ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2015

ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2015

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 www.powerco.co.nz. 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 2.6.4 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 2.6.5 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

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

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:

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 FY18. 2.5 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

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.

3 Schedules SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE Company Name AMP Planning Period Powerco Limited 1 April 2015 31 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 Mar 25 9 11a(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 22,967 11 System growth 28,835 26,090 37,898 31,742 31,166 34,419 36,454 37,926 38,841 39,733 40,603 12 Asset replacement and renewal 41,012 44,535 45,711 59,103 61,896 69,673 76,510 80,975 84,324 87,687 91,063 13 Asset relocations 4,056 2,530 2,533 2,610 2,683 2,777 2,855 2,927 2,988 3,050 3,113 14 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 26,664 16 Legislative and regulatory - - - - - - - - - - - 17 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 8,441 18 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 35,105 19 Expenditure on network assets 111,225 110,647 123,573 145,322 149,975 164,079 171,860 179,601 181,817 187,342 192,851 20 Non-network assets 5,531 9,379 12,346 8,830 6,020 4,894 5,029 5,130 5,233 5,337 5,444 21 Expenditure on assets 116,757 120,026 135,918 154,152 155,996 168,973 176,889 184,731 187,049 192,679 198,295 22 23 plus Cost of financing 1,975 2,119 2,366 2,730 2,719 2,967 3,000 3,031 3,064 3,163 3,249 24 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 17,735 25 plus Value of vested assets - - - - - - - - - - - 26 27 Capital expenditure forecast 100,643 107,736 123,867 142,022 143,439 156,123 163,626 171,088 173,088 178,463 183,809 28 29 Value of commissioned assets 96,231 106,260 109,251 170,472 143,439 156,123 163,626 171,088 173,088 178,463 183,809 30 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 Mar 25 32 $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 18,788 34 System growth 28,835 25,503 36,265 29,806 28,711 31,086 32,279 32,924 33,057 33,153 33,214 35 Asset replacement and renewal 41,012 43,533 43,741 55,498 57,021 62,927 67,747 70,295 71,767 73,166 74,493 36 Asset relocations 4,056 2,473 2,424 2,451 2,471 2,508 2,528 2,541 2,543 2,545 2,546 37 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 21,812 39 Legislative and regulatory - - - - - - - - - - - 40 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 6,905 41 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 28,717 42 Expenditure on network assets 111,225 108,156 118,248 136,459 138,163 148,192 152,176 155,912 154,741 156,317 157,758 43 Non-network assets 5,531 9,168 11,814 8,291 5,546 4,420 4,453 4,453 4,453 4,453 4,453 44 Expenditure on assets 116,757 117,323 130,062 144,750 143,709 152,612 156,629 160,366 159,194 160,770 162,212 45 46 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 1,400 700 700 700 700 700 700 48 Overhead to underground conversion 300 300 300 300 300 300 300 300 300 300 300 49 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+10 58 for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 Mar 25 59 Difference between nominal and constant price forecasts $000 60 Consumer connection - 420 804 1,174 1,558 1,983 2,412 2,848 3,283 3,727 4,179 61 System growth - 587 1,633 1,936 2,455 3,333 4,175 5,002 5,784 6,580 7,388 62 Asset replacement and renewal - 1,003 1,970 3,605 4,875 6,746 8,763 10,680 12,557 14,522 16,570 63 Asset relocations - 57 109 159 211 269 327 386 445 505 566 64 Reliability, safety and environment: 65 Quality of supply - 279 553 1,561 2,119 2,762 3,139 3,732 3,803 4,323 4,852 66 Legislative and regulatory - - - - - - - - - - - 67 Other reliability, safety and environment - 146 256 429 594 794 867 1,040 1,203 1,368 1,536 68 Total reliability, safety and environment - 424 808 1,990 2,713 3,556 4,006 4,772 5,006 5,691 6,388 69 Expenditure on network assets - 2,491 5,325 8,863 11,812 15,887 19,684 23,689 27,076 31,025 35,092 70 Non-network assets - 211 532 539 474 474 576 677 779 884 991 71 Expenditure on assets - 2,702 5,857 9,402 12,286 16,361 20,260 24,365 27,855 31,909 36,083 7

