ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2014

Transcription

1 ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2014

2 1 INTRODUCTION 1.1 Purpose Powerco is New Zealand s second largest electricity distribution company by customer numbers, supplying around one of every six residential customers in the country. We have the largest supply territory by area and largest overall network length. Our networks stretch across the North Island from the Coromandel to the Wairarapa. We provide an essential service to more than 320,000 homes and businesses. The electricity distribution assets we manage are capital-intensive and have long lives. We consider ourselves long-term asset stewards, providing effective and efficient asset planning and investment for current and future generations. In March 2013, we published a comprehensive Asset Management Plan, which is available on Powerco s website This Asset Management Plan Update (2014 AMP Update) builds on last year s plan and provides the latest information on Powerco s long-term strategy for managing our electricity assets. The 2014 AMP Update relates to the electricity distribution services supplied by Powerco. It covers the planning period from 1 April 2014 to 31 March 2024, and explains changes made to our asset management planning since the publication of our 2013 AMP. 1.2 Information disclosure requirements The Report on Forecast Capacity in Schedule 12b The Report on Forecast Network Demand in Schedule 12c The Report on Forecast Interruptions and Duration in Schedule 12d If an EDB has sub-networks, it must also complete the Report on Forecast Interruptions and Duration set out in Schedule 12d for each sub-network. 1.3 Structure This AMP Update has been structured to meet disclosure requirements. In the interests of brevity, we have not attempted to duplicate the more explanatory style of our full AMP. However, we would encourage readers to revert to our 2013 AMP where a greater level of detail is required. Key structural elements of this update include: Section 2.1, which provides an overview of aggregate forecast expenditure and outlines a small number of accounting and scoping changes that impact our forecasts. Sections 2.2 to 2.7, which provide detailed information on material changes to the schedules relating to this AMP update compared with our 2013 AMP. Section 3, which provides Schedules 11a 12d and 14a. Clause 2.6.3(4) in the Electricity Distribution Information Disclosure Determination 2012 requires Powerco to complete and publicly disclose, before 1 April 2014, an AMP Update. Clause states that the AMP Update must: Relate to the electricity distribution services supplied by the electricity distribution business (EDB) Identify any material changes to the network development plans disclosed in the last AMP Identify any material changes to the lifecycle asset management (maintenance and renewal) plans disclosed in the last AMP Provide the reasons for any material changes to the previous disclosures in the Report on Forecast Capital Expenditure set out in Schedule 11a and Report on Forecast Operational Expenditure set out in Schedule 11b Identify any changes to the asset management practices of the EDB that would affect Schedule 13 Report on Asset Management Maturity disclosure In addition, clause requires each EDB to complete the following reports before the start of each disclosure year: The Report on Forecast Capital Expenditure in Schedule 11a The Report on Forecast Operational Expenditure in Schedule 11b The Report on Asset Condition in Schedule 12a

3 2 Material changes since 2013 AMP Schedules 11a-12d and 14a are provided in section 3. This section provides an overview of the rational for changes to our forecasts and information provided in these schedules. This includes corrections where more reliable information is known, as well as modifications due to changes in policies or procedures. 2.1 Schedules 11a and 11b: Forecast operating and capital expenditure Overview Powerco s underlying level of expenditure has not changed substantially from the 2013 AMP. However, we have refined our accounting approach to more accurately align our expenditure classification to the Commission s guidance and accounting standards and added a number of key projects designed to optimise our approach to the management of network reliability into the future. The impact of these changes is shown in figure 1 (provided in nominal dollars) and outlined in more detail in section and below. Operating expenditure has reduced by around 7% and capital expenditure has increased by around 12% Refinement of expenditure classification Powerco is committed to continually refining its disclosure and accounting practices. Routine review during 2013 identified two key areas where a refinement of our internal processes was considered appropriate. These are set out below: Capitalisation of direct staff and support costs Powerco has progressively lifted network capital expenditure to reflect the increasing investment needs of our networks. Review of the processes used to calculate the proportion of staff and support costs for these capital programmes has highlighted the need to increase the share of future costs allocated to this category of expenditure. This has resulted in an increase in forecast capital expenditure of 5.3% and a reduction in forecast operating expenditure of 7.9%. Capital financing costs Many of our larger capital projects take time to complete, and there is a clear cost of financing these projects as they are developed and constructed. Review of our processes in this area, and analysis of applicable projects from FY2014, has highlighted our capital expenditure forecast did not reflect the full cost of financing. We have improved our forecasting methodology to ensure all applicable financing costs are captured, resulting in an increase to our capital expenditure forecast of 2.5%. The improvements to our capitalisation and cost of financing methodology ensure our costs are more in line with regulatory and financial guidance. These changes have been reviewed by Powerco s auditors and are in line with Generally Accepted Accounting Practice (GAAP). We consider it important that we continually refine our approach in this area to ensure we report our costs as closely as possible to the regulatory guidance. We consider this will make it easier for consumers to compare expenditure levels between networks Additional projects The 2014 AMP Update capex forecasts include four new key projects designed to optimise our investment approach and balance long-term costs against network performance outcome 1. These projects are noted as follows: Increased investment in automation through remote control of around $6m per year from FY18 to FY23. This will improve network visibility, helping us manage our networks to target levels and reducing call-outs and travel to remote sites. Improving our critical asset spares management and inventory with an investment of around $4m. This will improve management of network risks and help reduce outage restoration times. Upgrading our control room and data centre with an investment of around $6m over FY15 and FY16. This meets growing demands and will improve operations and resilience. Purchasing the Hinuera spur asset from Transpower in FY15. The cost of this transaction is yet to be confirmed, but is anticipated to be around $3m. We have brought forward the implementation of a new asset management system by a year. This is a crucial part of improving our asset management maturity and will deliver a range of benefits across several parts of the business Impacts of high level changes The impact of improved expenditure classification and recording, and the introduction of key new projects are illustrated below. In aggregate, total expenditure has increased, and there has been a refinement of the split between opex and capex expenditure. 1 All expenditure in section is in constant 2014 dollars. 3

