ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2015

Transcription

1 ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2015

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 (2015 AMP Update) provides the latest information on our forecasts and on Powerco s long-term strategy for managing our electricity assets. The 2015 AMP Update relates to the electricity distribution services supplied by Powerco. It covers the planning period from 1 April 2015 to 31 March 2025, and explains changes made to our asset management planning since the publication of our previous AMP. 1.2 Information disclosure requirements Clause 2.6.3(4) in the Electricity Distribution Information Disclosure Determination 2012 requires Powerco to complete and publicly disclose, before 1 April 2015, 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 (or AMP Update) Identify any material changes to the lifecycle asset management (maintenance and renewal) plans disclosed in the last AMP (or AMP Update) 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 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

3 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 and is in the same format as our previous AMP Updates. In the interests of brevity, we have not attempted to duplicate the detailed explanations in our full AMP. However, we would encourage readers to revert to our AMP whenever a greater level of detail is required. Section 2 provides an overview of aggregate forecast expenditure and outlines a small number of changes that have affected our forecasts. It also provides information on material changes to the schedules since our previous disclosure. Section 3 includes Schedules 11a 12d. 3

4 2 Material changes Schedules 11a-12d are included in section 3. This section provides an overview of the rationale for changes to our forecasts and the information provided in these schedules, as well as material changes to network development plans, asset lifecycle plans and asset management practices. In general, disclosure information related to expenditure forecasts, asset condition, forecast capacity, forecast demand, and forecast interuptions remains consistent with that included in our 2014 AMP Update and subject only to minor refinement. We belive these forecasts continue to provide a realistic view of future investment requirements and network performance. 2.1 Material changes to network development plans There are no material changes to our network development plans, relative to our 2014 AMP Update, other than to take into account the impact of large projects where the timing has been modified and this has affected the expenditure profile. These projects are: The purchase of Hinuera Spur Line ($3.3m), the transfer of which is now anticipated in FY17 (formerly FY15) The Putaruru and Papamoa projects, which have been deferred, commissioning of which is now anticipated during FY18 (formerly FY17) This deferral was due to slower than anticipated progress with land access negotiations that must be completed before the connecting lines can be built. 2.2 Material changes to lifecycle asset management plans There are no material changes to the renewal and lifecycle plans included in our 2014 AMP Update. 2.3 Material changes to asset management practices There have been no material changes to the asset management practices that underpin the development of this AMP update. We are currently in the process of refining the asset management tools, models, practices and processes and these changes will be reflected in future editions of our AMP. 2.4 Material changes to schedules 11a and 11b: Forecast operating and capital expenditure. Forecast operating and capital expenditure (pre-capitalisation) remains consistent with that noted in our 2014 AMP Update, and a comparison of forecast variance is provided below:

5 Figure 1: 2014 and 2015 Expenditure Forecasts The changes relate to the following refinements to the methodology used to develop our expenditure forecasts: The forecast of nominal capex has fallen slightly as the long-term inflator used has declined from 2.2% to 2.0% to reflect the latest expected changes in inflation. A number of significant customer-driven projects have led to an increase in capital contributions of approximately $4m in the FY15 year. Capital expenditure qualifying for interest capitalisation has been updated using the latest information (42% to 28%). This has slightly reduced the forecast of the cost of financing. The purchase of Hinuera spur line ($3.3m) has been moved from FY15 to FY17. The timing of expenditure on some elements of the Papamoa and Putaruru project has changed, with commissioning now anticipated during FY Material changes to Schedule 12a: Asset condition There have been a number of minor refinements made to Schedule 12a relating to improvements to our underlying methodologies. Key changes are: Alignment to the EEA Asset Health Indicator Guide, in particular for older problematic cable types, and for communciations equipment; Improved mapping of assets to categories reflecting the latest Commerce Commission guideance; Utilisation of improved data and resolution of data gaps as our asset inspection processes mature. The overall effect of these changes is a refinement of asset condition classification and categorisation. Data accuracy classifications remain consistent 5

6 with the position noted in our 2014 AMP Update. 2.6 Schedule 12b: Forecast capacity Forecast network capacity remains consistent with that noted in our 2014 AMP Update. There have been a number of minor refinements which relate to the following: Projects completed in the most recent financial year (FY15); Updated information on peak loads, derived from an improved forecasting methodology; Improved information on load transfer at new substations, which has influenced information for Bethlehem, Otumoetai and Te Maunga substations. 2.7 Schedule 12c: Forecast network demand Forecast network demand remains consistent with our 2014 AMP Update. There have been a number of minor refinements due to enhancements to our forecasting methodology, in particular: ICP growth is now based on using Statistics NZ s population growth forecast (previously the dwelling growth forecast); DG connection rate forecasts (in particular PV installations) have been moderated in line with latest trends and information; Large scale DG impact has been upated to reflect the latest information. Powerco continues to experience a decoupling of volume (0.6%p.a.) from peak demand trends (1.4% p.a). 2.8 Schedule 12d: Forecast interruptions and duration Overall our performance targets remain consistent with Commerce Commisison targets and we remain committed to delivering network performance in line with these targets. In parcular: Our forecast SAIDI performance remains in line with the position noted in our 2014 AMP Update; Our SAIFI forecast has been revised down reflecting historical performance improvements in this area. We note the significant challenge associated with simultaneously delivering forecast increased work volumes (requiring greater access to and isolation of the network to support additional works) and holding network performance stable. This situation is under review as we move to consider our approach to delivering additonal work volumes in greater detail.

