electricity asset management plan - powerco · 2.4 material changes to lifecycle asset management...

ELECTRICITY ASSET MANAGEMENT PLAN 31 March 2014

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 (2014 AMP Update) builds on last year’s plan and provides the latest information

on Powerco’s long-term strategy for managing our electricity assets. The 2014 AMP

Update relates to the electricity distribution services supplied by Powerco. It covers the

planning period from 1 April 2014 to 31 March 2024, and explains changes made to our

asset management planning since the publication of our 2013 AMP.

1.2 Information disclosure requirements

Clause 2.6.3(4) in the Electricity Distribution Information Disclosure Determination 2012

requires Powerco to complete and publicly disclose, before 1 April 2014, an AMP Update.

Clause 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

• Identify any material changes to the lifecycle asset management (maintenance and renewal) plans disclosed in the last AMP

• Provide the reasons for any material changes to the previous disclosures in the Report on Forecast Capital Expenditure set out in Schedule 11a and Report on Forecast Operational Expenditure set out in Schedule 11b

• Identify any changes to the asset management practices of the EDB that would affect Schedule 13 Report on Asset Management Maturity disclosure

In addition, clause 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. In the interests of

brevity, we have not attempted to duplicate the more explanatory style of our full AMP.

However, we would encourage readers to revert to our 2013 AMP where a greater level

of detail is required.

Key structural elements of this update include:

Section 2.1, which provides an overview of aggregate forecast expenditure and

outlines a small number of accounting and scoping changes that impact our

forecasts.

Sections 2.2 to 2.7, which provide detailed information on material changes to

the schedules relating to this AMP update compared with our 2013 AMP.

Section 3, which provides Schedules 11a – 12d and 14a.

http://www.powerco.co.nz/

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2 Material changes since 2013 AMP

Schedules 11a-12d and 14a are provided in section 3. This section provides an overview

of the rational for changes to our forecasts and information provided in these schedules.

This includes corrections where more reliable information is known, as well as

modifications due to changes in policies or procedures.

2.1 Schedules 11a and 11b: Forecast operating and capital

expenditure

2.1.1 Overview

Powerco’s underlying level of expenditure has not changed substantially from the 2013

AMP. However, we have refined our accounting approach to more accurately align our

expenditure classification to the Commission’s guidance and accounting standards and

added a number of key projects designed to optimise our approach to the management of

network reliability into the future. The impact of these changes is shown in figure 1

(provided in nominal dollars) and outlined in more detail in section 2.1.2 and 2.1.3 below.

Operating expenditure has reduced by around 7% and capital expenditure has increased

by around 12%.

2.1.2 Refinement of expenditure classification

Powerco is committed to continually refining its disclosure and accounting practices.

Routine review during 2013 identified two key areas where a refinement of our internal

processes was considered appropriate. These are set out below:

Capitalisation of direct staff and support costs – Powerco has progressively

lifted network capital expenditure to reflect the increasing investment needs of

our networks. Review of the processes used to calculate the proportion of staff

and support costs for these capital programmes has highlighted the need to

increase the share of future costs allocated to this category of expenditure. This

has resulted in an increase in forecast capital expenditure of 5.3% and a

reduction in forecast operating expenditure of 7.9%.

Capital financing costs – Many of our larger capital projects take time to com-plete, and there is a clear cost of financing these projects as they are developed and constructed. Review of our processes in this area, and analysis of applica-ble projects from FY2014, has highlighted our capital expenditure forecast did not reflect the full cost of financing. We have improved our forecasting method-ology to ensure all applicable financing costs are captured, resulting in an in-crease to our capital expenditure forecast of 2.5%.

The improvements to our capitalisation and cost of financing methodology ensure our

costs are more in line with regulatory and financial guidance. These changes have been

reviewed by Powerco’s auditors and are in line with Generally Accepted Accounting

Practice (GAAP).

We consider it important that we continually refine our approach in this area to ensure we

report our costs as closely as possible to the regulatory guidance. We consider this will

make it easier for consumers to compare expenditure levels between networks.

2.1.3 Additional projects

The 2014 AMP Update capex forecasts include four new key projects designed to

optimise our investment approach and balance long-term costs against network

performance outcome1. These projects are noted as follows:

Increased investment in automation through remote control of around $6m per

year from FY18 to FY23. This will improve network visibility, helping us manage

our networks to target levels and reducing call-outs and travel to remote sites.

Improving our critical asset spares management and inventory with an

investment of around $4m. This will improve management of network risks and

help reduce outage restoration times.

Upgrading our control room and data centre with an investment of around $6m

over FY15 and FY16. This meets growing demands and will improve operations

and resilience.

Purchasing the Hinuera spur asset from Transpower in FY15. The cost of this

transaction is yet to be confirmed, but is anticipated to be around $3m.

We have brought forward the implementation of a new asset management system by a

year. This is a crucial part of improving our asset management maturity and will deliver a

range of benefits across several parts of the business.

2.1.4 Impacts of high level changes

The impact of improved expenditure classification and recording, and the introduction of

key new projects are illustrated below. In aggregate, total expenditure has increased, and

there has been a refinement of the split between opex and capex expenditure.

1All expenditure in section 2.1.3 is in constant 2014 dollars.

Figure 1: 2013 and 2014 Expenditure Forecasts

2.2 Changes to asset management practices

In 2013, Powerco initiated a programme of work to achieve a step-change improvement

in our asset management practices with a focus on people, processes, and systems. Our

goal is to move to an intermediate status on the AMMAT scale within five years.

Over the last 12 months, Powerco has made solid progress in this area. We have

established a strategic framework and delivered improvements to asset data

management and analysis. These steps represent critical foundation elements which

support our capability for real time asset management and investment forecasting.

The next phase will be changing our business-as-usual processes and practices to align

with this more integrated asset management foundation. As this work is still underway,

we have not undertaken a review of our AMMAT score but intend to update this in 2015.

In the following sections, we have noted the material changes in disclosure schedules

when compared with the schedules included with our 2013 AMP. Where applicable, we

have set these in context in relation to the changes we are implementing within our asset

management processes.

2.3 Material changes to network development plans

Expenditure relating to Powerco’s network development plans has not changed materially

since the publication of our 2013 AMP, other than to take into account of the changes

outlined in section 2.1. There are three large projects where the scope, timing or

estimated costs have been modified since the 2013 AMP. This has been managed within

the capital expenditure envelope. These projects are:

Hinuera - Putaruru 33kV Upgrades: Since the 2013 AMP, the method to

reinforce the existing 33kV backfeed to the Hinuera GXP has been reviewed

and will now be approached by a different mix of projects. There is a slight

increase in overall expenditure expected resulting from developing a more

detailed scope and meeting the long-term security requirements.

Piako GXP Stage 2: An upgrade of a 50MVA transformer has been deferred

until Putaruru GXP developments are more certain. The addition of a second

transformer at the site will still proceed.

Papamoa/Mt Maunganui GXPs: Property rights could not be secured for the

preferred solution of a 110kV line route described in the 2013 AMP. A new

approach has been developed, however the total cost is largely unchanged.