72 73 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 74 11a(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 7,322 77 Commercial 9,095 7,168 7,022 7,102 7,163 7,272 78 Industrial 4,886 3,851 3,772 3,815 3,848 3,906 79 80 81 *include additional rows if needed 82 Consumer connection expenditure 23,139 18,238 17,865 18,069 18,223 18,500 83 less Capital contributions funding consumer connection 15,331 12,402 12,148 12,287 12,392 12,580 84 Consumer connection less capital contributions 7,809 5,836 5,717 5,782 5,831 5,920 85 11a(iii): System Growth 86 Subtransmission 6,439 11,940 13,498 8,167 7,893 8,543 87 Zone substations 6,172 7,169 16,253 15,096 14,302 15,514 88 Distribution and LV lines 5,407 316 1,458 2,669 2,548 2,762 89 Distribution and LV cables 2,028 495 836 1,710 1,640 1,777 90 Distribution substations and transformers 6,856 3,098 3,331 1,891 2,072 2,213 91 Distribution switchgear 23 20 26 36 37 40 92 Other network assets 1,910 2,464 864 237 218 237 93 System growth expenditure 28,835 25,503 36,265 29,806 28,711 31,086 94 less Capital contributions funding system growth - - - - - - 95 System growth less capital contributions 28,835 25,503 36,265 29,806 28,711 31,086 103 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 104 for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 105 11a(iv): Asset Replacement and Renewal $000 (in constant prices) 106 Subtransmission 4,700 3,008 4,423 6,343 7,084 7,825 107 Zone substations 3,640 6,714 7,046 9,703 5,883 6,490 108 Distribution and LV lines 18,254 20,734 17,742 22,474 25,095 27,690 109 Distribution and LV cables 5,252 4,873 5,767 5,962 6,657 7,341 110 Distribution substations and transformers 5,156 4,630 3,954 6,272 7,004 7,732 111 Distribution switchgear 3,023 3,037 3,520 3,730 4,166 4,599 112 Other network assets 986 535 1,289 1,013 1,131 1,249 113 Asset replacement and renewal expenditure 41,012 43,533 43,741 55,498 57,021 62,927 114 less Capital contributions funding asset replacement and renewal - - - - - - 115 Asset replacement and renewal less capital contributions 41,012 43,533 43,741 55,498 57,021 62,927 116 11a(v):Asset Relocations 117 Project or programme* 118 Devon Road 224 672 119 120 121 122 123 *include additional rows if needed 124 All other asset relocations projects or programmes 3,832 1,801 2,424 2,451 2,471 2,508 125 Asset relocations expenditure 4,056 2,473 2,424 2,451 2,471 2,508 126 less Capital contributions funding asset relocations 2,758 1,682 1,648 1,667 1,680 1,706 127 Asset relocations less capital contributions 1,298 791 776 784 791 803 128 129 11a(vi):Quality of Supply 130 Project or programme* 131 Automation projects 3,598 3,083 2,849 8,825 7,575 6,975 132 Distribution backfeed enhancement 710 250 1,420 80-200 133 Subtransmission & zone security enhancement 1,860 4,520 4,000 8,700 6,200-134 Putaruru GXP - 336 - - - - 135 Voltage regulator 446 450 360 - - 250 136 *include additional rows if needed 137 All other quality of supply projects or programmes 715 3,453 3,649 6,433 11,012 18,336 138 Quality of supply expenditure 7,329 12,092 12,278 24,037 24,786 25,760 139 less Capital contributions funding quality of supply - - - - - - 140 Quality of supply less capital contributions 7,329 12,092 12,278 24,037 24,786 25,760 141