4 reinforce the existing 33kV backfeed to the Hinuera GXP has been reviewed and will now be approached by a different mix of projects. There is a slight increase in overall expenditure expected resulting from developing a more detailed scope and meeting the long-term security requirements. Piako GXP Stage 2: An upgrade of a 50MVA transformer has been deferred until Putaruru GXP developments are more certain. The addition of a second transformer at the site will still proceed. Papamoa/Mt Maunganui GXPs: Property rights could not be secured for the preferred solution of a 110kV line route described in the 2013 AMP. A new approach has been developed, however the total cost is largely unchanged. 2.4 Material changes to lifecycle asset management plans Expenditure relating to renewal and lifecycle plans has not changed materially since the publication of our 2013 AMP, other than to take into account the changes outlined in section 2.1. Figure 1: 2013 and 2014 Expenditure Forecasts 2.2 Changes to asset management practices In 2013, Powerco initiated a programme of work to achieve a step-change improvement in our asset management practices with a focus on people, processes, and systems. Our goal is to move to an intermediate status on the AMMAT scale within five years. Over the last 12 months, Powerco has made solid progress in this area. We have established a strategic framework and delivered improvements to asset data management and analysis. These steps represent critical foundation elements which support our capability for real time asset management and investment forecasting. The next phase will be changing our business-as-usual processes and practices to align with this more integrated asset management foundation. As this work is still underway, we have not undertaken a review of our AMMAT score but intend to update this in In the following sections, we have noted the material changes in disclosure schedules when compared with the schedules included with our 2013 AMP. Where applicable, we have set these in context in relation to the changes we are implementing within our asset management processes. 2.3 Material changes to network development plans Expenditure relating to Powerco s network development plans has not changed materially since the publication of our 2013 AMP, other than to take into account of the changes outlined in section 2.1. There are three large projects where the scope, timing or estimated costs have been modified since the 2013 AMP. This has been managed within the capital expenditure envelope. These projects are: Hinuera - Putaruru 33kV Upgrades: Since the 2013 AMP, the method to We note that work underway to improve our asset management practices includes improving the sophistication of asset lifecycle analysis, including supporting models and documentation. More detail on this on-going programme of continuous improvement is provided in our 2013 AMP and good progress has been made in this area during The work underway will provide a strong basis to refine the quality of our asset fleet replacement forecasts. However the work it is not yet fully mature, and yet to undergo internal testing and challenge processes. For this reason we have chosen not to update our expenditure forecasts in these areas at this time. We are targeting completion of this work to inform our next comprehensive AMP, which we plan to publish in Schedule 12a: Asset condition Overview Powerco s information and analysis to support schedule 12a is still developing and we expect improvements to the data accuracy to continue over the next few years. We have made a number of changes to asset condition grading across several asset classes, in the main due to improved mapping of our asset categories to those specified by the Commerce Commission. This has resulted in different asset condition profiles (when compared to the 2013 AMP), particularly in the switchgear classes, where the Commission s schedule requires a greater amount of detail in its asset classes than we have previously provided (this issue was noted in our 2013 disclosure). Another driver of change to asset condition grading is the completion of further inspections. We have seen significant improvements in data availability and quality arising from a focus on asset inspection over the past 5 years. However, we have yet to gain a full view of all assets due primarily to the bedding in of new processes and associated data consistency issues in some areas. Therefore, we still have a number of unknown condition grades. We recognise that improving our real time asset data information is a critical element of reaching the asset management maturity level we