2.4 Material changes to lifecycle asset management plans

Expenditure relating to renewal and lifecycle plans has not changed materially since the

publication of our 2013 AMP, other than to take into account the changes outlined in

section 2.1.

We note that work underway to improve our asset management practices includes

improving the sophistication of asset lifecycle analysis, including supporting models and

documentation. More detail on this on-going programme of continuous improvement is

provided in our 2013 AMP and good progress has been made in this area during 2013.

The work underway will provide a strong basis to refine the quality of our asset fleet

replacement forecasts. However the work it is not yet fully mature, and yet to undergo

internal testing and challenge processes. For this reason we have chosen not to update

our expenditure forecasts in these areas at this time. We are targeting completion of this

work to inform our next comprehensive AMP, which we plan to publish in 2015.

2.5 Schedule 12a: Asset condition

2.5.1 Overview

Powerco’s information and analysis to support schedule 12a is still developing and we

expect improvements to the data accuracy to continue over the next few years.

We have made a number of changes to asset condition grading across several asset

classes, in the main due to improved mapping of our asset categories to those specified

by the Commerce Commission. This has resulted in different asset condition profiles

(when compared to the 2013 AMP), particularly in the switchgear classes, where the

Commission’s schedule requires a greater amount of detail in its asset classes than we

have previously provided (this issue was noted in our 2013 disclosure).

Another driver of change to asset condition grading is the completion of further

inspections. We have seen significant improvements in data availability and quality

arising from a focus on asset inspection over the past 5 years. However, we have yet to

gain a full view of all assets due primarily to the ‘bedding in’ of new processes and

associated data consistency issues in some areas. Therefore, we still have a number of

unknown condition grades. We recognise that improving our real time asset data

information is a critical element of reaching the asset management maturity level we

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aspire to, and will continue to target year-on-year improvement.

As well as the general trends above, there are also a number of specific drivers for

change in our asset condition assessments:

Improvement in the condition grading distribution for SCADA equipment has

been noted, reflecting the large scale replacement of RTUs for the DNP3

SCADA upgrade (for protocol alignment) in Powerco’s Western Region.

In three cases, our data accuracy assessment has been revised down from 4 to

3, reflecting the degree of changes between 2013 and 2014 data:

Distribution switchgear-reclosers and sectionalisers: Due to asset class

mapping changes, resulting in a higher number of grade unknown score for

this class

Capacitor banks: Due to changes in the condition scores, producing an

increase in grade unknown score (these are a small proportion of

Powerco’s asset base)

Load control-centralised plant: Due to a change in our methodology in

reporting this asset class. The 2014 condition scores are derived from field

inspection results, and the 34% condition unknown score reflects the

degree of completion of the inspection programme for these assets. The

2013 condition scores were derived from the Load Control Asset

Management Plan, which considered the holistic rather than individual

components.

2.5.2 Percentage of assets to be replaced in the next five years

More detailed analysis of this figure for overhead line poles, zone substation transformers

and SCADA equipment has been undertaken during 2013. This is a key area of focus

within Powerco and improvements in forecasts represent the first step in a programme of

onging enhancement as noted below.

In 2013, the pole replacement forecast was not representative of the replacement rate for

each pole type. Rather a generic forecast was applied across all pole types, informed by

historical replacement rates. Additional work over the last year has enabled separation of

those replacement rates into pole types. This is an area of analysis we continue to refine,

and further data improvement is anticipated to be completed in support of our 2015 AMP.

Powerco notes that until detailed work in this area work is completed, replacement rates

disclosed are based on historical disposals and are not directly linked to the condition

scores for this asset class (this is the case for this AMP update). Poles or lines may be

replaced for many reasons, such as an increase in pole strength required for network

upgrades, bringing lines up to modern design standards or reactive replacements due to

motor vehicle accidents. The work we currently have underway will enable us to

disaggregate this information and provide improved commentary on the drivers for

replacement and associated volumes.

Over the next 12 months, we will also be completing engineering analysis so we can

more accurately forecast the rate of replacement for asset components such as cross

arms and insulators, further refining our approach in this area.

2.6 Schedule 12b: Forecast capacity

There have been no material changes to schedule 12b. The minor changes that are apparent have occurred as a result of either:

Projects completed in the most recent financial year (FY14)

Proposed future projects that have altered their timing following the most recent annual optimisation and prioritisation of future works plans.

2.6.1 Projects completed in FY2014

The following substations had significant changes in Schedule 12b values, due to work completed in FY2014. This impacts the first five columns of Schedule 12b.

Substation Parameter(s) Changed AMP13 Value

AMP14 Value

Reason for Change

Coromandel Firm Capacity (also affects Utilisation)

None 5MVA Second transformer added.

Thames Firm Capacity (also affects Security Class and Utilisa-tion)

7.5MVA 17MVA Transformers upgraded.

Bethlehem ALL New substation in FY14

Otumoetai Security Class (affected by reduced Peak Load)

N N-1 Load shifted to Bethle-hem Substation.

Papamoa Peak Load 26.4 22.9 Load shifted to Te Maunga Substation.

Te Maunga ALL New substation in FY14

Farmer Rd Security Class (affected by reduced Peak Load)

N N-1 Load shifted to new Tatua Substation

Morrinsville Firm Capacity 7MVA 10MVA Transformers upgraded.

Tahuna Firm Capacity (also affects Security Class and Utilisa-tion)

None 7MVA Second transformer added

Maraetai Rd Firm Capacity 7MVA 17MVA Transformers upgraded.

Brooklands Peak Load 21MVA 19MVA Load shifted to Oakura Substation.

Oakura ALL New substation in FY14

Note – as the schedule was developed in December 2013, but reflects status as at 31 March 2014,

estimates have been made in regard to progress and commissioning of FY14 projects. If commis-

sioning dates were near the end of the period, the project was generally treated as complete, especially

since the bulk of the project expenditure would have been spent.

2.6.2 5 Year Plan – Altered Project Timing

The following changes to the +5 Year columns of Schedule 12b, are to be noted:

Substation Parameter Changed

AMP13 Val-ue

AMP14 Val-ue

Reason for Change

Whitianga Constraint Cause (+5 Yr)

Subtrans. Circuit

- 66kV upgrades resolve subtrans constraints (Whitianga only)

Matua Constraint Cause (+5 Yr)

- Subtrans. Circuit

Matua 2nd circuit now be-yond 5 Year Plan

Omokoroa Constraint Cause (+5 Yr)

Subtrans. Circuit

Transpower 33kV upgrades resolve subtrans constraints. Transpower GXP con-straint affects multiple other Subs also.

Otumoetai Firm Capacity (+5 Yr)

12MVA 15MVA Slightly larger transform-ers now proposed.

Atuaroa Firm Capacity (+5 Yr)

15MVA 17MVA Slightly larger transform-ers now proposed.

Browne St Constraint Cause (+5 Yr)

Transpower Transformer Hinuera GXP backstopped by Putaruru & Piako.