7 3 Schedules SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE Company Name AMP Planning Period Powerco Limited 1 April March 2025 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 sch ref 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 23,139 18,658 18,669 19,242 19,781 20,484 21,062 21,593 22,048 22,506 22, System growth 28,835 26,090 37,898 31,742 31,166 34,419 36,454 37,926 38,841 39,733 40, Asset replacement and renewal 41,012 44,535 45,711 59,103 61,896 69,673 76,510 80,975 84,324 87,687 91, Asset relocations 4,056 2,530 2,533 2,610 2,683 2,777 2,855 2,927 2,988 3,050 3, Reliability, safety and environment: 15 Quality of supply 7,329 12,370 12,831 25,599 26,906 28,522 27,406 28,294 25,539 26,102 26, Legislative and regulatory Other reliability, safety and environment 6,855 6,463 5,931 7,026 7,545 8,205 7,573 7,885 8,076 8,263 8, Total reliability, safety and environment 14,183 18,833 18,762 32,625 34,451 36,727 34,980 36,179 33,615 34,365 35, Expenditure on network assets 111, , , , , , , , , , , Non-network assets 5,531 9,379 12,346 8,830 6,020 4,894 5,029 5,130 5,233 5,337 5, Expenditure on assets 116, , , , , , , , , , , plus Cost of financing 1,975 2,119 2,366 2,730 2,719 2,967 3,000 3,031 3,064 3,163 3, less Value of capital contributions 18,088 14,408 14,417 14,860 15,275 15,817 16,263 16,673 17,025 17,378 17, plus Value of vested assets Capital expenditure forecast 100, , , , , , , , , , , Value of commissioned assets 96, , , , , , , , , , , Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 for year ended 31 Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar Mar $000 (in constant prices) 33 Consumer connection 23,139 18,238 17,865 18,069 18,223 18,500 18,649 18,745 18,765 18,779 18, System growth 28,835 25,503 36,265 29,806 28,711 31,086 32,279 32,924 33,057 33,153 33, Asset replacement and renewal 41,012 43,533 43,741 55,498 57,021 62,927 67,747 70,295 71,767 73,166 74, Asset relocations 4,056 2,473 2,424 2,451 2,471 2,508 2,528 2,541 2,543 2,545 2, Reliability, safety and environment: 38 Quality of supply 7,329 12,092 12,278 24,037 24,786 25,760 24,267 24,562 21,736 21,780 21, Legislative and regulatory Other reliability, safety and environment 6,855 6,317 5,676 6,597 6,951 7,410 6,706 6,845 6,874 6,894 6, Total reliability, safety and environment 14,183 18,409 17,954 30,635 31,737 33,171 30,973 31,407 28,609 28,674 28, Expenditure on network assets 111, , , , , , , , , , , Non-network assets 5,531 9,168 11,814 8,291 5,546 4,420 4,453 4,453 4,453 4,453 4, Expenditure on assets 116, , , , , , , , , , , Subcomponents of expenditure on assets (where known) 47 Energy efficiency and demand side management, reduction of energy losses 1,400 1,400 2,800 1,400 1, Overhead to underground conversion Research and development 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 ,174 1,558 1,983 2,412 2,848 3,283 3,727 4, System growth ,633 1,936 2,455 3,333 4,175 5,002 5,784 6,580 7, Asset replacement and renewal - 1,003 1,970 3,605 4,875 6,746 8,763 10,680 12,557 14,522 16, Asset relocations Reliability, safety and environment: 65 Quality of supply ,561 2,119 2,762 3,139 3,732 3,803 4,323 4, Legislative and regulatory Other reliability, safety and environment ,040 1,203 1,368 1, Total reliability, safety and environment ,990 2,713 3,556 4,006 4,772 5,006 5,691 6, Expenditure on network assets - 2,491 5,325 8,863 11,812 15,887 19,684 23,689 27,076 31,025 35, Non-network assets Expenditure on assets - 2,702 5,857 9,402 12,286 16,361 20,260 24,365 27,855 31,909 36,083 7

