ capacity is limited by the metering accuracy limit.Resolving the metering parameters will provide sufficient n-1 capacity for the forecast period.

Stoke 33 kV The peak load at Stoke is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2018, increasing to approximately 26 MW in 2031. The transformers’ capacity is limited by protection equipment of 138 MVA.Resolving the protection issue will reduce overloading in the forecast period.

Stoke 66 kV The peak load at Stoke 66 kV is forecast to exceed the transformer’s continuous rating by approximately 4 MW in 2016, increasing to approximately 15 MW in 2031. The Stoke 66 kV (Golden Bay area) load is supplied by a single 110/66 kV, 23 MVA transformer at Stoke, resulting in no n-1 security.

The Kikiwa load is normally supplied from the 11 kV tertiary winding of the Kikiwa–T1 interconnecting transformer, with a backup supply from the T2 interconnecting transformer. Transferring the load between T1 and T2 requires a short interruption to the load. An outage of the 11 kV switchgear or fault limiting reactor requires a total loss of supply, so there is no n 1 security for these assets.

The load at Murchison is supplied by two circuits, which do not have line protection at Murchison, and a single 110/11 kV, 5 MVA transformer. A fault on either circuit or the supply transformer will result in a loss of supply to Murchison. The lack of n-1 security can be managed operationally.

Orion is planning to transfer load from Islington to Bromley in 2025, which will exceed the existing transformers’ firm capacity by 94 MW in 2025 increasing to approximately 97 MW in 2031. We anticipate this issue will be managed by load shifting between Bromley and Islington within Orion’s network. A third transformer will be installed when the 220/66 kV transformers at Bromley and Islington run out of capacity.

The peak load at Culverden is forecast to exceed the supply transformers’ n-1 summer capacity by approximately 2 MW in 2016, increasing to approximately 13 MW in 2031 . In the short term the issue can be managed with operational measures. In the medium term, the existing 220/33 kV supply transformers will be replaced with higher rated 220/66 kV transformers. The timing of the upgrade will be determined by the possible increase in irrigation and in discussion with MainPower.

The peak load on the Hororata 33 kV bus is forecast to exceed the transformers’ firm summer capacity by approximately 3 MW in 2016 and increasing to approximately 4 MW in 2031. The supply transformer capacity issue can be managed operationally. From 2017, Orion will shift some of the load from the 33 kV to the 66 kV bus.

The peak load at Kaiapoi is forecast to exceed the supply transformers’ firm winter capacity by approximately 1 MW in 2023, increasing to approximately 5 MW in 2031. The transformers’ capacity is limited by a circuit breaker and LV cable limit, followed by the protection equipment limit Resolving all transformers’ branch component limits will solve the overloading issue beyond the forecast period. We will discuss options with MainPower closer to the need date.

A single 110/11 kV, 5 MVA transformer supplies load at Albury resulting in no n-1 security. The peak load at Albury is forecast to exceed the transformer’s summer capacity by approximately 3 MW in 2019, increasing to approximately 4 MW in 2031. The supply transformer has an expected end-of-life within the next five years. We have discussed transformer replacement options with Alpine Energy to provide for load growth and coordinating outages to minimise supply interruptions when replacing this transformer.

The peak load at Oamaru is forecast to exceed the transformers’ firm summer capacity by approximately 1 MW in 2025, increasing to approximately 4 MW in 2031. The 110 kV circuits supplying these transformers have a lower capacity than the transformers. Therefore, the transformers are not the first constraint on Oamaru load.

The peak load at Studholme already exceeds the transformers’ n-1 summer capacity, and the overload is forecast to increase to approximately 12 MW in 2031. Possible solutions include:• replacing the existing transformers with higher-rated units, orA single 110/11 kV, 35 MVA transformer in series with a single 33/11 kV, 10 MVA transformer supplies load at Tekapo, resulting in no n-1 security.Alpine Energy considers that the lack of firm security can be managed operationally for the forecast period.The peak load at Temuka is forecast to exceed the transformers’ n-1 summer capacity by approximately 16 MW in 2016, increasing to approximately 45 MW in 2031. We are discussing options with Alpine Energy. Short-term options include:• pre-contingency load management

The peak load at Cromwell is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2022, increasing to approximately 13 MW in 2031. Resolving the protection limit will provide sufficient firm capacity until 2026. Upgrading other transformer branch limiting components will resolve the issue for the forecast period and beyond. The peak load at Edendale is forecast to exceed the n-1 shoulder capacity by approximately 3 MW in 2016, increasing to approximately 14 MW in 2031. Possible solutions include:The peak load at Frankton is forecast to exceed n-1 capacity of the Cromwell-Frankton 110 kV circuits (connecting Frankton to the grid) from approximately 2021, and the supply transformers’ n-1 winter capacity by approximately 1 MW in 2023 and increasing to approximately 14 MW and 12 MW in 2031. We will discuss future supply options with Aurora closer to the time the issue arises. The peak load at Gore is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2025, increasing to approximately 4 MW in 2031. Possible solutions include:

Halfway Bush 110 kVHalfway Bush 33 kV-1 The peak load at Halfway Bush is forecast to exceed the transformer’s firm winter capacity by approximately 18 MW in 2016 and increasing to approximately 22 MW in 2031.

All three supply transformers have an expected end-of-life within the forecast period. After discussions with Aurora, we intend to replace the two 110/33 kV, 50 MVA supply transformers with a single 220/33 kV, 120 MVA supply transformer by 2018.Halfway Bush 33 kV-2

The peak load at Naseby is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2019, increasing to approximately 7 MW in 2031. We will discuss future supply options with PowerNet.

Rosedale generation is limited to approximately 1 MW due to insufficient gas at the site. This amount is not expected to rise significantly within the next few years.

This value includes an embedded generating unit with a nominal rating of 38 MW. However, its continuous output is approximately 25 MW.

193 Glenbrook 112 112 112 112 112 112 112 112 112 112 112 194 Mangere (Watercare Mangere) 7 7 7 7 7 7 7 7 7 7 7 195 Otahuhu (Greenmount Landfill) 1 1 1 1 1 1 1 1 1 1 1 Information from Envirowaste website. Lanfill is closed and presently produces 1 MW. This is expected to reduce over time.

196 Penrose (Auckland Hospital) 4 4 4 4 4 4 4 4 4 4 4 197 Silverdale (Redvale) 7 7 7 7 7 7 7 7 7 7 7 Waste Management website indicates that energy output is expected to double by 2025. However, no useful figures are given.

198 Takanini (Whitford Landfill) 3 3 3 3 3 3 3 3 3 3 3 199 Arapuni 197 197 197 197 197 197 197 197 197 197 197 200 Atiamuri 84 84 84 84 84 84 84 84 84 84 84 201 Hangatiki (Mangapehi) 3 3 3 3 3 3 3 3 3 3 3 202 Hangatiki (Wairere Falls) 4 4 4 4 4 4 4 4 4 4 4 203 Hangatiki (Mokauiti) 2 2 2 2 2 2 2 2 2 2 2 204 Hangatiki (Speedies Road) 2 2 2 2 2 2 2 2 2 2 2 205 Huntly 948 948 948 948 948 948 948 448 448 448 448 206 Karapiro 90 90 90 90 90 90 90 90 90 90 90 207 Kinleith 28 28 28 28 28 28 28 28 28 28 28 208 Maraetai 360 360 360 360 360 360 360 360 360 360 360 209 Mokai 112 112 112 112 112 112 112 112 112 112 112 210 Ohakuri 112 112 112 112 112 112 112 112 112 112 112 211 Te Awamutu (Anchor Products) 4 4 4 4 4 4 4 4 4 4 4 212 Te Kowhai (Te Rapa) 44 44 44 44 44 44 44 44 44 44 44 213 Te Kowhai (Te Uku) 64 64 64 64 64 64 64 64 64 64 64

Te Kowhai (Horotiu Landfill) 1 1 1 1 1 1 1 1 1 1 1 Waikino (Tirohia Landfill) 1 1 1 1 1 1 1 1 1 1 1 Waipapa 51 51 51 51 51 51 51 51 51 51 51 Whakamaru 100 100 100 100 100 100 100 100 100 100 100

218 Aniwhenua 25 25 25 25 25 25 25 25 25 25 25 219 Edgecumbe (Bay Milk) 10 10 10 10 10 10 10 10 10 10 10 220 Kawerau (BOPE) 6 6 6 6 6 6 6 6 6 6 6 221 Kawerau (CHH) 27 27 27 27 27 27 27 27 27 27 27 222 Kawerau (KAG) 105 105 105 105 105 105 105 105 105 105 105 223 Kawerau (KA24) 9 9 9 9 9 9 9 9 9 9 9 224 Kawerau (Norske Skog) 25 25 25 25 25 25 25 25 25 25 25 The electricity market designation for the Norske-Skog generator is Onepu.

225 Kawerau (TPP) 37 37 37 37 37 37 37 37 37 37 37 Kawerau (Eastland) - - 25 25 25 25 25 25 25 25 25 New generation scheduled for connection in 2018

227 Matahina 72 72 72 72 72 72 72 72 72 72 72 228 Mount Maunganui (Ballance Agri) 7 7 7 7 7 7 7 7 7 7 7 229 3 3 3 3 3 3 3 3 3 3 3 230 Rotorua (Wheao, Flaxy Scheme) 24 24 24 24 24 24 24 24 24 24 24 231 Tauranga (Kaimai) 42 42 42 42 42 42 42 42 42 42 42 232 Aratiatia 78 78 78 78 78 78 78 78 78 78 78 233 Bunnythorpe (Tararua Wind Stage 2) 36 36 36 36 36 36 36 36 36 36 36 234 Linton (Tararua Wind Stage 1) 32 32 32 32 32 32 32 32 32 32 32 235 Linton (Totara Road) 1 1 1 1 1 1 1 1 1 1 1 236 Mangahao 42 42 42 42 42 42 42 42 42 42 42 237 Nga Awa Purua 140 140 140 140 140 140 140 140 140 140 140 238 Nga Awa Purua – Ngatamariki 82 82 82 82 82 82 82 82 82 82 82 239 Ohaaki 46 46 46 46 46 46 46 46 46 46 46 240 Ongarue (Mokauiti, Kuratau and Wairere Falls) 13 13 13 13 13 13 13 13 13 13 13 241 Poihipi 51 51 51 51 51 51 51 51 51 51 51 242 Rangipo 120 120 120 120 120 120 120 120 120 120 120 243 Tararua Wind Central – Tararua Stage 3 93 93 93 93 93 93 93 93 93 93 93 244 Tararua Wind Central (Te Rere Hau) 49 49 49 49 49 49 49 49 49 49 49 245 Te Mihi 166 166 166 166 166 166 166 166 166 166 166 246 Tokaanu 240 240 240 240 240 240 240 240 240 240 240 247 Wairakei 109 109 109 109 109 109 109 109 109 109 109 248 Wairakei (Hinemaiaia) 7 7 7 7 7 7 7 7 7 7 7 249 Wairakei (Rotokawa) 35 35 35 35 35 35 35 35 35 35 35 250 Wairakei (Te Huka) 23 23 23 23 23 23 23 23 23 23 23 251 Woodville – Te Apiti 90 90 90 90 90 90 90 90 90 90 90 252 Carrington St (Mangorei) 5 5 5 5 5 5 5 5 5 5 5 253 Hawera – Kiwi Dairy (Whareroa) 70 70 70 70 70 70 70 70 70 70 70 254 Hawera – Patea 31 31 31 31 31 31 31 31 31 31 31 255 Huirangi (Mangahewa) 9 9 9 9 9 9 9 9 9 9 9 256 Huirangi (Motukawa) 5 5 5 5 5 5 5 5 5 5 5 257 Kapuni 25 25 25 25 25 25 25 25 25 25 25 258 McKee 100 100 100 100 100 100 100 100 100 100 100 259 Taranaki Combined Cycle 385 385 385 385 385 385 385 385 385 385 385 260 Stratford Peaker 200 200 200 200 200 200 200 200 200 200 200 261 Stratford (Stratford Austral Pacific) 1 1 1 1 1 1 1 1 1 1 1 262 Kaitawa 36 36 36 36 36 36 36 36 36 36 36 263 Piripaua 42 42 42 42 42 42 42 42 42 42 42 264 Redclyffe (Ravensdown) 8 8 8 8 8 8 8 8 8 8 8 265 Redclyffe (Esk River) 4 4 4 4 4 4 4 4 4 4 4 266 Tuai 60 60 60 60 60 60 60 60 60 60 60 267 Tuai (Gisborne) 4 4 4 4 4 4 4 4 4 4 4 268 Tuai (Matawai) 2 2 2 2 2 2 2 2 2 2 2 269 Tuai (Waihi) 5 5 5 5 5 5 5 5 5 5 5 270 Whirinaki 155 155 155 155 155 155 155 155 155 155 155 271 Whirinaki (Pan Pac) 13 13 13 13 13 13 13 13 13 13 13 272 Central Park (Southern Landfill) 1 1 1 1 1 1 1 1 1 1 1 273 Central Park (Wellington Hospital) 10 10 10 10 10 10 10 10 10 10 10 The Wellington Hospital generation is standby only.

274 Greytown (Hau Nui) 9 9 9 9 9 9 9 9 9 9 9 275 Haywards (Silverstream) 3 3 3 3 3 3 3 3 3 3 3 276 Masterton 1 1 1 1 1 1 1 1 1 1 1 277 West Wind 143 143 143 143 143 143 143 143 143 143 143 278 Wilton (Mill Creek) 60 60 60 60 60 60 60 60 60 60 60 279 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 280 Argyle – Branch River Scheme 11 11 11 11 11 11 11 11 11 11 11 281 Blenheim (Lulworth Wind) 1 1 1 1 1 1 1 1 1 1 1 282 Blenheim (Marlborough Lines Diesel) 9 9 9 9 9 9 9 9 9 9 9 283 Blenheim (Waihopai) 3 3 3 3 3 3 3 3 3 3 3 284 Motupipi (Onekaka) 1 1 1 1 1 1 1 1 1 1 1 285 Stoke (Cobb) 32 32 32 32 32 32 32 32 32 32 32 286 Dobson (Arnold) 3 3 3 3 3 3 3 3 3 3 3 287 Hokitika (Amethyst) 6 6 6 6 6 6 6 6 6 6 6 288 Hokitika(McKays Creek) 1 1 1 1 1 1 1 1 1 1 1 289 Hokitika (Wahapo-Okarito Forks) 3 3 3 3 3 3 3 3 3 3 3 290 Kumara (Hokitika Diesel) 3 3 3 3 3 3 3 3 3 3 3 291 Kumara (Kumara and Dillmans) 10 10 10 10 10 10 10 10 10 10 10

Huntly generation capacity assumes only two 250 MW coal-fired units remains in service from 2023

Rotorua (Fletcher Forests)

Haywards 220 kV (HVDC North transfer) The fourth cable may be installed in future as an additional stage in the HVDC development, increasing the HVDC link capacity to 1,400 MW.

Kumara and Dillmans share the same water and are offered into the market as a single 10 MW generator. Kumara does not have significant water storage but is expected to supply an average of 4 MW during summer peaks.

292 Robertson Street (Kawatiri Hydro) 4 4 4 4 4 4 4 4 4 4 4 293 Ashburton (Highbank) 25 25 25 25 25 25 25 25 25 25 25 294 Ashburton (Montalto) 2 2 2 2 2 2 2 2 2 2 2 295 Bromley (City Waste) 3 3 3 3 3 3 3 3 3 3 3 296 Bromley (QE2 diesel) 4 4 - - - - - - - - - The customer advised that QE2 diesel generation will be shifted to the Islington 66 kV GXP in 2017.

297 Coleridge 45 45 45 45 45 45 45 45 45 45 45 298 Islington (QE2 diesel) - - 4 4 4 4 4 4 4 4 4 The customer advised that QE2 diesel generation will be shifted to the Islington 66 kV GXP in 2017.

299 Albury (Opuha) 8 8 8 8 8 8 8 8 8 8 8 300 Aviemore 220 220 220 220 220 220 220 220 220 220 220 301 Benmore 540 540 540 540 540 540 540 540 540 540 540 302 Ohau A 264 264 264 264 264 264 264 264 264 264 264 303 Ohau B 212 212 212 212 212 212 212 212 212 212 212 304 Ohau C 212 212 212 212 212 212 212 212 212 212 212 305 Tekapo A 25 25 25 25 25 25 25 25 25 25 25 306 Tekapo B 160 160 160 160 160 160 160 160 160 160 160 307 Waitaki 90 105 105 105 105 105 105 105 105 105 105 308 Clyde 432 432 432 432 432 432 432 432 432 432 432 309 Manapouri 840 840 840 840 840 840 840 840 840 840 840 310 Roxburgh 320 320 320 320 320 320 320 320 320 320 320 311 Berwick/Halfway Bush (Waipori) 84 84 84 84 84 84 84 84 84 84 84 312 Berwick/Halfway Bush (Mahinerangi) 36 36 36 36 36 36 36 36 36 36 36 313 Balclutha (Mt. Stuart) 8 8 8 8 8 8 8 8 8 8 8 314 Clyde (Fraser) 3 3 3 3 3 3 3 3 3 3 3 315 Clyde (Horseshoe Bend hydro) 4 4 4 4 4 4 4 4 4 4 4 316 Clyde (Horseshoe Bend wind) 2 2 2 2 2 2 2 2 2 2 2 317 Clyde (Talla Burn) 3 3 3 3 3 3 3 3 3 3 3 318 Clyde (Teviot) 11 11 11 11 11 11 11 11 11 11 11 319 Clyde (Kowhai) 2 2 2 2 2 2 2 2 2 2 2 320 Cromwell (Roaring Meg) 4 4 4 4 4 4 4 4 4 4 4 321 Frankton (Wye Creek) 1 1 1 1 1 1 1 1 1 1 1 322 Halfway Bush (Deep Stream) 5 5 5 5 5 5 5 5 5 5 5 323 Invercargill (Flat Hill) 7 7 7 7 7 7 7 7 7 7 7 324 Naseby (Falls Dam) 1 1 1 1 1 1 1 1 1 1 1 325 Naseby (Paerau) 10 10 10 10 10 10 10 10 10 10 10 326 Naseby (Patearoa) 2 2 2 2 2 2 2 2 2 2 2 327 North Makarewa (Monowai) 7 7 7 7 7 7 7 7 7 7 7 328 North Makarewa (White Hill) 58 58 58 58 58 58 58 58 58 58 58 329330 GIPs Total 10,563 10,578 10,603 10,603 10,603 10,603 10,603 10,103 10,103 10,103 10,103 331 *Insert additional rows and update calculation of totals as needed332


Tab name: G4. Quality Grid Outputs 05/09/2023


SCHEDULE G4: QUALITY OF SUPPLY: GRID OUTPUTS AND PERFORMANCE MEASURES Disclosure Year (year ended) ###

ref

5 G4(i): Grid Output Historical and Forecast Measures and Targets6

7Grid Output Measure - Quality

Actual performance CY Target

Forecast Performance 8 CY-4 CY-3 CY-2 CY-1 CY (Yes/No) CY+1 CY+2 CY+3 CY+4 CY+5

9 Number of loss of supply events greater than 0.05 system minutes 13 10 N/A N/A * None None None None None10 Number of loss of supply events greater than 1 system minute 1 0 N/A N/A * None None None None None11 Unplanned HVAC circuit unavailability (%) 0.068% 0.026% N/A N/A * None None None None None12 Unplanned HVDC bi-pole unavailability (%) 0.13% 0.06% N/A N/A * None None None None None13 Total impact of interruptions (measured in system minutes) 12.20 3.15 N/A N/A * None None None None None14 *No target currently specified1516

17 G4(ii): Grid Connection Point Performance Measures18

1920 Point of Service Performance - Demand 21 (Points of Service as at 30 June 2016) Number of Interruptions Unserved energy % X10022 Point of Service CY-2 Actual CY-1 Actual CY Actual CY Target 5 year average CY-2 Actual CY-1 Actual CY Actual CY Target 5 year average 23 Albany 110 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.0424 Albany 33 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.0425 Albury 6 0 1.14 2.80 12.69 0.00 N/A 6.1126 Arthurs Pass 3 1 4.67 3.80 1.01 0.69 N/A 5.0727 Ashburton 33 kV 0 0 0.3 0.20 0.00 0.00 N/A 0.2228 Ashburton 66 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.0029 Ashley 0 0 0.2 0.00 0.00 0.00 N/A 0.0030 Atarau 1 0 0.2 0.40 0.30 0.00 N/A 0.1131 Balclutha 0 0 0.3 0.00 0.00 0.00 N/A 0.0032 Bells Pond 1 0 0.56 1.20 2.36 0.00 N/A 1.8433 BlackPoint 0 1 1.29 1.00 0.00 0.00 N/A 1.4234 Blenheim 0 0 0.3 0.00 0.00 0.00 N/A 0.0035 Bombay 110 kV 0 0 0.3 0.40 0.00 0.00 N/A 0.0836 Bombay 33 kV 0 0 0.3 0.60 0.00 0.00 N/A 0.6437 Bream Bay 0 0 0.1 0.40 0.00 0.00 N/A 0.0638 Bromley 66 kV 0 0 0.1 0.00 0.00 0.00 N/A 0.0039 Brunswick 0 0 0.54 0.60 0.00 0.00 N/A 0.0840 Brydone 0 0 0.2 0.00 0.00 0.00 N/A 0.0041 Brydone 0 0 0.2 0.00 0.00 0.00 N/A 0.0042 Bunnythorpe 33 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.1443 Bunnythorpe 55 kV 0 0 0.3 0.20 0.00 0.00 N/A 0.2444 Cambridge 0 0 0.2 0.80 0.00 0.00 N/A 2.54

45 Carrington St 0 0 0.3 0.40 0.00 0.00 N/A 0.1546 Castle Hill 4 1 5.03 4.20 11.03 0.25 N/A 10.0147 Central Park 11 kV 0 0 0.2 0.00 0.00 0.00 N/A 0.0048 Central Park 33 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.02

49 Clyde 0 0 0.3 0.00 0.00 0.00 N/A 0.0050 Coleridge 2 2 0.3 1.00 0.26 8.61 N/A 2.0351 Cromwell 0 2 0.3 0.60 0.00 1.99 N/A 0.44

52 Culverden 33 kV 1 0 0.3 0.40 0.35 0.00 N/A 0.20

53 Culverden 66 kV 1 0 0.54 0.20 0.00 0.00 N/A 0.0054 Dannevirke 0 0 0.3 1.20 0.00 0.00 N/A 0.6055 Dobson 0 0 0.3 0.00 0.00 0.00 N/A 0.00

56 Edendale 0 0 0.2 0.00 0.00 0.00 N/A 0.0057 Edgecumbe 1 0 0.2 0.60 0.09 0.00 N/A 0.1858 Fernhill 1 0 0.3 1.20 0.12 0.00 N/A 1.0959 Frankton (A) 0 0 0.3 0.20 0.00 0.00 N/A 0.05

60 Frankton (B) 0 0 0.3 0.20 0.00 0.00 N/A 0.0361 Glenbrook (A) 0 0 0.3 0.20 0.00 0.00 N/A 0.05

CY Target Achieved

Target interruption rates below are based on the outcome of our RCP2 reset process. Setting site-level targets in this way is a new approach and we are working through a long-term process of integrating the targets into our asset management practices and investment decision making. We expect performance against targets to vary considerably at an individual site level because events are infrequent, random events. Over coming months we will be engaging with customers and other stakeholders on refinements to our targets for RCP3.