5 aspire to, and will continue to target year-on-year improvement. As well as the general trends above, there are also a number of specific drivers for change in our asset condition assessments: Improvement in the condition grading distribution for SCADA equipment has been noted, reflecting the large scale replacement of RTUs for the DNP3 SCADA upgrade (for protocol alignment) in Powerco s Western Region. In three cases, our data accuracy assessment has been revised down from 4 to 3, reflecting the degree of changes between 2013 and 2014 data: Distribution switchgear-reclosers and sectionalisers: Due to asset class mapping changes, resulting in a higher number of grade unknown score for this class Capacitor banks: Due to changes in the condition scores, producing an increase in grade unknown score (these are a small proportion of Powerco s asset base) Load control-centralised plant: Due to a change in our methodology in reporting this asset class. The 2014 condition scores are derived from field inspection results, and the 34% condition unknown score reflects the degree of completion of the inspection programme for these assets. The 2013 condition scores were derived from the Load Control Asset Management Plan, which considered the holistic rather than individual components Percentage of assets to be replaced in the next five years More detailed analysis of this figure for overhead line poles, zone substation transformers and SCADA equipment has been undertaken during This is a key area of focus within Powerco and improvements in forecasts represent the first step in a programme of onging enhancement as noted below. In 2013, the pole replacement forecast was not representative of the replacement rate for each pole type. Rather a generic forecast was applied across all pole types, informed by historical replacement rates. Additional work over the last year has enabled separation of those replacement rates into pole types. This is an area of analysis we continue to refine, and further data improvement is anticipated to be completed in support of our 2015 AMP. Powerco notes that until detailed work in this area work is completed, replacement rates disclosed are based on historical disposals and are not directly linked to the condition scores for this asset class (this is the case for this AMP update). Poles or lines may be replaced for many reasons, such as an increase in pole strength required for network upgrades, bringing lines up to modern design standards or reactive replacements due to motor vehicle accidents. The work we currently have underway will enable us to disaggregate this information and provide improved commentary on the drivers for replacement and associated volumes. Over the next 12 months, we will also be completing engineering analysis so we can more accurately forecast the rate of replacement for asset components such as cross arms and insulators, further refining our approach in this area. 2.6 Schedule 12b: Forecast capacity There have been no material changes to schedule 12b. The minor changes that are apparent have occurred as a result of either: Projects completed in the most recent financial year (FY14) Proposed future projects that have altered their timing following the most recent annual optimisation and prioritisation of future works plans Projects completed in FY2014 The following substations had significant changes in Schedule 12b values, due to work completed in FY2014. This impacts the first five columns of Schedule 12b. Substation Parameter(s) Changed AMP13 AMP14 Reason for Change Value Value Coromandel Firm Capacity (also affects Utilisation) None 5MVA Second transformer added. Thames Firm Capacity (also affects 7.5MVA 17MVA Transformers upgraded. Security Class and Utilisation) Bethlehem ALL New substation in FY14 Otumoetai Security Class (affected by reduced Peak Load) N N-1 Load shifted to Bethlehem Substation. Papamoa Peak Load Load shifted to Te Maunga Substation. Te Maunga ALL New substation in FY14 Farmer Rd Security Class (affected by reduced Peak Load) N N-1 Load shifted to new Tatua Substation Morrinsville Firm Capacity 7MVA 10MVA Transformers upgraded. Tahuna Firm Capacity (also affects Security Class and Utilisation) None 7MVA Second transformer added Maraetai Rd Firm Capacity 7MVA 17MVA Transformers upgraded. Brooklands Peak Load 21MVA 19MVA Load shifted to Oakura Substation. Oakura ALL New substation in FY14 Note as the schedule was developed in December 2013, but reflects status as at 31 March 2014, estimates have been made in regard to progress and commissioning of FY14 projects. If commissioning dates were near the end of the period, the project was generally treated as complete, especially since the bulk of the project expenditure would have been spent. 5

6 Year Plan Altered Project Timing The following changes to the +5 Year columns of Schedule 12b, are to be noted: Substation Whitianga Matua Omokoroa Otumoetai Atuaroa Browne St Tirau Tower Rd Waihapa Waitara West Castlecliff Fielding Kairanga Sanson Akura Parameter Changed Firm Capacity (+5 Yr) Firm Capacity (+5 Yr) Firm Capacity (+5 Yr) Firm Capacity (+5 Yr) AMP13 Value AMP14 Value Reason for Change Subtrans. - 66kV upgrades resolve Circuit subtrans constraints (Whitianga only) - Subtrans. Matua 2 nd circuit now beyond Circuit 5 Year Plan Subtrans. Transpower 33kV upgrades resolve Circuit subtrans constraints. Transpower GXP constraint affects multiple other Subs also. 12MVA 15MVA Slightly larger transformers now proposed. 15MVA 17MVA Slightly larger transformers now proposed. Transpower Transformer Hinuera GXP backstopped by Putaruru & Piako. - Transformer Tirau 2 nd transformer now beyond 5 Year Plan Transpower Transformer Hinuera GXP backstopped by Putaruru. 2 nd Transformer at Tower Rd now beyond 5 Year plan. Transformer Subtrans Circuit Transformer upgrade now in 5 Year plan. Single circuit remains as constraint. 5MVA 10MVA Larger transformers than previously proposed (fits rotation plan) - Transformer Transformer upgrades now beyond 5 Year Plan Subtrans. - 3 rd Fielding circuit brought Circuit into 5 Year plan. 15MVA 24MVA Transformer upgrades now brought into 5 Year plan. Subtrans. Circuit Transformer 2 nd Sanson circuit now in 5 Year plan. Resolves subtrans constraint, which exposes lower priority transformer constraint. Ancillary Transformer 33kV Akura - Te Ore Ore ring upgraded resolves closed ring protection constraints. Transformer Chapel Martinborough Norfolk Tuhitarata Firm Capacity (+5 Yr) Demand Growth constraint remains at Akura. Subtrans. - 33kV Chapel Norfolk ring Circuit upgrades, now in 5 Year plan 5.5MVA 0MVA 2 nd transformer now beyond 5 Year plan. Subtrans. - 33kV Chapel Norfolk ring Circuit upgrades, now in 5 Year plan - Subtrans. Circuit Growth in Peak Load just triggers a new constraint in +5 Years. The following changes are material in terms of changing the Security Class, but immaterial in terms of the magnitude of the change. The growth in peak load is very small, but in each case triggers a shift to the next lower Information Disclosure Security Class. Substation Parameter(s) Changed AMP13 AMP14 Reason for Change Value Value Paeroa Security Class N-1 N Peak Load > Firm + Transfer Douglas Security Class N-1 SW N Peak Load > Transfer Capacity Motukawa Security Class N-1 SW N Peak Load > Transfer Capacity Tuhitarata Security Class N-1 SW N Peak Load > Transfer Capacity 2.7 Schedule 12c: Forecast network demand Number of connections There is a material change to the reported number of ICPs connected in the year. However, this does not reflect a major change to Powerco s planning assumptions or underlying data. It instead reflects a definitional change due to direction given by the Commission since the publication of the 2013 AMP. The basis for number of connections has changed from the number of existing connections (as was reported in the 2013 AMP) to the actual number of new connections gross of disconnections Distributed generation There is a material change to Powerco s forecast of the Installed connection capacity of distributed generation (MVA) reported in this AMP update. Similar to above, this results from a Powerco definitional change reflecting new direction provided by the Commission.