141 142 11a(vii): Legislative and Regulatory 143 Project or programme* 144 Nil 145 146 147 148 149 *include additional rows if needed 150 All other legislative and regulatory projects or programmes - - - - - - 151 Legislative and regulatory expenditure - - - - - - 152 less Capital contributions funding legislative and regulatory - - - - - - 153 Legislative and regulatory less capital contributions - - - - - - 161 162 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 163 11a(viii): Other Reliability, Safety and Environment for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 164 Project or programme* $000 (in constant prices) 165 LV safety improvement 1,315 1,920 1,930 1,930 654-166 Oil containment 385 500 570 120-200 167 Switchgear safety replacement 1,447 1,200 700 450 1,150 700 Zone sub seismic and safety - 375 300 300-200 Earth Fault Neutraliser - - 800 400 - - 168 Zone Sub equipment upgrades 749-720 400 - - 169 New Cable and Overhead Line 979 205 840 - - - 170 *include additional rows if needed 171 All other reliability, safety and environment projects or programmes 1,980 2,117 (184) 2,997 5,147 6,310 172 Other reliability, safety and environment expenditure 6,855 6,317 5,676 6,597 6,951 7,410 173 less Capital contributions funding other reliability, safety and environment - - - - - - 174 Other reliability, safety and environment less capital contributions 6,855 6,317 5,676 6,597 6,951 7,410 175 176 177 178 11a(ix): Non-Network Assets 179 Routine expenditure 180 Project or programme* 181 Think Safe Programme 132 130 127 124 121 118 182 Improve & Expand Network Data & Tools 199 406 406 406 406 406 183 IT Renewal 796 975 975 1,219 1,219 1,219 184 Site improvement capex 447 431 312 305 297 297 185 186 *include additional rows if needed 187 All other routine expenditure projects or programmes 2,083 1,715 1,837 1,604 1,614 1,617 188 Routine expenditure 3,658 3,658 3,658 3,658 3,658 3,658 189 Atypical expenditure 190 Project or programme* 191 Enterprise Asset Management System - 406 3,251 3,251 1,219-192 Upgrade of Network Operations Centre - 813 3,089 406 - - 193 Data Centre (DR) - 2,357 - - - - 194 Improve Network Operations (OMS/ DMS) 1,219 1,626 1,626 813 - - 195 Customer Engagement - 238 - - - - 196 *include additional rows if needed 197 All other atypical projects or programmes 654 70 191 163 669 762 198 Atypical expenditure 1,874 5,510 8,156 4,633 1,888 762 199 200 Non-network assets expenditure 5,531 9,168 11,814 8,291 5,546 4,420 9

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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 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 10,553 11 Vegetation management 5,010 4,700 5,273 9,706 10,538 10,859 11,053 11,257 10,767 10,946 11,171 12 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 17,853 13 Asset replacement and renewal 7,219 8,588 9,233 11,558 11,772 11,983 12,272 12,523 12,755 13,032 13,289 14 Network Opex 29,058 29,695 31,753 44,593 47,582 49,638 50,703 51,784 50,801 51,828 52,866 15 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 11,839 16 Business support 29,697 32,734 30,932 29,922 30,500 31,110 31,732 32,366 33,014 33,674 34,347 17 Non-network opex 39,295 43,165 41,280 41,154 41,837 42,388 43,097 43,828 44,503 45,330 46,186 18 Operational expenditure 68,353 72,860 73,033 85,747 89,419 92,026 93,800 95,613 95,304 97,158 99,053 19 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 20 for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 Mar 25 21 $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 8,633 23 Vegetation management 5,010 4,594 5,046 9,114 9,708 9,808 9,787 9,772 9,164 9,133 9,138 24 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 14,605 25 Asset replacement and renewal 7,219 8,395 8,835 10,853 10,845 10,823 10,866 10,872 10,856 10,874 10,871 26 Network Opex 29,058 29,027 30,385 41,873 43,834 44,832 44,896 44,954 43,236 43,245 43,246 27 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 9,685 28 Business support 29,697 31,997 29,599 28,097 28,097 28,097 28,097 28,097 28,097 28,097 28,097 29 Non-network opex 39,295 42,193 39,501 38,644 38,542 38,284 38,161 38,047 37,876 37,823 37,782 30 Operational expenditure 68,353 71,220 69,886 80,517 82,376 83,116 83,057 83,002 81,112 81,068 81,028 31 Subcomponents of operational expenditure (where known) 32 33 Energy efficiency and demand side management, reduction of energy losses 165 165 169 165 174 174 174 174 174 174 174 34 Direct billing* 35 Research and Development 492 492 492 492 492 492 492 492 492 492 492 36 Insurance 1,020 916 916 916 916 916 916 916 916 916 916 37 * Direct billing expenditure by suppliers that direct bill the majority of their consumers 38 39 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 40 for year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 31 Mar 25 41 Difference between nominal and real forecasts $000 Powerco Limited 1 April 2015 31 March 2025 42 Service interruptions and emergencies - 165 311 535 763 962 1,159 1,360 1,513 1,713 1,920 43 Vegetation management - 106 227 592 830 1,051 1,266 1,485 1,603 1,813 2,033 44 Routine and corrective maintenance and inspection - 205 433 887 1,227 1,632 1,977 2,334 2,549 2,899 3,249 45 Asset replacement and renewal - 193 398 705 927 1,160 1,406 1,652 1,899 2,158 2,418 46 Network Opex - 669 1,368 2,720 3,748 4,806 5,807 6,830 7,565 8,583 9,620 47 System operations and network support - 235 446 685 893 1,092 1,302 1,512 1,711 1,930 2,154 48 Business support - 737 1,333 1,825 2,402 3,012 3,634 4,269 4,916 5,577 6,250 49 Non-network opex - 972 1,779 2,510 3,295 4,104 4,936 5,781 6,627 7,507 8,404 50 Operational expenditure - 1,640 3,147 5,230 7,043 8,910 10,743 12,611 14,192 16,090 18,024