62 Glenbrook (B) 0 0 0.18 0.00 0.00 0.00 N/A 0.00

63 Gore 0 0 0.3 0.00 0.00 0.00 N/A 0.0064 Gracefield 0 1 0.2 1.40 0.00 0.52 N/A 0.9765 Greymouth 0 0 0.3 0.00 0.00 0.00 N/A 0.00

66 Greytown 2 0 0.3 0.80 1.48 0.00 N/A 0.71

67 Halfway Bush 110 kV 1 0 0.3 0.33 0.73 0.00 N/A 0.2468 Halfway Bush 33 kV 1 0 0.2 0.20 0.35 0.00 N/A 0.0769 Hamilton 11 kV 0 0 0.2 0.60 0.00 0.00 N/A 0.10

70 Hamilton 33 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.0371 Hamilton 55 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.0072 Hangatiki 0 0 0.3 0.80 0.00 0.00 N/A 0.7273 Hawera (A) 0 0 0.2 0.40 0.00 0.00 N/A 0.60

74 Hawera (B) 0 0 0.3 0.20 0.00 0.00 N/A 0.4475 Haywards 11 kV 0 0 0.2 0.60 0.00 0.00 N/A 0.5576 Haywards 33 kV 0 0 0.3 0.60 0.00 0.00 N/A 0.06

77 Henderson 0 0 0.1 0.40 0.00 0.00 N/A 0.05

78 Hepburn Road 0 0 0.1 0.40 0.00 0.00 N/A 0.0279 Hinuera 0 2 0.32 1.20 0.00 3.66 N/A 1.0180 Hobson Street 0 0 0.1 0.00 0.00 0.00 N/A 0.00

81 Hokitika 0 1 0.3 0.40 0.00 5.29 N/A 1.1382 Hororata 33 kV 0 0 0.2 0.00 0.00 0.00 N/A 0.0083 Hororata 66 kV 0 0 0.2 0.00 0.00 0.00 N/A 0.0084 Huirangi 0 0 0.2 0.20 0.00 0.00 N/A 0.02

85 Huntly 0 0 0.3 0.40 0.00 0.00 N/A 0.0786 Invercargill 0 0 0.1 0.00 0.00 0.00 N/A 0.0087 Islington 33 kV 0 0 0.2 0.00 0.00 0.00 N/A 0.0088 Islington 66 kV 0 0 0.1 0.00 0.00 0.00 N/A 0.0089 Kaiapoi 0 2 0.3 0.40 0.00 2.83 N/A 0.5790 Kaikohe 1 0 0.2 0.60 1.13 0.00 N/A 0.3691 Kaitimako 0 0 0.3 0.60 0.00 0.00 N/A 0.3792 Kaiwharawhara 0 0 0.2 0.60 0.00 0.00 N/A 0.1293 Kawerau (A) 0 0 0.3 0.00 0.00 0.00 N/A 0.0094 Kawerau (B) 0 0 0.2 0.40 0.00 0.00 N/A 0.6695 Kikiwa 0 0 0.67 0.40 0.00 0.00 N/A 0.1596 Kimberley 0 0 0.2 0.33 0.00 0.00 N/A 0.0997 Kinleith 11 kV 1 0 0.3 0.80 0.39 0.00 N/A 0.2098 Kinleith 33 kV 0 0 0.45 0.40 0.00 0.00 N/A 0.3999 Kopu 2 0 0.3 0.60 3.76 0.00 N/A 0.79

100 Kumara 0 1 0.3 0.20 0.00 0.00 N/A 0.00101 Lichfield 0 0 0.2 0.20 0.00 0.00 N/A 0.06102 Linton 0 0 0.3 0.80 0.00 0.00 N/A 0.52103 Mangahao 1 0 0.3 0.80 1.73 0.00 N/A 1.16104 Mangamaire 0 0 0.2 0.20 0.00 0.00 N/A 0.22105 Mangere 110 kV 0 0 0.2 0.20 0.00 0.00 N/A 0.07106 Mangere 33 kV 0 0 0.2 0.20 0.00 0.00 N/A 0.03107 Marton 0 1 0.3 0.60 0.00 0.07 N/A 0.24108 Masterton 1 0 0.3 0.60 3.10 0.00 N/A 0.81109 Mataroa 0 0 0.54 0.00 0.00 0.00 N/A 0.00110 Maungatapere 0 0 0.2 0.25 0.00 0.00 N/A 0.01111 Maungaturoto 0 1 0.3 1.00 0.00 0.18 N/A 0.28112 Melling 11kV 0 0 0.3 0.20 0.00 0.00 N/A 0.26113 Melling 33 kV 0 0 0.3 0.40 0.00 0.00 N/A 0.64114 Meremere 0 0 0.45 0.60 0.00 0.00 N/A 2.39115 Motunui 0 0 0.2 0.00 0.00 0.00 N/A 0.00116 Mt Maunganui 33 kV 0 0 0.3 0.60 0.00 0.00 N/A 0.31117 Mt Roskill 110 kV 0 0 0.2 0.40 0.00 0.00 N/A 0.06118 Mt Roskill 22 kV 0 0 0.1 0.40 0.00 0.00 N/A 0.11119 Murchison 1 0 0.58 0.40 0.12 0.00 N/A 0.08120 Naseby 1 0 0.3 0.20 0.18 0.00 N/A 0.04121 National Park 0 2 1.2 1.60 0.00 0.27 N/A 0.44122 New Plymouth 33 kV 0 0 0.3 0.20 0.00 0.00 N/A 0.23

New Plymouth 33 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.23124 North Makarewa 0 0 0.3 0.20 0.00 0.00 N/A 0.08125 Oamaru 0 0 0.3 0.00 0.00 0.00 N/A 0.00126 Ohakune (A) 0 1 0.56 0.80 0.00 3.49 N/A 2.24127 Ohakune (B) 0 1 0.56 0.60 0.00 12.85 N/A 2.01



128 Ongarue 0 1 0.56 0.80 0.00 0.10 N/A 0.86129 Opunake 0 0 0.1 0.80 0.00 0.00 N/A 2.75130 Orowaiti 0 0 0.3 0.00 0.00 0.00 N/A 0.00131 Otahuhu 22 kV (A) 0 0 0.2 0.40 0.00 0.00 N/A 0.05132 Otira 0 0 0.58 0.20 0.00 0.00 N/A 0.07133 Owhata 0 0 0.3 0.60 0.00 0.00 N/A 0.31134 Pakuranga 0 0 0.1 0.40 0.00 0.00 N/A 0.03135 Paraparaumu 0 0 0.2 0.60 0.00 0.00 N/A 0.20136 Pauatahanui 0 0 0.3 0.20 0.00 0.00 N/A 0.04137 Penrose 110 kV 0 0 0.1 0.20 0.00 0.00 N/A 0.02138 Penrose 22 kV 0 0 0.2 0.40 0.00 0.00 N/A 0.08139 Penrose 25 kV 0 0 0.45 0.00 0.00 0.00 N/A 0.00140 Penrose 33 kV (A) 0 0 0.1 0.40 0.00 0.00 N/A 0.05141 Penrose 33 kV (B) 0 0 0.3 0.00 0.00 0.00 N/A 0.00142 Piako 0 0 0.3 0.00 0.00 0.00 N/A 0.00143 Redclyffe 0 0 0.3 1.00 0.00 0.00 N/A 0.90144 Reefton 0 0 0.3 0.00 0.00 0.00 N/A 0.00145 Rotorua 11 kV 0 0 0.3 0.40 0.00 0.00 N/A 0.12146 Rotorua 33 kV 0 0 0.3 0.40 0.00 0.00 N/A 0.14147 Silverdale 0 0 0.1 0.60 0.00 0.00 N/A 0.02148 South Dunedin 0 0 0.3 0.00 0.00 0.00 N/A 0.00149 Southbrook 33 kV 0 2 0.3 0.40 0.00 2.01 N/A 0.40150 Southbrook 66 kV - 1 N/A 1.00 - 1.71 N/A

151 Southdown 25 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.00152 Stoke 33 kV 0 0 0.3 0.40 0.00 0.00 N/A 0.15153 Stoke 66 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.00154 Stratford 0 0 0.2 0.40 0.00 0.00 N/A 0.32155 Studholme 0 0 0.3 0.20 0.00 0.00 N/A 0.06156 Takanini 0 0 0.1 0.40 0.00 0.00 N/A 0.06157 Takapu Road 1 0 0.1 0.60 0.82 0.00 N/A 0.26158 Tangiwai 11 kV 0 0 0.2 0.40 0.00 0.00 N/A 0.27159 Tangiwai 55 kV 0 0 0.3 0.20 0.00 0.00 N/A 0.00160 Tarukenga 0 0 0.58 0.60 0.00 0.00 N/A 0.44161 Taumarunui 1 3 0.3 2.80 0.00 0.00 N/A 0.05162 Tauranga 11 kV 1 0 0.3 0.80 0.20 0.00 N/A 0.32163 Tauranga 33 kV 0 0 0.2 0.60 0.00 0.00 N/A 0.82164 Te Awamutu 0 1 0.32 0.80 0.00 1.65 N/A 0.51165 Te Kaha 2 2 16.75 5.60 1.76 2.76 N/A 5.40166 Te Kowhai 0 0 0.2 0.20 0.00 0.00 N/A 0.26167 Te Matai 0 0 0.3 0.40 0.00 0.00 N/A 0.08168 Tekapo A 3 0 1.14 2.40 15.54 0.00 N/A 4.54169 Temuka 0 0 0.2 0.20 0.00 0.00 N/A 0.00170 Timaru 1 0 0.3 0.20 0.06 0.00 N/A 0.01171 Tiwai 0 0 0.1 0.00 0.00 0.00 N/A 0.00172 Tokaanu (A) 0 1 0.3 0.40 0.00 0.22 N/A 0.11173 Tuai 0 0 0.3 0.00 0.00 0.00 N/A 0.00174 Twizel (A) 0 0 0.45 0.00 0.00 0.00 N/A 0.00175 Twizel (B) 0 0 0.45 0.00 0.00 0.00 N/A 0.00176 Upper Hutt 1 0 0.3 0.80 0.87 0.00 N/A 0.80177 Waihou 1 0 0.2 0.60 1.71 0.00 N/A 0.38178 Waikino 1 0 0.3 0.60 1.41 0.00 N/A 0.36179 Waiotahi 1 0 0.69 0.80 2.42 0.00 N/A 0.88180 Waipara 33 kV 0 0 0.58 0.20 0.00 0.00 N/A 0.24181 Waipara 66 kV 0 0 0.3 0.00 0.00 0.00 N/A 0.00182 Waipawa 11 kV 0 0 0.58 1.60 0.00 0.00 N/A 3.40183 Waipawa 33 kV 0 0 0.3 1.20 0.00 0.00 N/A 1.23184 Wairakei 0 0 0.3 0.40 0.00 0.00 N/A 3.15185 Wairau Road 0 0 0.2 0.00 0.00 0.00 N/A 0.00186 Waitaki 11 kV - 0 0.3 0.00 - 0.00 N/A187 Waitaki 33 kV 0 0 0.3 0.20 0.00 0.00 N/A 0.08188 Wanganui 1 0 0.3 1.20 0.12 0.00 N/A 0.51189 Waverley 0 1 0.56 0.60 0.00 4.40 N/A 1.51190 Wellsford 0 0 0.3 0.20 0.00 0.00 N/A 0.15191 Westport 0 0 0.3 0.20 0.00 0.00 N/A 0.06192 Whakatu 0 0 0.3 0.80 0.00 0.00 N/A 0.52193 Whirinaki 1 0 0.3 1.20 11.05 0.00 N/A 3.41



194 Wilton 1 0 0.2 0.80 0.13 0.00 N/A 0.11195 Wiri 0 1 0.2 0.80 0.00 0.23 N/A 0.14196 Woodville 0 0 0.3 0.20 0.00 0.00 N/A 0.26197198 *Insert additional rows as needed199200 Point of Service Performance - Injection201 (Points of Service as at 30 June 2016) Number of Interruptions Duration in minutes202 Point of Service CY-2 Actual CY-1 Actual CY Actual CY Target 5 year average CY-2 Actual CY-1 Actual CY Actual CY Target 5 year average 203 Arapuni 0 1 0.3 1.00 0 26 N/A 55204 Aratiatia 0 0 0.5 0.20 0 0 N/A 351205 Argyle 1 0 1.22 1.40 177 0 N/A 126206 Atiamuri 0 0 0.3 0.00 0 0 N/A 0207 Aviemore 0 0 0.3 0.20 0 0 N/A 285208 Benmore 220 kV 0 0 0.3 0.00 0 0 N/A 0209 Berwick 2 1 4.35 1.40 22 41 N/A 58210 Clyde 0 0 0.3 0.00 0 0 N/A 0211 Coleridge 2 0 0.3 0.60 2,734 0 N/A 552212 Glenbrook Generation 0 0 N/A 0.20 0 0 N/A 24213 Hawera (A) 0 0 0.2 0.20 0 0 N/A 22214 Hawera (B) 0 0 0.3 0.20 0 0 N/A 23215 Huntly 0 1 0.3 0.60 0 196 N/A 122216 Kaponga 1 0 0.74 0.60 183 0 N/A 151217 Karapiro 0 2 0.3 0.80 0 424 N/A 173218 Kawerau Geo 0 0 0.3 0.20 0 0 N/A 66219 Kinleith Gen 0 0 N/A 0.20 0 0 N/A 57220 Kumara 0 1 0.3 0.20 0 57 N/A 11221 Manapouri 0 0 0.3 0.00 0 0 N/A 0222 Mangahao 1 0 0.3 0.60 48 0 N/A 198223 Maraetai 3 0 0.3 1.40 426 0 N/A 187224 Matahina (A) 0 0 0.3 0.00 0 0 N/A 0225 Matahina (B) 0 0 0.3 1.00 0 0 N/A 103226 McKee 1 2 1.02 0.80 8 43 N/A 50227 Nga Awa Purua 0 0 0.3 0.40 0 0 N/A 22228 Ngatamariki 0 0 0.3 0.20 0 0 N/A 17229 Ohaaki 0 0 0.3 0.00 0 0 N/A 0230 Ohakuri 0 0 0.3 0.00 0 0 N/A 0231 Ohau A 0 0 0.3 0.00 0 0 N/A 0232 Ohau B 0 0 0.3 0.00 0 0 N/A 0233 Ohau C 0 0 0.3 0.00 0 0 N/A 0234 Poihipi 0 0 0.49 0.20 0 0 N/A 25235 Rangipo 0 0 0.3 0.80 0 0 N/A 586236 Rotorua 110 kV 0 0 0.3 0.20 0 0 N/A 25237 Roxburgh 110 kV 0 0 0.3 0.00 0 0 N/A 0238 Roxburgh 220 kV 0 0 0.3 0.40 0 0 N/A 207239 Southdown 0 0 0.3 0.00 0 0 N/A 0240 Stratford 0 0 0.2 0.20 0 0 N/A 724241 Tararua Windfarm C 0 0 0.3 0.00 0 0 N/A 0242 Te Apiti Wind Farm 0 0 0.3 0.20 0 0 N/A 20243 Te Mihi 0 0 0.3 0.20 0 0 N/A 10244 Tekapo A 3 0 1.14 2.60 761 0 N/A 221245 Tekapo B 0 0 0.3 0.60 0 0 N/A 4246 Tokaanu 0 0 0.3 0.00 0 0 N/A 0247 Tuai 0 0 0.3 0.40 0 0 N/A 58248 Waipapa 3 0 0.54 1.40 435 0 N/A 191249 Wairakei 0 0 0.3 0.00 0 0 N/A 0250 Waitaki 0 0 0.3 0.40 0 0 N/A 110251 West Wind 0 3 0.69 1.00 0 652 N/A 134252 Whakamaru 0 0 0.3 0.00 0 0 N/A 0253 Whirinaki 0 0 0.3 0.60 0 0 N/A 46254255 *Insert additional rows as needed

257

258 G4(iii): Unplanned Interruption Causes 259260 Cause of interruption

Annual Performance (System Minutes) Significant Events (System Minutes) Underlying Events (System Minutes)261 CY-4 CY-3 CY-2 CY-1 CY CY-4 CY-3 CY-2 CY-1 CY CY-4 CY-3 CY-2 CY-1 CY



262 Transpower Unplanned263 Environment 2.27 1.02 0.00 0.00 2.27 1.02264 Equipment 6.18 0.47 5.28 0.00 0.90 0.47265 Human error 0.64 0.80 0.00 0.00 0.64 0.80266 Miscellaneous 0.09 0.00 0.00 0.00 0.09 0.00267 Not Known 0.00 0.51 0.00 0.00 0.00 0.51268 Total Unplanned 0.0 0.0 0.0 9.18 2.80 0.0 0.0 0.00 5.28 0.00 0.0 0.0 0.0 3.90 2.80269270 Transpower Planned 3.02 0.36 0.00 0.00 3.02 0.36271272 Total Transpower Planned and Unplanned 0 0 0 12.20 3.15 0 0 0.00 5.28 0.00 0 0 0 6.92 3.15273274


Tab name: G5. Quality interconnection 05/09/2023


SCHEDULE G5: QUALITY OF SUPPLY: INTERCONNECTION ASSETS Disclosure Year (year ended) ###

ref

5 G5(i): Interconnection Asset Report6

7

Asset Type* Sub Cat Incidents Affecting Performance IDENT

8

CCT 110 1.67 .07 .08 .5 .28 10.45 None Apply None Apply

9 ALB-HEN-1 I CCT 110 1.04 0 0 0 0 0 1 0 N/N Planned Outage /

10 ALB-HEN-2 I CCT 110 1.01 0 0 0 0 0 2 0 N/N Planned Outage /

11 ARI-BOB-1 I CCT 110 5.94 .19 0 0 0 0 0 0 Y/Y Planned Outage /

12

24-SEP-2015: ARI-BOB-1 tripped, lightning, circuit patrolled, no cause found SN15199

13

SN15223

14SN15228

15

SN15232

16 14-JUN-2016: ARI-BOB-1 tripped, patrol found no cause SN16130

17 ARI-HAM-1 I CCT 110 3.51 0 0 0 0 0 0 0 Y/N Planned Outage /

18 ARI-HAM-2 I CCT 110 4.46 0 0 0 0 0 0 0 Y/N Planned Outage /

19 ARI-HTI-1 B CCT 110 1.97 0 0 0 0 0 0 0 Y/N Planned Outage /

20 ARI-HTI-ONG-1 B CCT 110 1.43 0 0 0 0 0 0 0 N/N Planned Outage /

21

ARI-KIN-1 I CCT 110 .95 .08 0 0 0 0 2 0 N/Y SN15214

22

SN16091

23 ARI-KIN-2 I CCT 110 .51 0 0 0 0 0 0 0 N/N Planned Outage /

24 ATU-DOB-1 I CCT 110 1.6 0 2 4.27 0 0 0 0 Y/N Planned Outage /

25 ATU-RFN-IGH-1 I CCT 110 1.42 0 2 4.27 0 0 0 0 Y/N Planned Outage /

26 BAL-GOR-1 B CCT 110 13.53 0 0 0 0 0 0 0 Y/N Planned Outage /

27 BAL-HWB-1 B CCT 110 5.4 0 0 0 0 0 1 0 Y/N Planned Outage /

28 BDE-EDN-1 B CCT 110 3.56 .04 0 0 0 0 0 0 Y/N Planned Outage /

29 BDE-GOR-1 B CCT 110 .49 0 0 0 0 0 0 0 N/N Planned Outage /

30 BLN-KIK-1 I CCT 110 2.6 0 0 0 0 0 0 0 Y/N Planned Outage /

31 BLN-STK-1 I CCT 110 .8 0 0 0 0 0 0 0 N/N Planned Outage /

32 BLN-STK-2 I CCT 110 0 0 0 0 0 0 1 0 N/N

33 BOB-HAM-1 I CCT 110 5.5 0 0 0 0 0 1 0 Y/N Planned Outage /

34 BOB-HAM-2 I CCT 110 5.22 .18 0 0 0 0 0 0 Y/Y Planned Outage /

35

SN15223

36SN15228

37 BOB-OTA-1 B CCT 110 3.63 0 0 0 1 10.37 1 0 Y/Y Planned Outage /

38

SN15203

39 BOB-OTA-2 B CCT 110 2.6 .01 0 0 0 0 1 0 Y/N Planned Outage /

40 BPE-MTR-1 I CCT 110 1.81 0 0 0 0 0 2 0 Y/N Planned Outage /

41 BPE-WDV-1 I CCT 110 .41 0 0 0 0 0 0 0 N/N Planned Outage /

42 BPE-WDV-2 I CCT 110 1.12 .02 0 0 0 0 0 0 N/N Planned Outage /43 BPE-WGN-1 I CCT 110 1.44 0 0 0 0 0 0 0 N/N Planned Outage /

44

BPE-WGN-2 I CCT 110 1.32 .07 0 0 0 0 0 0 N/Y SN16040

45 CST-HUI-1 I CCT 110 .35 0 0 0 0 0 0 0 N/N Planned Outage /46 CST-HUI-2 I CCT 110 .08 0 0 0 0 0 1 0 N/N Planned Outage /47 CST-MNI-1 I CCT 110 .37 0 0 0 0 0 0 0 N/N Planned Outage /48 CST-NPL-1 I CCT 110 .81 0 0 0 0 0 0 0 N/N Planned Outage /

49

CST-NPL-2 I CCT 110 .82 .32 0 0 0 0 0 0 N/Y 07-JUN-2016: CST-NPL-2 RFS to repair oil leak on NPL-VT-72 red phase unit SN16125

Asset Category

Planned Unavailability %

Unplanned Unavailability %

Number Planned Interruptions

Planned Unserved Energy

MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh

Number of Outages <1

Min

Number of Interruptions <1

min

Measures Exceeded

(plan/Unplan) ?

Steps Being Taken To Improve Performance(1)

Index Measures for Asset Category

Transmission circuits are prone to lightning strike. Transpower's design standards optimise lightning protection [e.g. earthwire] vs installation cost. Transpower has also implemented auto-reclose in a wide range of locations across the network, seeking to improve performance. Specific fault circumstances can prevent successful AR, and AR has not been installed everywhere due to specific constraints e.g. generation in the area. Transpower may investigate special protection schemes where applicable.

20-OCT-2015: ARI-BOB-1 RFS, only BOB-CSA-232 opened, after SF6 leak on BOB-CSA-242 had been investigated.

Transpower is aware that leaking SF6 is a primary cause of unplanned outages for Circuit Breakers. Options are being investigated to address the underlying factors.Issue being worked through with manufacturer.

06-NOV-2015: ARI-BOB-1 RFS for SF6 top up of BOB-CSA-242. Only BOB-CSA-232 opened (ARI-BOB-1) to step into BOB 110kV bus section 214 - 227.11-NOV-2015: ARI-BOB-1 tripped, patrolled structures 133 to 233 on ARI-HAM-A line, no cause found

While Transpower typically patrols after such faults, often the cause cannot be determined. Transpower is currently considering options to investigate "unknown cause" events to learn more about their causal factors.

07-OCT-2015: ARI-KIN-1 tripped for red phase to earth fault cause unknown. ARI-KIN-2 out of service for maintenance so there was a forced outage to ARI 110kV South Bus as ARI CB48 open for system split. MRP's G5, G6, G7 tripped as generation was islanded so partial interruption of connection at ARI.


15-MAY-2016: ARI-KIN-1 tripped, only KIN end A/R, for a high impedance red phase to earth fault probably caused by bird droppings (streaming). A lot of bird streaming found on the insulators of structure 648W and 649A on KIN-DEV A. It is proposed to install bird deterrents on structures in this area.

20-OCT-2015: BOB-HAM-2 RFS to investigate SF6 leak on BOB-CSA-242. BOB-CSA-252 and HAM-CB162 opened to step into BOB 110kV bus section 227-247.

Transpower is aware that leaking SF6 is a primary cause of unplanned outages for Circuit Breakers. Options are being investigated to address the underlying factors.Issue being worked through with manufacturer.