7 The basis for installed connection capacity of distributed generation (MVA) has changed from the cumulative capacity (as was reported in the 2013 AMP) to the incremental capacity expected from new connections. 2.8 Schedule 12c: Forecast interruptions and duration Powerco s view on the level of future planned and unplanned SAIDI and SAIFI has not changed since the 2013 AMP. However, Powerco has changed its internal definition to more accurately align to the Commission s definition. Powerco s 2013 reliability forecasts were adjusted for major event days (MEDs), whereas the Commission requires an unadjusted forecast. This update removes the MED adjustment. Forecast unplanned SAIDI is the only figure impacted, and is increased by 57 SAIDI minutes. This is the average MED adjustment over the last five years ( ). 7

8 3 Schedules SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE sch ref Company Name AMP Planning Period Powerco Limited 1 April March 2024 This schedule requires a breakdown of forecast expenditure on assets for the current disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms. Also required is a forecast of the value of commissioned assets (i.e., the value of RAB additions) EDBs must provide explanatory comment on the difference between constant price and nominal dollar forecasts of expenditure on assets in Schedule 14a (Mandatory Explanatory Notes). This information is not part of audited disclosure information. 7 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 8 for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar a(i): Expenditure on Assets Forecast $000 (in nominal dollars) 10 Consumer connection 17,464 17,141 18,728 18,759 19,431 20,027 20,779 21,408 21,991 22,498 23, System growth 27,775 29,161 27,885 28,649 32,937 31,554 34,916 37,053 38,625 39,634 40, Asset replacement and renewal 39,220 43,008 44,503 45,932 59,681 62,667 70,680 77,767 82,467 86,046 89, Asset relocations 2,344 2,338 2,540 2,545 2,636 2,716 2,817 2,902 2,981 3,049 3, Reliability, safety and environment: 15 Quality of supply 5,281 15,736 12,417 12,893 25,849 27,241 28,934 27,857 28,816 26,061 26, Legislative and regulatory Other reliability, safety and environment 6,662 4,930 6,487 5,960 7,094 7,639 8,323 7,698 8,030 8,241 8, Total reliability, safety and environment 11,943 20,666 18,904 18,853 32,943 34,880 37,257 35,554 36,846 34,302 35, Expenditure on network assets 98, , , , , , , , , , , Non-network assets 7,177 7,063 9,564 11,376 8,371 4,792 5,002 5,112 5,225 5,340 5, Expenditure on assets 105, , , , , , , , , , , plus Cost of financing 3,110 3,763 3,771 3,844 4,946 5,087 5,577 5,853 6,128 6,216 6, less Value of capital contributions 14,150 14,025 15,313 15,339 15,888 16,375 16,990 17,503 17,980 18,394 18, plus Value of vested assets Capital expenditure forecast 94, , , , , , , , , , , Value of commissioned assets 107, , , , , , , , , , , Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY $000 (in constant prices) for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Consumer connection 17,464 16,798 17,950 17,583 17,784 17,935 18,208 18,355 18,449 18,469 18, System growth 27,775 28,578 26,726 26,852 30,145 28,258 30,596 31,770 32,405 32,535 32, Asset replacement and renewal 39,220 42,147 42,654 43,051 54,623 56,122 61,935 66,678 69,186 70,635 72, Asset relocations 2,344 2,291 2,434 2,385 2,412 2,432 2,469 2,488 2,501 2,503 2, Reliability, safety and environment: 38 Quality of supply 5,281 15,421 11,901 12,084 23,658 24,396 25,354 23,885 24,175 21,393 21, Legislative and regulatory Other reliability, safety and environment 6,662 4,831 6,217 5,586 6,493 6,841 7,293 6,600 6,737 6,765 6, Total reliability, safety and environment 11,943 20,252 18,119 17,670 30,152 31,237 32,648 30,485 30,912 28,158 28, Expenditure on network assets 98, , , , , , , , , , , Non-network assets 7,177 6,922 9,167 10,663 7,661 4,291 4,383 4,383 4,383 4,383 4, Expenditure on assets 105, , , , , , , , , , , Subcomponents of expenditure on assets (where known) 47 Energy efficiency and demand side management, reduction of energy losses 1,400 1,400 1,400 2,800 1,400 1, Overhead to underground conversion Research and development