SCHEDULE 12a: REPORT ON ASSET CONDITION Company Name AMP Planning Period Powerco Limited 1 April 2015 31 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% 3 1.46% 11 All Overhead Line Wood poles No. 0.43% 8.94% 37.40% 37.18% 16.05% 3 4.81% 12 All Overhead Line Other pole types No. - 0.43% 1.55% 11.91% 86.10% 3 7.66% 13 HV Subtransmission Line Subtransmission OH up to 66kV conductor km 0.01% 0.22% 31.53% 59.30% 8.93% 2 1.01% 14 HV Subtransmission Line Subtransmission OH 110kV+ conductor km - - - N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km - - 9.00% 91.00% - 3 4.30% 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km - - 100.00% - - 3-17 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km N/A 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km 100.00% 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. - 7.69% 16.15% 76.15% - 3 1.83% 25 HV Zone substation Buildings Zone substations 110kV+ No. N/A 26 HV Zone substation switchgear 22/33kV CB (Indoor) No. - - 2.08% 87.50% 10.42% 2 2.00% 27 HV Zone substation switchgear 22/33kV CB (Outdoor) No. - 1.06% 6.88% 43.39% 48.68% 2 2.00% 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. - - - 68.75% 31.25% 2 2.00% 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No. - 1.03% 4.00% 75.91% 19.06% 2 10.00% 30 HV Zone substation switchgear 33kV RMU No. - - - - 100.00% 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. 42.86% 57.14% 2-33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No. - 1.49% 7.32% 90.07% 1.12% 3 3.80% 34 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No. - - 3.70% 77.78% 18.52% 3 3.80% 11

42 43 44 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% - 3 8.84% 46 HV Distribution Line Distribution OH Open Wire Conductor km 0.16% 1.82% 25.58% 51.80% 20.65% 2 1.54% 47 HV Distribution Line Distribution OH Aerial Cable Conductor km N/A 48 HV Distribution Line SWER conductor km - - 3.60% 63.57% 32.83% 2 0.50% 49 HV Distribution Cable Distribution UG XLPE or PVC km - 22.00% 50.00% 28.00% - 3 4.27% 50 HV Distribution Cable Distribution UG PILC km - - - 100.00% - 3 4.27% 51 HV Distribution Cable Distribution Submarine Cable km - - 8.00% 92.00% - 2-52 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No. - 0.69% 3.22% 79.08% 17.01% 3 34.00% 53 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No. - - 8.70% 64.91% 26.40% 4 3.80% 54 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No. - 0.37% 0.86% 18.83% 79.94% 2 10.00% 55 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No. - 1.39% 8.18% 80.39% 10.03% 4 1.50% 56 HV Distribution switchgear 3.3/6.6/11/22kV RMU No. - 2.65% 11.05% 85.21% 1.09% 4 1.50% 57 HV Distribution Transformer Pole Mounted Transformer No. - 2.35% 15.64% 67.81% 14.20% 4 4.00% 58 HV Distribution Transformer Ground Mounted Transformer No. - 3.12% 17.12% 77.52% 2.23% 4 4.00% 59 HV Distribution Transformer Voltage regulators No. - - 0.56% 90.45% 8.99% 4-60 HV Distribution Substations Ground Mounted Substation Housing No. - 3.48% 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% 2 0.35% 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. - 1.65% 9.87% 31.68% 56.80% 2 0.50% 65 All Protection Protection relays (electromechanical, solid state and numeric) No. - 25.88% 13.14% 60.98% - 3 37.00% 66 All SCADA and communications SCADA and communications equipment operating as a single system Lot 33.50% 21.89% 44.61% - 3 4.65% 67 All Capacitor Banks Capacitors including controls No. - 4.08% - 89.80% 6.12% 3-68 All Load Control Centralised plant Lot - 4.55% 9.09% 70.45% 15.91% 3 10.00% 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