06-NOV-2015: BOB-HAM-2 RFS for SF6 top up of BOB-CSA-242. BOB-CSA-252 and HAM-CB162 opened to step into BOB 110kV bus section 227-247-267

29-SEP-2015: OTA-VT-selection failure,OTA-WIR1&2 & WIR T1&T2 trip, LOS at WIR

Switch was not operated in recommended way and led to significant interruption between switching. Guidance was provided on switching and recommendation for label on site.

24-FEB-2016: BPE-MTN-WGN-2 RFS to replace exploded or "blown" yellow and blue phase insulator strings at tower 50. Mist from Tower painter's water blasting plus pollution caused tracking on the insulator surface, localised heating, expanded then exploded. Damaged insulator strings were replaced.

Process has been introduce in regards to risk evaluation when Tower painters inadvertently cause failure of insulators. Independent investigation conducted to find root cause of failures and find best mode of blasting

The circuit was forced out to top up and temporary repair oil leak at the base of the VT, job has been raised in Maximo to replace VT



50 CST-SFD-1 I CCT 110 1.31 0 0 0 0 0 1 0 N/N Planned Outage /51 DOB-RFN-IGH-2 I CCT 110 3.09 0 0 0 0 0 2 0 Y/N Planned Outage /52 EDG-KAW-1 I CCT 110 1.27 .05 0 0 0 0 0 0 N/N Planned Outage /53 EDG-KAW-2 I CCT 110 .96 0 0 0 0 0 0 0 N/N Planned Outage /54 EDG-OWH-2 B CCT 110 .94 .01 0 0 0 0 2 0 N/N Planned Outage /55 EDN-INV-1 I CCT 110 2.63 0 0 0 0 0 0 0 Y/N Planned Outage /56 FHL-RDF-1 I CCT 110 2.27 .07 0 0 0 0 0 0 Y/N Planned Outage /57 FHL-RDF-2 I CCT 110 .34 .07 0 0 0 0 0 0 N/N Planned Outage /58 FHL-TUI-1 I CCT 110 .13 .11 0 0 0 0 1 0 N/Y 19-NOV-2015: FHL-TUI-1 RFS to repair unravelling strands span 18-19 Conductor repaired. Damage caused by Lightning Strike SN1524659 FHL-WPW-1 I CCT 110 1.26 .07 0 0 0 0 0 0 N/N Planned Outage /60 FHL-WPW-2 I CCT 110 1.62 .07 0 0 0 0 1 0 N/N Planned Outage /61 GOR-ROX-1 I CCT 110 5.26 0 0 0 0 0 0 0 Y/N Planned Outage /62 HAY-TKR-1 I CCT 110 1.09 .01 0 0 0 0 0 0 N/N Planned Outage /

63HAY-TKR-2 I CCT 110 .27 .08 0 0 0 0 0 0 N/Y 22-JAN-2016: HAY-TKR-2 RFS to replace loose inter-phase spacer at tower 18 SN16016

64 HAY-UHT-1 I CCT 110 .56 0 0 0 0 0 0 0 N/N Planned Outage /65 HAY-UHT-2 I CCT 110 1.09 0 0 0 0 0 0 0 N/N Planned Outage /66 HEN-HEP-1 I CCT 110 .12 0 0 0 0 0 0 0 N/N Planned Outage /67 HEN-HEP-2 I CCT 110 .19 0 0 0 0 0 0 0 N/N Planned Outage /

68

HEN-HEP-3 I CCT 110 1.06 .67 0 0 0 0 0 0 N/Y SN16053

69 HEN-HEP-4 I CCT 110 .78 0 0 0 0 0 0 0 N/N Planned Outage /70 HEN-MPE-1 I CCT 110 13.06 .01 0 0 1 1.79 6 5 Y/Y Planned Outage /

71

SN16139

72 HEN-MPE-2 I CCT 110 13.35 .01 0 0 1 1.79 4 5 Y/Y Planned Outage /

73

SN16139

74 HEP-ROS-1 I CCT 110 .49 .02 0 0 0 0 0 0 N/N Planned Outage /75 HEP-ROS-2 I CCT 110 .5 .02 0 0 0 0 0 0 N/N Planned Outage /76 HOR-KBY-ISL-1 I CCT 110 1.13 0 0 0 0 0 0 0 N/N Planned Outage /77 HOR-KBY-ISL-2 I CCT 110 1.02 0 0 0 0 0 0 0 N/N Planned Outage /78 HUI-MNI-1 I CCT 110 .6 0 0 0 0 0 0 0 N/N Planned Outage /79 HWA-SFD-1 I CCT 110 .22 .06 0 0 0 0 0 0 N/N Planned Outage /80 HWA-WVY-1 I CCT 110 3.09 0 0 0 0 0 0 0 Y/N Planned Outage /81 HWB-ROX-1 I CCT 110 3.56 .04 0 0 0 0 2 0 Y/N Planned Outage /82 HWB-ROX-2 I CCT 110 3.69 0 0 0 0 0 1 0 Y/N Planned Outage /83 IGH-KIK-1 I CCT 110 .44 0 0 0 0 0 2 1 N/N Planned Outage /84 IGH-KIK-2 I CCT 110 .22 0 0 0 0 0 0 0 N/N Planned Outage /85 KIK-STK-3 I CCT 110 4.46 0 0 0 0 0 0 0 Y/N Planned Outage /86 KIN-TRK-1 I CCT 110 1.69 0 0 0 0 0 5 0 Y/N Planned Outage /87 KIN-TRK-2 I CCT 110 2.05 0 0 0 0 0 1 0 Y/N Planned Outage /88 KMO-MTM-1 I CCT 110 1.79 0 0 0 0 0 0 0 Y/N Planned Outage /89 KMO-MTM-TGA-2 B CCT 110 4.04 .02 0 0 0 0 0 0 Y/N Planned Outage /

90KMO-TMI-1 I CCT 110 .53 .09 0 0 0 0 0 0 N/Y SN16044

91 MDN-MPE-1 I CCT 110 .45 0 0 0 0 0 0 0 N/N Planned Outage /92 MDN-MPE-2 I CCT 110 1.07 0 0 0 0 0 0 0 N/N Planned Outage /93 MGM-MST-1 I CCT 110 2.29 .04 0 0 0 0 0 0 Y/N Planned Outage /94 MGM-WDV-1 I CCT 110 1.24 .01 0 0 0 0 0 0 N/N Planned Outage /95 MNG-OTA-1 I CCT 110 1.18 0 0 0 0 0 0 0 N/N Planned Outage /96 MNG-OTA-2 I CCT 110 0 0 0 0 0 0 0 0 N/N97 MNG-ROS-1 I CCT 110 .1 0 0 0 0 0 0 0 N/N Planned Outage /98 MNG-ROS-2 I CCT 110 .09 0 0 0 0 0 1 0 N/N Planned Outage /99 MNI-MKE-SFD-1 I CCT 110 .23 0 0 0 0 0 2 0 N/N Planned Outage /

100 MST-UHT-1 I CCT 110 .42 .04 0 0 0 0 0 0 N/N Planned Outage /101 MST-UHT-2 I CCT 110 .17 .02 0 0 0 0 1 0 N/N Planned Outage /102 MTR-OKN-1 I CCT 110 .61 0 0 0 0 0 0 0 N/N Planned Outage /103 OAM-BPT-WTK-1 B CCT 110 2.54 .04 3 1.17 1 0 0 0 Y/Y Planned Outage /

104

SS16040

105 OAM-STU-BPD-WTK-2 B CCT 110 3.19 0 0 0 0 0 0 0 Y/N Planned Outage /106 OKN-ONG-1 B CCT 110 1.58 0 0 0 0 0 0 0 N/N Planned Outage /107 OTA-PEN-2 I CCT 110 2.81 0 0 0 0 0 0 0 Y/N Planned Outage /108 OTA-ROS-1 I CCT 110 5.03 0 0 0 0 0 0 0 Y/N Planned Outage /109 OTA-ROS-2 I CCT 110 5.45 0 0 0 0 0 0 0 Y/N Planned Outage /110 RDF-TUI-1 I CCT 110 .55 0 0 0 0 0 0 0 N/N Planned Outage /111 RDF-TUI-2 I CCT 110 .42 0 0 0 0 0 0 0 N/N Planned Outage /112 STU-TIM-1 I CCT 110 1.61 0 0 0 0 0 0 0 N/N Planned Outage /113 TKR-WIL-1 I CCT 110 1.85 .04 0 0 0 0 0 0 Y/N Planned Outage /114 TKR-WIL-2 I CCT 110 3.65 .1 0 0 0 0 0 0 Y/Y Planned Outage /

Repair completed, bolt replaced in interphase spacer assembly

12-MAR-2016: HEN-HEP-3 tripped, only at HEN, for a faulty SEL-321 relay for HEN 292DIST/DCEF. There was no primary system fault to HEN-HEP-3 also HEN relay 292LDIF, HEP relay 202DIST and 202LDIF did not operate. Faulty SEL-321 was replaced on 14 MAR 2016.

Relay manufacturer SEL advised of batch failure mode. A maintenance advisory was issued.

26-JUN-2016: HEN-MPE-1 and 2 trip & A/R, lightning, LOS at MTO, MTO-TF-T1 & MTO-TF-T2 inter tripped


26-JUN-2016: HEN-MPE-1 and 2 trip & A/R, lightning, LOS at MTO, MTO-TF-T1 & MTO-TF-T2 inter tripped


27-FEB-2016: KMO-TMI-1 RFS to trim trees that were in the minimum access distance (MAD).

24-APR-2016: OAM-BPT-WTK1 tripped, LOS @ BPT to Network Waitaki, circuit patrol found no cause for the tripping




115

23-MAY-2016: TKR-WIL-2 RFS for crane safety clearance for work at WIL SN16106

116 TMI-OWH-TRK-1 B CCT 110 .74 0 0 0 0 0 2 0 N/N Planned Outage /117 WDV-DVK-WPW-1 I CCT 110 1.3 .05 0 0 0 0 0 0 N/N Planned Outage /118 WDV-DVK-WPW-2 I CCT 110 1.23 .04 0 0 0 0 0 0 N/N Planned Outage /119 WGN-WVY-1 I CCT 110 .42 .03 0 0 0 0 0 0 N/N Planned Outage /120

121


122

CCT 220 .88 .05 0 0 .13 9.87 None Apply None Apply

123 ALB-HEN-3 I CCT 220 .99 0 0 0 0 0 0 0 Y/N Planned Outage /124 ALB-HPI-1 I CCT 220 .39 .01 0 0 0 0 0 0 N/N Planned Outage /125 ASB-BRY-1 B CCT 220 .89 .23 0 0 0 0 1 0 Y/Y Planned Outage /

126SS16005

127 ASB-ISL-1 I CCT 220 .48 0 0 0 0 0 1 0 N/N Planned Outage /128 ASB-TIM-TWZ-1 I CCT 220 .03 0 0 0 0 0 0 0 N/N Planned Outage /129 ASB-TIM-TWZ-2 I CCT 220 .06 0 0 0 0 0 0 0 N/N Planned Outage /130 ATI-OHK-1 I CCT 220 .05 0 0 0 0 0 0 0 N/N Planned Outage /131 ATI-TRK-1 I CCT 220 .11 0 0 0 0 0 0 0 N/N Planned Outage /132 ATI-TRK-2 I CCT 220 2.12 0 0 0 0 0 0 0 Y/N Planned Outage /133 ATI-WKM-1 I CCT 220 1.01 .03 0 0 0 0 0 0 Y/N Planned Outage /134 AVI-BEN-1 I CCT 220 .46 0 0 0 0 0 0 0 N/N Planned Outage /135 AVI-BEN-2 I CCT 220 0 0 0 0 0 0 0 0 N/N136 AVI-WTK-1 I CCT 220 .43 0 0 0 0 0 0 0 N/N Planned Outage /137 BEN-OHB-1 I CCT 220 .25 0 0 0 0 0 0 0 N/N Planned Outage /138 BEN-OHC-2 I CCT 220 1.1 0 0 0 0 0 0 0 Y/N Planned Outage /139 BEN-TWZ-1 I CCT 220 .06 0 0 0 0 0 0 0 N/N Planned Outage /140 BPE-BRK-1 I CCT 220 1.01 .01 0 0 0 0 0 0 Y/N Planned Outage /141 BPE-BRK-2 I CCT 220 1.18 0 0 0 0 0 0 0 Y/N Planned Outage /142 BPE-PRM-HAY-1 I CCT 220 16.29 0 0 0 0 0 2 0 Y/N Planned Outage /143 BPE-PRM-HAY-2 I CCT 220 20.69 .03 0 0 0 0 0 0 Y/N Planned Outage /144 BPE-TKU-1 B CCT 220 1.47 0 0 0 0 0 0 0 Y/N Planned Outage /145 BPE-TKU-2 B CCT 220 1.44 .54 0 0 0 0 1 0 Y/Y Planned Outage /

146

This fault was caused by a third party 11kv line SN15202

147

SN16086

148 BPE-TNG-1 B CCT 220 .92 0 0 0 0 0 0 0 Y/N Planned Outage /149 BPE-TWC-LTN-1 B CCT 220 .38 0 0 0 0 0 0 0 N/N Planned Outage /150 BPE-WIL-1 I CCT 220 1.61 .01 0 0 0 0 0 0 Y/N Planned Outage /151 BRB-HPI-1 B CCT 220 2.88 0 0 0 0 0 0 0 Y/N Planned Outage /152 BRK-SFD-1 I CCT 220 .65 0 0 0 0 0 0 0 N/N Planned Outage /153 BRK-SFD-2 I CCT 220 .66 0 0 0 0 0 1 0 N/N Planned Outage /154 BRK-SFD-3 I CCT 220 .78 0 0 0 0 0 0 0 N/N Planned Outage /155 BRY-ISL-1 B CCT 220 4.42 0 0 0 0 0 0 0 Y/N Planned Outage /156 CYD-CML-TWZ-1 I CCT 220 0 0 0 0 0 0 0 0 N/N157 CYD-CML-TWZ-2 I CCT 220 1.2 0 0 0 0 0 0 0 Y/N Planned Outage /158 CYD-ROX-1 I CCT 220 .64 0 0 0 0 0 0 0 N/N Planned Outage /159 CYD-ROX-2 I CCT 220 .09 0 0 0 0 0 0 0 N/N Planned Outage /160 DRY-HLY-1 I CCT 220 .49 0 0 0 0 0 0 0 N/N Planned Outage /161 DRY-OTA-1 I CCT 220 1.25 0 0 0 0 0 0 0 Y/N Planned Outage /162 EDG-KAW-3 I CCT 220 .31 0 0 0 0 0 1 0 N/N Planned Outage /163 EDG-TRK-1 I CCT 220 3.59 0 0 0 0 0 0 0 Y/N Planned Outage /164 EDG-TRK-2 I CCT 220 2.64 .22 0 0 0 0 0 0 Y/Y Planned Outage /

165

SN15152

166 HAM-OHW-1 I CCT 220 1.87 0 0 0 0 0 0 0 Y/N Planned Outage /167 HAM-WKM-1 I CCT 220 1.11 0 0 0 0 0 0 0 Y/N Planned Outage /168 HAY-LTN-1 I CCT 220 1.44 0 0 0 0 0 0 0 Y/N Planned Outage /169 HAY-WIL-1 I CCT 220 .81 .02 0 0 0 0 0 0 N/N Planned Outage /170 HEN-HPI-1 I CCT 220 2.09 0 0 0 0 0 1 0 Y/N Planned Outage /171 HEN-OTA-1 I CCT 220 .12 0 0 0 0 0 0 0 N/N Planned Outage /172 HEN-SWN-1 I CCT 220 1.36 .02 0 0 0 0 4 0 Y/N Planned Outage /173 HLY-OHW-1 I CCT 220 1.22 0 0 0 0 0 0 0 Y/N Planned Outage /174 HLY-OHW-2 I CCT 220 1.02 .01 0 0 0 0 0 0 Y/N Planned Outage /175 HLY-OTA-2 B CCT 220 1.49 0 0 0 0 0 0 0 Y/N Planned Outage /176 HLY-SFD-1 I CCT 220 .23 0 0 0 0 0 2 0 N/N Planned Outage /177 HLY-TWH-1 B CCT 220 .24 0 0 0 0 0 0 0 N/N Planned Outage /178 HPI-MDN-1 I CCT 220 2.37 0 0 0 0 0 0 0 Y/N Planned Outage /179 HWB-SDN-1 B CCT 220 .44 0 0 0 0 0 0 0 N/N Planned Outage /180 HWB-TMH-1 I CCT 220 .71 0 0 0 0 0 0 0 N/N Planned Outage /181 INV-MAN-2 B CCT 220 2.7 0 0 0 0 0 0 0 Y/N Planned Outage /182 INV-NMA-1 I CCT 220 1.21 0 0 0 0 0 0 0 Y/N Planned Outage /183 INV-ROX-1 I CCT 220 4.14 0 0 0 0 0 0 0 Y/N Planned Outage /184 INV-ROX-2 I CCT 220 1.36 0 0 0 0 0 1 0 Y/N Planned Outage /185 INV-TWI-1 I CCT 220 1.66 0 0 0 0 0 0 0 Y/N Planned Outage /186 INV-TWI-2 I CCT 220 2.68 .25 0 0 0 0 0 0 Y/Y Planned Outage /

Project related. Enable safe removal of a bulk oil 110kV circuit breaker. Wind conditions had been too high for an extended period of time, and the planned outage could not be utilised. A window in the weather presented itself, and the project team requested a short notice outage to remove the breaker. A delay would have impacted the project programme further. (Major works to re-build the Wilton 110kV bus).

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



20-JAN-2016: ASB-BRY-1 RFS to check ASB-CB-382, loose bridging link in terminal block

Terminal connections are required to be checked as a part of SMP work.

27-SEP-2015: BPE-TKU-2 trip and A/R for a Yph - Bph fault after a delay another trip and A/R for a Yph - Bph fault then a trip and lockout for a Bph-E fault caused by smoke from a pine forest fire started by a Genesis 33kV pole crossarm failure. No damage to circuit. Outage to fell burnt fall distance trees.

12-MAY-2016: BPE-TKU-2 RFS to clear BPE 220 kV bus B and isolate BPE-CB722 which was locked out due to low air pressure. Contractor found a cracked 90 degree elbow at compressor outlet and leaking air resulted in a pressure drop. Replaced elbow and compressor checked for leaks.

Compressor pipework replaced with a high quality braided type, to compensate for compressor movement during starting/stopping. The failure was due to stress on the fixed pipe connection. This failure mode is now addressed.

09-JUL-2015: EDG-TRK-2 RFS to top up SF6 gas in EDG CB482 as its Yph pole had a low pressure of 3.6 bar.

Transpower is aware that leaking SF6 is a primary cause of unplanned outages for Circuit Breakers. Options are being investigated to address the underlying factors.



187 13-OCT-2015: INV-TWI-2 RFS to replacer loose shackle at twr 9 SS15096188 ISL-KIK-1 I CCT 220 3.26 .04 0 0 0 0 0 0 Y/N Planned Outage /189 ISL-LIV-1 I CCT 220 1.41 0 0 0 0 0 7 0 Y/N Planned Outage /190 ISL-TKB-1 B CCT 220 2.04 0 0 0 0 0 1 0 Y/N Planned Outage /191 ISL-WPR-CUL-KIK-2 B CCT 220 .26 .03 0 0 0 0 0 0 N/N Planned Outage /192 ISL-WPR-CUL-KIK-3 B CCT 220 .79 0 0 0 0 0 0 0 N/N Planned Outage /

193

KAW-OHK-1 I CCT 220 .26 .08 0 0 0 0 0 0 N/Y SN15165

194 KIK-STK-1 I CCT 220 .39 .04 0 0 0 0 0 0 N/N Planned Outage /195 KIK-STK-2 I CCT 220 .14 0 0 0 0 0 0 0 N/N Planned Outage /196 KMO-TRK-1 I CCT 220 .11 0 0 0 0 0 0 0 N/N Planned Outage /197 KMO-TRK-2 I CCT 220 .2 0 0 0 0 0 0 0 N/N Planned Outage /198 LIV-NSY-1 I CCT 220 .3 0 0 0 0 0 0 0 N/N Planned Outage /199 LIV-WTK-1 I CCT 220 16.69 .02 0 0 0 0 1 0 Y/N Planned Outage /200 NMA-TMH-1 I CCT 220 0 0 0 0 0 0 0 0 N/N201 NMA-TMH-2 I CCT 220 .1 0 0 0 0 0 0 0 N/N Planned Outage /202 NMA-TWI-1 I CCT 220 1.25 0 0 0 0 0 0 0 Y/N Planned Outage /203 NMA-TWI-2 I CCT 220 1.21 0 0 0 0 0 0 0 Y/N Planned Outage /204 NPL-SFD-1 I CCT 220 9.39 0 0 0 0 0 0 0 Y/N Planned Outage /205 NPL-SFD-2 I CCT 220 9.37 .17 0 0 0 0 0 0 Y/Y Planned Outage /

206

SN15209

207

SN16010

208 NSY-ROX-1 I CCT 220 .1 0 0 0 0 0 1 0 N/N Planned Outage /209 OHB-TWZ-3 I CCT 220 0 0 0 0 0 0 0 0 N/N210 OHC-TWZ-4 I CCT 220 .37 0 0 0 0 0 0 0 N/N Planned Outage /211 OHK-WRK-1 I CCT 220 .12 .01 0 0 0 0 0 0 N/N Planned Outage /212 OHW-OTA-1 I CCT 220 .59 0 0 0 0 0 0 0 N/N Planned Outage /213 OHW-OTA-2 I CCT 220 .61 0 0 0 0 0 0 0 N/N Planned Outage /214 OHW-WKM-1 I CCT 220 1.75 .02 0 0 0 0 0 0 Y/N Planned Outage /215 OTA-PAK-3 I CCT 220 1.31 0 0 0 0 0 0 0 Y/N Planned Outage /216 OTA-PAK-4 I CCT 220 1.83 0 0 0 0 0 0 0 Y/N Planned Outage /217 OTA-PEN-5 I CCT 220 2.96 0 0 0 0 0 0 0 Y/N Planned Outage /218 OTA-PEN-6 I CCT 220 1.74 0 0 0 0 0 0 0 Y/N Planned Outage /219 OTA-SWN-1 I CCT 220 0 0 0 0 0 0 0 0 N/N220 OTA-WKM-1 I CCT 220 1.23 .05 0 0 0 0 9 0 Y/Y Planned Outage /

221SN15198

222 OTA-WKM-2 I CCT 220 .21 .05 0 0 0 0 4 0 N/N Planned Outage /

223

PAK-WKM-1 I CCT 220 .38 .1 0 0 0 0 0 0 N/Y SN15174

224SN15192

225 PAK-WKM-2 I CCT 220 .37 0 0 0 0 0 0 0 N/N Planned Outage /226 PPI-THI-1 I CCT 220 0 0 0 0 0 0 0 0 N/N227 RDF-WHI-1 I CCT 220 1.01 0 0 0 0 0 0 0 Y/N Planned Outage /228 RDF-WRK-1 I CCT 220 .34 0 0 0 0 0 0 0 N/N Planned Outage /229 ROX-TMH-1 I CCT 220 .31 0 0 0 0 0 0 0 N/N Planned Outage /230 ROX-TMH-2 I CCT 220 0 0 0 0 0 0 0 0 N/N231 RPO-TNG-1 B CCT 220 1.03 .04 0 0 0 0 2 0 Y/N Planned Outage /232 RPO-WRK-1 B CCT 220 .94 .03 0 0 0 0 0 0 Y/N Planned Outage /233 SFD-TMN-1 I CCT 220 .33 0 0 0 0 0 0 0 N/N Planned Outage /234 THI-WKM-1 I CCT 220 0 0 0 0 0 0 0 0 N/N235 THI-WRK-1 I CCT 220 .23 0 0 0 0 0 0 0 N/N Planned Outage /236 TKB-TWZ-1 B CCT 220 .06 0 0 0 0 0 0 0 N/N Planned Outage /237 TKU-WKM-1 B CCT 220 1.55 0 0 0 0 0 0 0 Y/N Planned Outage /238 TKU-WKM-2 B CCT 220 1.57 .06 0 0 0 0 2 0 Y/Y Planned Outage /

239

SN15234

240TMN-TWH-1 B CCT 220 .76 .1 0 0 3 0 2 0 N/Y SN16019

241SN16020

242 WHI-WRK-1 I CCT 220 .64 0 0 0 0 0 1 0 N/N Planned Outage /243 WKM-WRK-1 I CCT 220 .18 0 0 0 0 0 0 0 N/N Planned Outage /244

245


246

CCT 66 1.25 .08 .14 .46 1.31 1.88 None Apply None Apply

247 ASY-SBK-1 B CCT 66 4.17 .02 0 0 0 0 0 0 Y/N Planned Outage /248 ASY-WPR-1 B CCT 66 .63 0 0 0 0 0 0 0 N/N Planned Outage /249 COL-HOR-2 I CCT 66 1.16 0 0 0 0 0 0 0 N/N Planned Outage /250 COL-HOR-3 I CCT 66 .73 0 0 0 0 0 0 0 N/N Planned Outage /251 COL-OTI-1 I CCT 66 3.25 .04 0 0 2 .13 4 10 Y/Y Planned Outage /

252

SS15086

21-JUL-2015: KAW-OHK-1 RFS to repair the red phase insulator string on structure 171 that was damaged by rifle fire (wilful damage) by a member of the public (human error). 12 insulator discs were replaced. A patrol between structures 140 and 200 checked for any additional damage.

