electricity asset management plan - powerco · 2.4 material changes to lifecycle asset management...
TRANSCRIPT
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.
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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
30 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10
for year ended 31 Mar 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
35 Asset replacement and renewal 39,220 42,147 42,654 43,051 54,623 56,122 61,935 66,678 69,186 70,635 72,012
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
37 Reliability, safety and environment:
38 Quality of supply 5,281 15,421 11,901 12,084 23,658 24,396 25,354 23,885 24,175 21,393 21,436
39 Legislative and regulatory - - - - - - - - - - -
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.
9
57 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10
58 for year ended 31 Mar 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
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
64 Reliability, safety and environment:
65 Quality of supply - 315 516 809 2,191 2,845 3,580 3,972 4,641 4,668 5,251
66 Legislative and regulatory - - - - - - - - - - -
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
123 *include additional rows if needed
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 - -
136 *include additional rows if needed
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
149 *include additional rows if needed
150 All other legislative and regulatory projects or programmes - - - - - -
151 Legislative and regulatory expenditure - - - - - -
152 less Capital contributions funding legislative and regulatory - - - - - -
153 Legislative and regulatory less capital contributions - - - - - -
161
11
162 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5
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
170 *include additional rows if needed
171 All other reliability, safety and environment projects or programmes 3,724 1,972 3,285 2,952 4,123 4,620
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
186 *include additional rows if needed
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
196 *include additional rows if needed
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
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 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
13 Asset replacement and renewal 8,293 9,044 10,675 11,378 11,671 11,919 12,156 12,473 12,754 13,016 13,324
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
19 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10
20 for year ended 31 Mar 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
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
25 Asset replacement and renewal 8,293 8,863 10,231 10,664 10,682 10,674 10,652 10,695 10,700 10,685 10,702
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
39 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10
40 for year ended 31 Mar 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
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
9 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5
10 for year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19
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
18 *include additional rows if needed
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
8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5
9 for year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19
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
14 Class B (planned interruptions on the network) 0.2 0.2 0.2 0.2 0.2 0.2
15 Class C (unplanned interruptions on the network) 2.6 2.6 2.6 2.6 2.6 2.6
Company Name
AMP Planning Period
Network / Sub-network Name
SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION
sch ref
8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5
9 for year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19
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
14 Class B (planned interruptions on the network) 0.2 0.2 0.2 0.2 0.2 0.2
15 Class C (unplanned interruptions on the network) 2.6 2.6 2.6 2.6 2.6 2.6
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
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
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
Network / Sub-network Name
SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION
sch ref
8 Current Year CY CY+1 CY+2 CY+3 CY+4 CY+5
9 for year ended 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19
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
14 Class B (planned interruptions on the network) 0.2 0.2 0.2 0.2 0.2 0.2
15 Class C (unplanned interruptions on the network) 2.6 2.6 2.6 2.6 2.6 2.6
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
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