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 2015 31 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-1 3 127% 8 136% Subtransmission Circuit Single 66kV circuit. 66kV upgrade in progress but not complete. 11 Matatoki 5 - N 3 - - - Transformer Single Tx 12 Tairua 8 8 N-1 1 111% 8 118% Transformer Just over Tx firm capacity. 13 Thames 12 17 N-1 6 69% 17 71% No constraint within +5 years 14 Thames T3 3 - N-1 SW 7 - - - No constraint within +5 years 15 Whitianga 16 17 N-1 2 95% 17 102% 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 18 10 N 2 184% 10 200% No constraint within +5 years Customer agreed security. 18 Waihi Beach 5 - N 2-5 114% Subtransmission Circuit Single 33kV circuit 19 Whangamata 9 5 N 2 188% 10 100% No constraint within +5 years Second 33kV circuit proposed. 20 Aongatete 6 6 N-1 5 105% 6 113% No constraint within +5 years Transfer capacity provides required security 21 Bethlehem 8 - N-1 SW 8 - - - No constraint within +5 years New Substation 22 Hamilton St 16 24 N-1 6 65% 24 71% No constraint within +5 years 23 Katikati 8 - N 4-11 77% No constraint within +5 years 24 Kauri Pt 3 - N 2 - - - Subtransmission Circuit Single Tx and 33kV circuit 25 Matapihi 12 21 N-1 10 56% 21 59% No constraint within +5 years 26 Matua 10 6 N 4 178% 17 66% Subtransmission circuit Single 33kV circuit 27 Omanu 14 21 N-1 10 67% 21 73% No constraint within +5 years Omokoroa 11 11 N-1 2 107% 11 117% Transpower 33kV subtrans upgraded, GXP & 110kV constrained. Otumoetai 9 11 N-1 4 81% 15 61% No constraint within +5 years Papamoa 22 19 N-1 4 117% 19 129% No constraint within +5 years Offloaded to other new Subs. Te Maunga 6 - N-1 SW 6 - - - No constraint within +5 years New Substation Triton 20 19 N-1 10 108% 19 120% No constraint within +5 years Waihi Rd 21 21 N-1 5 100% 21 109% No constraint within +5 years Welcome Bay 21 20 N-1 2 106% 20 121% No constraint within +5 years Atuaroa 8 - N 5-17 49% Subtransmission Circuit 33kV tee section (single circuit) Pongakawa 7 5 N-1 3 140% 5 152% Subtransmission Circuit Single 33kV circuit Te Puke 19 21 N-1 3 89% 21 98% No constraint within +5 years Farmer Rd 6 6 N-1 3 98% 6 112% No constraint within +5 years Inghams 4 - N 4 - - - No constraint within +5 years Customer agreed security Mikkelsen Rd 15 17 N-1 4 87% 17 92% No constraint within +5 years Morrinsville 9 10 N-1 3 93% 10 101% No constraint within +5 years 2nd 33kV circuit proposed in next 5 yrs Piako 13 17 N-1 4 78% 17 84% No constraint within +5 years Tahuna 6 7 N-1 3 81% 7 84% Subtransmission Circuit Single 33kV circuit. Tatua 4 - N - - - - No constraint within +5 years Customer agreed security Waitoa 12 20 N-1-60% 20 77% No constraint within +5 years Walton 6 - N 4 - - - Transformer Single Transformer & Transfer < Peak Browne St 9 10 N-1 3 91% 10 99% Transformer Firm capacity just less than Peak Load - Transfer Lake Rd 6 - N 2-5 126% No constraint within +5 years Tirau 9 - N 3 - - - Transformer Single transformer. Putaruru 11 8 N-1 4 133% 8 143% No constraint within +5 years New GXP and subtransmission upgrades proposed. 13