02-OCT-2015: NPL 220kV bus (both West and East sections) and NPL-SFD 2 tripped for a three phase to earth fault caused by human error as earths left on NPL 220kV bus (West bus section) between DS247 and CB238. NPL 220kV differential bus zone operated correctly to trip CB238 and CB262. CB222 & CB102 were open.

Safety alert was issued after maintenance switcher failed to complete switching sequence correctly and left a set of earths on the 220kV bus, switcher was stood down until refresher training was completed

04-FEB-2016: NPL-SFD-2 RFS for safety clearance during work to replace SFD CB602's yellow phase pole which had a SF6 leak. A refurbished pole was installed and acceptance tested.


24-SEP-2015: OTA-WKM-1 RFS to replace insulators on all 3 phases at tower 482 due to flashover damage to blue phase insulator.

11-AUG-2015: PAK CB492 tripped incorrectly via 492LDIF2 during trip testing of PAK-PEN 3 from PEN. Project contractor made wiring error in PAK panel P16, during protection upgrade project in April 2012, as an intertrip was incorrectly wired to terminal block B137 whereas it should have been B139.

20-SEP-2015: PAK-WKM1 RFS due to lack of reactive capacity in upper North Island after MDN STC6 tripped

16-NOV-2015: TKU-WKM-2 delayed RTS, HEI ,TKU CB82 tripped on closing, TKU CVT isolation switch left in isolate position

Maintenance switcher failed to follow switching sequence, discussed at the next tool box meeting of the requirement to check and follow procedures

27-JAN-2016: TMN-TWH-1 trip &A/R, lightning, TMN T8 tripped also LOS at TMN, no load27-JAN-2016: TMN-TWH-1 trip &A/R, lightning, TMN T8 tripped also, LOS at TMN, no load

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



16-AUG-2015: COL-OTI-1 tripped, A/R @ COL, patrolled COL to structure 40, no fault found




253

12-MAY-2016: COL-OTI1 trip, A/R, trip LOS CLH& APS, circuit not patrolled SS16048

254 COL-OTI-2 I CCT 66 2.75 0 0 0 0 0 10 0 Y/N Planned Outage /255 DOB-GYM-1 I CCT 66 3.19 0 0 0 0 0 0 0 Y/N Planned Outage /256 GYM-KUM-1 I CCT 66 2.21 .1 0 0 1 16.65 0 0 Y/Y Planned Outage /

257SS15089

258 24-NOV-2015: GYM-KUM1 tripped, LOS to HKK & KUM SS15107

259

HKK-KUM-1 B CCT 66 0 .34 0 0 0 0 0 0 N/Y 09-JUL-2015: HKK-KUM1 RFS to top up SF6 in Westpower owned HKK CB262 SS15079

260SS15107

261 HKK-OTI-2 B CCT 66 1.48 .08 0 0 0 0 0 0 Y/N Planned Outage /262 ISL-SBK-1 I CCT 66 1.42 .07 0 0 0 0 0 0 Y/N Planned Outage /263 ISL-SBK-2 I CCT 66 3.17 .07 0 0 0 0 0 0 Y/N Planned Outage /264 KUM-OTI-1 I CCT 66 1.5 .08 0 0 0 0 0 0 Y/N Planned Outage /265 SBK-WPR-1 I CCT 66 .62 .04 0 0 0 0 1 0 N/N Planned Outage /266

267


268

Shunt CAP_HV .81 1.33 0 0 .02 .03 None Apply None Apply

269 ALB-CAPS-C1 I Shunt CAP_HV .1 .09 0 0 0 0 0 0 N/N Planned Outage /270 ALB-CAPS-C2 I Shunt CAP_HV 1.77 0 0 0 0 0 0 0 Y/N Planned Outage /271 BOB-CAPS-C11 I Shunt CAP_HV .17 0 0 0 0 0 0 0 N/N Planned Outage /272 HEN-CAPS-C1 I Shunt CAP_HV 75.06 0 0 0 0 0 0 0 Y/N Planned Outage /273 HEP-CAPS-C11 I Shunt CAP_HV .32 0 0 0 0 0 0 0 N/N Planned Outage /274 HEP-CAPS-C12 I Shunt CAP_HV .32 0 0 0 0 0 0 0 N/N Planned Outage /275 HEP-CAPS-C13 I Shunt CAP_HV .24 0 0 0 0 0 0 0 N/N Planned Outage /276 ISL-CAPS-C14 I Shunt CAP_HV .43 0 0 0 0 0 0 0 N/N Planned Outage /277 ISL-CAPS-C15 I Shunt CAP_HV 0 0 0 0 0 0 0 0 N/N278 ISL-CAPS-C16 I Shunt CAP_HV 0 0 0 0 0 0 0 0 N/N279 ISL-CAPS-C21 I Shunt CAP_HV 1.34 0 0 0 0 0 0 0 Y/N Planned Outage /280 ISL-CAPS-C22 I Shunt CAP_HV .46 0 0 0 0 0 0 0 N/N Planned Outage /281 ISL-CAPS-C25 I Shunt CAP_HV 0 .39 0 0 0 0 0 0 N/N282 ISL-CAPS-C26 I Shunt CAP_HV .82 .94 0 0 0 0 0 0 Y/N Planned Outage /283 ISL-CAPS-C27 I Shunt CAP_HV 0 0 0 0 0 0 0 0 N/N284 MTM-CAPS-C1 I Shunt CAP_HV .51 .18 0 0 0 0 0 0 N/N Planned Outage /285 NMA-CAPS-C1 I Shunt CAP_HV .39 .82 0 0 0 0 0 0 N/N Planned Outage /286 NMA-CAPS-C3 I Shunt CAP_HV .01 0 0 0 0 0 0 0 N/N Planned Outage /287 OTA-CAPS-C11 I Shunt CAP_HV .2 0 0 0 0 0 0 0 N/N Planned Outage /288 OTA-CAPS-C12 I Shunt CAP_HV .2 0 0 0 0 0 0 0 N/N Planned Outage /289 OTA-CAPS-C29 I Shunt CAP_HV .22 0 0 0 0 0 0 0 N/N Planned Outage /290 OTA-CAPS-C30 I Shunt CAP_HV 0 0 0 0 0 0 0 0 N/N291 OTA-CAPS-C31 I Shunt CAP_HV .08 0 0 0 0 0 0 0 N/N Planned Outage /

292

PEN-CAPS-C1 I Shunt CAP_HV .23 49.03 0 0 0 0 0 0 N/Y 23-NOV-2015: PEN C1 RFS to top up SF6 in CB732 SN15245

293 30-NOV-2015: PEN-C1 RFS to top up SF6 in CB-732 SN15251

294SN15252

295 PEN-CAPS-C11 I Shunt CAP_HV .08 0 0 0 0 0 0 0 N/N Planned Outage /296 PEN-CAPS-C12 I Shunt CAP_HV .14 0 0 0 0 0 0 0 N/N Planned Outage /297 PEN-CAPS-C13 I Shunt CAP_HV .35 0 0 0 0 0 0 0 N/N Planned Outage /298 PEN-CAPS-C14 I Shunt CAP_HV .35 0 0 0 0 0 0 0 N/N Planned Outage /299 SBK-CAPS-C11 I Shunt CAP_HV 3.06 0 0 0 0 0 0 0 Y/N Planned Outage /300 TGA-CAPS-C11 I Shunt CAP_HV 1.23 0 0 0 0 0 0 0 Y/N Planned Outage /301

302


303

Shunt CAP_LV .81 1.33 0 0 .02 .03 None Apply None Apply

304 BAL-CAP-C1 I Shunt CAP_LV .03 0 0 0 0 0 0 0 N/N Planned Outage /305 BAL-CAP-C2 I Shunt CAP_LV .02 0 0 0 0 0 0 0 N/N Planned Outage /306 BAL-CAPS-C1 I Shunt CAP_LV .07 0 0 0 0 0 0 0 N/N Planned Outage /307 BAL-CAPS-C2 I Shunt CAP_LV .05 .03 0 0 0 0 0 0 N/N Planned Outage /308 BLN-CAPS-C1 I Shunt CAP_LV .08 0 0 0 0 0 0 0 N/N Planned Outage /309 BLN-CAPS-C2 I Shunt CAP_LV .05 0 0 0 0 0 0 0 N/N Planned Outage /310 BLN-CAPS-C3 I Shunt CAP_LV .06 0 0 0 0 0 0 0 N/N Planned Outage /311 BLN-CAPS-C4 I Shunt CAP_LV .02 5.53 0 0 0 0 0 0 N/Y 11-NOV-2015: BLN-C-4 RFS due to blown and leaking capacitor can SS15100

31201-APR-2016: BLN-CAPS-C4 RFS to replace leaking can SS16033

313 BRY-CAPS-C5A I Shunt CAP_LV .96 0 0 0 0 0 0 0 Y/N Planned Outage /314 BRY-CAPS-C6A I Shunt CAP_LV .06 .08 0 0 0 0 0 0 N/N Planned Outage /315 GYM-CAPS-C1 I Shunt CAP_LV 17.6 0 0 0 0 0 0 0 Y/N Planned Outage /316 GYM-CAPS-C2 I Shunt CAP_LV .11 0 0 0 0 0 0 0 N/N Planned Outage /317 GYM-CAPS-C3 I Shunt CAP_LV .11 97.35 0 0 0 0 0 0 N/Y 01-JUL-2015: C3 could not be RTS due to faulty LB3 - open/close solenoid faulty SS15032318 HKK-CAPS-C7 I Shunt CAP_LV .06 .02 0 0 0 0 0 0 N/N Planned Outage /319 HKK-CAPS-C8 I Shunt CAP_LV .06 .02 0 0 0 0 0 0 N/N Planned Outage /320 HKK-CAPS-C9 I Shunt CAP_LV .06 .02 0 0 0 0 0 0 N/N Planned Outage /


27-AUG-2015: GYM-KUM-1 tripped, broken insulator at pole 172. Note GYM-KUM1 is owned by Westpower and leased by Transpower


24-NOV-2015: HKK-KUM1 RFS following tripping of GYM-KUM1 and falling 66kV at HKK

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?




02-DEC-2015: PEN-CB-732 low SF6, C1 RFS, rapid gas leak, yellow phase pole remove from site, repaired by PBA and reinstalled at PEN

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



Capacitor cans were replaced. Thermography inspections of all capacitor banks nation wide were undertaken.



321 KTA-CAPS-C1 I Shunt CAP_LV .03 0 0 0 0 0 0 0 N/N Planned Outage /322 ONG-CAPS-C1 I Shunt CAP_LV .12 .11 0 0 0 0 0 0 N/N Planned Outage /323 OTA-CAPS-C4A I Shunt CAP_LV 0 0 0 0 0 0 0 0 N/N324 OTA-CAPS-C4B I Shunt CAP_LV 0 0 0 0 0 0 0 0 N/N325 STK-CAPS-C31 I Shunt CAP_LV .07 0 0 0 0 0 0 0 N/N Planned Outage /326 STK-CAPS-C32 I Shunt CAP_LV .25 .31 0 0 0 0 0 0 N/N Planned Outage /327 STK-CAPS-C33 I Shunt CAP_LV .2 .27 0 0 0 0 0 0 N/N Planned Outage /328 STK-CAPS-C34 I Shunt CAP_LV 0 0 0 0 0 0 0 0 N/N329 STK-CAPS-C7A I Shunt CAP_LV .14 0 0 0 0 0 0 0 N/N Planned Outage /330 STK-CAPS-C7B I Shunt CAP_LV .1 0 0 0 0 0 0 0 N/N Planned Outage /331 STK-CAPS-C7C I Shunt CAP_LV .2 0 0 0 0 0 0 0 N/N Planned Outage /332 STK-CAPS-C7D I Shunt CAP_LV .03 0 0 0 0 0 0 0 N/N Planned Outage /333

334


335

Shunt Filter 1.03 1.71 0 0 0 0 None Apply None Apply

336 BEN-FLT-3 I Shunt Filter 1.26 0.00 0 0 0 0 0 0 Y/N Planned Outage /337 BEN-FLT-4 I Shunt Filter 1.22 0.00 0 0 0 0 0 0 Y/N Planned Outage /338 BEN-FLT-5 I Shunt Filter 0.99 0.00 0 0 0 0 0 0 N/N339 BEN-FLT-6 I Shunt Filter 0.64 0.00 0 0 0 0 0 0 N/N340 BEN-FLT-7 I Shunt Filter 0.64 0.00 0 0 0 0 0 0 N/N341 HAY-FLT-3A I Shunt Filter 1.75 0.02 0 0 0 0 0 0 Y/N Planned Outage /342 HAY-FLT-3B I Shunt Filter 1.75 0.05 0 0 0 0 0 0 Y/N Planned Outage /

343 HAY-FLT-4A I Shunt Filter 1.22 0.07 0 0 0 0 0 0 Y/N Planned Outage /

344 HAY-FLT-4B I Shunt Filter 1.22 0.03 0 0 0 0 0 0 Y/N Planned Outage /345 HAY-FLT-5A I Shunt Filter 0.92 0.00 0 0 0 0 0 0 N/N346 HAY-FLT-5B I Shunt Filter 0.92 0.00 0 0 0 0 0 0 N/N347 HAY-FLT-6A I Shunt Filter 0.93 0.00 0 0 0 0 0 0 N/N348 HAY-FLT-7 I Shunt Filter 1.01 0.00 0 0 0 0 0 0 N/N349 HAY-FLT-8 I Shunt Filter 0.89 0.00 0 0 0 0 0 0 N/N350

351


352

Shunt REA 1.33 .31 0 0 0 0 None Apply None Apply

353 HAY-REA-R1 I Shunt REA .62 0 0 0 0 0 0 0 N/N Planned Outage /354 HAY-REA-R5 I Shunt REA .37 0 0 0 0 0 0 0 N/N Planned Outage /355 HWA-REA-R72 I Shunt REA 0 0 0 0 0 0 0 0 N/N356 PEN-REA-862 I Shunt REA 0 0 0 0 0 0 0 0 N/N357 STK-REA-R7A I Shunt REA .03 0 0 0 0 0 0 0 N/N Planned Outage /358 STK-REA-R7B I Shunt REA .03 0 0 0 0 0 0 0 N/N Planned Outage /359 WRD-REA-R182 I Shunt REA 0 0 0 0 0 0 0 0 N/N360

361


362

Shunt SCM 2.11 1.00 0 0 0 0 None Apply None Apply

363 HAY-SC1 I Shunt SCM 5.42 11.78 0 0 0 0 0 0 Y/Y Planned Outage /364 22-JUL-2015: Hay SC1 tripped while tech was working on oil level circuits

365366 HAY-SC2 I Shunt SCM 4.82 0.86 0 0 0 0 0 0 Y/N Planned Outage /367 HAY-SC3 I Shunt SCM 2.50 0.01 0 0 0 0 0 0 Y/N Planned Outage /368 HAY-SC4 I Shunt SCM 2.37 0.01 0 0 0 0 0 0 Y/N Planned Outage /369 HAY-SC7 I Shunt SCM 2.50 0.00 0 0 0 0 0 0 Y/N Planned Outage /370 HAY-SC8 I Shunt SCM 2.49 0.00 0 0 0 0 0 0 Y/N Planned Outage /371 HAY-SC9 I Shunt SCM 2.62 0.01 0 0 0 0 0 0 Y/N Planned Outage /372 HAY-SC10 I Shunt SCM 5.58 0.00 0 0 0 0 0 0 Y/N Planned Outage /373

374


375

Shunt SVC .82 .04 0 0 0 0 None Apply None Apply

376 ALB-SVC-7 I Shunt SVC 2.28 .03 0 0 0 0 0 0 Y/N Planned Outage /377 ISL-SVC-3 I Shunt SVC .32 1.16 0 0 0 0 0 0 N/Y 24-JUL-2015: ISL-SVC-3 RFS for major repair of water leak SS15081

378ISL-SVC-9 I Shunt SVC .49 37.64 0 0 0 0 0 0 N/Y SS15083

379 05-DEC-2015: ISL-SVC-9 tripped, controller hardware fault SS15112380 29-DEC-2015: ISL-SVC-9 tripped, suspect capacitor failure (see SFIR SS15125) Capacitor can replaced SS15124381 31-DEC-2015: ISL-SVC-9 RFS to restore capacitor Capacitor can replaced SS15125382 24-JAN-2016: ISL-SVC-9 tripped, 400V surge caused a fan failure. SS16011383 15-FEB-2016: ISL-SVC-9 tripped, failed capacitor can, oil on fire Half of TSC capacitor bank burned down. Investigation init SS16018384 KIK-STC-2 I Shunt SVC 1.18 2.3 0 0 0 0 0 0 Y/Y Planned Outage /

385SS15098

386 02-JAN-2016: KIK-STC2B tripped, air conditioning fault. SS16001

387

SS16012

388 15-FEB-2016: KIK STC2B tripped due to air conditioning fault. SS16017

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



08-MAR-2016: HAY-SC1 forced outage due to excessive arcing at brushes. Delayed RTS because of waiting for parts.

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



30-JUL-2015: ISL-SVC-9 tripped when trying to reset alarm, HEI, opened fuse isolator and phase fail operation cause SVC9 to trip

29-OCT-2015: KIK-STC-2 delayed RTS from planned maintenance Event 87356, SCADA indication inverted.

18-JAN-2016: KIK-STC-2A,STC-2B failed to start after T2 outage (see Event 88485). STC-2B RTS at 1356 on 18/1/16 but delayed RTS of STC-2A. Control module failure. Post capacity reduced to +-40 because STC-2B RTS.



389 18-MAR-2016: KIK-STC-2B tripped, air-conditioning fault SS16027390 20-MAR-2016: KIK-STC-2B tripped, aircon fault SS16028

391SS16029

392

SS16035

393

SS16044

394SS16067

395 22-JUN-2016: KIK-STC2 tripped, both battery chargers failed Battery chargers replaced. Still investigating root cause. SS16068396 MDN-STC-5 I Shunt SVC 1.12 .02 0 0 0 0 0 0 Y/N Planned Outage /397 MDN-STC-6 I Shunt SVC 11.83 .1 0 0 0 0 0 0 Y/Y Planned Outage /

398

SN15192

399

SN16048

400

SN16059

401 PEN-STC-1 I Shunt SVC 7.88 3.8 0 0 0 0 0 0 Y/Y Planned Outage /

402SN15242

403

SN16046

404 HAY-STC-31 I Shunt SVC 1.18 0 0 0 0 0 0 0 Y/N Planned Outage /405

406


407

TF 110/066 2.25 .02 0 0 0 0 None Apply None Apply

408 DOB-TF-T11 I TF 110/066 3.09 0 0 0 0 0 2 0 Y/N Planned Outage /409 DOB-TF-T12 I TF 110/066 1.61 0 0 0 0 0 0 0 N/N Planned Outage /410

411


412

TF 220/066 .66 .02 0 0 0 0 None Apply None Apply

413 ISL-TF-T3 I TF 220/066 0 0 0 0 0 0 0 0 N/N414 ISL-TF-T6 I TF 220/066 .74 .44 0 0 0 0 0 0 Y/Y Planned Outage /

415

SS16042

416

SS16063

417 ISL-TF-T7 I TF 220/066 1.46 0 0 0 0 0 0 0 Y/N Planned Outage /

418WPR-TF-T12 I TF 220/066 .26 .05 0 0 0 0 0 0 N/Y SS15085

419SS15119

420 WPR-TF-T13 I TF 220/066 1.28 0 0 0 0 0 0 0 Y/N Planned Outage /421

422


423

TF 220/110 1.56 .06 .03 .1 .02 .72 None Apply None Apply

424 ALB-TF-T4 I TF 220/110 .67 .01 0 0 0 0 0 0 N/N Planned Outage /425 BPE-TF-T1 I TF 220/110 .11 0 0 0 0 0 0 0 N/N Planned Outage /426 BPE-TF-T2 I TF 220/110 .04 0 0 0 0 0 0 0 N/N Planned Outage /427 BPE-TF-T3 I TF 220/110 0 .01 0 0 0 0 0 0 N/N428 CML-TF-T5A I TF 220/110 1.34 0 0 0 0 0 0 0 N/N Planned Outage /429 CML-TF-T8 I TF 220/110 1.8 .01 0 0 1 2.82 0 0 Y/Y Planned Outage /

430

SS15108

431 EDG-TF-T4 I TF 220/110 .34 0 0 0 0 0 0 0 N/N Planned Outage /432 EDG-TF-T5 I TF 220/110 .58 0 0 0 0 0 0 0 N/N Planned Outage /

433

HAM-TF-T6 I TF 220/110 .38 .08 0 0 0 0 0 0 N/Y SN15153

434 HAM-TF-T9 I TF 220/110 .32 0 0 0 0 0 0 0 N/N Planned Outage /435 HAY-TF-T1 I TF 220/110 .59 0 0 0 0 0 0 0 N/N Planned Outage /436 HAY-TF-T2 I TF 220/110 .51 0 0 0 0 0 0 0 N/N Planned Outage /437 HAY-TF-T5 I TF 220/110 .33 0 0 0 0 0 0 0 N/N Planned Outage /

21-MAR-2016: KIK-STC-2B tripped, control board microchip failed in air conditioning unit04-APR-2016: KIK-STC-2A tripped followed by KIK-STC-2B. The reason STC2B tripped was due to design issue limitation such that when one unit’s controls are turned off (namely STC2A’s controls in this case) it will trip the other unit (namely STC2B in this case) on its return.

06-MAY-2016: KIK-STC-2B tripped, HEI, contractor did not follow plan and isolated wrong signal such that SCT2B thought it had lost both air conditioners and thus tripped.

Entire air conditioning system has been replaced at Kikiwa STC

21-JUN-2016: KIK-STC-2 tripped while work on aircon, HEI - technician shorted a live DC wire to earth which caused the STC to trip,

20-SEP-2015: MDN-STC-6 tripped via its SVC6 Plus Controller when an infra-red (IR) sensor (camera) detected overheating. No cause for overheating was found. Sensor was reset after 3 hours and STC6 was returned to service. PAK - WKM 1 RFS due to lack of reactive capacity in upper NI.