8 72 73 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 9,159 7,219 7,071 7,152 7,213 7, Commercial 9,095 7,168 7,022 7,102 7,163 7, Industrial 4,886 3,851 3,772 3,815 3,848 3, *include additional rows if needed 82 Consumer connection expenditure 23,139 18,238 17,865 18,069 18,223 18, less Capital contributions funding consumer connection 15,331 12,402 12,148 12,287 12,392 12, Consumer connection less capital contributions 7,809 5,836 5,717 5,782 5,831 5, a(iii): System Growth 86 Subtransmission 6,439 11,940 13,498 8,167 7,893 8, Zone substations 6,172 7,169 16,253 15,096 14,302 15, Distribution and LV lines 5, ,458 2,669 2,548 2, Distribution and LV cables 2, ,710 1,640 1, Distribution substations and transformers 6,856 3,098 3,331 1,891 2,072 2, Distribution switchgear Other network assets 1,910 2, System growth expenditure 28,835 25,503 36,265 29,806 28,711 31, less Capital contributions funding system growth System growth less capital contributions 28,835 25,503 36,265 29,806 28,711 31, 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 4,700 3,008 4,423 6,343 7,084 7, Zone substations 3,640 6,714 7,046 9,703 5,883 6, Distribution and LV lines 18,254 20,734 17,742 22,474 25,095 27, Distribution and LV cables 5,252 4,873 5,767 5,962 6,657 7, Distribution substations and transformers 5,156 4,630 3,954 6,272 7,004 7, Distribution switchgear 3,023 3,037 3,520 3,730 4,166 4, Other network assets ,289 1,013 1,131 1, Asset replacement and renewal expenditure 41,012 43,533 43,741 55,498 57,021 62, less Capital contributions funding asset replacement and renewal Asset replacement and renewal less capital contributions 41,012 43,533 43,741 55,498 57,021 62, a(v):Asset Relocations 117 Project or programme* 118 Devon Road *include additional rows if needed 124 All other asset relocations projects or programmes 3,832 1,801 2,424 2,451 2,471 2, Asset relocations expenditure 4,056 2,473 2,424 2,451 2,471 2, less Capital contributions funding asset relocations 2,758 1,682 1,648 1,667 1,680 1, Asset relocations less capital contributions 1, a(vi):Quality of Supply 130 Project or programme* 131 Automation projects 3,598 3,083 2,849 8,825 7,575 6, Distribution backfeed enhancement , Subtransmission & zone security enhancement 1,860 4,520 4,000 8,700 6, Putaruru GXP Voltage regulator *include additional rows if needed 137 All other quality of supply projects or programmes 715 3,453 3,649 6,433 11,012 18, Quality of supply expenditure 7,329 12,092 12,278 24,037 24,786 25, less Capital contributions funding quality of supply Quality of supply less capital contributions 7,329 12,092 12,278 24,037 24,786 25,

9 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 Current Year CY CY+1 CY+2 CY+3 CY+4 CY a(viii): Other Reliability, Safety and Environment for year ended 31 Mar Mar Mar Mar Mar Mar Project or programme* $000 (in constant prices) 165 LV safety improvement 1,315 1,920 1,930 1, Oil containment Switchgear safety replacement 1,447 1, , Zone sub seismic and safety Earth Fault Neutraliser Zone Sub equipment upgrades New Cable and Overhead Line *include additional rows if needed 171 All other reliability, safety and environment projects or programmes 1,980 2,117 (184) 2,997 5,147 6, Other reliability, safety and environment expenditure 6,855 6,317 5,676 6,597 6,951 7, less Capital contributions funding other reliability, safety and environment Other reliability, safety and environment less capital contributions 6,855 6,317 5,676 6,597 6,951 7, a(ix): Non-Network Assets 179 Routine expenditure 180 Project or programme* 181 Think Safe Programme Improve & Expand Network Data & Tools IT Renewal ,219 1,219 1, Site improvement capex *include additional rows if needed 187 All other routine expenditure projects or programmes 2,083 1,715 1,837 1,604 1,614 1, Routine expenditure 3,658 3,658 3,658 3,658 3,658 3, Atypical expenditure 190 Project or programme* 191 Enterprise Asset Management System ,251 3,251 1, Upgrade of Network Operations Centre , Data Centre (DR) - 2, Improve Network Operations (OMS/ DMS) 1,219 1,626 1, Customer Engagement *include additional rows if needed 197 All other atypical projects or programmes Atypical expenditure 1,874 5,510 8,156 4,633 1, Non-network assets expenditure 5,531 9,168 11,814 8,291 5,546 4,420 9