9 57 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Difference between nominal and constant price forecasts $ Consumer connection ,177 1,647 2,092 2,571 3,053 3,542 4,030 4, System growth ,159 1,797 2,791 3,296 4,320 5,283 6,220 7,099 7, Asset replacement and renewal ,849 2,881 5,058 6,545 8,745 11,089 13,281 15,411 17, Asset relocations Reliability, safety and environment: 65 Quality of supply ,191 2,845 3,580 3,972 4,641 4,668 5, Legislative and regulatory Other reliability, safety and environment ,030 1,098 1,293 1,476 1, Total reliability, safety and environment ,182 2,792 3,643 4,610 5,070 5,934 6,144 6, Expenditure on network assets 0 2,247 4,677 7,197 12,511 15,860 20,594 24,908 29,457 33,229 37, Non-network assets , Expenditure on assets 0 2,388 5,074 7,910 13,220 16,360 21,213 25,637 30,298 34,186 38, Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 for year ended 31 Mar Mar Mar Mar Mar Mar a(ii): Consumer Connection 75 Consumer types defined by EDB* $000 (in constant prices) 76 Small 7,494 7,208 7,702 7,545 7,631 7, Commercial 5,925 5,700 6,091 5,966 6,034 6, Industrial 4,045 3,891 4,157 4,072 4,119 4, *include additional rows if needed 82 Consumer connection expenditure 17,464 16,798 17,950 17,583 17,784 17, less Capital contributions funding consumer connection 12,574 12,095 12,924 12,660 12,804 12, Consumer connection less capital contributions 4,890 4,704 5,026 4,923 4,979 5, a(iii): System Growth 86 Subtransmission 8,057 7,238 10,790 8,029 8,316 7, Zone substations 12,637 13,183 11,028 16,578 15,432 14, Distribution and LV lines 3,702 3,133 2, ,690 2, Distribution and LV cables 1,949 1, ,621 1, Distribution substations and transformers 1,336 2,132 1, ,811 1, Distribution switchgear Other network assets System growth expenditure 27,775 28,578 26,726 26,852 30,145 28, less Capital contributions funding system growth System growth less capital contributions 27,775 28,578 26,726 26,852 30,145 28, Current Year CY CY+1 CY+2 CY+3 CY+4 CY for year ended 31 Mar Mar Mar Mar Mar Mar a(iv): Asset Replacement and Renewal $000 (in constant prices) 106 Subtransmission 6,414 5,118 5,269 5,184 6,243 6, Zone substations 2,879 4,534 3,590 5,357 9,550 5, Distribution and LV lines 15,895 19,187 20,197 18,443 22,120 24, Distribution and LV cables 5,344 4,739 4,824 4,986 5,868 6, Distribution substations and transformers 5,222 4,844 5,086 5,192 6,173 6, Distribution switchgear 2,931 3,168 3,092 3,025 3,671 4, Other network assets , Asset replacement and renewal expenditure 39,220 42,147 42,654 43,051 54,623 56, less Capital contributions funding asset replacement and renewal Asset replacement and renewal less capital contributions 39,220 42,147 42,654 43,051 54,623 56,122 9

10 116 11a(v):Asset Relocations 117 Project or programme* 118 Transit Road Widening - Linton Transit Road Widening - Waiwhakaiho Transit Tirau Roundabout *include additional rows if needed 124 All other asset relocations projects or programmes 2,186 1,791 2,434 2,385 2,412 2, Asset relocations expenditure 2,344 2,291 2,434 2,385 2,412 2, less Capital contributions funding asset relocations 1,688 1,650 1,753 1,717 1,737 1, Asset relocations less capital contributions a(vi):Quality of Supply 130 Project or programme* 131 Automation projects 2,070 3,311 2,167 2,701 8,678 8, Distribution backfeed enhancement 1,710 1, Subtransmission & zone security enhancement 426 1,289 3,930 3,749 2,746 4, Putaruru GXP 870 3,626 3, Voltage regulator *include additional rows if needed 137 All other quality of supply projects or programmes 204 4,840 1,305 4,449 12,024 11, Quality of supply expenditure 5,281 15,421 11,901 12,084 23,658 24, less Capital contributions funding quality of supply Quality of supply less capital contributions 5,281 15,421 11,901 12,084 23,658 24, a(vii): Legislative and Regulatory 143 Project or programme* 144 Nil *include additional rows if needed 150 All other legislative and regulatory projects or programmes Legislative and regulatory expenditure less Capital contributions funding legislative and regulatory Legislative and regulatory less capital contributions