05-MAR-2016: MDN-STC-6 tripped via SVC Plus Controller for an intermittent TDC control rack fault. The TDC rack was found with 2 hardware alarms flashing on main boards and 2 trip lockout relays operated. Rebooted TDC rack using a specific power up sequence, it came back online, SVC trips reset, SVC RTS.

18-MAR-2016: MDN-STC-6 tripped, momentary interruption on CPU computer unit to cooling system. Pump 2 stopped working for 2 milliseconds. No fault found with cooling system.

22-NOV-2015: PEN STC1 tripped via T1's differential protection for a flashover to PEN 33kV DS1606 insulators probably caused by a lightning strike.28-FEB-2016: PEN-STC-1A tripped for a container air conditioning fault assume via the SVC plus controller. Service provider on site testing when aircon alarm reset and started to work again.

Defect raised with the manufacturer for the air conditioning unit and a motor was replaced to prevent this fault occurring again.

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



05-MAY-2016: ISL-TF-T6 tripped, water in tertiary (11kV) off load tap changer control box - corrosion around micro-switch caused DC earth fault and shorted trip circuit

Consideration is being made into inspections of control boxes on transformers due to spurious trippings. The benefit of checking vs the potential broken seals needs to be considered.

08-JUN-2016: ISL-DS-253 caught on fire after closing, repairs required, ISL-TF-T6 RFS

The DS contacts were replaced. New arcing horns fitted. This DS experiences high loop current when switching. The performance of this DS is being closely monitored.

15-AUG-2015: KIK-BS-220kV bus B fault trip, no cause found, WPR T12 RFS after tripping16-DEC-2015: WPR T12 delayed RTS CB172 fail to close - SCADA issue, closed locally at panel

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



24-NOV-2015: CML-TF-T8 tripped for CB1052 high impedance feeder fault, feeder protection did not operate so T8 protection operated in back up mode, LOS

Asset feedback register item added for consideration of more discriminative protection and co-ordination with distribution companies. Have advised and are working with the distribution company DELTA to improve future performance

10-JUL-2015: HAM T6 RFS to replace a faulty GE type Multilin SR760 relay on CB482 (T6's 220kVbreaker).

Service advisory and plan to deal with generic relay power supply problem has been developed and is in progress.



438

HEN-TF-T1 I TF 220/110 1.06 .1 0 0 0 0 0 0 N/Y SN15260

439

SN16120

440 HEN-TF-T5 I TF 220/110 .81 .03 0 0 0 0 0 0 N/N Planned Outage /441 HWB-TF-T4 I TF 220/110 1.34 0 0 0 0 0 0 0 N/N Planned Outage /442 HWB-TF-T6 I TF 220/110 .71 0 0 0 0 0 0 0 N/N Planned Outage /443 INV-TF-T1 I TF 220/110 2.62 0 0 0 0 0 0 0 Y/N Planned Outage /444 KAW-TF-T12 I TF 220/110 .39 0 0 0 0 0 0 0 N/N Planned Outage /445 KAW-TF-T13 I TF 220/110 .26 0 0 0 0 0 0 0 N/N Planned Outage /446 KIK-TF-T1 I TF 220/110 4.05 .04 2 6.6 0 0 0 0 Y/N Planned Outage /447 KIK-TF-T2 I TF 220/110 1.13 0 0 0 0 0 0 0 N/N Planned Outage /448 KMO-TF-T2 I TF 220/110 0 0 0 0 0 0 0 0 N/N449 KMO-TF-T4 I TF 220/110 .1 0 0 0 0 0 0 0 N/N Planned Outage /

450

MDN-TF-T5 I TF 220/110 .12 .11 0 0 0 0 0 0 N/Y SN16087

451 MDN-TF-T6 I TF 220/110 11.2 0 0 0 0 0 0 0 Y/N Planned Outage /452 NPL-TF-T8 I TF 220/110 .53 .06 0 0 0 0 0 0 N/N Planned Outage /453 OTA-TF-T2 I TF 220/110 3.45 .01 0 0 0 0 0 0 Y/N Planned Outage /454 OTA-TF-T3 I TF 220/110 4.92 0 0 0 0 0 0 0 Y/N Planned Outage /455 OTA-TF-T4 I TF 220/110 2.72 .47 0 0 0 0 0 0 Y/Y Planned Outage /

456

SN15205

457SN15237

458 OTA-TF-T5 I TF 220/110 0 0 0 0 0 0 0 0 N/N459 PEN-TF-T10 I TF 220/110 10.55 0 0 0 0 0 0 0 Y/N Planned Outage /460 PEN-TF-T6 I TF 220/110 13.4 0 0 0 0 0 0 0 Y/N Planned Outage /461 RDF-TF-T3 I TF 220/110 1.32 0 0 0 0 0 0 0 N/N Planned Outage /462 RDF-TF-T4 I TF 220/110 .65 0 0 0 0 0 0 0 N/N Planned Outage /463 ROX-TF-T10 I TF 220/110 .69 0 0 0 0 0 0 0 N/N Planned Outage /464 SFD-TF-T10 I TF 220/110 .08 0 0 0 0 0 0 0 N/N Planned Outage /465 STK-TF-T7 I TF 220/110 .92 0 0 0 0 0 0 0 N/N Planned Outage /466 TIM-TF-T5 I TF 220/110 2.06 0 0 0 0 0 0 0 Y/N Planned Outage /467 TIM-TF-T8 I TF 220/110 2.04 0 0 0 0 0 0 0 Y/N Planned Outage /468 TRK-TF-T1 I TF 220/110 .11 0 0 0 0 0 0 0 N/N Planned Outage /469 TRK-TF-T2 I TF 220/110 .68 0 0 0 0 0 0 0 N/N Planned Outage /470 TRK-TF-T3 I TF 220/110 .11 0 0 0 0 0 0 0 N/N Planned Outage /471 WIL-TF-T8 I TF 220/110 1.29 .04 0 0 0 0 0 0 N/N Planned Outage /472 WTK-TF-T23 I TF 220/110 2.56 0 0 0 0 0 0 0 Y/N Planned Outage /473 WTK-TF-T24 I TF 220/110 2.54 .04 1 0 0 0 0 0 Y/N Planned Outage /474

475


476

HVDC HVDC 1.27 0.51 0 0 0.2 0.85 None apply

477 HVDC Bipole HVDC HVDC 1.04 0.06 0 0 0 0 31 0 N/N478

479

480

11-DEC-2015: HEN-T1 delayed RTS after scheduled work, NCC could not tap T1, red phase did not follow yellow and blue phase, run through taps successfully and RTS

03-JUN-2016: HEN-TF-T1 RFS to replace a faulty GE type Multilin SR760 on T1's 110kV CB432. No interruption of supply.

Service advisory and plan to deal with generic relay power supply problem has been developed and is in progress.

12-MAY-2016: MDN-TF-T5 RFS to repair hot spot on 110kV red phase bushing. Contact resistance of red phase bushing spigot to clamp connection was 180 micro ohm so this connection was cleaned, polished and coated with contact paste. Re-tested bushing spigot to clamp connection at 0.1 micro ohm..

30-SEP-2015: OTA-TF-T4 RFS to investigate Buchholz alarm, low oil level in Blue phase, blue phase topped up with 900 litres of oil and yellow phase topped up with 200 litres of oil.

All three phases have been raised as an issue in the asset feedback register to complete further investigation and oil leak repairs.

20-NOV-2015: OTA-T4 delayed RTS, no tap via SCADA, operating error, not aware could not tap via SCADA

Asset Category





MWh

Number Unplanned

Interruptions

Unplanned Unserved

Energy MWh


Min


min

Measures Exceeded

(plan/Unplan) ?



None apply

(1) Transpower’s asset management systems include plans and processes to maintain performance of all our assets, and to minimise the impact of events on customers and end-consumers. Events mentioned in this report will have been dealt with according to these plans and processes whether or not a specific response is given here.


Tab name: G6. Asset Health and Age 05/09/2023


SCHEDULE G6: ASSET HEALTH AND AGE Disclosure Year (year e ###

ref

5 G6(i): Asset Health

6 Asset Age Asset Health/Remaining Expected Life Asset Replacement/Refurbishment/Development/Enhancement of Existing Assets Asset Additions

Some rows below have been added by Transpower to complete the data set. Those rows have been coloured green. Actual Forecast from Expenditure Proposal for Reset Period Actual Forecast from Expenditure Proposal for Reset Period

8Category Asset Category Voltage Asset Class 1 Asset Class 2 Units Notes on Units of measure

Asset health accuracy Due now 0-2 years 2-7 years CY-2 CY-1 CY CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY-2 CY-1 CY CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6

9 HVDC HVDC Power Transformers HVDC Converter No of Transformer banks 4 2 2 - - - - - -

10 HV Outdoor Circuit Breakers HVDC No. of breakers 37 23 5 6 3 - - - - - - 11 Thyristor Valves and Control HVDC No. of quadrivalves (valve stacks) 12 6 6 - - - - - -

12

HVDC Capacitors Banks / Filter Banks 184 106 74 4 - - - - - -

13 HVDC Reactors No. of standalone reactors 115 53 14 48 - - - - - - 14 HVDC Disconnectors No. of disconnectors 41 17 3 2 18 1 - - - - - - 15 HVDC Earthswitches No. of earthswitches 75 33 6 2 33 1 - - - - - -

16

No. of transformers 324 179 6 91 48 - - - - - -

17

No. of transformers 66 38 3 19 6 - - - - - -

18

Kilometres of cable 3x38km - - - - - -

19 Cable Fibre Optic Submarine Kilometres of cable 3x38km - - - - - - 20 AC Stations Power Transformers 220 Interconnector Single Phase No. of transformer banks Primary voltage 220 kV 21 1 1 10 9 8 1 2 - 10 - - - - - - 21 Three Phase No. of transformers 34 8 7 4 2 10 3 - - - - 34 - - - - 2 - 1 22 Supply Single Phase No. of transformer banks 14 1 8 5 3 - - 3 8 - - - - - - 23 Three Phase No. of transformers 68 9 12 5 7 9 16 10 2 - 2 2 62 1 1 2 - 2 3 24 110 Interconnector Single Phase No. of transformer banks Primary voltage 110 kV 1 1 - - - 1 - - - - - - - 25 Three Phase No. of transformers 1 1 - - - - 1 - - - - - - 26 Supply Single Phase No. of transformer banks 62 24 38 11 3 11 11 26 - - - - - - 27 Three Phase No. of transformers 94 16 16 18 11 9 13 11 - - - 2 92 - 1 6 7 1 1 28 66 & 50 Supply Single Phase No. of transformer banks 2 2 2 - - - - - - - - - - 29 Three Phase No. of transformers 16 3 3 3 1 5 1 - - - - 16 - - - - - - 30 Various Other (33 & below, Earthing, Local Service) No. of transformers 306 53 47 26 22 33 64 33 28 - 1 - - 9 3 - - - - -

31

AC Stations Switchyards Various No. of switchyards 333 - - - - - -

32 AC Stations Outdoor Circuit Breakers 220 SF6 SF6 No. of 3 phase sets 504 57 137 83 60 110 57 3 6 33 105 356 3 - 2 1 - 6

33 110 Bulk Oil No. of 3 phase sets 36 35 1 1 35 - - - - - - - - - Minimum Oil No. of 3 phase sets 9 9 9 - - - -

35 SF6 No. of 3 phase sets 468 57 93 94 94 118 12 18 13 6 59 369 30 15 23 12 11 15 36 66 & 50 Bulk Oil No. of 3 phase sets 25 25 - 25 - - - - - - - - - 37 Minimium Oil No. of 3 phase sets 3 1 2 3 - - - - - - - - - - 38 SF6 No. of 3 phase sets 83 15 8 15 15 22 8 7 2 8 5 61 1 - 7 19 3 5 39 Vacuum No. of 3 phase sets - - - - - - - - - - - - 40 33,22,11 Vacuum No. of 3 phase sets 29 1 4 13 2 3 4 2 - - - - 8 49 9 1 8 1 3 41 Bulk Oil No. of 3 phase sets 195 1 50 107 37 24 171 - - - - - - - - - 42 Minimum Oil No. of 3 phase sets 3 2 1 3 - - - - - - - - - - 43 SF6 No. of 3 phase sets 111 14 38 18 14 25 2 1 - 3 9 92 - - - - - - 44 AC Stations Indoor Switchgear 220 SF6 No. of 3 phase sets 64 12 12 8 32 15 2 9 14 24 - - - - - -

45 110 SF6 No. of 3 phase sets 9 9 - 9 - - - - - - - - - 46 33,22,11 Bulk Oil No. of 3 phase sets 86 2 26 57 1 10 74 - - - - - - - - - 47 Minimum Oil No. of 3 phase sets 9 9 9 - - - - - - - - - - 48 SF6 No. of 3 phase sets 156 4 21 28 70 23 9 1 2 5 19 9 105 - - - - - - 49 Vacuum No. of 3 phase sets 629 305 110 142 70 2 34 - - - 613 89 23 20 1 25 34 50 Various Other (Airblast/Airbreak) No. of 3 phase sets 12 12 - - 12 - - - - - - - - 51 AC Stations Reactive Power 220 Reactors

15 2 7 2 3 1

- - - - - -

52 110 Reactors No. 3 phase sets of standalone reactors 13 5 5 3 - - - - - - 53 66 Reactors No. 3 phase sets of standalone reactors - - - - - - - 54 <66 Reactors No. 3 phase sets of standalone reactors 100 24 14 11 16 18 3 2 10 2 - - - - - -

unknown 6 2 1 3 56 Capacitors - - - - - - 57 AC Stations Reactive Power 220 Capacitor Banks / Filter Banks 18 9 2 1 6 - - - 1 - -

58 110 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks 13 9 1 3 - 1 - - - - 59 66 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks 4 1 3 - - - - 1 - 60 < 66 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks 66 25 12 7 10 7 4 1 - - - - - 1 61 AC and DC Stations Reactive Power Synchronous Condensers 8 8 - - - - - -

62 STATCOMs No. of Statcoms 7 7 - - - - - -

63 Static Var Compensators ( SVC) No. of SVCs 4 1 1 2 - - - - - -

64 AC Stations 220 CT 555 99 110 83 41 82 90 50 100 1 36 42 350 17 24 27 27 20 4

65

VT 8 2 4 2 - - - - 3 - - - - - -

66

CVT 292 48 39 49 75 31 21 28 1 67 8 1 3 191 12 13 7 8 11 2

67

110 CT 451 36 79 104 78 102 33 17 2 51 9 18 18 333 2 - 2 1 1 8

68

VT 173 16 27 47 31 25 26 1 35 2 12 4 116 7 1 2 1 4 -

69

CVT 35 4 6 2 6 17 7 1 7 7 12 - - - - - -

70

66 & 50 CT 78 14 4 10 7 27 10 6 11 - 1 7 57 - - - - - -

71

VT 41 7 9 6 3 2 14 6 1 1 8 22 2 2 - - - -

72

33 & below CT 211 11 53 20 64 15 6 27 3 12 25 - - - 43 - - - - - -

73

VT 240 51 20 51 35 26 19 20 2 16 24 4 5 2 50 6 2 3 - - -

74 AC Stations Disconnectors (standalone) 220 No. of 3 phase sets 1,535 182 178 81 77 249 310 376 45 37 - 4 3 - 7 14

75 110 No. of 3 phase sets 1,165 21 123 141 94 68 138 242 214 124 1 32 24 8 29 25 76 66 & 50 No. of 3 phase sets 238 11 11 35 10 24 37 55 41 14 - - 14 2 11 - 77 33,22,11 No. of 3 phase sets 1,015 115 90 58 24 44 143 336 117 88 - - - - - -

unknown No. of 3 phase sets 2 1 1 79 AC Stations Earth Switches (standalone) 220 No. of 3 phase sets 752 174 164 27 8 75 130 60 1 113 - - - - - -

80 110 No. of 3 phase sets 362 23 85 48 18 15 36 16 4 117 - - - - - - 81 66 & 50 No. of 3 phase sets 63 12 6 11 1 7 2 4 20 - - - - - - 82 33,22,11 No. of 3 phase sets 489 72 74 38 62 29 55 13 146 2 - - - - -

unknown No. of 3 phase sets 73 53 13 1 3 1 1 1 84 AC Stations Power Cables greater than 1 km 220 Paper Insulated (oil filled) Metres of cable (circuit length) - - - - - - - 85 XLPE Metres of cable (circuit length) 62 36 26 - - - - - - 86 110 Paper Insulated (oil filled) Metres of cable (circuit length) - - - - - - - 87 XLPE Metres of cable (circuit length) 15 15 - - - - - - 88 66 & 50 XLPE Metres of cable (circuit length) - - - - - - - 89 AC Stations Power Cables 1 km or less 220 Paper Insulated (oil filled) No of circuits 25 24 1 - - - - - - 90 XLPE No of circuits 210 191 11 4 4 - - - - - - 91 110 Paper Insulated (oil filled) No of circuits 3 2 1 - - - - - - 92 XLPE No of circuits 64 25 3 1 8 19 8 - - - - - - 93 66 & 50 XLPE No of circuits 28 9 6 6 7 - - - - - - 94 33,22,11 Paper Insulated No of circuits 64 8 16 14 26 - - - - - - 95 XLPE No of circuits 1,075 166 277 203 66 25 3 335 19 - - - - - 96 Secondary Systems Revenue Metering No. of meters 454 179 192 1 15 67 - - - - - - 97 Secondary Systems Bus Protection Scheme 220/110/66/33 Bus Zone Protection Scheme (Incl CB fail) No. of protection schemes 2,810 466 578 415 273 414 459 82 123 10 5 5 6 6 5 98 Bus Coupler Protection Scheme No. of protection schemes 655 43 68 71 72 141 157 4 3 96 - - - - - - 99 Arc Flash Detection Scheme No. of protection schemes 13 11 2 - - - - - -

100 Secondary Systems Line Protection Scheme 220/110/66/33 No. of protection schemes 1,205 260 466 232 149 28 3 67 28 29 25 17 29 28 101 Secondary Systems Transformer Protection Scheme 220/110/66 No. of protection schemes 3,108 354 394 432 455 603 179 53 24 614 6 14 13 15 14 18

These are our Grid Refurbishment and Replacement jobs. The RCP2 expenditure proposal covers the period from 2015/16 to 2019/20 (CY to CY+4 below). The same applies to the additions, disposals and divestments columns.

These are our Grid Enhancement and Development (E&D) jobs. Our RCP2 expenditure proposal included allowances for several E&D projects, but costings were high-level and did not include numbers of assets.

Total Number of Assets

CY

1-5 years

6-10 years

11-15 years

16-20 years

21-30 years

31-40 years

41-50 years

50 + years

Unknown Age

7-12 years

12 + years

Converter Station/Cable Stations/Electrode Stations

SCOPE:HVDC equipment is not scheduled to be modelled at this stage. There are not enough individual assets for statistical analysis and model-based future predictions to be worthwhile and necessary.

No. of HVDC capacitors banks and filter banks

HVDC Standalone Current Transformers and Current Transducers

HVDC Voltage Transformers (CVTs and VTs) and Voltage Dividers

Cables HVDC submarine cables and terminations

ACCURACY:Modelling currently based on non-quantified data, and consequently has limited accuracy. This model will become more accurate with use of quantified data by June 2017.

SCOPE:Asset health model covers 220-33kV Supply and interconnecting transformers at this stage. "Various transformers" are not modelled due to lower criticallity and small populations.

SCOPE:Yards not modelled. These are not considered degradable assets and do not have a finite useful life.

There are situations where there are connections to only 2 phases but for the purpose of recording these will be counted as a three phase set

ACCURACY:Modelling currenly based on number of switching opperations and non-quantified data. Accuracy will improve with use of quantified data by August 2017.

For the Indoor switch gear the 3 phase sets includes the disconnectors , earthswitches, and integral instrument transformers. We have treated each panel as a 3-phase set.

ACCURACY:Modelling currenly based on number of switching opperations and non-quantified data. Accuracy will improve with use of quantified data by August 2017.

No.of 3 phase sets of standalone reactors

Theses are standalone power reactors that are not part of capacitor or filter banks, Statcoms or SVCs SCOPE:

Model design and implementation for reactors is scheduled to be completed by November 2017.

Excludes the Capacitor Banks and Filter banks which are part of the HVDC installations SCOPE:

Model design and implementation for capacitors is scheduled to be completed by November 2017

No of Synchronous Condensers including all associated equipment

This includes all associated equipment such as cooling, excitaion systems etc

SCOPE:There are not enough individual assets for statistical analysis and model-based future predictions to be worthwhile and necessary at this stage.

This includes all associated equipment such as transformers reactors, capacitors , cooling systems, controls etc


Instrument Transformers ( Standalone)

No. of 3 phase sets standalone transformers


ACCURACY:Modelling currenly based on non-quantified data. Accuracy will improve with use of quantified data by June 2017.











SCOPE:Model design and implementation for disconnectors and earth switches is scheduled to be completed by September 2017There are situations where there

are connections to only 2 phases but for the purpose of recording these will be counted as a three phase set

SCOPE:Model design and implementation for power cables is scheduled to be completed by November 2017.

SCOPE:Protection and metering assets do not have enough data for statistical analysis and model-based future predictions to be worthwhile and necessary.



Transpower

SCHEDULE G6: ASSET HEALTH AND AGE

ref

5 G6(i): Asset Health

6

Some rows below have been added by Transpower to complete the data set. Those rows have been coloured green.

8Category Asset Category Voltage Asset Class 1 Asset Class 2 Units Notes on Units of measure

9 HVDC HVDC Power Transformers HVDC Converter No of Transformer banks

10 HV Outdoor Circuit Breakers HVDC No. of breakers

11 Thyristor Valves and Control HVDC No. of quadrivalves (valve stacks)

12

HVDC Capacitors Banks / Filter Banks

13 HVDC Reactors No. of standalone reactors

14 HVDC Disconnectors No. of disconnectors

15 HVDC Earthswitches No. of earthswitches

16

No. of transformers

17

No. of transformers

18

Kilometres of cable

19 Cable Fibre Optic Submarine Kilometres of cable

20 AC Stations Power Transformers 220 Interconnector Single Phase No. of transformer banks Primary voltage 220 kV

21 Three Phase No. of transformers

22 Supply Single Phase No. of transformer banks


24 110 Interconnector Single Phase No. of transformer banks Primary voltage 110 kV


26 Supply Single Phase No. of transformer banks


28 66 & 50 Supply Single Phase No. of transformer banks

29 Three Phase No. of transformers30 Various Other (33 & below, Earthing, Local Service) No. of transformers

31

AC Stations Switchyards Various No. of switchyards

32 AC Stations Outdoor Circuit Breakers 220 SF6 SF6 No. of 3 phase sets

33 110 Bulk Oil No. of 3 phase sets Minimum Oil No. of 3 phase sets

35 SF6 No. of 3 phase sets

36 66 & 50 Bulk Oil No. of 3 phase sets

37 Minimium Oil No. of 3 phase sets


39 Vacuum No. of 3 phase sets

40 33,22,11 Vacuum No. of 3 phase sets

41 Bulk Oil No. of 3 phase sets

42 Minimum Oil No. of 3 phase sets

43 SF6 No. of 3 phase sets 44 AC Stations Indoor Switchgear 220 SF6 No. of 3 phase sets

45 110 SF6 No. of 3 phase sets

46 33,22,11 Bulk Oil No. of 3 phase sets

47 Minimum Oil No. of 3 phase sets


49 Vacuum No. of 3 phase sets

50 Various Other (Airblast/Airbreak) No. of 3 phase sets 51 AC Stations Reactive Power 220 Reactors

52 110 Reactors No. 3 phase sets of standalone reactors

53 66 Reactors No. 3 phase sets of standalone reactors

54 <66 Reactors No. 3 phase sets of standalone reactors unknown

56 Capacitors57 AC Stations Reactive Power 220 Capacitor Banks / Filter Banks

58 110 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks

59 66 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks

60 < 66 Capacitor Banks / Filter Banks No of Capacitor Banks and Filter Banks 61 AC and DC Stations Reactive Power Synchronous Condensers

62 STATCOMs No. of Statcoms

63 Static Var Compensators ( SVC) No. of SVCs

64 AC Stations 220 CT

65

VT

66

CVT

67

110 CT

68

VT

69

CVT

70

66 & 50 CT

71

VT

72

33 & below CT

73

VT

74 AC Stations Disconnectors (standalone) 220 No. of 3 phase sets

75 110 No. of 3 phase sets

76 66 & 50 No. of 3 phase sets

77 33,22,11 No. of 3 phase sets unknown No. of 3 phase sets

79 AC Stations Earth Switches (standalone) 220 No. of 3 phase sets

80 110 No. of 3 phase sets

81 66 & 50 No. of 3 phase sets

82 33,22,11 No. of 3 phase sets unknown No. of 3 phase sets

84 AC Stations Power Cables greater than 1 km 220 Paper Insulated (oil filled) Metres of cable (circuit length)

85 XLPE Metres of cable (circuit length)

86 110 Paper Insulated (oil filled) Metres of cable (circuit length)

87 XLPE Metres of cable (circuit length)

88 66 & 50 XLPE Metres of cable (circuit length)

89 AC Stations Power Cables 1 km or less 220 Paper Insulated (oil filled) No of circuits

90 XLPE No of circuits

91 110 Paper Insulated (oil filled) No of circuits


93 66 & 50 XLPE No of circuits

94 33,22,11 Paper Insulated No of circuits


96 Secondary Systems Revenue Metering No. of meters

97 Secondary Systems Bus Protection Scheme 220/110/66/33 Bus Zone Protection Scheme (Incl CB fail) No. of protection schemes

98 Bus Coupler Protection Scheme No. of protection schemes

99 Arc Flash Detection Scheme No. of protection schemes

100 Secondary Systems Line Protection Scheme 220/110/66/33 No. of protection schemes

101 Secondary Systems Transformer Protection Scheme 220/110/66 No. of protection schemes

Converter Station/Cable Stations/Electrode Stations

No. of HVDC capacitors banks and filter banks

HVDC Standalone Current Transformers and Current Transducers

HVDC Voltage Transformers (CVTs and VTs) and Voltage Dividers

Cables HVDC submarine cables and terminations


For the Indoor switch gear the 3 phase sets includes the disconnectors , earthswitches, and integral instrument transformers. We have treated each panel as a 3-phase set.