10 SCHEDULE 11b: REPORT ON FORECAST OPERATIONAL EXPENDITURE 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. sch ref 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 25 9 Operational Expenditure Forecast $000 (in nominal dollars) 10 Service interruptions and emergencies 6,332 7,314 7,206 8,779 9,689 9,940 10,119 10,310 10,159 10,344 10, Vegetation management 5,010 4,700 5,273 9,706 10,538 10,859 11,053 11,257 10,767 10,946 11, Routine and corrective maintenance and inspection 10,496 9,093 10,041 14,550 15,582 16,856 17,260 17,695 17,120 17,507 17, Asset replacement and renewal 7,219 8,588 9,233 11,558 11,772 11,983 12,272 12,523 12,755 13,032 13, Network Opex 29,058 29,695 31,753 44,593 47,582 49,638 50,703 51,784 50,801 51,828 52, System operations and network support 9,597 10,431 10,348 11,231 11,338 11,279 11,365 11,462 11,489 11,656 11, Business support 29,697 32,734 30,932 29,922 30,500 31,110 31,732 32,366 33,014 33,674 34, Non-network opex 39,295 43,165 41,280 41,154 41,837 42,388 43,097 43,828 44,503 45,330 46, Operational expenditure 68,353 72,860 73,033 85,747 89,419 92,026 93,800 95,613 95,304 97,158 99, 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 6,332 7,149 6,896 8,244 8,926 8,977 8,960 8,950 8,646 8,631 8, Vegetation management 5,010 4,594 5,046 9,114 9,708 9,808 9,787 9,772 9,164 9,133 9, Routine and corrective maintenance and inspection 10,496 8,889 9,609 13,663 14,355 15,224 15,283 15,361 14,570 14,608 14, Asset replacement and renewal 7,219 8,395 8,835 10,853 10,845 10,823 10,866 10,872 10,856 10,874 10, Network Opex 29,058 29,027 30,385 41,873 43,834 44,832 44,896 44,954 43,236 43,245 43, System operations and network support 9,597 10,196 9,902 10,546 10,445 10,187 10,063 9,950 9,778 9,726 9, Business support 29,697 31,997 29,599 28,097 28,097 28,097 28,097 28,097 28,097 28,097 28, Non-network opex 39,295 42,193 39,501 38,644 38,542 38,284 38,161 38,047 37,876 37,823 37, Operational expenditure 68,353 71,220 69,886 80,517 82,376 83,116 83,057 83,002 81,112 81,068 81, Subcomponents of operational expenditure (where known) Energy efficiency and demand side management, reduction of energy losses Direct billing* 35 Research and Development Insurance 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 $000 Powerco Limited 1 April March Service interruptions and emergencies ,159 1,360 1,513 1,713 1, Vegetation management ,051 1,266 1,485 1,603 1,813 2, Routine and corrective maintenance and inspection ,227 1,632 1,977 2,334 2,549 2,899 3, Asset replacement and renewal ,160 1,406 1,652 1,899 2,158 2, Network Opex ,368 2,720 3,748 4,806 5,807 6,830 7,565 8,583 9, System operations and network support ,092 1,302 1,512 1,711 1,930 2, Business support ,333 1,825 2,402 3,012 3,634 4,269 4,916 5,577 6, Non-network opex ,779 2,510 3,295 4,104 4,936 5,781 6,627 7,507 8, Operational expenditure - 1,640 3,147 5,230 7,043 8,910 10,743 12,611 14,192 16,090 18,024

11 SCHEDULE 12a: REPORT ON ASSET CONDITION Company Name AMP Planning Period Powerco Limited 1 April March 2025 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. 0.08% 1.55% 18.08% 70.04% 10.26% % 11 All Overhead Line Wood poles No. 0.43% 8.94% 37.40% 37.18% 16.05% % 12 All Overhead Line Other pole types No % 1.55% 11.91% 86.10% % 13 HV Subtransmission Line Subtransmission OH up to 66kV conductor km 0.01% 0.22% 31.53% 59.30% 8.93% % 14 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km % 91.00% % 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 % 16.15% 76.15% % 25 HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 22/33kV CB (Indoor) No % 87.50% 10.42% % 27 HV Zone substation switchgear 22/33kV CB (Outdoor) No % 6.88% 43.39% 48.68% % 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No % 31.25% % 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No % 4.00% 75.91% 19.06% % 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 % 57.14% 2-33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No % 7.32% 90.07% 1.12% % 34 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No % 77.78% 18.52% % 11

