electricity asset management plan - powerco€¦ · management plan update (2015 amp update) ......

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

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.

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 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

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

Company Name

AMP Planning Period

SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE

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 Rel iabi li ty, 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 rel iabi li ty, 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


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


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


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


40 Other rel iabi li ty, 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



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


65 Quality of supply - 279 553 1,561 2,119 2,762 3,139 3,732 3,803 4,323 4,852


67 Other rel iabi li ty, 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

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 dol lar terms. Also required is a forecast of the value

72

73 CY+1 CY+2 CY+3 CY+4 CY+5

74 11a(ii): Consumer Connectionfor year ended 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20

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 l ines 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 l ines 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 Relocations117 Project or programme*

118 Devon Road 224 672

119

120

121

122


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 Supply130 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


137 All other qual ity 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

Current Year CY

9

141

142 11a(vii): Legislative and Regulatory143 Project or programme*

144 Nil

145

146

147

148


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


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 - - -


171 All other rel iabil ity, 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 rel iabil ity, 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 Assets179 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


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 - - - -


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

Company Name

AMP Planning Period

SCHEDULE 11b: REPORT ON FORECAST OPERATIONAL EXPENDITURE

sch ref



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


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



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


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

33 165 165 169 165 174 174 174 174 174 174 174

34 Direct bi ll ing*

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



41 Difference between nominal and real forecasts $000

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

Powerco Limited

1 April 2015 – 31 March 2025

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.

Energy efficiency and demand side management, reduction of

energy losses

11

Company Name

AMP Planning Period

SCHEDULE 12a: REPORT ON ASSET CONDITION

sch ref

7

8

9

Voltage Asset category Asset class Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknownData accuracy

(1–4)

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%

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 l ine assets, that are expressed in km, refer to circuit lengths.

Asset condition at start of planning period (percentage of units by grade)

% of asset forecast

to be replaced in

next 5 years

42

43

44

Voltage Asset category Asset class Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknownData accuracy

(1–4)

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 Streetl ighting LV OH/UG Streetl ight 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, sol id 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 s ingle 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

% of asset forecast

to be replaced in

next 5 years

Asset condition at start of planning period (percentage of units by grade)

13

Company Name Powerco Limited

AMP Planning Period 1 April 2015 – 31 March 2025

SCHEDULE 12b: REPORT ON FORECAST CAPACITY

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) Explanation

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

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

Morrinsvi lle 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.

This schedule requires a breakdown of current and forecast capacity and uti l isation 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.

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

Castlecl iff 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 ful l (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% Anci llary 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

15

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

Parkvi l le 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, unti l 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

Clarevi lle 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 Primari ly 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 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. Cycl ic, 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.

Note 2 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}

Note 3 The definition of Firm Capacity in the I.D. is such that it is based on transformers alone - not circuits, anci llary equipment or upstream (or downstream) equipment, which al l could impact "constraints".

To continue with this interpretation for this column "Instal led Firm Capacity Constraint +5 years (Cause)", would mean the only val id 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 al igned 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 wil l have l ittle or no direct relationship to the preceding columns ("Instal led Firm Capacity + 5 Years" and "Uti l isation 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 al l , substations downstream).

Note 4 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 al low 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.

Company Name

AMP Planning Period

SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND

sch ref

7 12c(i): Consumer Connections

8 Number of ICPs connected in year by consumer type



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


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 Demand23 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%

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 util isation forecasts in Schedule 12b.

Number of connections

17

Company Name

AMP Planning Period

Network / Sub-network Name

SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION

sch ref



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



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.

Company Name

AMP Planning Period



sch ref



10 SAIDI



13 SAIFI



Powerco Limited

1 April 2015 – 31 March 2025

Eastern Region



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.

Company Name

AMP Planning Period



sch ref



10 SAIDI



13 SAIFI



Powerco Limited

1 April 2015 – 31 March 2025

Western Region



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 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 in-crease 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

electricity asset management plan - powerco€¦ · management plan update (2015 amp update) ......

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