No.of 3 phase sets of standalone reactors

Theses are standalone power reactors that are not part of capacitor or filter banks, Statcoms or SVCs

Excludes the Capacitor Banks and Filter banks which are part of the HVDC installations

No of Synchronous Condensers including all associated equipment

This includes all associated equipment such as cooling, excitaion systems etc



Instrument Transformers ( Standalone)














In the current year (2015/16) we disposed of only Ashley Deviation Line

Asset Disposal Asset Divestments

Assumptions and Comments Actual Forecast from Expenditure Proposal for Reset Period Actual Forecast from Expenditure Proposal for Reset Period

CY-2 CY-1 CY CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY-2 CY-1 CY CY-2 CY-1 CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6

- - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - - - - - - 2 - - - - - - - - - - - - - - - - - 1 1 2 - 2 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2 - - - - - - 6 7 1 1 - - - - - - - - - - - - - 2 - - - - - - - - 2 - - - - 3 - - - - - 2 - 2 - -

- - - - - - 3 1 2 - -

3 - 2 1 - 6 - - - - -

- - - - - - - - - - -

29 15 23 12 11 15 2 - - - - - - - - - - - - - - - - - - - - - - - - - - 1 - 7 19 3 5 - - 2 - - - - - - - - - - - - - 38 9 1 8 1 3 - - 4 - - - - - - - - 6 - - - - - - - - - - - - - - - - - - - - - 5 - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - 7 - - - - - - - - - - - - - - - - - - - - - 7 - - - 21 21 18 - 14 21 - 18 - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

17 24 27 27 20 4 - - - - -

- - - - - - - - - - -

12 13 7 8 11 2 - - - - -

1 - 2 1 1 8 1 - - - -

4 1 1 1 4 - 1 - - - -

- - - - - - - - - - -

- - - - - - - - - - -

2 2 - - - - - - - - -

- - - - - - 1 - 2 - -

6 2 3 - - - 4 1 2 - -

- 4 - - 6 14 - - - - -

- 32 24 8 29 25 3 - - - - - - 14 2 11 - - - 2 - - - - - - - - 26 13 8 - -

- - - - - - - - - - -

- - - - - - 1 - - - - - - - - - - - - - - - 2 - - - - - 4 6 - - -

- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 19 - - - - - - - - - - - - - - - - - - - - - 5 3 3 4 4 4 - 19 - - - - - - - - - - 1 - - - - - - - - - - 1 - - - 24 29 25 17 29 28 1 - 2 - - 5 13 13 15 14 18 4 - 2 - -

Disposals of individual assets are not always recorded in our system at this level of detail. We have therefore assumed that for every asset replacement there is a corresponding disposal.



102 Secondary Systems Feeder Protection Scheme 33/22/11 No. of protection schemes 1,173 240 166 364 101 58 53 35 23 133 6 17 7 7 15 6 103 Secondary Systems Special Protection Scheme 33/22/11 No. of protection schemes - - - - - - 104 Secondary Systems Batteries & DC Systems - - - - - -

105

Secondary Systems Battery Banks 125 VDC No. of banks

4 4 40 38 36 32 31 35

106

Secondary Systems Battery Banks 24 and 48 VDC No. of banks

2 1 1 - - - - - -

107 Secondary Systems Battery Chargers 125 VDC No. of chargers 6 - 1 6 - - 108 Secondary Systems Battery Chargers 24 and 48 VDC No. of chargers 140 119 16 4 1 - - - - - -

109

Secondary Systems SubstationTelemetry Systems RTU No. of RTUs

239 25 79 126 9 3 7 10 6 6 4

110

SMS Platform No. of SMS

57 57 11 13 11 10 10 13

111 GPS Clocks No. of GPS clocks 192 71 74 29 18 4 10 7 8 15 9 112 Human Machine Interface (HMI) No. of HMI's 164 79 54 17 14 2 3 8 2 5 2

113

Transmission Lines Tower 400 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures 6 6 - - - - - -

114 Painted No of Structures - - - - - -

115

Unpainted No of Structures 420 420 - - - - - -

116 Painted No of Structures - - - - - -

117

220 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures 6,412 26 26 2 4 33 329 5,992 - - - - - -

118 Painted No of Structures 1,167 9 1 3 9 1,145 - - - - - -

119

Unpainted No of Structures 6,117 111 19 7 1 736 2,027 2,708 508 274 255 197 164 260 325

120 Painted No of Structures 1,391 2 440 896 53 187 80 147 209 165 114

121

110/66 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures 8,037 110 1,027 498 305 2,415 988 11 2,683 - - - - - -

122 Painted No of Structures 85 25 1 59 - - - - - - 123 Double Cct Steel Tower or Monopole Unpainted No of Structures 4,901 88 98 393 280 28 438 854 2,722 - 46 89 106 117 104 124 Painted No of Structures 1,278 1 162 295 820 - 46 90 38 16 12

125

350 kV HVDC Single/Double Cct Steel Tower or monopole Unpainted No of Structures 1,535 88 55 1,392

- - - - - -

126 Painted No of Structures 114 42 72 - - - - - -

127

Single/Double Cct Steel Tower or monopole Unpainted No of Structures 4 1 1 2 - - - - - -

128 Painted No of Structures - - - - - - -

129 Transmission Lines Tower Foundation Concrete foundation No of Structures 9,465 525 12 8 1 737 3,045 4,611 526 61 11 186 113 9,091 1 - - - - -

130 Buried Steel Grillage No of Structures 10,760 3 30 8 31 580 10,108 269 136 639 644 9,069 - - - - - -

131

Concrete Encased Grillage No of Structures 2,758 1,863 670 1 224

85 - 24 2 2,511 275 339 396 408 390 377

132 Other No of Structures 743 31 2 - - 80 92 72 466 240 8 29 27 438

133 Transmission Lines Conductor Copper Circuit Kilometres 1,564 1 0 0 0 0 1,562 - - - - - -

134 AAAC Circuit Kilometres 601 421 48 33 38 0 61 - - - - - -

135 ACSR Circuit Kilometres 9,291 67 92 37 50 354 1,374 2,408 4,909 - - - - - -

136

Earthwire Circuit Kilometres 9,047 707 99 47 15 48 2,305 2,777 3,049

52 87 157 82 20 45

137

Circuit Kilometres 1,137 649 34 422 30 2 - - - - - -

138 Transmission Lines Pole Single Pole (steel) No of Structures 114 8 27 24 9 2 2 1 41 3 2 1 1 107 - - - - - -

139

Single Pole (wood/concrete) No of Structures 7,848 172 1,112 885 582 2,401 963 241 1,489

3 79 94 205 318 7,132 62 87 74 72 87 75

140 Pi-Pole (wood/concrete/steel) No of Structures 6,127 290 686 1,088 821 574 788 158 1,718 4 109 145 448 455 4,945 131 151 135 140 131 141

141 Unclassified No of Structures 366 71 63 24 9 56 9 13 92 29 8 122 11 3 221

142 Transmission Lines Insulators Composite No. of insulator circuits sets 10,822 1,013 4,426 1,824 1,527 355 337 233 1,107 1,578 34 693 720 7,729 - - - - - -

143

Glass and Porcelain No. of insulator circuits sets 42,616 1,110 3,062 1,882 3,298 5,844 5,274 8,342 13,804

1,687 895 3,028 3,073 33,817 755 1,532 1,466 1,402 1,315 1,375

144 Unknown No. of insulator circuits sets 798 86 8 13 1 13 32 73 572 80 180 93 79 344

G6(ii): Transmission Line Terrain factor and Corrosion Zones Corrosion Zones Route length ( kM) Extreme 125

Very Severe 1018Severe 1781Moderate 5718Low 1690Benign 759Unknown 5

Terrain Route length ( kM)1 Flat n/a2 Hilly n/a3 Mountainous n/a4 Rolling n/a5 Steep n/a6 Urban n/a

SCOPE:Protection and metering assets do not have enough data for statistical analysis and model-based future predictions to be worthwhile and necessary.

SCOPE:Model design and implementation for battery banks and chargers is currently in development. Expected remaining life figures will be available June 2017.

In relation to divestments: Where Transpower is retaining ownership of some assets at a divested substation it is common (with previous divestments) for Transpower to retain the existing DC supplies for its own use. The distributor will usually install a new DC supply for their own equipment. Therefore we have not included battery banks as part of the divestments.

In relation to divestments: Where Transpower is retaining ownership of some assets at a divested substation the existing RTU/SMS is used exclusively by Transpower. The distributor will usually install a new RTU/SMS that is compatible with its own equipment.

SCOPE:Substation telemetry systems assets do not have enough data for statistical analysis and model-based future predictions to be worthwhile and necessary.

SCOPE:Transmission towers are broken down into functional subsystems and modelled individually. Currently, tower paint and steel have a model developed, but this cannot be used to model the entirety of the tower.

Double Cct Lattice Steel Tower or Monopole


HVDC Electrode Line

ACCURACY:Modeling is currently based on continuously quantified data, providing relatively good accuracy.

In the forecast for the expenditure proposal we have assumed that all tower foundations are concrete encased grillage.

SCOPE:Model design and implementation for conductors is scheduled to be completed by July 2017.

Our unit is number of circuit spans which we have converted to circuit kilometres using 0.34 km per circuit span (average length of span)

OPGW ( includes areaial communications cables)

ACCURACY: Modelling is currently based on continuously quantified data, providing relatively good accuracy.

In the forecasts for the expenditure proposal we have assumed a combination of wood/concrete but could include some steel

ACCURACY:Modelling is currently based on continuously quantified data, providing relatively good accuracy.

In the forecast for the expenditure proposal we have assumed that all insulators are glass and porcelain.

Note: these terrain attributes are associated by Transpower with tower foundations, not on spans which have lengths.



102 Secondary Systems Feeder Protection Scheme 33/22/11 No. of protection schemes

103 Secondary Systems Special Protection Scheme 33/22/11 No. of protection schemes

104 Secondary Systems Batteries & DC Systems

105

Secondary Systems Battery Banks 125 VDC No. of banks

106

Secondary Systems Battery Banks 24 and 48 VDC No. of banks

107 Secondary Systems Battery Chargers 125 VDC No. of chargers

108 Secondary Systems Battery Chargers 24 and 48 VDC No. of chargers

109

Secondary Systems SubstationTelemetry Systems RTU No. of RTUs

110

SMS Platform No. of SMS

111 GPS Clocks No. of GPS clocks

112 Human Machine Interface (HMI) No. of HMI's

113

Transmission Lines Tower 400 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures

114 Painted No of Structures

115

Unpainted No of Structures


117

220 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures


119

Unpainted No of Structures


121

110/66 Single Cct Lattice Steel Tower or Monopole Unpainted No of Structures


123 Double Cct Steel Tower or Monopole Unpainted No of Structures


125

350 kV HVDC Single/Double Cct Steel Tower or monopole Unpainted No of Structures


127

Single/Double Cct Steel Tower or monopole Unpainted No of Structures


129 Transmission Lines Tower Foundation Concrete foundation No of Structures

130 Buried Steel Grillage No of Structures

131

Concrete Encased Grillage No of Structures

132 Other No of Structures

133 Transmission Lines Conductor Copper Circuit Kilometres

134 AAAC Circuit Kilometres

135 ACSR Circuit Kilometres

136

Earthwire Circuit Kilometres

137

Circuit Kilometres

138 Transmission Lines Pole Single Pole (steel) No of Structures

139

Single Pole (wood/concrete) No of Structures

140 Pi-Pole (wood/concrete/steel) No of Structures

141 Unclassified No of Structures

142 Transmission Lines Insulators Composite No. of insulator circuits sets

143

Glass and Porcelain No. of insulator circuits sets

144 Unknown No. of insulator circuits sets

G6(ii): Transmission Line Terrain factor and Corrosion Zones Corrosion Zones Route length ( kM) Extreme 125

Very Severe 1018Severe 1781Moderate 5718Low 1690Benign 759Unknown 5

Terrain Route length ( kM)1 Flat n/a2 Hilly n/a3 Mountainous n/a4 Rolling n/a5 Steep n/a6 Urban n/a

In relation to divestments: Where Transpower is retaining ownership of some assets at a divested substation it is common (with previous divestments) for Transpower to retain the existing DC supplies for its own use. The distributor will usually install a new DC supply for their own equipment. Therefore we have not included battery banks as part of the divestments.

In relation to divestments: Where Transpower is retaining ownership of some assets at a divested substation the existing RTU/SMS is used exclusively by Transpower. The distributor will usually install a new RTU/SMS that is compatible with its own equipment.



HVDC Electrode Line

In the forecast for the expenditure proposal we have assumed that all tower foundations are concrete encased grillage.

Our unit is number of circuit spans which we have converted to circuit kilometres using 0.34 km per circuit span (average length of span)

OPGW ( includes areaial communications cables)

In the forecasts for the expenditure proposal we have assumed a combination of wood/concrete but could include some steel

In the forecast for the expenditure proposal we have assumed that all insulators are glass and porcelain.

Note: these terrain attributes are associated by Transpower with tower foundations, not on spans which have lengths.

6 17 7 7 15 6 7 26 3 - - - - - - - - - - - - - - - - - - - - - - - -

40 38 35 32 31 35 - - - - -

- - - - - - - - - - -

6 - 1 6 - - - - - - - - - - - - - - - - - -

3 7 10 6 6 4 - - - - -

4 13 11 10 10 13 - - - - -

4 10 7 8 15 9 - - - - - 2 3 8 2 5 2 - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

10 - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - -

- - - - - - 1 - - - - - - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - - - - - - - - - - - - -

- - - - - - - - - - -

- - - - - - - - - - - 1 - - - - - - - - - - - - - - - - 33 95 - - - -

- 83 309 286 314 263 - - - - -

- - - - - - 5 36 - - - - - - - - - - - - - - -

- - - - - - 21 - - - -

52 87 53 82 20 45 - - - - -

- - - - - - - - - - -

- - - - - - 33 94 - - - -

62 128 112 117 108 118 263 - - - - 131 - - - - -

- - - - - - - - - - -

723 1,322 1,366 1,227 1,280 1,293 33 1,071 - - - -


Tab name: G7. AMMAT 05/09/2023


SCHEDULE G7: ASSET MANAGEMENT MATURITY ASSESSMENT TOOL (AMMAT) Disclosure Year (year ended) ###

ref

5Function Question Maturity Level 0 Maturity Level 1 Maturity Level 2 Maturity Level 3 Maturity Level 4 Why Who Record/documented Information User Guidance Evidence—Summary Score

6

3 3

7

10 2

8

11 2

9

26 3

10

27 3

11

29 3

Question No. (See note 1)

Asset management policy

To what extent has an asset management policy been documented, authorised and communicated?

The organisation does not have a documented asset management policy.

The organisation has an asset management policy, but it has not been authorised by top management, or it is not influencing the management of the assets.

The organisation has an asset management policy, which has been authorised by top management, but it has had limited circulation. It may be in use to influence development of strategy and planning but its effect is limited.

The asset management policy is authorised by top management, is widely and effectively communicated to all relevant employees and stakeholders, and used to make these persons aware of their asset related obligations.

The organisation's process(es) surpass the standard required to comply with requirements set out in a recognised standard.

The assessor is advised to note in the Evidence section why this is the case and the evidence seen.

Widely used AM practice standards require an organisation to document, authorise and communicate its asset management policy (eg, as required in PAS 55 para 4.2 i). A key pre-requisite of any robust policy is that the organisation's top management must be seen to endorse and fully support it. Also vital to the effective implementation of the policy, is to tell the appropriate people of its content and their obligations under it. Where an organisation outsources some of its asset-related activities, then these people and their organisations must equally be made aware of the policy's content. Also, there may be other stakeholders, such as regulatory authorities and shareholders who should be made aware of it.

Top management. The management team that has overall responsibility for asset management.

The organisation's asset management policy, its organisational strategic plan, documents indicating how the asset management policy was based upon the needs of the organisation and evidence of communication.

Transpower has achieved PAS 55 certification

Asset management strategy

What has the organisation done to ensure that its asset management strategy is consistent with other appropriate organisational policies and strategies, and the needs of stakeholders?

The organisation has not considered the need to ensure that its asset management strategy is appropriately aligned with the organisation's other organisational policies and strategies or with stakeholder requirements. ORThe organisation does not have an asset management strategy.

The need to align the asset management strategy with other organisational policies and strategies as well as stakeholder requirements is understood and work has started to identify the linkages or to incorporate them in the drafting of asset management strategy.

Some of the linkages between the long-term asset management strategy and other organisational policies, strategies and stakeholder requirements are defined but the work is fairly well advanced but still incomplete.

All linkages are in place and evidence is available to demonstrate that, where appropriate, the organisation's asset management strategy is consistent with its other organisational policies and strategies. The organisation has also identified and considered the requirements of relevant stakeholders.



In setting an organisation's asset management strategy, it is important that it is consistent with any other policies and strategies that the organisation has and has taken into account the requirements of relevant stakeholders. This question examines to what extent the asset management strategy is consistent with other organisational policies and strategies (eg, as required by PAS 55 para 4.3.1 b) and has taken account of stakeholder requirements as required by PAS 55 para 4.3.1 c). Generally, this will take into account the same polices, strategies and stakeholder requirements as covered in drafting the asset management policy but at a greater level of detail.

Top management. The organisation's strategic planning team. The management team that has overall responsibility for asset management.

The organisation's asset management strategy document and other related organisational policies and strategies. Other than the organisation's strategic plan, these could include those relating to health and safety, environmental, etc. Results of stakeholder consultation.

Transpower has achieved PAS 55 certification. There is a recognition that not all strategies are SMART, so they are currently being reviewed.

Asset management strategy

In what way does the organisation's asset management strategy take account of the lifecycle of the assets, asset types and asset systems over which the organisation has stewardship?

The organisation has not considered the need to ensure that its asset management strategy is produced with due regard to the lifecycle of the assets, asset types or asset systems that it manages. ORThe organisation does not have an asset management strategy.

The need is understood, and the organisation is drafting its asset management strategy to address the lifecycle of its assets, asset types and asset systems.

The long-term asset management strategy takes account of the lifecycle of some, but not all, of its assets, asset types and asset systems.

The asset management strategy takes account of the lifecycle of all of its assets, asset types and asset systems.



Good asset stewardship is the hallmark of an organisation compliant with widely used AM standards. A key component of this is the need to take account of the lifecycle of the assets, asset types and asset systems. (For example, this requirement is recognised in 4.3.1 d) of PAS 55). This question explores what an organisation has done to take lifecycle into account in its asset management strategy.

Top management. People in the organisation with expert knowledge of the assets, asset types, asset systems and their associated life-cycles. The management team that has overall responsibility for asset management. Those responsible for developing and adopting methods and processes used in asset management

The organisation's documented asset management strategy and supporting working documents.


Asset management plan(s)

How does the organisation establish and document its asset management plan(s) across the life cycle activities of its assets and asset systems?

The organisation does not have an identifiable asset management plan(s) covering asset systems and critical assets.

The organisation has asset management plan(s) but they are not aligned with the asset management strategy and objectives and do not take into consideration the full asset life cycle (including asset creation, acquisition, enhancement, utilisation, maintenance decommissioning and disposal).

The organisation is in the process of putting in place comprehensive, documented asset management plan(s) that cover all life cycle activities, clearly aligned to asset management objectives and the asset management strategy.

Asset management plan(s) are established, documented, implemented and maintained for asset systems and critical assets to achieve the asset management strategy and asset management objectives across all life cycle phases.



The asset management strategy need to be translated into practical plan(s) so that all parties know how the objectives will be achieved. The development of plan(s) will need to identify the specific tasks and activities required to optimize costs, risks and performance of the assets and/or asset system(s), when they are to be carried out and the resources required.

The management team with overall responsibility for the asset management system. Operations, maintenance and engineering managers.

The organisation's asset management plan(s).



How has the organisation communicated its plan(s) to all relevant parties to a level of detail appropriate to the receiver's role in their delivery?

The organisation does not have plan(s) or their distribution is limited to the authors.

The plan(s) are communicated to some of those responsible for delivery of the plan(s). OR Communicated to those responsible for delivery is either irregular or ad-hoc.

The plan(s) are communicated to most of those responsible for delivery but there are weaknesses in identifying relevant parties resulting in incomplete or inappropriate communication. The organisation recognises improvement is needed as is working towards resolution.

The plan(s) are communicated to all relevant employees, stakeholders and contracted service providers to a level of detail appropriate to their participation or business interests in the delivery of the plan(s) and there is confirmation that they are being used effectively.



Plans will be ineffective unless they are communicated to all those, including contracted suppliers and those who undertake enabling function(s). The plan(s) need to be communicated in a way that is relevant to those who need to use them.

The management team with overall responsibility for the asset management system. Delivery functions and suppliers.

Distribution lists for plan(s). Documents derived from plan(s) which detail the receivers role in plan delivery. Evidence of communication.

Transpower has achieved PAS 55 certification and the plan is widely communicated and used effectively


How are designated responsibilities for delivery of asset plan actions documented?

The organisation has not documented responsibilities for delivery of asset plan actions.

Asset management plan(s) inconsistently document responsibilities for delivery of plan actions and activities and/or responsibilities and authorities for implementation inadequate and/or delegation level inadequate to ensure effective delivery and/or contain misalignments with organisational accountability.

Asset management plan(s) consistently document responsibilities for the delivery of actions but responsibility/authority levels are inappropriate/ inadequate, and/or there are misalignments within the organisation.