11 162 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 for year ended 31 Mar Mar Mar Mar Mar Mar a(viii): Other Reliability, Safety and Environment 164 Project or programme* $000 (in constant prices) 165 LV safety improvement 1,375 1,235 1,419 1,387 1, Oil containment Switchgear safety replacement 1,350 1,198 1,054 1, , *include additional rows if needed 171 All other reliability, safety and environment projects or programmes 3,724 1,972 3,285 2,952 4,123 4, Other reliability, safety and environment expenditure 6,662 4,831 6,217 5,586 6,493 6, less Capital contributions funding other reliability, safety and environment Other reliability, safety and environment less capital contributions 6,662 4,831 6,217 5,586 6,493 6, a(ix): Non-Network Assets 179 Routine expenditure 180 Project or programme* 181 Think Safe Programme Improve & Expand Network Data & Tools IT Renewal Site improvement capex *include additional rows if needed 187 All other routine expenditure projects or programmes 819 1,043 1,413 1, Routine expenditure 2,793 2,809 3,140 3,071 2,024 1, Atypical expenditure 190 Project or programme* 191 Improve Network Operations (OMS / DMS) 1,638 2,007 1,570 1,535 1, Enterprise Asset Management System ,311 2, Upgrade of Network Operations Centre and Data Centre - 1,662 3, *include additional rows if needed 197 All other atypical projects or programmes 2, ,765 2, Atypical expenditure 4,385 4,112 6,027 7,592 5,638 2, Non-network assets expenditure 7,177 6,922 9,167 10,663 7,661 4,291 11

12 SCHEDULE 11b: REPORT ON FORECAST OPERATIONAL EXPENDITURE sch ref Company Name AMP Planning Period This schedule requires a breakdown of forecast operational expenditure for the disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms. EDBs must provide explanatory comment on the difference between constant price and nominal dollar operational expenditure forecasts in Schedule 14a (Mandatory Explanatory Notes). This information is not part of audited disclosure information. Powerco Limited 1 April March Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 8 for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar 24 9 Operational Expenditure Forecast $000 (in nominal dollars) 10 Service interruptions and emergencies 5,613 7,201 7,341 7,241 8,865 9,810 10,083 10,285 10,500 10,366 10, Vegetation management 4,681 5,080 4,717 5,299 9,801 10,669 11,016 11,235 11,464 10,987 11, Routine and corrective maintenance and inspection 11,229 8,778 9,128 10,090 14,692 15,776 17,099 17,543 18,021 17,470 17, Asset replacement and renewal 8,293 9,044 10,675 11,378 11,671 11,919 12,156 12,473 12,754 13,016 13, Network Opex 29,815 30,102 31,861 34,008 45,029 48,174 50,355 51,537 52,739 51,839 52, System operations and network support 14,232 12,317 12,447 12,420 13,736 13,927 13,944 14,110 14,288 14,397 14, Business support 25,301 24,908 25,076 23,592 23,469 23,876 24,201 24,648 25,108 25,621 26, Non-network opex 39,534 37,225 37,523 36,011 37,205 37,803 38,146 38,758 39,396 40,018 40, Operational expenditure 69,349 67,327 69,384 70,019 82,234 85,977 88,500 90,294 92,134 91,857 93, Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar $000 (in constant prices) 22 Service interruptions and emergencies 5,613 7,057 7,036 6,787 8,114 8,785 8,836 8,819 8,809 8,510 8, Vegetation management 4,681 4,978 4,521 4,966 8,970 9,555 9,653 9,633 9,618 9,019 8, Routine and corrective maintenance and inspection 11,229 8,602 8,749 9,457 13,447 14,129 14,983 15,042 15,119 14,341 14, Asset replacement and renewal 8,293 8,863 10,231 10,664 10,682 10,674 10,652 10,695 10,700 10,685 10, Network Opex 29,815 29,500 30,537 31,875 41,213 43,143 44,125 44,188 44,245 42,554 42, System operations and network support 14,232 12,070 11,929 11,641 12,572 12,473 12,219 12,098 11,987 11,818 11, Business support 25,301 24,410 24,034 22,112 21,480 21,382 21,207 21,133 21,064 21,032 21, Non-network opex 39,534 36,480 35,964 33,752 34,052 33,855 33,426 33,231 33,051 32,851 32, Operational expenditure 69,349 65,980 66,501 65,627 75,265 76,997 77,551 77,419 77,296 75,405 75, Subcomponents of operational expenditure (where known) 32 Energy efficiency and demand side management, reduction of 33 energy losses Direct billing* Research and Development Insurance 981 1,057 1,110 1,165 1,224 1,285 1,349 1,416 1,487 1,562 1, * Direct billing expenditure by suppliers that direct bill the majority of their consumers Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Difference between nominal and real forecasts $ Service interruptions and emergencies ,025 1,248 1,467 1,691 1,857 2, Vegetation management ,114 1,363 1,602 1,846 1,968 2, Routine and corrective maintenance and inspection ,245 1,648 2,116 2,501 2,902 3,129 3, Asset replacement and renewal ,245 1,504 1,779 2,054 2,331 2, Network Opex ,324 2,133 3,816 5,032 6,230 7,349 8,493 9,285 10, System operations and network support ,164 1,455 1,725 2,012 2,301 2,579 2, Business support ,042 1,480 1,989 2,494 2,994 3,515 4,044 4,589 5, Non-network opex ,559 2,259 3,153 3,948 4,720 5,526 6,345 7,167 8, Operational expenditure - 1,347 2,883 4,392 6,969 8,980 10,950 12,875 14,838 16,452 18,455