12 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 45 HV Zone Substation Transformer Zone Substation Transformers No. 0.53% 11.76% 66.84% 20.86% % 46 HV Distribution Line Distribution OH Open Wire Conductor km 0.16% 1.82% 25.58% 51.80% 20.65% % 47 HV Distribution Line Distribution OH Aerial Cable Conductor km N/A 48 HV Distribution Line SWER conductor km % 63.57% 32.83% % 49 HV Distribution Cable Distribution UG XLPE or PVC km % 50.00% 28.00% % 50 HV Distribution Cable Distribution UG PILC km % % 51 HV Distribution Cable Distribution Submarine Cable km % 92.00% HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No % 3.22% 79.08% 17.01% % 53 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No % 64.91% 26.40% % 54 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No % 0.86% 18.83% 79.94% % 55 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No % 8.18% 80.39% 10.03% % 56 HV Distribution switchgear 3.3/6.6/11/22kV RMU No % 11.05% 85.21% 1.09% % 57 HV Distribution Transformer Pole Mounted Transformer No % 15.64% 67.81% 14.20% % 58 HV Distribution Transformer Ground Mounted Transformer No % 17.12% 77.52% 2.23% % 59 HV Distribution Transformer Voltage regulators No % 90.45% 8.99% 4-60 HV Distribution Substations Ground Mounted Substation Housing No % 16.35% 73.29% 6.88% 1-61 LV LV Line LV OH Conductor km 0.07% 0.72% 22.41% 49.77% 27.03% % 62 LV LV Cable LV UG Cable km 53.00% 47.00% 1-63 LV LV Streetlighting LV OH/UG Streetlight circuit km 18.00% 43.00% 39.00% 1-64 LV Connections OH/UG consumer service connections No % 9.87% 31.68% 56.80% % 65 All Protection Protection relays (electromechanical, solid state and numeric) No % 13.14% 60.98% % 66 All SCADA and communications SCADA and communications equipment operating as a single system Lot 33.50% 21.89% 44.61% % 67 All Capacitor Banks Capacitors including controls No % % 6.12% 3-68 All Load Control Centralised plant Lot % 9.09% 70.45% 15.91% % 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

13 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 2025 sch ref 7 12b(i): System Growth - Zone Substations Refer note 4 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 Constraint +5 years (cause) 9 Coromandel 5 5 N-1-90% 5 96% Subtransmission circuit Single 66kV circuit. 10 Kerepehi 10 8 N % 8 136% Subtransmission Circuit Single 66kV circuit. 66kV upgrade in progress but not complete. 11 Matatoki 5 - N Transformer Single Tx 12 Tairua 8 8 N % 8 118% Transformer Just over Tx firm capacity. 13 Thames N % 17 71% No constraint within +5 years 14 Thames T3 3 - N-1 SW No constraint within +5 years 15 Whitianga N % % No constraint within +5 years Explanation Upgraded 66kV circuits. New Whenuakite sub (proposed) offloads Whitianga. 16 Paeroa 8 5 N 3 164% 5 167% No constraint within +5 years Transfer capacity provides adequate security 17 Waihi N 2 184% % No constraint within +5 years Customer agreed security. 18 Waihi Beach 5 - N % Subtransmission Circuit Single 33kV circuit 19 Whangamata 9 5 N 2 188% % No constraint within +5 years Second 33kV circuit proposed. 20 Aongatete 6 6 N % 6 113% No constraint within +5 years Transfer capacity provides required security 21 Bethlehem 8 - N-1 SW No constraint within +5 years New Substation 22 Hamilton St N % 24 71% No constraint within +5 years 23 Katikati 8 - N % No constraint within +5 years 24 Kauri Pt 3 - N Subtransmission Circuit Single Tx and 33kV circuit 25 Matapihi N % 21 59% No constraint within +5 years 26 Matua 10 6 N 4 178% 17 66% Subtransmission circuit Single 33kV circuit 27 Omanu N % 21 73% No constraint within +5 years Omokoroa N % % Transpower 33kV subtrans upgraded, GXP & 110kV constrained. Otumoetai 9 11 N % 15 61% No constraint within +5 years Papamoa N % % No constraint within +5 years Offloaded to other new Subs. Te Maunga 6 - 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 8 - N % Subtransmission Circuit 33kV tee section (single circuit) Pongakawa 7 5 N % 5 152% Subtransmission Circuit Single 33kV circuit Te Puke N % 21 98% No constraint within +5 years Farmer Rd 6 6 N % 6 112% No constraint within +5 years Inghams 4 - N No constraint within +5 years Customer agreed security Mikkelsen Rd N % 17 92% No constraint within +5 years Morrinsville 9 10 N % % No constraint within +5 years 2nd 33kV circuit proposed in next 5 yrs Piako N % 17 84% No constraint within +5 years Tahuna 6 7 N % 7 84% Subtransmission Circuit Single 33kV circuit. Tatua 4 - N No constraint within +5 years Customer agreed security Waitoa N-1-60% 20 77% No constraint within +5 years Walton 6 - N Transformer Single Transformer & Transfer < Peak Browne St 9 10 N % 10 99% Transformer Firm capacity just less than Peak Load - Transfer Lake Rd 6 - N % No constraint within +5 years Tirau 9 - N Transformer Single transformer. Putaruru 11 8 N % 8 143% No constraint within +5 years New GXP and subtransmission upgrades proposed. 13