Tirau Constraint Cause (+5 Yr)

- Transformer Tirau 2nd transformer now beyond 5 Year Plan

Tower Rd Constraint Cause (+5 Yr)

Transpower Transformer Hinuera GXP backstopped by Putaruru. 2nd Trans-former at Tower Rd now beyond 5 Year plan.

Waihapa Constraint Cause (+5 Yr)

Transformer Subtrans Circuit

Transformer upgrade now in 5 Year plan. Single circuit remains as con-straint.

Waitara West Firm Capacity (+5 Yr)

5MVA 10MVA Larger transformers than previously proposed (fits rotation plan)

Castlecliff Constraint Cause (+5 Yr)

- Transformer Transformer upgrades now beyond 5 Year Plan

Fielding Constraint Cause (+5 Yr)

Subtrans. Circuit

- 3rd Fielding circuit brought into 5 Year plan.

Kairanga Firm Capacity (+5 Yr)

15MVA 24MVA Transformer upgrades now brought into 5 Year plan.

Sanson Constraint Cause (+5 Yr)

Subtrans. Circuit

Transformer 2nd Sanson circuit now in 5 Year plan. Resolves subtrans constraint, which exposes lower priority transformer constraint.

Akura Constraint Cause (+5 Yr)

Ancillary Transformer 33kV Akura - Te Ore Ore ring upgraded – resolves closed ring protection constraints. Transformer

constraint remains at Akura.

Chapel Constraint Cause (+5 Yr)

Subtrans. Circuit

- 33kV Chapel – Norfolk ring upgrades, now in 5 Year plan

Martinborough Firm Capacity (+5 Yr)

5.5MVA 0MVA 2nd transformer now be-yond 5 Year plan.

Norfolk Constraint Cause (+5 Yr)

Subtrans. Circuit

- 33kV Chapel – Norfolk ring upgrades, now in 5 Year plan

Tuhitarata Constraint Cause (+5 Yr)

- Subtrans. Circuit

Growth in Peak Load just triggers a new constraint in +5 Years.

2.6.3 Demand Growth

The following changes are material in terms of changing the Security Class, but

immaterial in terms of the magnitude of the change. The growth in peak load is very small,

but in each case triggers a shift to the next lower Information Disclosure Security Class.

Substation Parameter(s) Changed AMP13 Value

AMP14 Value

Reason for Change

Paeroa Security Class N-1 N Peak Load > Firm + Transfer

Douglas Security Class N-1 SW N Peak Load > Transfer Capacity

Motukawa Security Class N-1 SW N Peak Load > Transfer Capacity

Tuhitarata Security Class N-1 SW N Peak Load > Transfer Capacity

2.7 Schedule 12c: Forecast network demand

2.7.1 Number of connections

There is a material change to the reported “number of ICPs connected in the year”.

However, this does not reflect a major change to Powerco’s planning assumptions or

underlying data. It instead reflects a definitional change due to direction given by the

Commission since the publication of the 2013 AMP. The basis for “number of

connections” has changed from the “number of existing connections” (as was reported in

the 2013 AMP) to the actual number of “new connections gross of disconnections”.

2.7.1 Distributed generation

There is a material change to Powerco’s forecast of the “Installed connection capacity of

distributed generation (MVA)” reported in this AMP update. Similar to above, this results

from a Powerco definitional change reflecting new direction provided by the Commission.

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The basis for “installed connection capacity of distributed generation (MVA)” has changed

from the cumulative capacity (as was reported in the 2013 AMP) to the incremental

capacity expected from new connections.

2.8 Schedule 12c: Forecast interruptions and duration

Powerco’s view on the level of future planned and unplanned SAIDI and SAIFI has not

changed since the 2013 AMP. However, Powerco has changed its internal definition to

more accurately align to the Commission’s definition. Powerco’s 2013 reliability forecasts

were adjusted for major event days (MEDs), whereas the Commission requires an

unadjusted forecast. This update removes the MED adjustment. Forecast unplanned

SAIDI is the only figure impacted, and is increased by 57 SAIDI minutes. This is the

average MED adjustment over the last five years (2009-2013).

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 14 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

9 11a(i): Expenditure on Assets Forecast $000 (in nominal dollars)

10 Consumer connection 17,464 17,141 18,728 18,759 19,431 20,027 20,779 21,408 21,991 22,498 23,011

11 System growth 27,775 29,161 27,885 28,649 32,937 31,554 34,916 37,053 38,625 39,634 40,624

12 Asset replacement and renewal 39,220 43,008 44,503 45,932 59,681 62,667 70,680 77,767 82,467 86,046 89,654

13 Asset relocations 2,344 2,338 2,540 2,545 2,636 2,716 2,817 2,902 2,981 3,049 3,119

14 Reliability, safety and environment:

15 Quality of supply 5,281 15,736 12,417 12,893 25,849 27,241 28,934 27,857 28,816 26,061 26,688

16 Legislative and regulatory - - - - - - - - - - -

17 Other reliability, safety and environment 6,662 4,930 6,487 5,960 7,094 7,639 8,323 7,698 8,030 8,241 8,448

18 Total reliability, safety and environment 11,943 20,666 18,904 18,853 32,943 34,880 37,257 35,554 36,846 34,302 35,136

19 Expenditure on network assets 98,746 112,314 112,560 114,738 147,627 151,844 166,449 174,684 182,910 185,530 191,543

20 Non-network assets 7,177 7,063 9,564 11,376 8,371 4,792 5,002 5,112 5,225 5,340 5,457

21 Expenditure on assets 105,923 119,377 122,124 126,115 155,998 156,636 171,451 179,796 188,135 190,869 197,000

22

23 plus Cost of financing 3,110 3,763 3,771 3,844 4,946 5,087 5,577 5,853 6,128 6,216 6,418

24 less Value of capital contributions 14,150 14,025 15,313 15,339 15,888 16,375 16,990 17,503 17,980 18,394 18,813

25 plus Value of vested assets - - - - - - - - - - -

26

27 Capital expenditure forecast 94,884 109,115 110,582 114,620 145,056 145,348 160,038 168,146 176,284 178,691 184,604

28

29 Value of commissioned assets 107,384 109,115 110,582 114,620 145,056 145,348 160,038 168,146 176,284 178,691 184,604


for year ended 31 Mar 14 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

32 $000 (in constant prices)

33 Consumer connection 17,464 16,798 17,950 17,583 17,784 17,935 18,208 18,355 18,449 18,469 18,483

34 System growth 27,775 28,578 26,726 26,852 30,145 28,258 30,596 31,770 32,405 32,535 32,630


36 Asset relocations 2,344 2,291 2,434 2,385 2,412 2,432 2,469 2,488 2,501 2,503 2,505


38 Quality of supply 5,281 15,421 11,901 12,084 23,658 24,396 25,354 23,885 24,175 21,393 21,436


40 Other reliability, safety and environment 6,662 4,831 6,217 5,586 6,493 6,841 7,293 6,600 6,737 6,765 6,786

41 Total reliability, safety and environment 11,943 20,252 18,119 17,670 30,152 31,237 32,648 30,485 30,912 28,158 28,222