Tower Rd 9 - N 3 - - - Transformer GXP and Subtrans upgrades proposed. Single Tx. Waharoa 8 8 N-1 3 98% 8 139% Subtransmission Circuit 33kV upgrades increase Subtrans capacity Baird Rd 9 17 N-1 5 52% 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 11 17 N-1 4 67% 17 74% No constraint within +5 years Bell Block 17 21 N-1 10 82% 21 89% No constraint within +5 years Brooklands 23 21 N-1 12 107% 21 112% No constraint within +5 years Cardiff 2 - N 1 - - - No constraint within +5 years City 20 20 N-1 15 98% 20 107% No constraint within +5 years Cloton Rd 11 11 N-1 4 92% 11 102% No constraint within +5 years Douglas 2 - N 2 - - - No constraint within +5 years Eltham 10 9 N-1 5 115% 17 63% No constraint within +5 years Inglewood 5 5 N-1 1 103% 5 108% No constraint within +5 years Kaponga 3 2 N 1 143% 2 148% No constraint within +5 years Katere 12 21 N-1 5 55% 21 63% No constraint within +5 years McKee 1 1 N-1 1 106% - - No constraint within +5 years Motukawa 1 - N 1 - - - No constraint within +5 years Moturoa 21 20 N-1 10 104% 20 108% No constraint within +5 years Oakura 3 - N-1 SW 3 - - - No constraint within +5 years New Substation Pohokura 5 10 N-1-52% 10 72% No constraint within +5 years Waihapa 1 1 N-1 1 100% - - Subtransmission circuit Single Tx & Single 33kV Tee Waitara East 7 8 N-1 4 82% 8 84% No constraint within +5 years Waitara West 8 5 N-1 4 158% 10 89% No constraint within +5 years Cambria 14 15 N-1 5 97% 15 98% No constraint within +5 years Kapuni 10 13 N-1 3 78% 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 6 - - - Subtransmission Circuit Section of single 33kV circuit Ngariki 4 - N 3 - - - No constraint within +5 years Pungarehu 5 4 N 1 131% 4 140% No constraint within +5 years Tasman 7 5 N-1 3 140% 5 146% No constraint within +5 years Whareroa 7 - N 4 - - - No constraint within +5 years Beach Rd 14 10 N-1 6 143% 11 169% Subtransmission Circuit Proposed 33kV upgrades - completed FY20+ Blink Bonnie 5 - N 3 - - - No constraint within +5 years Castlecliff 11 7 N-1 5 150% 7 157% Transformer Switching speed inadequate for Tx fault Hatricks Wharf 12 - N 9 - - - Other Switched c/o inadequate for full (breakless) N-1 Kai Iwi 2 - N 2 - - - Subtransmission Circuit Single 33kV cct & single Tx. Peat St 17 17 N-1 10 100% 17 101% Transpower Single GXP transformer. Roberts Ave 10 - N 5 - - - Transpower Single GXP transformer. Taupo Quay 11 - N 8 - - - Subtransmission Circuit Proposed 33kV upgrades - completed FY20+ Wanganui East 8 - N 6 - - - Subtransmission Circuit Single 33kV circuit & single transformer Taihape 5 - N 3 - - - Transformer Single transformer Waiouru 3 - N-1 SW 3 - - - Transformer Single transformer Arahina 9 - N 7 - - - Subtransmission Circuit Single 33kV and single transformer Bulls 6 - N 4 - - - Subtransmission Circuit Single 33kV circuit & single transformer Pukepapa 9 - N 4 - - - No constraint within +5 years Rata 2 - N 2 - - - No constraint within +5 years Proposed increase in transfer capacity Feilding 22 21 N-1 4 102% 21 110% No constraint within +5 years Proposed 33kV upgrades in 5Yr plan Kairanga 18 15 N-1 7 117% 24 80% Ancillary Equipment Comms / Prot prevent closed ring. Keith St 20 19 N-1 9 108% 19 117% No constraint within +5 years Proposed new Sub offloads circuits Kelvin Grove 13 15 N-1 11 89% 15 103% No constraint within +5 years Kimbolton 3 - N 2 - - - Subtransmission Circuit Single 33kV circuit & single transformer Main St 28 20 N-1 12 142% 20 150% No constraint within +5 years Proposed new Sub and 33kV circuits Milson 16 15 N-1 7 106% 15 110% No constraint within +5 years Pascal St 23 19 N-1 16 121% 19 127% No constraint within +5 years