13 SCHEDULE 12a: REPORT ON ASSET CONDITION Company Name AMP Planning Period Powerco Limited 1 April March 2024 This schedule requires a breakdown of asset condition by asset class as at the start of the forecast year. The data accuracy assessment relates to the percentage values disclosed in the asset condition columns. Also required is a forecast of the percentage of units to be replaced in the next 5 years. All information should be consistent with the information provided in the AMP and the expenditure on assets forecast in Schedule 11a. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. sch ref 7 Asset condition at start of planning period (percentage of units by grade) 8 % of asset forecast Voltage Asset category Asset class Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknown Data accuracy to be replaced in (1 4) next 5 years 9 10 All Overhead Line Concrete poles / steel structure No. 0.07% 1.31% 3.92% 68.42% 26.28% % 11 All Overhead Line Wood poles No. 0.31% 9.40% 27.58% 33.96% 28.75% % 12 All Overhead Line Other pole types No % 0.89% 9.20% 89.48% % 13 HV Subtransmission Line Subtransmission OH up to 66kV conductor km 0.17% 0.37% 10.04% 67.60% 21.81% % 14 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km % 45.40% % 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km % HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km N/A 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 22 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km N/A 23 HV Subtransmission Cable Subtransmission submarine cable km N/A 24 HV Zone substation Buildings Zone substations up to 66kV No % 25.20% 71.54% % 25 HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 22/33kV CB (Indoor) No % 11.54% 86.54% % 27 HV Zone substation switchgear 22/33kV CB (Outdoor) No % 83.63% % 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No % 90.00% % 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No % 2.80% 53.92% 42.94% % 30 HV Zone substation switchgear 33kV RMU No % 2-31 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 32 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No % 75.00% 2-33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No % 5.22% 80.22% 11.52% % 34 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No % 7.14% % 13

14 42 43 Asset condition at start of planning period (percentage of units by grade) Voltage Asset category Asset class Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknown HV Zone Substation Transformer Zone Substation Transformers No. 0.55% 11.60% 70.17% 17.68% % 46 HV Distribution Line Distribution OH Open Wire Conductor km 0.18% 1.42% 13.80% 56.81% 27.79% % 47 HV Distribution Line Distribution OH Aerial Cable Conductor km N/A 48 HV Distribution Line SWER conductor km % 1.85% 74.90% 22.22% % 49 HV Distribution Cable Distribution UG XLPE or PVC km % 98.00% 1.40% % 50 HV Distribution Cable Distribution UG PILC km % % 51 HV Distribution Cable Distribution Submarine Cable km % 92.10% HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No % 2.13% 59.70% 37.31% % 53 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No % 73.00% 10.00% % 54 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No % 0.83% 10.22% 88.66% % 55 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No % 8.12% 71.32% 18.83% % 56 HV Distribution switchgear 3.3/6.6/11/22kV RMU No % 5.61% 83.37% 10.55% % 57 HV Distribution Transformer Pole Mounted Transformer No % 16.73% 49.85% 31.09% % 58 HV Distribution Transformer Ground Mounted Transformer No % 19.07% 71.62% 6.33% % 59 HV Distribution Transformer Voltage regulators No % % 31.47% 4-60 HV Distribution Substations Ground Mounted Substation Housing No % 20.00% 70.00% 5.00% 1-61 LV LV Line LV OH Conductor km 0.13% 1.28% 12.80% 56.16% 29.63% % 62 LV LV Cable LV UG Cable km % 40.00% LV LV Streetlighting LV OH/UG Streetlight circuit km % 44.00% 36.00% LV Connections OH/UG consumer service connections No % 14.65% 42.36% 40.36% % 65 All Protection Protection relays (electromechanical, solid state and numeric) No % 76.87% 22.00% % 66 All SCADA and communications SCADA and communications equipment operating as a single system Lot % 13.95% 72.97% 8.14% % 67 All Capacitor Banks Capacitors including controls No % 15.22% 3-68 All Load Control Centralised plant Lot % 11.36% 50.00% 34.09% % 69 All Load Control Relays No. N/A 70 All Civils Cable Tunnels km N/A Data accuracy (1 4) % of asset forecast to be replaced in next 5 years