14 Tower Rd 9 - N Transformer GXP and Subtrans upgrades proposed. Single Tx. Waharoa 8 8 N % 8 139% Subtransmission Circuit 33kV upgrades increase Subtrans capacity Baird Rd 9 17 N % 17 55% No constraint within +5 years Lakeside + Midway 4 3 N - 142% 3 145% No constraint within +5 years Customer agreed security Maraetai Rd N % 17 74% No constraint within +5 years Bell Block N % 21 89% No constraint within +5 years Brooklands N % % No constraint within +5 years Cardiff 2 - N No constraint within +5 years City N % % No constraint within +5 years Cloton Rd N % % No constraint within +5 years Douglas 2 - N No constraint within +5 years Eltham 10 9 N % 17 63% No constraint within +5 years Inglewood 5 5 N % 5 108% No constraint within +5 years Kaponga 3 2 N 1 143% 2 148% No constraint within +5 years Katere N % 21 63% No constraint within +5 years McKee 1 1 N % - - No constraint within +5 years Motukawa 1 - N No constraint within +5 years Moturoa N % % No constraint within +5 years Oakura 3 - N-1 SW No constraint within +5 years New Substation Pohokura 5 10 N-1-52% 10 72% No constraint within +5 years Waihapa 1 1 N % - - Subtransmission circuit Single Tx & Single 33kV Tee Waitara East 7 8 N % 8 84% No constraint within +5 years Waitara West 8 5 N % 10 89% No constraint within +5 years Cambria N % 15 98% No constraint within +5 years Kapuni N % 13 83% No constraint within +5 years Livingstone 3 2 N 1 141% 2 146% Transformer Peak Load > Firm Tx Capacity + Transfer Manaia 8 - N Subtransmission Circuit Section of single 33kV circuit Ngariki 4 - N No constraint within +5 years Pungarehu 5 4 N 1 131% 4 140% No constraint within +5 years Tasman 7 5 N % 5 146% No constraint within +5 years Whareroa 7 - N No constraint within +5 years Beach Rd N % % Subtransmission Circuit Proposed 33kV upgrades - completed FY20+ Blink Bonnie 5 - N No constraint within +5 years Castlecliff 11 7 N % 7 157% Transformer Switching speed inadequate for Tx fault Hatricks Wharf 12 - N Other Switched c/o inadequate for full (breakless) N-1 Kai Iwi 2 - N Subtransmission Circuit Single 33kV cct & single Tx. Peat St N % % Transpower Single GXP transformer. Roberts Ave 10 - N Transpower Single GXP transformer. Taupo Quay 11 - N Subtransmission Circuit Proposed 33kV upgrades - completed FY20+ Wanganui East 8 - N Subtransmission Circuit Single 33kV circuit & single transformer Taihape 5 - N Transformer Single transformer Waiouru 3 - N-1 SW Transformer Single transformer Arahina 9 - N Subtransmission Circuit Single 33kV and single transformer Bulls 6 - N Subtransmission Circuit Single 33kV circuit & single transformer Pukepapa 9 - N No constraint within +5 years Rata 2 - 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 % 24 80% 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 3 - 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