Asset management plan(s) consistently document responsibilities for the delivery actions and there is adequate detail to enable delivery of actions. Designated responsibility and authority for achievement of asset plan actions is appropriate.



The implementation of asset management plan(s) relies on (1) actions being clearly identified, (2) an owner allocated and (3) that owner having sufficient delegated responsibility and authority to carry out the work required. It also requires alignment of actions across the organisation. This question explores how well the plan(s) set out responsibility for delivery of asset plan actions.

The management team with overall responsibility for the asset management system. Operations, maintenance and engineering managers. If appropriate, the performance management team.

The organisation's asset management plan(s). Documentation defining roles and responsibilities of individuals and organisational departments.

Transpower has achieved PAS 55 certification and the roles and responsibilities for delivering the plan are in place. They have been further enhanced through a recent organisational restructure which has improved role clarity and responsibility.



12

31 3

13

33 3

14

37 3

15

40 3

16

42 3

17

45 3


What has the organisation done to ensure that appropriate arrangements are made available for the efficient and cost effective implementation of the plan(s)?

(Note this is about resources and enabling support)

The organisation has not considered the arrangements needed for the effective implementation of plan(s).

The organisation recognises the need to ensure appropriate arrangements are in place for implementation of asset management plan(s) and is in the process of determining an appropriate approach for achieving this.

The organisation has arrangements in place for the implementation of asset management plan(s) but the arrangements are not yet adequately efficient and/or effective. The organisation is working to resolve existing weaknesses.

The organisation's arrangements fully cover all the requirements for the efficient and cost effective implementation of asset management plan(s) and realistically address the resources and timescales required, and any changes needed to functional policies, standards, processes and the asset management information system.



It is essential that the plan(s) are realistic and can be implemented, which requires appropriate resources to be available and enabling mechanisms in place. This question explores how well this is achieved. The plan(s) not only need to consider the resources directly required and timescales, but also the enabling activities, including for example, training requirements, supply chain capability and procurement timescales.

The management team with overall responsibility for the asset management system. Operations, maintenance and engineering managers. If appropriate, the performance management team. If appropriate, the performance management team. Where appropriate the procurement team and service providers working on the organisation's asset-related activities.

The organisation's asset management plan(s). Documented processes and procedures for the delivery of the asset management plan.

The organisation has PAS55 certification, and has taken a step further and restructured the organisation to a better asset management best practice model to deliver more asset management efficiencies and clarity of role of function across the business.

Contingency planning

What plan(s) and procedure(s) does the organisation have for identifying and responding to incidents and emergency situations and ensuring continuity of critical asset management activities?

The organisation has not considered the need to establish plan(s) and procedure(s) to identify and respond to incidents and emergency situations.

The organisation has some ad-hoc arrangements to deal with incidents and emergency situations, but these have been developed on a reactive basis in response to specific events that have occurred in the past.

Most credible incidents and emergency situations are identified. Either appropriate plan(s) and procedure(s) are incomplete for critical activities or they are inadequate. Training/ external alignment may be incomplete.

Appropriate emergency plan(s) and procedure(s) are in place to respond to credible incidents and manage continuity of critical asset management activities consistent with policies and asset management objectives. Training and external agency alignment is in place.



Widely used AM practice standards require that an organisation has plan(s) to identify and respond to emergency situations. Emergency plan(s) should outline the actions to be taken to respond to specified emergency situations and ensure continuity of critical asset management activities including the communication to, and involvement of, external agencies. This question assesses if, and how well, these plan(s) triggered, implemented and resolved in the event of an incident. The plan(s) should be appropriate to the level of risk as determined by the organisation's risk assessment methodology. It is also a requirement that relevant personnel are competent and trained.

The manager with responsibility for developing emergency plan(s). The organisation's risk assessment team. People with designated duties within the plan(s) and procedure(s) for dealing with incidents and emergency situations.

The organisation's plan(s) and procedure(s) for dealing with emergencies. The organisation's risk assessments and risk registers.

The organisation has PAS55 certification, and has a robust set of contingency plans in place, both for business continuity as well as operational. There is still some work to be done in an overarching framework to ensure that we have not missed anything and to allow prioritisation of their development

Structure, authority and responsibilities

What has the organisation done to appoint member(s) of its management team to be responsible for ensuring that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s)?

Top management has not considered the need to appoint a person or persons to ensure that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s).

Top management understands the need to appoint a person or persons to ensure that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s).

Top management has appointed an appropriate people to ensure the assets deliver the requirements of the asset management strategy, objectives and plan(s) but their areas of responsibility are not fully defined and/or they have insufficient delegated authority to fully execute their responsibilities.

The appointed person or persons have full responsibility for ensuring that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s). They have been given the necessary authority to achieve this.



In order to ensure that the organisation's assets and asset systems deliver the requirements of the asset management policy, strategy and objectives responsibilities need to be allocated to appropriate people who have the necessary authority to fulfil their responsibilities. (This question, relates to the organisation's assets eg, para b), s 4.4.1 of PAS 55, making it therefore distinct from the requirement contained in para a), s 4.4.1 of PAS 55).

Top management. People with management responsibility for the delivery of asset management policy, strategy, objectives and plan(s). People working on asset-related activities.

Evidence that managers with responsibility for the delivery of asset management policy, strategy, objectives and plan(s) have been appointed and have assumed their responsibilities. Evidence may include the organisation's documents relating to its asset management system, organisational charts, job descriptions of post-holders, annual targets/objectives and personal development plan(s) of post-holders as appropriate.



What evidence can the organisation's top management provide to demonstrate that sufficient resources are available for asset management?

The organisation's top management has not considered the resources required to deliver asset management.

The organisations top management understands the need for sufficient resources but there are no effective mechanisms in place to ensure this is the case.

A process exists for determining what resources are required for its asset management activities and in most cases these are available but in some instances resources remain insufficient.

An effective process exists for determining the resources needed for asset management and sufficient resources are available. It can be demonstrated that resources are matched to asset management requirements.



Optimal asset management requires top management to ensure sufficient resources are available. In this context the term 'resources' includes manpower, materials, funding and service provider support.

Top management. The management team that has overall responsibility for asset management. Risk management team. The organisation's managers involved in day-to-day supervision of asset-related activities, such as frontline managers, engineers, foremen and chargehands as appropriate.

Evidence demonstrating that asset management plan(s) and/or the process(es) for asset management plan implementation consider the provision of adequate resources in both the short and long term. Resources include funding, materials, equipment, services provided by third parties and personnel (internal and service providers) with appropriate skills competencies and knowledge.



To what degree does the organisation's top management communicate the importance of meeting its asset management requirements?

The organisation's top management has not considered the need to communicate the importance of meeting asset management requirements.

The organisations top management understands the need to communicate the importance of meeting its asset management requirements but does not do so.

Top management communicates the importance of meeting its asset management requirements but only to parts of the organisation.

Top management communicates the importance of meeting its asset management requirements to all relevant parts of the organisation.



Widely used AM practice standards require an organisation to communicate the importance of meeting its asset management requirements such that personnel fully understand, take ownership of, and are fully engaged in the delivery of the asset management requirements (eg, PAS 55 s 4.4.1 g).

Top management. The management team that has overall responsibility for asset management. People involved in the delivery of the asset management requirements.

Evidence of such activities as road shows, written bulletins, workshops, team talks and management walk-abouts would assist an organisation to demonstrate it is meeting this requirement of PAS 55.

The organisation has PAS55 certification, and the commitment has be recently reaffirmed though an organisation restructure and embedding initiatives to ensure we can deliver our plan and asset management more effectively and efficiently.

Outsourcing of asset management activities

Where the organisation has outsourced some of its asset management activities, how has it ensured that appropriate controls are in place to ensure the compliant delivery of its organisational strategic plan, and its asset management policy and strategy?

The organisation has not considered the need to put controls in place.

The organisation controls its outsourced activities on an ad-hoc basis, with little regard for ensuring for the compliant delivery of the organisational strategic plan and/or its asset management policy and strategy.

Controls systematically considered but currently only provide for the compliant delivery of some, but not all, aspects of the organisational strategic plan and/or its asset management policy and strategy. Gaps exist.

Evidence exists to demonstrate that outsourced activities are appropriately controlled to provide for the compliant delivery of the organisational strategic plan, asset management policy and strategy, and that these controls are integrated into the asset management system



Where an organisation chooses to outsource some of its asset management activities, the organisation must ensure that these outsourced process(es) are under appropriate control to ensure that all the requirements of widely used AM standards (eg, PAS 55) are in place, and the asset management policy, strategy objectives and plan(s) are delivered. This includes ensuring capabilities and resources across a time span aligned to life cycle management. The organisation must put arrangements in place to control the outsourced activities, whether it be to external providers or to other in-house departments. This question explores what the organisation does in this regard.

Top management. The management team that has overall responsibility for asset management. The manager(s) responsible for the monitoring and management of the outsourced activities. People involved with the procurement of outsourced activities. The people within the organisations that are performing the outsourced activities. The people impacted by the outsourced activity.

The organisation's arrangements that detail the compliance required of the outsourced activities. For example, this this could form part of a contract or service level agreement between the organisation and the suppliers of its outsourced activities. Evidence that the organisation has demonstrated to itself that it has assurance of compliance of outsourced activities.

The organisation has PAS55 ceritication and has recently undergone a service provider contract review. The organisation did not renew the contract with one service provider. Efficiencies and costs outcomes have been improved. There is room for improvement in understanding the competence of the service provider workforce and around the assurance of their work.



18

48 3

19

49 3

20

50 2

21

53 3

Training, awareness and competence

How does the organisation develop plan(s) for the human resources required to undertake asset management activities - including the development and delivery of asset management strategy, process(es), objectives and plan(s)?

The organisation has not recognised the need for assessing human resources requirements to develop and implement its asset management system.

The organisation has recognised the need to assess its human resources requirements and to develop a plan(s). There is limited recognition of the need to align these with the development and implementation of its asset management system.

The organisation has developed a strategic approach to aligning competencies and human resources to the asset management system including the asset management plan but the work is incomplete or has not been consistently implemented.

The organisation can demonstrate that plan(s) are in place and effective in matching competencies and capabilities to the asset management system including the plan for both internal and contracted activities. Plans are reviewed integral to asset management system process(es).



There is a need for an organisation to demonstrate that it has considered what resources are required to develop and implement its asset management system. There is also a need for the organisation to demonstrate that it has assessed what development plan(s) are required to provide its human resources with the skills and competencies to develop and implement its asset management systems. The timescales over which the plan(s) are relevant should be commensurate with the planning horizons within the asset management strategy considers e.g. if the asset management strategy considers 5, 10 and 15 year time scales then the human resources development plan(s) should align with these. Resources include both 'in house' and external resources who undertake asset management activities.

Senior management responsible for agreement of plan(s). Managers responsible for developing asset management strategy and plan(s). Managers with responsibility for development and recruitment of staff (including HR functions). Staff responsible for training. Procurement officers. Contracted service providers.

Evidence of analysis of future work load plan(s) in terms of human resources. Document(s) containing analysis of the organisation's own direct resources and contractors resource capability over suitable timescales. Evidence, such as minutes of meetings, that suitable management forums are monitoring human resource development plan(s). Training plan(s), personal development plan(s), contract and service level agreements.

The organisation has PAS55, but there is room for more improvement around the embedding of competence frameworks across the organisation.


How does the organisation identify competency requirements and then plan, provide and record the training necessary to achieve the competencies?

The organisation does not have any means in place to identify competency requirements.

The organisation has recognised the need to identify competency requirements and then plan, provide and record the training necessary to achieve the competencies.

The organisation is the process of identifying competency requirements aligned to the asset management plan(s) and then plan, provide and record appropriate training. It is incomplete or inconsistently applied.

Competency requirements are in place and aligned with asset management plan(s). Plans are in place and effective in providing the training necessary to achieve the competencies. A structured means of recording the competencies achieved is in place.



Widely used AM standards require that organisations to undertake a systematic identification of the asset management awareness and competencies required at each level and function within the organisation. Once identified the training required to provide the necessary competencies should be planned for delivery in a timely and systematic way. Any training provided must be recorded and maintained in a suitable format. Where an organisation has contracted service providers in place then it should have a means to demonstrate that this requirement is being met for their employees. (eg, PAS 55 refers to frameworks suitable for identifying competency requirements).

Senior management responsible for agreement of plan(s). Managers responsible for developing asset management strategy and plan(s). Managers with responsibility for development and recruitment of staff (including HR functions). Staff responsible for training. Procurement officers. Contracted service providers.

Evidence of an established and applied competency requirements assessment process and plan(s) in place to deliver the required training. Evidence that the training programme is part of a wider, co-ordinated asset management activities training and competency programme. Evidence that training activities are recorded and that records are readily available (for both direct and contracted service provider staff) e.g. via organisation wide information system or local records database.



How does the organization ensure that persons under its direct control undertaking asset management related activities have an appropriate level of competence in terms of education, training or experience?

The organization has not recognised the need to assess the competence of person(s) undertaking asset management related activities.

Competency of staff undertaking asset management related activities is not managed or assessed in a structured way, other than formal requirements for legal compliance and safety management.

The organization is in the process of putting in place a means for assessing the competence of person(s) involved in asset management activities including contractors. There are gaps and inconsistencies.

Competency requirements are identified and assessed for all persons carrying out asset management related activities - internal and contracted. Requirements are reviewed and staff reassessed at appropriate intervals aligned to asset management requirements.



A critical success factor for the effective development and implementation of an asset management system is the competence of persons undertaking these activities. organisations should have effective means in place for ensuring the competence of employees to carry out their designated asset management function(s). Where an organisation has contracted service providers undertaking elements of its asset management system then the organisation shall assure itself that the outsourced service provider also has suitable arrangements in place to manage the competencies of its employees. The organisation should ensure that the individual and corporate competencies it requires are in place and actively monitor, develop and maintain an appropriate balance of these competencies.

Managers, supervisors, persons responsible for developing training programmes. Staff responsible for procurement and service agreements. HR staff and those responsible for recruitment.

Evidence of a competency assessment framework that aligns with established frameworks such as the asset management Competencies Requirements Framework (Version 2.0); National Occupational Standards for Management and Leadership; UK Standard for Professional Engineering Competence, Engineering Council, 2005.


Communication, participation and consultation

How does the organisation ensure that pertinent asset management information is effectively communicated to and from employees and other stakeholders, including contracted service providers?

The organisation has not recognised the need to formally communicate any asset management information.

There is evidence that the pertinent asset management information to be shared along with those to share it with is being determined.

The organisation has determined pertinent information and relevant parties. Some effective two way communication is in place but as yet not all relevant parties are clear on their roles and responsibilities with respect to asset management information.

Two way communication is in place between all relevant parties, ensuring that information is effectively communicated to match the requirements of asset management strategy, plan(s) and process(es). Pertinent asset information requirements are regularly reviewed.



Widely used AM practice standards require that pertinent asset management information is effectively communicated to and from employees and other stakeholders including contracted service providers. Pertinent information refers to information required in order to effectively and efficiently comply with and deliver asset management strategy, plan(s) and objectives. This will include for example the communication of the asset management policy, asset performance information, and planning information as appropriate to contractors.

Top management and senior management representative(s), employee's representative(s), employee's trade union representative(s); contracted service provider management and employee representative(s); representative(s) from the organisation's Health, Safety and Environmental team. Key stakeholder representative(s).

Asset management policy statement prominently displayed on notice boards, intranet and internet; use of organisation's website for displaying asset performance data; evidence of formal briefings to employees, stakeholders and contracted service providers; evidence of inclusion of asset management issues in team meetings and contracted service provider contract meetings; newsletters, etc.

The organisation has PAS55 and communication between both internal staff and with service providers are effective.



22

59 3

23

62 3

24

63 3

25

64 3

26

69 2

27

79 3

Asset Management System documentation

What documentation has the organisation established to describe the main elements of its asset management system and interactions between them?

The organisation has not established documentation that describes the main elements of the asset management system.

The organisation is aware of the need to put documentation in place and is in the process of determining how to document the main elements of its asset management system.

The organisation in the process of documenting its asset management system and has documentation in place that describes some, but not all, of the main elements of its asset management system and their interaction.

The organisation has established documentation that comprehensively describes all the main elements of its asset management system and the interactions between them. The documentation is kept up to date.



Widely used AM practice standards require an organisation maintain up to date documentation that ensures that its asset management systems (ie, the systems the organisation has in place to meet the standards) can be understood, communicated and operated. (eg, s 4.5 of PAS 55 requires the maintenance of up to date documentation of the asset management system requirements specified throughout s 4 of PAS 55).

The management team that has overall responsibility for asset management. Managers engaged in asset management activities.

The documented information describing the main elements of the asset management system (process(es)) and their interaction.

The organisation has PAS55 and a high standard of asset management documentation. There is some room for improvement in the AM Strategies to ensure they are SMART

Information management

What has the organisation done to determine what its asset management information system(s) should contain in order to support its asset management system?

The organisation has not considered what asset management information is required.

The organisation is aware of the need to determine in a structured manner what its asset information system should contain in order to support its asset management system and is in the process of deciding how to do this.

The organisation has developed a structured process to determine what its asset information system should contain in order to support its asset management system and has commenced implementation of the process.

The organisation has determined what its asset information system should contain in order to support its asset management system. The requirements relate to the whole life cycle and cover information originating from both internal and external sources.



Effective asset management requires appropriate information to be available. Widely used AM standards therefore require the organisation to identify the asset management information it requires in order to support its asset management system. Some of the information required may be held by suppliers.The maintenance and development of asset management information systems is a poorly understood specialist activity that is akin to IT management but different from IT management. This group of questions provides some indications as to whether the capability is available and applied. Note: To be effective, an asset information management system requires the mobilisation of technology, people and process(es) that create, secure, make available and destroy the information required to support the asset management system.

The organisation's strategic planning team. The management team that has overall responsibility for asset management. Information management team. Operations, maintenance and engineering managers

Details of the process the organisation has employed to determine what its asset information system should contain in order to support its asset management system. Evidence that this has been effectively implemented.

The organisation has PAS55 and runs Maximo. There is some room for improvement in asset data quality and mechanisms for achieving that are underway.


How does the organisation maintain its asset management information system(s) and ensure that the data held within it (them) is of the requisite quality and accuracy and is consistent?

There are no formal controls in place or controls are extremely limited in scope and/or effectiveness.

The organisation is aware of the need for effective controls and is in the process of developing an appropriate control process(es).

The organisation has developed a controls that will ensure the data held is of the requisite quality and accuracy and is consistent and is in the process of implementing them.

The organisation has effective controls in place that ensure the data held is of the requisite quality and accuracy and is consistent. The controls are regularly reviewed and improved where necessary.



The response to the questions is progressive. A higher scale cannot be awarded without achieving the requirements of the lower scale.

This question explores how the organisation ensures that information management meets widely used AM practice requirements (eg, s 4.4.6 (a), (c) and (d) of PAS 55).

The management team that has overall responsibility for asset management. Users of the organisational information systems.

The asset management information system, together with the policies, procedure(s), improvement initiatives and audits regarding information controls.



How has the organisation's ensured its asset management information system is relevant to its needs?

The organisation has not considered the need to determine the relevance of its management information system. At present there are major gaps between what the information system provides and the organisations needs.

The organisation understands the need to ensure its asset management information system is relevant to its needs and is determining an appropriate means by which it will achieve this. At present there are significant gaps between what the information system provides and the organisations needs.

The organisation has developed and is implementing a process to ensure its asset management information system is relevant to its needs. Gaps between what the information system provides and the organisations needs have been identified and action is being taken to close them.

The organisation's asset management information system aligns with its asset management requirements. Users can confirm that it is relevant to their needs.



Widely used AM standards need not be prescriptive about the form of the asset management information system, but simply require that the asset management information system is appropriate to the organisations needs, can be effectively used and can supply information which is consistent and of the requisite quality and accuracy.

The organisation's strategic planning team. The management team that has overall responsibility for asset management. Information management team. Users of the organisational information systems.

The documented process the organisation employs to ensure its asset management information system aligns with its asset management requirements. Minutes of information systems review meetings involving users.


Risk management process(es)

How has the organisation documented process(es) and/or procedure(s) for the identification and assessment of asset and asset management related risks throughout the asset life cycle?

The organisation has not considered the need to document process(es) and/or procedure(s) for the identification and assessment of asset and asset management related risks throughout the asset life cycle.

The organisation is aware of the need to document the management of asset related risk across the asset lifecycle. The organisation has plan(s) to formally document all relevant process(es) and procedure(s) or has already commenced this activity.

The organisation is in the process of documenting the identification and assessment of asset related risk across the asset lifecycle but it is incomplete or there are inconsistencies between approaches and a lack of integration.

Identification and assessment of asset related risk across the asset lifecycle is fully documented. The organisation can demonstrate that appropriate documented mechanisms are integrated across life cycle phases and are being consistently applied.



Risk management is an important foundation for proactive asset management. Its overall purpose is to understand the cause, effect and likelihood of adverse events occurring, to optimally manage such risks to an acceptable level, and to provide an audit trail for the management of risks. Widely used standards require the organisation to have process(es) and/or procedure(s) in place that set out how the organisation identifies and assesses asset and asset management related risks. The risks have to be considered across the four phases of the asset lifecycle (eg, para 4.3.3 of PAS 55).

The top management team in conjunction with the organisation's senior risk management representatives. There may also be input from the organisation's Safety, Health and Environment team. Staff who carry out risk identification and assessment.

The organisation's risk management framework and/or evidence of specific process(es) and/ or procedure(s) that deal with risk control mechanisms. Evidence that the process(es) and/or procedure(s) are implemented across the business and maintained. Evidence of agendas and minutes from risk management meetings. Evidence of feedback in to process(es) and/or procedure(s) as a result of incident investigation(s). Risk registers and assessments.

The organisation has PAS55 and has has a reasonably sound risk management process. Bow-tie risk analysis and SQRA is currently being rolled out to improve this - there is still a number of bow-ties to be completed before this will be fully functional.

Use and maintenance of asset risk information

How does the organisation ensure that the results of risk assessments provide input into the identification of adequate resources and training and competency needs?

The organisation has not considered the need to conduct risk assessments.

The organisation is aware of the need to consider the results of risk assessments and effects of risk control measures to provide input into reviews of resources, training and competency needs. Current input is typically ad-hoc and reactive.

The organisation is in the process ensuring that outputs of risk assessment are included in developing requirements for resources and training. The implementation is incomplete and there are gaps and inconsistencies.

Outputs from risk assessments are consistently and systematically used as inputs to develop resources, training and competency requirements. Examples and evidence is available.



Widely used AM standards require that the output from risk assessments are considered and that adequate resource (including staff) and training is identified to match the requirements. It is a further requirement that the effects of the control measures are considered, as there may be implications in resources and training required to achieve other objectives.

Staff responsible for risk assessment and those responsible for developing and approving resource and training plan(s). There may also be input from the organisation's Safety, Health and Environment team.

The organisations risk management framework. The organisation's resourcing plan(s) and training and competency plan(s). The organisation should be able to demonstrate appropriate linkages between the content of resource plan(s) and training and competency plan(s) to the risk assessments and risk control measures that have been developed.

The organisation has PAS55 and has has a reasonably sound risk management process. The National Event Review Group and the RESOLVE processes track risks through to mitigation.



28

82 3

29

88 Life Cycle Activities 3

30

91 Life Cycle Activities 3

31

95 3

32

99 3

33

105 Audit 2

Legal and other requirements

What procedure does the organisation have to identify and provide access to its legal, regulatory, statutory and other asset management requirements, and how is requirements incorporated into the asset management system?

The organisation has not considered the need to identify its legal, regulatory, statutory and other asset management requirements.

The organisation identifies some its legal, regulatory, statutory and other asset management requirements, but this is done in an ad-hoc manner in the absence of a procedure.