42 Expenditure on network assets 98,745 110,068 107,883 107,542 135,116 135,984 145,855 149,776 153,453 152,300 153,852

43 Non-network assets 7,177 6,922 9,167 10,663 7,661 4,291 4,383 4,383 4,383 4,383 4,383

44 Expenditure on assets 105,923 116,989 117,050 118,204 142,777 140,275 150,238 154,159 157,837 156,684 158,235

45

46 Subcomponents of expenditure on assets (where known)

47 Energy efficiency and demand side management, reduction of energy losses 1,400 1,400 1,400 2,800 1,400 1,400 700 700 700 700 700

48 Overhead to underground conversion 300 300 300 300 300 300 300 300 300 300 300

49 Research and development

Powerco Limited

1 April 2014 – 31 March 2024

This schedule requires a breakdown of forecast expenditure on assets for the current disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms. Also required is a forecast of the

value of commissioned assets (i.e., the value of RAB additions)

EDBs must provide explanatory comment on the difference between constant price and nominal dollar forecasts of expenditure on assets in Schedule 14a (Mandatory Explanatory Notes).

This information is not part of audited disclosure information.

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59 Difference between nominal and constant price forecasts $000

60 Consumer connection - 343 778 1,177 1,647 2,092 2,571 3,053 3,542 4,030 4,528

61 System growth 0 583 1,159 1,797 2,791 3,296 4,320 5,283 6,220 7,099 7,994

62 Asset replacement and renewal - 860 1,849 2,881 5,058 6,545 8,745 11,089 13,281 15,411 17,642

63 Asset relocations - 47 106 160 223 284 349 414 480 546 614


65 Quality of supply - 315 516 809 2,191 2,845 3,580 3,972 4,641 4,668 5,251


67 Other reliability, safety and environment - 99 270 374 601 798 1,030 1,098 1,293 1,476 1,662

68 Total reliability, safety and environment - 413 785 1,182 2,792 3,643 4,610 5,070 5,934 6,144 6,914

69 Expenditure on network assets 0 2,247 4,677 7,197 12,511 15,860 20,594 24,908 29,457 33,229 37,691

70 Non-network assets - 141 397 714 709 500 619 729 841 956 1,074

71 Expenditure on assets 0 2,388 5,074 7,910 13,220 16,360 21,213 25,637 30,298 34,186 38,765

72

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

74 11a(ii): Consumer Connectionfor year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19

75 Consumer types defined by EDB* $000 (in constant prices)

76 Small 7,494 7,208 7,702 7,545 7,631 7,696

77 Commercial 5,925 5,700 6,091 5,966 6,034 6,086

78 Industrial 4,045 3,891 4,157 4,072 4,119 4,154

79

80

81 *include additional rows if needed

82 Consumer connection expenditure 17,464 16,798 17,950 17,583 17,784 17,935

83 less Capital contributions funding consumer connection 12,574 12,095 12,924 12,660 12,804 12,914

84 Consumer connection less capital contributions 4,890 4,704 5,026 4,923 4,979 5,022

85 11a(iii): System Growth86 Subtransmission 8,057 7,238 10,790 8,029 8,316 7,821

87 Zone substations 12,637 13,183 11,028 16,578 15,432 14,186

88 Distribution and LV lines 3,702 3,133 2,932 970 2,690 2,497

89 Distribution and LV cables 1,949 1,914 850 420 1,621 1,520

90 Distribution substations and transformers 1,336 2,132 1,105 833 1,811 1,986

91 Distribution switchgear 89 16 17 17 32 33

92 Other network assets 5 961 4 4 242 216

93 System growth expenditure 27,775 28,578 26,726 26,852 30,145 28,258

94 less Capital contributions funding system growth - - - - - -

95 System growth less capital contributions 27,775 28,578 26,726 26,852 30,145 28,258

103 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5

104 for year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19

105 11a(iv): Asset Replacement and Renewal $000 (in constant prices)

106 Subtransmission 6,414 5,118 5,269 5,184 6,243 6,972

107 Zone substations 2,879 4,534 3,590 5,357 9,550 5,790

108 Distribution and LV lines 15,895 19,187 20,197 18,443 22,120 24,700

109 Distribution and LV cables 5,344 4,739 4,824 4,986 5,868 6,552

110 Distribution substations and transformers 5,222 4,844 5,086 5,192 6,173 6,894

111 Distribution switchgear 2,931 3,168 3,092 3,025 3,671 4,100

112 Other network assets 535 558 597 863 997 1,113

113 Asset replacement and renewal expenditure 39,220 42,147 42,654 43,051 54,623 56,122

114 less Capital contributions funding asset replacement and renewal - - - - - -

115 Asset replacement and renewal less capital contributions 39,220 42,147 42,654 43,051 54,623 56,122

Current Year CY

116 11a(v):Asset Relocations117 Project or programme*

118 Transit Road Widening - Linton 158

119 Transit Road Widening - Waiwhakaiho 300

120 Transit Tirau Roundabout 200

121

122


124 All other asset relocations projects or programmes 2,186 1,791 2,434 2,385 2,412 2,432

125 Asset relocations expenditure 2,344 2,291 2,434 2,385 2,412 2,432

126 less Capital contributions funding asset relocations 1,688 1,650 1,753 1,717 1,737 1,751

127 Asset relocations less capital contributions 656 642 682 668 675 681

128

129 11a(vi):Quality of Supply130 Project or programme*

131 Automation projects 2,070 3,311 2,167 2,701 8,678 8,647

132 Distribution backfeed enhancement 1,710 1,949 810 848 211 -

133 Subtransmission & zone security enhancement 426 1,289 3,930 3,749 2,746 4,657

134 Putaruru GXP 870 3,626 3,690 - - -

135 Voltage regulator - 407 - 337 - -


137 All other quality of supply projects or programmes 204 4,840 1,305 4,449 12,024 11,091

138 Quality of supply expenditure 5,281 15,421 11,901 12,084 23,658 24,396

139 less Capital contributions funding quality of supply - - - - - -

140 Quality of supply less capital contributions 5,281 15,421 11,901 12,084 23,658 24,396

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

11


163 11a(viii): Other Reliability, Safety and Environmentfor year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19

164 Project or programme* $000 (in constant prices)

165 LV safety improvement 1,375 1,235 1,419 1,387 1,355 654

166 Oil containment 213 426 460 216 238 179

167 Switchgear safety replacement 1,350 1,198 1,054 1,031 778 1,388

168

169


171 All other reliability, safety and environment projects or programmes 3,724 1,972 3,285 2,952 4,123 4,620

172 Other reliability, safety and environment expenditure 6,662 4,831 6,217 5,586 6,493 6,841

173 less Capital contributions funding other reliability, safety and environment - - - - - -