15 SCHEDULE 12b: REPORT ON FORECAST CAPACITY This schedule requires a breakdown of current and forecast capacity and utilisation for each zone substation and current distribution transformer capacity. The data provided should be consistent with the information provided in the AMP. Information provided in this table should relate to the operation of the network in its normal steady state configuration. Company Name Powerco Limited AMP Planning Period 1 April March 2024 sch ref 7 12b(i): System Growth - Zone Substations Refer Note 5 Refer Note 1 Refer Note 2 Refer Note 3 8 Existing Zone Substations Current Peak Load (MVA) Installed Firm Capacity (MVA) Security of Supply Classification (type) Transfer Capacity (MVA) Utilisation of Installed Firm Capacity % Installed Firm Capacity +5 years (MVA) Utilisation of Installed Firm Capacity + 5yrs % Installed Firm Capacity +5 years (cause) Coromandel N - 101% % Subtransmission circuit Single 66kV circuit. Kerepehi N % % Subtransmission circuit Single 66kV circuit. 66kV upgrade in progress but not complete. Matatoki N Transformer Single Tx Tairua N % % Transformer Just over Tx firm capacity. Thames N % % No constraint within +5 years Thames T N-1 SW No constraint within +5 years Whitianga N % % No constraint within +5 years Upgraded 66kV circuits. New Whenuakite sub (proposed) offloads Whitianga. Paeroa N % % No constraint within +5 years Transfer capacity provides adequate security Waihi N % % No constraint within +5 years Customer agreed security. Waihi Beach N % Subtransmission circuit Single 33kV circuit Whangamata N % % No constraint within +5 years Second 33kV circuit proposed. Aongatete N % % No constraint within +5 years Transfer capacity provides required security Bethlehem N-1 SW No constraint within +5 years New Substation Hamilton St N % % No constraint within +5 years Katikati N % No constraint within +5 years Kauri Pt N Subtransmission circuit Single Tx and 33kV circuit Matapihi N % % No constraint within +5 years Matua N % % Subtransmission circuit Single 33kV circuit Omanu N % % No constraint within +5 years Omokoroa N % % Transpower 33kV subtrans upgraded, GXP & 110kV constrained. Otumoetai N % % No constraint within +5 years Papamoa N % % No constraint within +5 years Offloaded to other new Subs. Te Maunga N-1 SW No constraint within +5 years New Substation Triton N % % No constraint within +5 years Waihi Rd N % % No constraint within +5 years Welcome Bay N % % No constraint within +5 years Atuaroa N % Subtransmission circuit 33kV tee section (single circuit) Pongakawa N % % Subtransmission circuit Single 33kV circuit Te Puke N % % No constraint within +5 years Farmer Rd N % % No constraint within +5 years Inghams N No constraint within +5 years Customer agreed security Mikkelsen Rd N % % No constraint within +5 years Morrinsville N % % No constraint within +5 years 2nd 33kV circuit proposed in next 5 yrs Piako N % % No constraint within +5 years Tahuna N % % Subtransmission circuit Single 33kV circuit. Tatua N No constraint within +5 years Customer agreed security Waitoa N-1-78% % No constraint within +5 years Walton N Transformer Single Transformer & Transfer < Peak Browne St N % % Transformer Firm capacity just less than Peak Load - Transfer 9 Lake Rd N % No constraint within +5 years 10 Tirau N Transformer Single transformer. 11 Putaruru N % % No constraint within +5 years New GXP and subtransmission upgrades proposed. 12 Tower Rd N Transformer GXP and Subtrans upgrades proposed. Single Tx. 13 Waharoa N Subtransmission circuit 33kV upgrades increase Subtrans capacity 14 Baird Rd N % % No constraint within +5 years 15 Lakeside + Midway N - 144% % No constraint within +5 years Customer agreed security Explanation 15

16 16 Maraetai Rd N % % No constraint within +5 years 17 Bell Block N % % No constraint within +5 years 18 Brooklands N % % No constraint within +5 years 19 Cardiff N No constraint within +5 years 20 City N % % No constraint within +5 years Cloton Rd N % % No constraint within +5 years 21 Douglas N No constraint within +5 years 22 Eltham N % % No constraint within +5 years 23 Inglewood N % % No constraint within +5 years 24 Kaponga N % % No constraint within +5 years Katere N % % No constraint within +5 years McKee N % - - No constraint within +5 years Motukawa N No constraint within +5 years Moturoa N % % No constraint within +5 years Oakura N-1 SW No constraint within +5 years New Substation Pohokura N-1-60% % No constraint within +5 years Waihapa N % - - Subtransmission circuit Single Tx & Single 33kV Tee Waitara East N % % No constraint within +5 years Waitara West N % % No constraint within +5 years Cambria N % % No constraint within +5 years Kapuni N % % No constraint within +5 years Livingstone N % % Transformer Peak Load > Firm Tx Capacity + Transfer Manaia N Subtransmission circuit Section of single 33kV circuit Ngariki N-1 SW No constraint within +5 years Pungarehu N % % No constraint within +5 years Tasman N % % No constraint within +5 years Whareroa N No constraint within +5 years Beach Rd N % Subtransmission circuit Proposed 33kV upgrades - completed FY20+ Blink Bonnie N No constraint within +5 years Castlecliff N % % Transformer Switching speed inadequate for Tx fault Hatricks Wharf N Other Switched c/o inadequate for full (breakless) N-1 Kai Iwi N Subtransmission circuit Single 33kV cct & single Tx. Peat St N % % Transpower Single GXP transformer. Roberts Ave N Transpower Single GXP transformer. Taupo Quay N-1 SW Subtransmission circuit Proposed 33kV upgrades - completed FY20+ Wanganui East N Subtransmission circuit Single 33kV circuit & single transformer Taihape N Transformer Single transformer Waiouru N Transformer Single transformer Arahina N Subtransmission circuit Single 33kV and single transformer Bulls N Subtransmission circuit Single 33kV circuit & single transformer Pukepapa N-1 SW No constraint within +5 years Rata N No constraint within +5 years Proposed increase in transfer capacity Feilding N % % No constraint within +5 years Proposed 33kV upgrades in 5Yr plan Kairanga N % % Ancillary Equipment Comms / Prot prevent closed ring. Keith St N % % No constraint within +5 years Proposed new Sub offloads circuits Kelvin Grove N % % No constraint within +5 years Kimbolton N Subtransmission circuit Single 33kV circuit & single transformer Main St N % % No constraint within +5 years Proposed new Sub and 33kV circuits Milson N % % No constraint within +5 years Pascal St N % % No constraint within +5 years Sanson N % % Transformer Proposed 2nd circuit. Switched transfer capacity. Turitea N % % Subtransmission circuit Single main 33kV circuit, with switched backfeed Alfredton N-1 SW No constraint within +5 years Mangamutu N % % No constraint within +5 years