15 Sanson 9 8 N % 8 128% Transformer Proposed 2nd circuit. Switched transfer capacity. Turitea N % % Subtransmission Circuit Single main 33kV circuit, with switched backfeed Alfredton 0 - N-1 SW No constraint within +5 years Mangamutu 10 8 N % 17 93% No constraint within +5 years Parkville 2 - N No constraint within +5 years Pongaroa 1 - N No constraint within +5 years Akura 13 9 N % 9 165% Transformer Tx short term overload, until load transferred Awatoitoi 1 - N-1 SW No constraint within +5 years Chapel N % 19 85% No constraint within +5 years Clareville 11 9 N 2 131% 9 136% No constraint within +5 years Featherston 6 - N No constraint within +5 years Gladstone 1 - N-1 SW No constraint within +5 years Hau Nui 1 - N No constraint within +5 years Primarily an injection site. Kempton 5 - N Subtransmission Circuit Single 33kV circuit & single transformer Martinborough 5 - N No constraint within +5 years Norfolk 6 6 N % 10 66% No constraint within +5 years Proposed Transformer and subtrans upgrades. Te Ore Ore 8 - N Transformer Single transformer Tinui 1 - N-1 SW No constraint within +5 years 28 Tuhitarata 2 - N Subtransmission circuit Single 33kV circuit. 29 ¹ Extend forecast capacity table as necessary to disclose all capacity by each zone substation 30 12b(ii): Transformer Capacity Note: Transformer Capacity is not required, as per # 346 in Issues Register 31 (MVA) 32 Distribution transformer capacity (EDB owned) 33 Distribution transformer capacity (Non-EDB owned) 34 Total distribution transformer capacity Zone substation transformer capacity Note 1 Note 2 Note 3 Note 4 As per Information Disclosure (I.D.) Definitions, Firm Capacity is only a function of the Zone Substation transformers, not the 33kV subtransmission circuits or any other upstream equipment. The Firm Capacity quoted is based on transformer continuous, 20C (Powerco standard) rating basis. Cyclic, thermal or any other short term rating is ignored. Firm Capacity is assumed to imply "No break" supply. Hence, any substation with only 1 x Transformer must have Firm Capacity = 0.0. Although Powerco queried the definitions this year, there was insufficient time to alter tha basis for completing the Schedule. Hence, the same assumptions and interpretations are used for this 2014 Schedule as were made for the prior 2013 year. The definition of Security of Supply classification implies that for more than 1 x Tx, for the N-1 criteria to be met requires that Peak Load <= {Firm Capacity + Transfer Capacity} The definition of Firm Capacity in the I.D. is such that it is based on transformers alone - not circuits, ancillary equipment or upstream (or downstream) equipment, which all could impact "constraints". To continue with this interpretation for this column "Installed Firm Capacity Constraint +5 years (Cause)", would mean the only valid selection for a constraint would then be "Transformer". Therefore, for this column only, the definition of "Constraint" is therefore interpreted in the context of considering constraints caused by any primary equipment. Since Powerco's Planning is aligned to it's own Security of Supply classifications and definitions of Class Capacity, these are used as the basis for completing this column. Any existing constraints, in addition to those that might commence within the 5 year projection, are included in this column. Any existing constraints which scheduled investment projects cause to be resolved, are not identified here. Note - this is based on the nominal planned 5 year project works. Hence, this column will have little or no direct relationship to the preceding columns ("Installed Firm Capacity + 5 Years" and "Utilisation of Installed Firm Capacity + 5 Years" etc). In many instances there is more than one constraint affecting a substation - in such cases, the most obvious or influential constraint is listed. In some instances it is not clearly identifiable what substations a constraint impacts (eg - a GXP or subtransmission circuit constraint often impacts several, but not all, substations downstream). The Peak Load is required in MVA. Most of Powerco's raw demand data is in MW, and there is insufficient information on power factor to permit a rigorous conversion. An assumption of 0.98 power factor is therefore made, to allow approximate conversion from MW to MVA. This is a change from the 2013 Schedule. The effect is that Peak Loads will "appear" to grow by an additional 2% approximately. 15

16 SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND Company Name AMP Planning Period Powerco Limited 1 April March 2025 This schedule requires a forecast of new connections (by consumer type), peak demand and energy volumes for the disclosure year and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumptions used in developing the expenditure forecasts in Schedule 11a and Schedule 11b and the capacity and utilisation forecasts in Schedule 12b. sch ref 7 12c(i): Consumer Connections 8 Number of ICPs connected in year by consumer type Number of connections 9 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 10 for year ended 31 Mar Mar Mar Mar Mar Mar Consumer types defined by EDB* 12 Small 3,237 3,099 3,097 3,098 3,099 3, Commercial Industrial Connections total 3,261 3,119 3,120 3,120 3,119 3, *include additional rows if needed 19 Distributed generation 20 Number of connections Installed connection capacity of distributed generation (MVA) c(ii) System Demand 23 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 24 Maximum coincident system demand (MW) for year ended 31 Mar Mar Mar Mar Mar Mar GXP demand plus Distributed generation output at HV and above Maximum coincident system demand less Net transfers to (from) other EDBs at HV and above 29 Demand on system for supply to consumers' connection points Electricity volumes carried (GWh) 31 Electricity supplied from GXPs 4,217 4,241 4,265 4,290 4,314 4, less Electricity exports to GXPs plus Electricity supplied from distributed generation less Net electricity supplied to (from) other EDBs Electricity entering system for supply to ICPs 4,964 4,993 5,021 5,050 5,078 5, less Total energy delivered to ICPs 4,667 4,693 4,720 4,747 4,774 4, Losses Load factor 66% 64% 64% 63% 63% 62% 40 Loss ratio 6.0% 6.0% 6.0% 6.0% 6.0% 6.0%