174 Other reliability, safety and environment less capital contributions 6,662 4,831 6,217 5,586 6,493 6,841

175

176

177

178 11a(ix): Non-Network Assets179 Routine expenditure

180 Project or programme*

181 Think Safe Programme 241 161 157 154 150 147

182 Improve & Expand Network Data & Tools 614 241 235 230 225 220

183 IT Renewal 321 963 942 921 900 880

184 Site improvement capex 798 401 392 384 375 367

185


187 All other routine expenditure projects or programmes 819 1,043 1,413 1,382 375 367

188 Routine expenditure 2,793 2,809 3,140 3,071 2,024 1,980

189 Atypical expenditure

190 Project or programme*

191 Improve Network Operations (OMS / DMS) 1,638 2,007 1,570 1,535 1,424 -

192 Enterprise Asset Management System - - 409 5,311 2,448 -

193 Upgrade of Network Operations Centre and Data Centre - 1,662 3,491 - - -

194

195


197 All other atypical projects or programmes 2,747 443 557 746 1,765 2,311

198 Atypical expenditure 4,385 4,112 6,027 7,592 5,638 2,311

199

200 Non-network assets expenditure 7,177 6,922 9,167 10,663 7,661 4,291

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 5,613 7,201 7,341 7,241 8,865 9,810 10,083 10,285 10,500 10,366 10,575

11 Vegetation management 4,681 5,080 4,717 5,299 9,801 10,669 11,016 11,235 11,464 10,987 11,191

12 Routine and corrective maintenance and inspection 11,229 8,778 9,128 10,090 14,692 15,776 17,099 17,543 18,021 17,470 17,899


14 Network Opex 29,815 30,102 31,861 34,008 45,029 48,174 50,355 51,537 52,739 51,839 52,990

15 System operations and network support 14,232 12,317 12,447 12,420 13,736 13,927 13,944 14,110 14,288 14,397 14,650

16 Business support 25,301 24,908 25,076 23,592 23,469 23,876 24,201 24,648 25,108 25,621 26,149

17 Non-network opex 39,534 37,225 37,523 36,011 37,205 37,803 38,146 38,758 39,396 40,018 40,798

18 Operational expenditure 69,349 67,327 69,384 70,019 82,234 85,977 88,500 90,294 92,134 91,857 93,788



21 $000 (in constant prices)

22 Service interruptions and emergencies 5,613 7,057 7,036 6,787 8,114 8,785 8,836 8,819 8,809 8,510 8,494

23 Vegetation management 4,681 4,978 4,521 4,966 8,970 9,555 9,653 9,633 9,618 9,019 8,989

24 Routine and corrective maintenance and inspection 11,229 8,602 8,749 9,457 13,447 14,129 14,983 15,042 15,119 14,341 14,377


26 Network Opex 29,815 29,500 30,537 31,875 41,213 43,143 44,125 44,188 44,245 42,554 42,563

27 System operations and network support 14,232 12,070 11,929 11,641 12,572 12,473 12,219 12,098 11,987 11,818 11,767

28 Business support 25,301 24,410 24,034 22,112 21,480 21,382 21,207 21,133 21,064 21,032 21,003

29 Non-network opex 39,534 36,480 35,964 33,752 34,052 33,855 33,426 33,231 33,051 32,851 32,770

30 Operational expenditure 69,349 65,980 66,501 65,627 75,265 76,997 77,551 77,419 77,296 75,405 75,333

31 Subcomponents of operational expenditure (where known)

32

33 165 165 169 169 174 174 178 178 182 182 187

34 Direct bil l ing* - - - - - - - - - - -

35 Research and Development 484 484 484 484 484 484 484 484 484 484 484

36 Insurance 981 1,057 1,110 1,165 1,224 1,285 1,349 1,416 1,487 1,562 1,640

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 - 144 305 454 751 1,025 1,248 1,467 1,691 1,857 2,081

43 Vegetation management - 102 196 332 831 1,114 1,363 1,602 1,846 1,968 2,202

44 Routine and corrective maintenance and inspection - 176 379 633 1,245 1,648 2,116 2,501 2,902 3,129 3,522

45 Asset replacement and renewal - 181 444 714 989 1,245 1,504 1,779 2,054 2,331 2,622

46 Network Opex - 602 1,324 2,133 3,816 5,032 6,230 7,349 8,493 9,285 10,427

47 System operations and network support - 246 517 779 1,164 1,455 1,725 2,012 2,301 2,579 2,883

48 Business support - 498 1,042 1,480 1,989 2,494 2,994 3,515 4,044 4,589 5,145

49 Non-network opex - 745 1,559 2,259 3,153 3,948 4,720 5,526 6,345 7,167 8,028

50 Operational expenditure - 1,347 2,883 4,392 6,969 8,980 10,950 12,875 14,838 16,452 18,455

Powerco Limited

1 April 2014 – 31 March 2024

This schedule requires a breakdown of forecast operational expenditure for the disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms.

EDBs must provide explanatory comment on the difference between constant price and nominal dollar operational expenditure forecasts in Schedule 14a (Mandatory Explanatory Notes).

This information is not part of audited disclosure information.

Energy efficiency and demand side management, reduction of

energy losses

13

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. 0.07% 1.31% 3.92% 68.42% 26.28% 3 1.46%

11 All Overhead Line Wood poles No. 0.31% 9.40% 27.58% 33.96% 28.75% 3 4.81%

12 All Overhead Line Other pole types No. - 0.43% 0.89% 9.20% 89.48% 3 7.66%

13 HV Subtransmission Line Subtransmission OH up to 66kV conductor km 0.17% 0.37% 10.04% 67.60% 21.81% 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 - - 54.60% 45.40% - 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 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. - 3.25% 25.20% 71.54% - 3 1.83%

25 HV Zone substation Buildings Zone substations 110kV+ No. N/A

26 HV Zone substation switchgear 22/33kV CB (Indoor) No. - - 1.92% 11.54% 86.54% 2 2.00%

27 HV Zone substation switchgear 22/33kV CB (Outdoor) No. - - - 16.37% 83.63% 2 2.00%

28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. - - - 10.00% 90.00% 2 2.00%

29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No. - 0.34% 2.80% 53.92% 42.94% 2 27.00%

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. 25.00% 75.00% 2 -

33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No. - 3.04% 5.22% 80.22% 11.52% 3 3.80%

34 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No. - - - 92.86% 7.14% 3 3.80%

Powerco Limited

1 April 2013 - 31 March 2024

This schedule requires a breakdown of asset condition by asset class as at the start of the forecast year. The data accuracy assessment relates to the percentage values disclosed in the asset condition columns. Also required is a forecast of the percentage of units to be

replaced in the next 5 years. All information should be consistent with the information provided in the AMP and the expenditure on assets forecast in Schedule 11a. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths.