The organisation has procedure(s) to identify its legal, regulatory, statutory and other asset management requirements, but the information is not kept up to date, inadequate or inconsistently managed.

Evidence exists to demonstrate that the organisation's legal, regulatory, statutory and other asset management requirements are identified and kept up to date. Systematic mechanisms for identifying relevant legal and statutory requirements.



In order for an organisation to comply with its legal, regulatory, statutory and other asset management requirements, the organisation first needs to ensure that it knows what they are (eg, PAS 55 specifies this in s 4.4.8). It is necessary to have systematic and auditable mechanisms in place to identify new and changing requirements. Widely used AM standards also require that requirements are incorporated into the asset management system (e.g. procedure(s) and process(es))

Top management. The organisations regulatory team. The organisation's legal team or advisors. The management team with overall responsibility for the asset management system. The organisation's health and safety team or advisors. The organisation's policy making team.

The organisational processes and procedures for ensuring information of this type is identified, made accessible to those requiring the information and is incorporated into asset management strategy and objectives

The organisation has PAS55 and has competently demonstrated that it undertakes its legal and compliance obligations seriously.

How does the organisation establish implement and maintain process(es) for the implementation of its asset management plan(s) and control of activities across the creation, acquisition or enhancement of assets. This includes design, modification, procurement, construction and commissioning activities?

The organisation does not have process(es) in place to manage and control the implementation of asset management plan(s) during activities related to asset creation including design, modification, procurement, construction and commissioning.

The organisation is aware of the need to have process(es) and procedure(s) in place to manage and control the implementation of asset management plan(s) during activities related to asset creation including design, modification, procurement, construction and commissioning but currently do not have these in place (note: procedure(s) may exist but they are inconsistent/incomplete).

The organisation is in the process of putting in place process(es) and procedure(s) to manage and control the implementation of asset management plan(s) during activities related to asset creation including design, modification, procurement, construction and commissioning. Gaps and inconsistencies are being addressed.

Effective process(es) and procedure(s) are in place to manage and control the implementation of asset management plan(s) during activities related to asset creation including design, modification, procurement, construction and commissioning.



Life cycle activities are about the implementation of asset management plan(s) i.e. they are the "doing" phase. They need to be done effectively and well in order for asset management to have any practical meaning. As a consequence, widely used standards (eg, PAS 55 s 4.5.1) require organisations to have in place appropriate process(es) and procedure(s) for the implementation of asset management plan(s) and control of lifecycle activities. This question explores those aspects relevant to asset creation.

Asset managers, design staff, construction staff and project managers from other impacted areas of the business, e.g. Procurement

Documented process(es) and procedure(s) which are relevant to demonstrating the effective management and control of life cycle activities during asset creation, acquisition, enhancement including design, modification, procurement, construction and commissioning.

The organisation has PAS55 and has competently demonstrated that it undertakes lifecycle management of its assets - although some processes are currently being reviews and refreshed since the organisational restucture as roles and responsibilities have changed in some areas.

How does the organisation ensure that process(es) and/or procedure(s) for the implementation of asset management plan(s) and control of activities during maintenance (and inspection) of assets are sufficient to ensure activities are carried out under specified conditions, are consistent with asset management strategy and control cost, risk and performance?

The organisation does not have process(es)/procedure(s) in place to control or manage the implementation of asset management plan(s) during this life cycle phase.

The organisation is aware of the need to have process(es) and procedure(s) in place to manage and control the implementation of asset management plan(s) during this life cycle phase but currently do not have these in place and/or there is no mechanism for confirming they are effective and where needed modifying them.

The organisation is in the process of putting in place process(es) and procedure(s) to manage and control the implementation of asset management plan(s) during this life cycle phase. They include a process for confirming the process(es)/procedure(s) are effective and if necessary carrying out modifications.

The organisation has in place process(es) and procedure(s) to manage and control the implementation of asset management plan(s) during this life cycle phase. They include a process, which is itself regularly reviewed to ensure it is effective, for confirming the process(es)/ procedure(s) are effective and if necessary carrying out modifications.



Having documented process(es) which ensure the asset management plan(s) are implemented in accordance with any specified conditions, in a manner consistent with the asset management policy, strategy and objectives and in such a way that cost, risk and asset system performance are appropriately controlled is critical. They are an essential part of turning intention into action (eg, as required by PAS 55 s 4.5.1).

Asset managers, operations managers, maintenance managers and project managers from other impacted areas of the business

Documented procedure for review. Documented procedure for audit of process delivery. Records of previous audits, improvement actions and documented confirmation that actions have been carried out.

The organisation has PAS55 and has undertakes project reviews of all its projects. Improvements are noted and processes are updated. Recent PAS55 audits have noted that field audits have been a weekness so we have introduced this assurance back into the business over the last 6 months.

Performance and condition monitoring

How does the organisation measure the performance and condition of its assets?

The organisation has not considered how to monitor the performance and condition of its assets.

The organisation recognises the need for monitoring asset performance but has not developed a coherent approach. Measures are incomplete, predominantly reactive and lagging. There is no linkage to asset management objectives.

The organisation is developing coherent asset performance monitoring linked to asset management objectives. Reactive and proactive measures are in place. Use is being made of leading indicators and analysis. Gaps and inconsistencies remain.

Consistent asset performance monitoring linked to asset management objectives is in place and universally used including reactive and proactive measures. Data quality management and review process are appropriate. Evidence of leading indicators and analysis.



Widely used AM standards require that organisations establish implement and maintain procedure(s) to monitor and measure the performance and/or condition of assets and asset systems. They further set out requirements in some detail for reactive and proactive monitoring, and leading/lagging performance indicators together with the monitoring or results to provide input to corrective actions and continual improvement. There is an expectation that performance and condition monitoring will provide input to improving asset management strategy, objectives and plan(s).

A broad cross-section of the people involved in the organisation's asset-related activities from data input to decision-makers, i.e. an end-to end assessment. This should include contactors and other relevant third parties as appropriate.

Functional policy and/or strategy documents for performance or condition monitoring and measurement. The organisation's performance monitoring frameworks, balanced scorecards etc. Evidence of the reviews of any appropriate performance indicators and the action lists resulting from these reviews. Reports and trend analysis using performance and condition information. Evidence of the use of performance and condition information shaping improvements and supporting asset management strategy, objectives and plan(s).

The organisation has PAS55 and is continuing to develop its asset health models. KPIs are consistently monitored.

Investigation of asset-related failures, incidents and nonconformities

How does the organisation ensure responsibility and the authority for the handling, investigation and mitigation of asset-related failures, incidents and emergency situations and non conformances is clear, unambiguous, understood and communicated?

The organisation has not considered the need to define the appropriate responsibilities and the authorities.

The organisation understands the requirements and is in the process of determining how to define them.

The organisation are in the process of defining the responsibilities and authorities with evidence. Alternatively there are some gaps or inconsistencies in the identified responsibilities/authorities.

The organisation have defined the appropriate responsibilities and authorities and evidence is available to show that these are applied across the business and kept up to date.



Widely used AM standards require that the organisation establishes implements and maintains process(es) for the handling and investigation of failures incidents and non-conformities for assets and sets down a number of expectations. Specifically this question examines the requirement to define clearly responsibilities and authorities for these activities, and communicate these unambiguously to relevant people including external stakeholders if appropriate.

The organisation's safety and environment management team. The team with overall responsibility for the management of the assets. People who have appointed roles within the asset-related investigation procedure, from those who carry out the investigations to senior management who review the recommendations. Operational controllers responsible for managing the asset base under fault conditions and maintaining services to customers. Contractors and other third parties as appropriate.

Process(es) and procedure(s) for the handling, investigation and mitigation of asset-related failures, incidents and emergency situations and non conformances. Documentation of assigned responsibilities and authority to employees. Job Descriptions, Audit reports. Common communication systems i.e. all Job Descriptions on Internet etc.

The organisation has PAS55 and consistently demonstrates good event review through the NERG and RESOLVE process.

What has the organisation done to establish procedure(s) for the audit of its asset management system (process(es))?

The organisation has not recognised the need to establish procedure(s) for the audit of its asset management system.

The organisation understands the need for audit procedure(s) and is determining the appropriate scope, frequency and methodology(s).

The organisation is establishing its audit procedure(s) but they do not yet cover all the appropriate asset-related activities.

The organisation can demonstrate that its audit procedure(s) cover all the appropriate asset-related activities and the associated reporting of audit results. Audits are to an appropriate level of detail and consistently managed.



This question seeks to explore what the organisation has done to comply with the standard practice AM audit requirements (eg, the associated requirements of PAS 55 s 4.6.4 and its linkages to s 4.7).

The management team responsible for its asset management procedure(s). The team with overall responsibility for the management of the assets. Audit teams, together with key staff responsible for asset management. For example, Asset Management Director, Engineering Director. People with responsibility for carrying out risk assessments

The organisation's asset-related audit procedure(s). The organisation's methodology(s) by which it determined the scope and frequency of the audits and the criteria by which it identified the appropriate audit personnel. Audit schedules, reports etc. Evidence of the procedure(s) by which the audit results are presented, together with any subsequent communications. The risk assessment schedule or risk registers.

The organisation has PAS55 and recognises the importance of audit beyond external (independent audits) so a quality assurance function to assess the 2nd line of defence of asset management processes and controls has been implemented as part of the recent organisational restructure.



34

109 3

35

113 3

36

115 3

37

Note1The question numbers refer to te review clauses in pas 55 assesement methodology

Corrective & Preventative action

How does the organisation instigate appropriate corrective and/or preventive actions to eliminate or prevent the causes of identified poor performance and non conformance?

The organisation does not recognise the need to have systematic approaches to instigating corrective or preventive actions.

The organisation recognises the need to have systematic approaches to instigating corrective or preventive actions. There is ad-hoc implementation for corrective actions to address failures of assets but not the asset management system.

The need is recognized for systematic instigation of preventive and corrective actions to address root causes of non compliance or incidents identified by investigations, compliance evaluation or audit. It is only partially or inconsistently in place.

Mechanisms are consistently in place and effective for the systematic instigation of preventive and corrective actions to address root causes of non compliance or incidents identified by investigations, compliance evaluation or audit.



Having investigated asset related failures, incidents and non-conformances, and taken action to mitigate their consequences, an organisation is required to implement preventative and corrective actions to address root causes. Incident and failure investigations are only useful if appropriate actions are taken as a result to assess changes to a businesses risk profile and ensure that appropriate arrangements are in place should a recurrence of the incident happen. Widely used AM standards also require that necessary changes arising from preventive or corrective action are made to the asset management system.

The management team responsible for its asset management procedure(s). The team with overall responsibility for the management of the assets. Audit and incident investigation teams. Staff responsible for planning and managing corrective and preventive actions.

Analysis records, meeting notes and minutes, modification records. Asset management plan(s), investigation reports, audit reports, improvement programmes and projects. Recorded changes to asset management procedure(s) and process(es). Condition and performance reviews. Maintenance reviews

The organisation has PAS55 and consistently demonstrates good event review through the NERG and RESOLVE process. Corrective and preventative maintenance is highly related to asset health and is included on the asset management plan where and if possible.

Continual Improvement

How does the organisation achieve continual improvement in the optimal combination of costs, asset related risks and the performance and condition of assets and asset systems across the whole life cycle?

The organisation does not consider continual improvement of these factors to be a requirement, or has not considered the issue.

A Continual Improvement ethos is recognised as beneficial, however it has just been started, and or covers partially the asset drivers.

Continuous improvement process(es) are set out and include consideration of cost risk, performance and condition for assets managed across the whole life cycle but it is not yet being systematically applied.

There is evidence to show that continuous improvement process(es) which include consideration of cost risk, performance and condition for assets managed across the whole life cycle are being systematically applied.



Widely used AM standards have requirements to establish, implement and maintain process(es)/procedure(s) for identifying, assessing, prioritising and implementing actions to achieve continual improvement. Specifically there is a requirement to demonstrate continual improvement in optimisation of cost risk and performance/condition of assets across the life cycle. This question explores an organisation's capabilities in this area—looking for systematic improvement mechanisms rather that reviews and audit (which are separately examined).

The top management of the organisation. The manager/team responsible for managing the organisation's asset management system, including its continual improvement. Managers responsible for policy development and implementation.

Records showing systematic exploration of improvement. Evidence of new techniques being explored and implemented. Changes in procedure(s) and process(es) reflecting improved use of optimisation tools/techniques and available information. Evidence of working parties and research.

The organisation has PAS55 and consistently demonstrates good event review through the NERG and RESOLVE process. Lessons learned from projects are fed back into processes for improvement.

Continual Improvement

How does the organisation seek and acquire knowledge about new asset management related technology and practices, and evaluate their potential benefit to the organisation?

The organisation makes no attempt to seek knowledge about new asset management related technology or practices.

The organisation is inward looking, however it recognises that asset management is not sector specific and other sectors have developed good practice and new ideas that could apply. Ad-hoc approach.

The organisation has initiated asset management communication within sector to share and, or identify 'new' to sector asset management practices and seeks to evaluate them.

The organisation actively engages internally and externally with other asset management practitioners, professional bodies and relevant conferences. Actively investigates and evaluates new practices and evolves its asset management activities using appropriate developments.



One important aspect of continual improvement is where an organisation looks beyond its existing boundaries and knowledge base to look at what 'new things are on the market'. These new things can include equipment, process(es), tools, etc. An organisation which does this (eg, by the PAS 55 s 4.6 standards) will be able to demonstrate that it continually seeks to expand its knowledge of all things affecting its asset management approach and capabilities. The organisation will be able to demonstrate that it identifies any such opportunities to improve, evaluates them for suitability to its own organisation and implements them as appropriate. This question explores an organisation's approach to this activity.

The top management of the organisation. The manager/team responsible for managing the organisation's asset management system, including its continual improvement. People who monitor the various items that require monitoring for 'change'. People that implement changes to the organisation's policy, strategy, etc. People within an organisation with responsibility for investigating, evaluating, recommending and implementing new tools and techniques, etc.

Research and development projects and records, benchmarking and participation knowledge exchange professional forums. Evidence of correspondence relating to knowledge acquisition. Examples of change implementation and evaluation of new tools, and techniques linked to asset management strategy and objectives.

The organisation has PAS55 and consistently demonstrates effective management review through its senior leadership team, the asset management leadership team and the sub-authorities.


Tab name: G8. AMMAT Results 05/09/2023


SCHEDULE G8: AMMAT RESULTS SUMMARY Disclosure Year (year ended) ###

ref5

6 Question Function Score7 3 Asset management policy 38 10 Asset management strategy 29 11 Asset management strategy 2

10 26 Asset management plan(s) 311 27 Asset management plan(s) 312 29 Asset management plan(s) 313 31 Asset management plan(s) 314 33 Contingency planning 315 37 Structure, authority and responsibilities 316 40 Structure, authority and responsibilities 317 42 Structure, authority and responsibilities 318 45 Outsourcing of asset management activities 319 48 Training, awareness and competence 320 49 Training, awareness and competence 321 50 Training, awareness and competence 222 53 Communication, participation and consultation 323 59 Asset Management System documentation 324 62 Information management 325 63 Information management 326 64 Information management 327 69 Risk management process(es) 228 79 Use and maintenance of asset risk information 329 82 Legal and other requirements 330 88 Life Cycle Activities 331 91 Life Cycle Activities 332 95 Performance and condition monitoring 3

33

99

334 105 Audit 235 109 Corrective & Preventative action 336 113 Continual Improvement 337 115 Continual Improvement 338

39 Overall average score 2.840

41Focus Assessment Area Questions

42 Process Asset strategy and delivery 2.6 10, 11, 26, 33, 69, 91 and 10943 Process Documentation, controls and review 2.944 Process Systems, integration and information manageme 3.0 31, 62, 63 and 6445 Process Communication and participation 3.046 People Structure, capability and authority 3.047 People Competency and training 2.848

4950515253545556575859

6061

Investigation of asset-related failures, incidents and nonconformities

Assessment Area Average

45, 59, 82, 88, 95, 105 and 113

3, 27, 42 and 5329, 37, 99 and 11540, 48, 49, 50 and 79

Assessment Area Average0.0

1.0

2.0

3.0

4.0

AMMAT summary results

Asset strategy and delivery Documentation, controls and review

Systems, integration and information management Communication and participation

Structure, capability and authority Competency and training

Scor

e

3 10 11 26 27 29 31 33 37 40 42 45 48 49 50 53 59 62 63 64 69 79 82 88 91 95 99 105

109

113

115

0

1

2

3

4

AMMAT results

AMMAT question #

Scor

e


Tab name: SO1. System Operator 05/09/2023


SCHEDULE SO1: SYSTEM OPERATOR Disclosure Year (year ended) ###

ref

5 SO1(i): Return on Investment6 CY CY7 ($000) ($000)8 Operating surplus/(deficit) 20,525.5 9 less Assets purchased or commissioned 9,963.1

10 less Tax payable 2,583.6 11 Notional cash flows for the year 7,978.8 1213 Opening fixed assets (36,821.2)1415 Closing fixed assets 34,405.4 16 plus Lost assets - 17 less Found assets - 18 Adjusted closing fixed assets 34,405.4 192021 CY-4 CY-3 CY-2 CY-1 CY22 Vanilla ROI 16.31% 16.86% 2324 Leverage (%) ` 44.00% 44.00% 25 Cost of debt (%) Transpower's Information Disclosure regulatory cost of debt 6.27% 5.11% 26 Corporate tax rate (%) 28.00% 28.00% 2728 Post-tax ROI 15.54% 16.23% 2930

SO1(ii): Regulatory Profit31 CY-4 CY-3 CY-2 CY-1 CY32 ($000) ($000) ($000) ($000) ($000)33 Total revenue - - - 41,404.8 42,964.6 3435 less Operating expenditure - - - 22,505.0 22,439.1 3637 Operating surplus/(deficit) - - - 18,899.8 20,525.5 3839 less Total depreciation 11,401.6 12,378.8 4041 Regulatory profit/(loss) before tax - - - 7,498.2 8,146.7 4243 less Tax payable 1,773.1 2,583.6 4445 Regulatory profit/(loss) after tax - - - 5,725.2 5,563.1 4647 SO1(iii): Revenue48 CY-4 CY-3 CY-2 CY-1 CY49 Revenue ($000) ($000) ($000) ($000) ($000)50 System operator service provider agreement revenue - operating 25,032.5 25,238.1

System operator service provider agreement revenue - capital 15,685.3 16,615.0 52 Technical services advisory revenue 534.4 660.2 53 Other gains /(losses) (provide details) This is the notional 2016 wash-up 152.6 451.3 54 Total revenue This is the ex-post revenue, including the wash-up - - - 41,404.8 42,964.6 5556 CY+1 CY+2 CY+3 CY+4 CY+557 Revenue forecast ($000) ($000) ($000) ($000) ($000)58 System operator service provider agreement revenue - operating 25,519.2 25,787.2 26,058.0 26,331.6 26,608.0 59 System operator service provider agreement revenue - capital 19,253.8 16,139.9 16,466.9 16,532.3 16,532.3 60 Technical services advisory revenue 492.2 497.4 502.6 507.9 513.2 61 Other gains /(losses) (provide details)62 Total forecast revenue 45,265.3 42,424.5 43,027.5 43,371.8 43,653.6 6364 CY-4 CY-3 CY-2 CY-1 CY65 Actual vs. forecast ($000) ($000) ($000) ($000) ($000)66 Historical forecast revenue This is the amount charged to the EA during the year - - - 41,252.2 42,513.3 67 Actual revenue This is the amount that should have been charged (ex-post) - - - 41,404.8 42,964.6 68 Variance ($) This is the wash-up: the amount due back to the EA. - - - (152.6) (451.3)69 Variance (%) - - - (0%) (1%)7071 SO1(iv): Operating Expenditure72 CY-4 CY-3 CY-2 CY-1 CY73 Operating expenditure ($000) ($000) ($000) ($000) ($000)74 Operating Costs 17,568.4 17,316.9 75 IT Operations 4,936.6 5,122.2 76 Opex category 3 (provide description)77 Opex category 4 (provide description)78 Opex category 5 (provide description)79 Other opex80 Total operating expenditure - - - 22,505.0 22,439.1 81 *Insert additional rows and update calculation of totals as needed82 CY+1 CY+2 CY+3 CY+4 CY+583 Operating expenditure forecast (see note below) ($000) ($000) ($000) ($000) ($000)84 Operating Costs 16,664.2 17,228.8 17,642.7 17,999.1 18,359.1 85 IT Operations 5,385.5 5,339.4 5,479.9 5,619.8 5,758.0 86 Investigation Expenses 1,101.6 1,147.8 1,172.0 1,195.7 1,219.6 87 Opex category 4 (provide description)88 Opex category 5 (provide description)89 Other opex90 Total forecast operating expenditure 23,151.2 23,715.9 24,294.6 24,814.5 25,336.7 9192 CY-4 CY-3 CY-2 CY-1 CY93 Actual vs. forecast operating expenditure ($000) ($000) ($000) ($000) ($000)94 Historical forecast operating expenditure - - - 25,032.5 23,580.5


Tab name: SO1. System Operator 05/09/2023

95 Actual operating expenditure - - - 22,505.0 22,439.1 96 Variance ($) - - - 2,527.5 1,141.4 97 Variance (%) - - - 10% 5%9899

100 SO1(v): Capital Expenditure: Commissioned capex101 CY-4 CY-3 CY-2 CY-1 CY

102 Capital expenditure ($000) ($000) ($000) ($000) ($000)103 Buildings and grounds 449.2 163.2 104 IT market systems 7,653.2 9,395.7 105 IT market changes 103.6 126.2 106 Other 1,214.8 277.9 107108 Capital Expenditure - - - 9,420.7 9,963.1 109 *Insert additional rows and update calculation of totals as needed110 CY+1 CY+2 CY+3 CY+4 CY+5111 Capital expenditure forecast (see note below) ($000) ($000) ($000) ($000) ($000)112 Buildings and grounds 1,015.7 2,593.3 78.1 336.9 - 113 IT market changes 7,667.5 2,577.3 4,258.2 2,631.8 13,095.4 114 IT market systems 4,537.0 10,988.9 3,620.7 10,354.9 5,340.1 115 Other 3,017.5 289.7 2,272.5 438.6 1,829.3 116117 Total forecast capital expenditure 16,237.7 16,449.2 10,229.5 13,762.1 20,264.8 118119 CY-4 CY-3 CY-2 CY-1 CY120 Actual vs. forecast capital expenditure ($000) ($000) ($000) ($000) ($000)121 Historical forecast capital expenditure 5,934.1 15,910.2 122 Actual capital expenditure - - - 9,420.7 9,963.1 123 Variance ($) - - - (3,486.6) 5,947.1 124 Variance (%) - - - (59%) 37%125126 SO1(vi): Fixed Assets: RAB equivalent values127 CY-4 CY-3 CY-2 CY-1 CY128 ($000) ($000) ($000) ($000) ($000)129 Opening fixed assets 38,802.1 36,821.2 130 plus Found assets131 less Disposed assets132 less Lost assets133 plus Assets purchased or commissioned 9,420.7 9,963.1 134 less Total depreciation 11,401.6 12,378.8 135 plus Adjustment resulting from asset allocation 136 Closing fixed assets - - - 36,821.2 34,405.4 137138


Tab name: Drop down boxes 05/09/2023

Drop down boxes and Categories

dd_YesNoYesNo[Select one]

dd_opexsalescapexTransmission revenuesInsurance and otherOpexBase capexMajor capexOther assets (IP, etc)Assets acquiredAssets disposedInvestmentsDebt issueLoan[Select one]

Grid R&RGrid E&DISTBusiness Support

AC StationsProtection and MeteringHVDC StationsTransmission LinesGrid E&D Transmission Systems Asset Management SystemsGrid Operations Telecommunications & NetworkCorporate SystemsIST Shared ServicesSecurity ServicesOtherOffice buildings and facilitiesSpares and inventoryProperties