17 SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April March 2025 Powerco Limited This schedule requires a forecast of SAIFI and SAIDI for disclosure and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumed impact of planned and unplanned SAIFI and SAIDI on the expenditures forecast provided in Schedule 11a and Schedule 11b. sch ref 8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 9 for year ended 31 Mar Mar Mar Mar Mar Mar SAIDI 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) SAIFI 14 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April March 2025 Eastern Region This schedule requires a forecast of SAIFI and SAIDI for disclosure and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumed impact of planned and unplanned SAIFI and SAIDI on the expenditures forecast provided in Schedule 11a and Schedule 11b. sch ref 8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 9 for year ended 31 Mar Mar Mar Mar Mar Mar SAIDI 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) SAIFI 14 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network)

18 SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April March 2025 Western Region This schedule requires a forecast of SAIFI and SAIDI for disclosure and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumed impact of planned and unplanned SAIFI and SAIDI on the expenditures forecast provided in Schedule 11a and Schedule 11b. sch ref 8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 9 for year ended 31 Mar Mar Mar Mar Mar Mar SAIDI 11 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) SAIFI 14 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) Notes to Schedules 12a - 12d Schedule 12a: The values provided reflect our best estimate at this time, noting that we are currently refining the process we use to determine condition and replacement requirements on our networks. We anticipate that the accuracy of both our data and forecast replacements will improve progressively over time. Please see the commentary in Section 2.5 Schedule 12a: Asset condition of this AMP Update for more detail. Schedule 12b: The values provided in this schedule reflect calculated values prepared in support of the 2014 AMP UPDATE, updated for anticipated growth since that time, and known material changes in loads / reconfiguration of substations. We consider this a suitable basis for the purpose of this disclosure. The forecasts assume a continuation of the current load control usage. Further supporting notes can be found on Schedule 12b. Schedule 12c: Values provided in this schedule reflect our most recent available information on co-incident peak demand and volumes carried. We note that there are some minor variances when compared with our 2014 AMP Update. Please see the commentary at the start of this AMP update for more detail. Schedule 12d: The values for SAIDI and SAIFI disclosed in these schedules have been set out as required for each of our operating regions. The calculation methodology used reflects an averaging of forecast performance outcomes across both regions. Disaggregation of SAIDI across our regions on a more computational basis is an area under consideration; however, such an approach is difficult to apply reliably for forecasting purposes due to the varying impact of storm events over time. The forecast uses the definition of SAIDI and SAIFI in the information disclosure regime. This means planned SAIDI and SAIFI are not weighted at 50%, as per the Default Price Quality Path definition.

19 Schedule 14a: Mandatory Explanatory Notes on Forecast Information 1. This Schedule provides for EDBs to provide explanatory notes to reports prepared in accordance with clause This Schedule is mandatory EDBs must provide the explanatory comment specified below, in accordance with clause This information is not part of the audited disclosure information, and so is not subject to the assurance requirements specified in section 2.8. Commentary on difference between nominal and constant price capital expenditure forecasts (Schedule 11a) 3. In the box below, comment on the difference between nominal and constant price capital expenditure for the disclosure year, as disclosed in Schedule 11a. Box 1: Commentary on difference between nominal and constant price capital expenditure forecasts The index used to translate nominal $ forecasts into constant $ forecasts is the Statistics NZ CPI (All Groups). The CPI index applied is the annual average rate of increase based on the CPI index predictions included in the NZIER Quarterly Predictions from November For example, the index used for the year ending 31 March 2015 is based on the annual average movement using CPI predictions (actuals where available) as follows: (Q1 RY15* + Q2 RY15 + Q3 RY15 + Q4 RY15)/(Q1 RY14 + Q2 RY14 + Q3 RY14 + Q4 RY14). Powerco is currently reviewing its escalation approach for its electricity business and developing more accurate cost escalators. As this analysis is not yet finalised, we have continued with the same approach as used in the 2014 AMP Update for the 2015 AMP Update (using CPI as the index). *RY refers to the regulatory year ending 31 March Commentary on difference between nominal and constant price operational expenditure forecasts (Schedule 11b) 4. In the box below, comment on the difference between nominal and constant price operational expenditure for the disclosure year, as disclosed in Schedule 11b. Box 2: Commentary on difference between nominal and constant price operational expenditure forecasts The index used to translate nominal $ forecasts into constant $ forecasts is the Statistics NZ CPI (All Groups). The CPI index applied is the annual average rate of increase based on the CPI index predictions included in the NZIER Quarterly Predictions from November For example, the index used for the year ending 31 March 2015 is based on the annual average movement using CPI predictions (actuals where available) as follows: (Q1 RY15* + Q2 RY15 + Q3 RY15 + Q4 RY15)/(Q1 RY14 + Q2 RY14 + Q3 RY14 + Q4 RY14). Powerco is currently reviewing its escalation approach and developing more accurate cost escalators. As this analysis is not yet finalised, we have continued with the same approach as used in the 2014 AMP Update for the 2015 AMP Update (using CPI as the index). *RY refers to the regulatory year ending 31 March 19