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. 0.55% 11.60% 70.17% 17.68% - 3 8.84%

46 HV Distribution Line Distribution OH Open Wire Conductor km 0.18% 1.42% 13.80% 56.81% 27.79% 2 1.54%

47 HV Distribution Line Distribution OH Aerial Cable Conductor km N/A

48 HV Distribution Line SWER conductor km - 1.03% 1.85% 74.90% 22.22% 2 0.50%

49 HV Distribution Cable Distribution UG XLPE or PVC km - 0.60% 98.00% 1.40% - 3 4.27%

50 HV Distribution Cable Distribution UG PILC km - - - 100.00% - 3 4.27%

51 HV Distribution Cable Distribution Submarine Cable km - - 7.90% 92.10% - 2 -

52 HV Distribution switchgear 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No. - 0.85% 2.13% 59.70% 37.31% 3 34.00%

53 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) No. - - 17.00% 73.00% 10.00% 4 3.80%

54 HV Distribution switchgear 3.3/6.6/11/22kV Switches and fuses (pole mounted) No. - 0.29% 0.83% 10.22% 88.66% 2 10.00%

55 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No. - 1.73% 8.12% 71.32% 18.83% 4 1.50%

56 HV Distribution switchgear 3.3/6.6/11/22kV RMU No. - 0.48% 5.61% 83.37% 10.55% 4 1.50%

57 HV Distribution Transformer Pole Mounted Transformer No. - 2.33% 16.73% 49.85% 31.09% 4 4.00%

58 HV Distribution Transformer Ground Mounted Transformer No. - 2.98% 19.07% 71.62% 6.33% 4 4.00%

59 HV Distribution Transformer Voltage regulators No. - 0.70% - 67.83% 31.47% 4 -

60 HV Distribution Substations Ground Mounted Substation Housing No. - 5.00% 20.00% 70.00% 5.00% 1 -

61 LV LV Line LV OH Conductor km 0.13% 1.28% 12.80% 56.16% 29.63% 2 0.35%

62 LV LV Cable LV UG Cable km - - 60.00% 40.00% - 1 -

63 LV LV Streetlighting LV OH/UG Streetlight circuit km - 20.00% 44.00% 36.00% - 1 -

64 LV Connections OH/UG consumer service connections No. - 2.62% 14.65% 42.36% 40.36% 2 0.50%

65 All Protection Protection relays (electromechanical, solid state and numeric) No. - 1.13% 76.87% 22.00% - 3 37.00%

66 All SCADA and communications SCADA and communications equipment operating as a single system Lot - 4.94% 13.95% 72.97% 8.14% 3 4.65%

67 All Capacitor Banks Capacitors including controls No. - - - 84.78% 15.22% 3 -

68 All Load Control Centralised plant Lot - 4.55% 11.36% 50.00% 34.09% 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)

15

Company Name Powerco Limited

AMP Planning Period 1 April 2014 – 31 March 2024

SCHEDULE 12b: REPORT ON FORECAST CAPACITY

sch ref

7 12b(i): System Growth - Zone Substations Refer Note 5 Refer Note 1 Refer Note 2 Refer Note 3

8

Existing Zone Substations

Current Peak Load

(MVA)

Installed Firm

Capacity

(MVA)

Security of Supply

Classification

(type)

Transfer Capacity

(MVA)

Utilisation of

Installed Firm

Capacity

%

Installed Firm

Capacity +5 years

(MVA)

Utilisation of

Installed Firm

Capacity + 5yrs

%

Installed Firm Capacity

Constraint +5 years

(cause) Explanation

Coromandel 5.0 5.0 N - 101% 5 103.5% Subtransmission circuit Single 66kV circuit.

Kerepehi 9.2 5.0 N 3.0 185% 5 194.3% Subtransmission circuit Single 66kV circuit. 66kV upgrade in progress but not complete.

Matatoki 5.2 - N 3.0 - - - Transformer Single Tx

Tairua 8.4 7.5 N-1 1.0 111% 8 120.1% Transformer Just over Tx firm capacity.

Thames 14.4 17.0 N-1 6.1 84% 17 88.8% No constraint within +5 years

Thames T3 4.7 - N-1 SW 6.9 - - - No constraint within +5 years

Whitianga 16.6 17.0 N-1 1.5 98% 17 96.1% No constraint within +5 years Upgraded 66kV circuits. New Whenuakite sub (proposed) offloads Whitianga.

Paeroa 7.9 4.8 N 3.0 165% 5 166.0% No constraint within +5 years Transfer capacity provides adequate security

Waihi 18.2 10.0 N 2.0 182% 10 201.0% No constraint within +5 years Customer agreed security.

Waihi Beach 5.7 - N 2.0 - 5 126.5% Subtransmission circuit Single 33kV circuit

Whangamata 10.3 5.0 N 2.0 206% 10 111.0% No constraint within +5 years Second 33kV circuit proposed.

Aongatete 7.1 5.8 N-1 5.0 123% 6 139.3% No constraint within +5 years Transfer capacity provides required security

Bethlehem 5.5 - N-1 SW 5.5 - - - No constraint within +5 years New Substation

Hamilton St 14.9 24.0 N-1 6.0 62% 24 72.1% No constraint within +5 years

Katikati 7.3 - N 4.0 - 11 76.0% No constraint within +5 years

Kauri Pt 2.9 - N 2.0 - - - Subtransmission circuit Single Tx and 33kV circuit

Matapihi 11.0 21.1 N-1 10.0 52% 21 59.0% No constraint within +5 years

Matua 11.1 5.8 N 3.5 191% 17 70.3% Subtransmission circuit Single 33kV circuit

Omanu 13.2 21.1 N-1 10.0 63% 21 76.3% No constraint within +5 years

Omokoroa 11.1 10.6 N-1 1.5 105% 11 121.3% Transpower 33kV subtrans upgraded, GXP & 110kV constrained.

Otumoetai 14.1 10.6 N-1 4.0 133% 15 103.9% No constraint within +5 years

Papamoa 22.9 18.6 N 4.0 123% 19 112.7% No constraint within +5 years Offloaded to other new Subs.

Te Maunga 5.0 - N-1 SW 5.0 - - - No constraint within +5 years New Substation

Triton 21.1 18.6 N-1 10.0 114% 19 120.5% No constraint within +5 years

Waihi Rd 23.3 21.1 N-1 5.0 110% 21 124.8% No constraint within +5 years

Welcome Bay 20.5 20.2 N-1 2.0 102% 20 115.1% No constraint within +5 years

Atuaroa 10.2 - N 5.0 - 17 78.0% Subtransmission circuit 33kV tee section (single circuit)

Pongakawa 7.5 5.0 N-1 3.2 149% 5 140.5% Subtransmission circuit Single 33kV circuit

Te Puke 24.0 21.1 N-1 3.0 114% 21 109.0% No constraint within +5 years

Farmer Rd 5.9 5.8 N-1 2.5 101% 6 111.6% No constraint within +5 years

Inghams 3.8 - N 3.5 - - - No constraint within +5 years Customer agreed security

Mikkelsen Rd 14.3 17.0 N-1 3.7 84% 17 90.9% No constraint within +5 years

Morrinsvil le 9.7 10.0 N-1 3.0 97% 10 104.8% No constraint within +5 years 2nd 33kV circuit proposed in next 5 yrs

Piako 14.7 17.0 N-1 4.0 87% 17 95.6% No constraint within +5 years

Tahuna 5.6 7.0 N-1 3.0 79% 7 83.5% Subtransmission circuit Single 33kV circuit.