Sanson 9 8 N-1 5 118% 8 128% Transformer Proposed 2nd circuit. Switched transfer capacity. Turitea 15 15 N-1 3 99% 15 104% Subtransmission Circuit Single main 33kV circuit, with switched backfeed Alfredton 0 - N-1 SW 1 - - - No constraint within +5 years Mangamutu 10 8 N-1 2 118% 17 93% No constraint within +5 years Parkville 2 - N 2 - - - No constraint within +5 years Pongaroa 1 - N 1 - - - No constraint within +5 years Akura 13 9 N-1 7 157% 9 165% Transformer Tx short term overload, until load transferred Awatoitoi 1 - N-1 SW 1 - - - No constraint within +5 years Chapel 15 19 N-1 9 79% 19 85% No constraint within +5 years Clareville 11 9 N 2 131% 9 136% No constraint within +5 years Featherston 6 - N 4 - - - No constraint within +5 years Gladstone 1 - N-1 SW 1 - - - No constraint within +5 years Hau Nui 1 - N - - - - No constraint within +5 years Primarily an injection site. Kempton 5 - N 4 - - - Subtransmission Circuit Single 33kV circuit & single transformer Martinborough 5 - N 3 - - - No constraint within +5 years Norfolk 6 6 N-1 4 115% 10 66% No constraint within +5 years Proposed Transformer and subtrans upgrades. Te Ore Ore 8 - N 7 - - - Transformer Single transformer Tinui 1 - N-1 SW 1 - - - No constraint within +5 years 28 Tuhitarata 2 - N 2 - - - 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 - 35 36 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

SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND Company Name AMP Planning Period Powerco Limited 1 April 2015 31 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 11 Consumer types defined by EDB* 12 Small 3,237 3,099 3,097 3,098 3,099 3,100 13 Commercial 12 14 16 15 14 14 14 Industrial 12 6 7 7 6 6 15 16 17 Connections total 3,261 3,119 3,120 3,120 3,119 3,120 18 *include additional rows if needed 19 Distributed generation 20 Number of connections 420 420 420 420 420 420 21 Installed connection capacity of distributed generation (MVA) 2 2 2 2 2 2 22 12c(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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 25 GXP demand 726 751 763 775 787 799 26 plus Distributed generation output at HV and above 135 135 136 137 138 139 27 Maximum coincident system demand 860 886 899 912 925 938 28 less Net transfers to (from) other EDBs at HV and above 29 Demand on system for supply to consumers' connection points 860 886 899 912 925 938 30 Electricity volumes carried (GWh) 31 Electricity supplied from GXPs 4,217 4,241 4,265 4,290 4,314 4,338 32 less Electricity exports to GXPs 211 212 213 215 216 217 33 plus Electricity supplied from distributed generation 958 964 969 975 980 986 34 less Net electricity supplied to (from) other EDBs - - - - - - 35 Electricity entering system for supply to ICPs 4,964 4,993 5,021 5,050 5,078 5,107 36 less Total energy delivered to ICPs 4,667 4,693 4,720 4,747 4,774 4,801 37 Losses 298 300 301 303 305 306 38 39 Load factor 66% 64% 64% 63% 63% 62% 40 Loss ratio 6.0% 6.0% 6.0% 6.0% 6.0% 6.0%

SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April 2015 31 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 10 SAIDI 11 Class B (planned interruptions on the network) 40.0 40.0 40.0 40.0 40.0 40.0 12 Class C (unplanned interruptions on the network) 226.0 226.0 226.0 226.0 226.0 226.0 13 SAIFI 14 Class B (planned interruptions on the network) 0.20 0.20 0.20 0.20 0.20 0.20 15 Class C (unplanned interruptions on the network) 2.21 2.21 2.21 2.21 2.21 2.21 SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April 2015 31 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 10 SAIDI 11 Class B (planned interruptions on the network) 40.0 40.0 40.0 40.0 40.0 40.0 12 Class C (unplanned interruptions on the network) 226.0 226.0 226.0 226.0 226.0 226.0 13 SAIFI 14 Class B (planned interruptions on the network) 0.20 0.20 0.20 0.20 0.20 0.20 15 Class C (unplanned interruptions on the network) 2.21 2.21 2.21 2.21 2.21 2.21 17

SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name AMP Planning Period Network / Sub-network Name Powerco Limited 1 April 2015 31 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 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 10 SAIDI 11 Class B (planned interruptions on the network) 40.0 40.0 40.0 40.0 40.0 40.0 12 Class C (unplanned interruptions on the network) 226.0 226.0 226.0 226.0 226.0 226.0 13 SAIFI 14 Class B (planned interruptions on the network) 0.20 0.20 0.20 0.20 0.20 0.20 15 Class C (unplanned interruptions on the network) 2.21 2.21 2.21 2.21 2.21 2.21 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.

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 2.6.5. 2. This Schedule is mandatory EDBs must provide the explanatory comment specified below, in accordance with clause 2.7.1. 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 2014. 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 2014. 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