Tatua 3.9 - N - - - - No constraint within +5 years Customer agreed security

Waitoa 15.6 20.0 N-1 - 78% 20 78.2% No constraint within +5 years

Walton 5.5 - N 3.5 - - - Transformer Single Transformer & Transfer < Peak

Browne St 10.7 10.0 N-1 3.0 107% 10 118.3% Transformer Firm capacity just less than Peak Load - Transfer

9 Lake Rd 6.6 - N 2.4 - 5 141.9% No constraint within +5 years

10 Tirau 8.8 - N 2.8 - - - Transformer Single transformer.

11 Putaruru 10.9 8.3 N-1 3.5 132% 8 138.5% No constraint within +5 years New GXP and subtransmission upgrades proposed.

12 Tower Rd 9.1 - N 3.0 - - - Transformer GXP and Subtrans upgrades proposed. Single Tx.

13 Waharoa 7.0 - N 3.0 - - - Subtransmission circuit 33kV upgrades increase Subtrans capacity

14 Baird Rd 9.2 17.0 N-1 5.0 54% 17 58.1% No constraint within +5 years

15 Lakeside + Midway 4.2 2.9 N - 144% 3 144.3% No constraint within +5 years Customer agreed security

This schedule requires a breakdown of current and forecast capacity and util 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.

16 Maraetai Rd 10.3 17.0 N-1 4.0 61% 17 67.2% No constraint within +5 years

17 Bell Block 18.1 21.1 N-1 10.0 86% 21 94.8% No constraint within +5 years

18 Brooklands 19.0 21.1 N-1 12.0 90% 21 97.2% No constraint within +5 years

19 Cardiff 1.5 - N 1.4 - - - No constraint within +5 years

20 City 18.8 20.4 N-1 15.0 92% 20 96.6% No constraint within +5 years

Cloton Rd 9.7 11.4 N-1 3.5 85% 11 92.0% No constraint within +5 years

21 Douglas 1.5 - N 1.5 - - - No constraint within +5 years

22 Eltham 10.2 8.8 N-1 5.0 115% 17 64.3% No constraint within +5 years

23 Inglewood 5.4 5.0 N-1 1.0 108% 5 116.0% No constraint within +5 years

24 Kaponga 3.2 2.4 N-1 1.0 131% 2 138.0% No constraint within +5 years

Katere 10.5 21.1 N-1 5.0 50% 21 55.0% No constraint within +5 years

McKee 1.4 1.2 N-1 1.0 116% - - No constraint within +5 years

Motukawa 1.1 - N 1.1 - - - No constraint within +5 years

Moturoa 18.8 20.4 N-1 10.0 92% 20 99.3% No constraint within +5 years

Oakura 3.0 - N-1 SW 3.0 - - - No constraint within +5 years New Substation

Pohokura 6.0 10.0 N-1 - 60% 10 64.3% No constraint within +5 years

Waihapa 1.2 1.2 N-1 0.6 102% - - Subtransmission circuit Single Tx & Single 33kV Tee

Waitara East 4.5 7.9 N-1 4.0 57% 8 59.8% No constraint within +5 years

Waitara West 6.8 5.0 N-1 4.3 136% 10 71.5% No constraint within +5 years

Cambria 14.5 15.0 N-1 5.4 97% 15 104.1% No constraint within +5 years

Kapuni 7.6 5.8 N-1 2.8 132% 8 97.7% No constraint within +5 years

Livingstone 3.4 2.4 N 0.5 142% 2 148.9% Transformer Peak Load > Firm Tx Capacity + Transfer

Manaia 7.0 - N 5.5 - - - Subtransmission circuit Section of single 33kV circuit

Ngariki 2.6 - N-1 SW 3.0 - - - No constraint within +5 years

Pungarehu 3.2 3.5 N-1 1.0 91% 4 95.9% No constraint within +5 years

Tasman 6.9 4.8 N-1 3.0 144% 5 151.2% No constraint within +5 years

Whareroa 4.3 - N 3.8 - - - No constraint within +5 years

Beach Rd 11.4 - N 6.0 - 11 115.8% Subtransmission circuit Proposed 33kV upgrades - completed FY20+

Blink Bonnie 3.1 - N 2.7 - - - No constraint within +5 years

Castlecliff 9.6 7.2 N-1 5.4 134% 7 144.1% Transformer Switching speed inadequate for Tx fault

Hatricks Wharf 11.8 - N 9.2 - - - Other Switched c/o inadequate for full (breakless) N-1

Kai Iwi 2.4 - N 1.5 - - - Subtransmission circuit Single 33kV cct & single Tx.

Peat St 16.0 17.0 N-1 9.7 94% 17 101.1% Transpower Single GXP transformer.

Roberts Ave 4.9 - N 4.5 - - - Transpower Single GXP transformer.

Taupo Quay 8.0 - N-1 SW 8.0 - - - Subtransmission circuit Proposed 33kV upgrades - completed FY20+

Wanganui East 7.3 - N 5.9 - - - Subtransmission circuit Single 33kV circuit & single transformer

Taihape 4.9 - N 3.0 - - - Transformer Single transformer

Waiouru 2.8 - N 2.6 - - - Transformer Single transformer

Arahina 9.2 - N 7.4 - - - Subtransmission circuit Single 33kV and single transformer

Bulls 7.0 - N 3.6 - - - Subtransmission circuit Single 33kV circuit & single transformer

Pukepapa 3.9 - N-1 SW 4.0 - - - No constraint within +5 years

Rata 2.1 - N 2.0 - - - No constraint within +5 years Proposed increase in transfer capacity

Feilding 22.3 21.1 N-1 4.0 106% 21 110.9% No constraint within +5 years Proposed 33kV upgrades in 5Yr plan

Kairanga 18.5 15.0 N-1 7.4 123% 24 85.0% Ancillary Equipment Comms / Prot prevent closed ring.

Keith St 16.9 18.6 N-1 9.0 91% 19 95.5% No constraint within +5 years Proposed new Sub offloads circuits

Kelvin Grove 13.0 15.0 N-1 11.0 86% 15 97.8% No constraint within +5 years

Kimbolton 3.7 - N 2.0 - - - Subtransmission circuit Single 33kV circuit & single transformer

Main St 26.5 20.0 N-1 12.0 133% 20 116.5% No constraint within +5 years Proposed new Sub and 33kV circuits

Milson 14.0 15.0 N-1 7.1 93% 15 100.4% No constraint within +5 years

Pascal St 23.7 19.2 N-1 15.5 124% 19 112.2% No constraint within +5 years

Sanson 8.8 7.5 N-1 5.2 117% 8 126.5% Transformer Proposed 2nd circuit. Switched transfer capacity.

Turitea 15.0 14.9 N-1 3.0 101% 15 108.6% Subtransmission circuit Single main 33kV circuit, with switched backfeed

Alfredton 0.5 - N-1 SW 0.6 - - - No constraint within +5 years

Mangamutu 9.5 8.3 N-1 1.6 114% 8 120.1% No constraint within +5 years

17

Parkville 2.0 - N 1.9 - - - No constraint within +5 years

Pongaroa 0.8 - N-1 SW 0.8 - - - No constraint within +5 years

Akura 11.8 8.5 N-1 7.0 139% 9 149.6% Transformer Tx short term overload, until load transferred

Awatoitoi 0.5 - N-1 SW 1.2 - - - No constraint within +5 years

Chapel 13.2 18.6 N-1 9.4 71% 19 76.2% No constraint within +5 years

Clareville 8.8 8.5 N-1 2.0 104% 9 111.6% No constraint within +5 years

Featherston 4.3 - N 4.0 - - - No constraint within +5 years

Gladstone 1.3 - N 1.2 - - - No constraint within +5 years

Hau Nui 3.6 - N - - - - No constraint within +5 years Primarily an injection site.

Kempton 4.8 - N 3.8 - - - Subtransmission circuit Single 33kV circuit & single transformer

Martinborough 4.7 - N 2.5 - - - No constraint within +5 years

Norfolk 6.8 5.5 N-1 4.0 124% 10 71.5% No constraint within +5 years Proposed Transformer and subtrans upgrades.

Te Ore Ore 7.4 - N 6.9 - - - Transformer Single transformer

Tinui 0.9 - N 0.8 - - - No constraint within +5 years

Tuhitarata 2.1 - N 2.0 - - - Subtransmission circuit Single 33kV circuit.

- [Select one]

28 - [Select one]

29 ¹ Extend forecast capacity table as necessary to disclose all capacity by each zone substation

30 12b(ii): Transformer Capacity31 (MVA)

32 Distribution transformer capacity (EDB owned) 2,977

33 Distribution transformer capacity (Non-EDB owned) 115

34 Total distribution transformer capacity 3,092

35

36 Zone substation transformer capacity 1,984 Refer Note 4

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. 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.

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, ancil lary 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 "Util 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 l isted.

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).

Note 4 Assumed that ratings at 20C as per Powerco standard, and as used for all Planning and reporting purposes apply. These differ from nominal nameplate ratings.

Assumed that this total applies as at 31/03/2014 - not the future "+ 5 Year forecast capacity".

Assumed that system spares and units being overhauled are not included in the above. The above only includes transformers in service in the field.

Does not include auxiliary, instrument or local supply transformers, nor regulators or 11/22kV step up transformers. Only Zone Substation Power Transformers are included.

Note 5 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.

Company Name

AMP Planning Period

SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND

sch ref

7 12c(i): Consumer Connections Version 3 difference 2013 v 2014

8 Number of ICPs connected in year by consumer type



11 Consumer types defined by EDB*

12 Small 3,286 3,891 3,891 3,892 3,890 3,889

13 Commercial 45 9 9 8 10 10

14 Industrial 6 4 4 4 4 4

15

16

17 Connections total 3,337 3,904 3,904 3,904 3,904 3,904


19 Distributed generation

20 Number of connections 248 271 329 387 445 504

21 Installed connection capacity of distributed generation (MVA) 4 4 5 5 6 7

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 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19

25 GXP demand 717 728 740 752 766 779

26 plus Distributed generation output at HV and above 149 150 152 154 156 158

27 Maximum coincident system demand 866 878 892 907 922 937

28 less Net transfers to (from) other EDBs at HV and above - - - - - -

29 Demand on system for supply to consumers' connection points 866 878 892 907 922 937

30 Electricity volumes carried (GWh)

31 Electricity supplied from GXPs 4,207 4,235 4,262 4,289 4,317 4,345

32 less Electricity exports to GXPs 47 51 54 58 62 66

33 plus Electricity supplied from distributed generation 695 706 717 729 741 753

34 less Net electricity supplied to (from) other EDBs - - - - - -

35 Electricity entering system for supply to ICPs 4,855 4,890 4,925 4,960 4,996 5,032

36 less Total energy delivered to ICPs 4,563 4,596 4,630 4,663 4,696 4,730

37 Losses 291 293 296 298 300 302

38

39 Load factor 64% 64% 63% 62% 62% 61%

40 Loss ratio 6.0% 6.0% 6.0% 6.0% 6.0% 6.0%

Powerco Limited

1 April 2014 – 31 March 2024

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

19

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) 227.1 227.1 227.1 227.1 227.1 227.1

13 SAIFI



Company Name

AMP Planning Period



sch ref



10 SAIDI



13 SAIFI



Powerco Limited

1 April 2014 – 31 March 2024

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.

Powerco Limited

1 April 2014 – 31 March 2024

Eastern Region


Notes to Schedules 12a-12d

Schedule 12 a: 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 the accuracy of our forecasts will improve progressively over the next few years. Please see the commentary at the start of this AMP update for future detail.

Schedule 12b: The values provided in this schedule reflect calculated values prepared in support of the 2013 AMP, 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. We are currently enhancing our processes in this area and so have chosen not to calculate load forecasts

from a first principle approach in this instance. Refined estimates based on new load measurements and our latest forecasting methodology will be provided in our 2015 AMP.

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 minor variances when compared with

our 2013 AMP, most notably a slight reduction in GXP demand / energy supplied, and a slight increase in the contribution of distributed generation at peak. We have chosen to reflect this as a change to our

‘base year forecast’ and not an indication of a longer term trend, noting that some year on year variance is to expected due to natural variations in demand which relate to temperature and the configuration /

output of distributed generation plant during the period that coincident demand is measured.

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.

Company Name

AMP Planning Period



sch ref



10 SAIDI



13 SAIFI




Powerco Limited

1 April 2014 – 31 March 2024

Western Region

21

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 dis-closure 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 2013.

For example, the index used for the year ending 31 March 2014 is based on the annual average movement using CPI predictions (actuals where available) as follows: (Q1 RY14* + Q2 RY14 + Q3 RY14 + Q4 RY14)/(Q1 RY13 + Q2 RY13 + Q3 RY13 + Q4 RY13). 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 the 2013 AMP for the 2014 AMP Update (using CPI as the index). Initial indications are that EDB’s capex cost escalation is around 0.5-2% higher than CPI.

*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 2013.

For example, the index used for the year ending 31 March 2014 is based on the annual average movement using CPI predictions (actuals where available) as follows:

(Q1 RY14* + Q2 RY14 + Q3 RY14 + Q4 RY14)/(Q1 RY13 + Q2 RY13 + Q3 RY13 + Q4 RY13).

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 the 2013 AMP for the 2014 AMP Update (using CPI as the index). Initial indications are that EDB’s opex cost escalation is around 1.5% higher than CPI.

*RY refers to the regulatory year ending 31 March

electricity asset management plan - powerco · 2.4 material changes to lifecycle asset management...

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