Otagonet Asset Management Plan (2014-2024)
Asset Management
Plan 2014 – 2024
Clarks Substation in winter
Publicly disclosed in March 2014
CONTENTS
Contents
0. SUMMARY OF THE PLAN ....................................................................................................................5
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
0.10
0.11
0.12
BACKGROUND AND OBJECTIVES ......................................................................................................5
DETAILS OF THE NETWORK ..............................................................................................................6
COMPARATIVE BENCHMARKING .......................................................................................................8
RISK MANAGEMENT ........................................................................................................................8
PERFORMANCE AND IMPROVEMENT .................................................................................................9
PROPOSED SERVICE LEVELS ...........................................................................................................9
DEVELOPMENT PLANS ................................................................................................................. 10
MANAGING THE ASSET‘S LIFECYCLE .............................................................................................. 11
PROCESSES AND SYSTEMS .......................................................................................................... 12
RESOURCING THE BUSINESS ........................................................................................................ 12
REGULATORY COMPLIANCE OF THIS PLAN ..................................................................................... 12
FEEDBACK AND COMMENTS .......................................................................................................... 12
1. BACKGROUND AND OBJECTIVES .................................................................................................. 13
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
HISTORY OF THE NETWORK ......................................................................................................... 13
PURPOSE OF THE ASSET MANAGEMENT PLAN .............................................................................. 14
INTERACTION WITH OTHER GOALS AND DRIVERS ............................................................................ 15
KEY PLANNING DOCUMENTS AND PROCESSES ............................................................................... 16
INTERACTION OF GOALS AND STRATEGIES ..................................................................................... 19
PERIOD COVERED BY ASSET MANAGEMENT PLAN ......................................................................... 19
STAKEHOLDER INTERESTS ........................................................................................................... 20
ACCOUNTABILITIES FOR ASSET MANAGEMENT ............................................................................... 26
SYSTEMS AND PROCESSES .......................................................................................................... 27
2. DESCRIPTION OF NETWORK ........................................................................................................... 28
2.1
2.2
SERVICE AREA............................................................................................................................. 28
SUMMARY OF NETWORK CONFIGURATION...................................................................................... 35
3. PERFORMANCE BENCHMARKING .................................................................................................. 49
3.1
3.2
3.3
3.4
COSTS ........................................................................................................................................ 49
RELIABILITY ................................................................................................................................. 54
TECHNICAL EFFICIENCY ............................................................................................................... 58
ASSET BASE ................................................................................................................................ 60
4. RISK MANAGEMENT ......................................................................................................................... 63
4.1
4.2
4.3
4.4
RISK METHODS ............................................................................................................................ 63
RISK DETAILS .............................................................................................................................. 64
CONTINGENCY PLANS .................................................................................................................. 69
INSURANCE ................................................................................................................................. 69
5. PERFORMANCE AND IMPROVEMENT ............................................................................................ 70
5.1
5.2
5.3
OUTCOMES AGAINST PLANS ......................................................................................................... 70
PERFORMANCE AGAINST TARGETS ............................................................................................... 71
IMPROVEMENT AREAS AND STRATEGIES ........................................................................................ 79
6. PROPOSED SERVICE LEVELS ......................................................................................................... 81
6.1
6.2
6.3
6.4
CUSTOMER-ORIENTED SERVICE LEVELS ........................................................................................ 82
SAFETY ....................................................................................................................................... 85
OTHER SERVICE LEVELS .............................................................................................................. 85
REGULATORY SERVICE LEVELS..................................................................................................... 86
7. DEVELOPMENT PLANS .................................................................................................................... 88
7.1
7.2
7.3
7.4
7.5
7.6
7.7
PLANNING APPROACH AND CRITERIA ............................................................................................. 88
PRIORITISATION METHODOLOGY ................................................................................................... 93
OTAGONET‘S DEMAND FORECAST ................................................................................................ 98
OTAGONET NETWORK CONSTRAINTS .......................................................................................... 104
POLICIES FOR DISTRIBUTED GENERATION.................................................................................... 105
USE OF NON-ASSET SOLUTIONS .................................................................................................. 106
NETWORK DEVELOPMENT OPTIONS............................................................................................. 107
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CONTENTS
7.8
7.9
7.10
DEVELOPMENT PROGRAMME ...................................................................................................... 109
NON-NETWORK DEVELOPMENT ................................................................................................... 119
DEVELOPMENT STRATEGIES THAT PROMOTE ENERGY EFFICIENCY ................................................ 120
8. MANAGING THE ASSETS’ LIFECYCLE ......................................................................................... 121
8.1
8.2
8.3
8.4
8.5
8.6
8.7
8.8
8.9
8.10
8.11
8.12
LIFECYCLE OF THE ASSETS......................................................................................................... 121
OPERATING OTAGONET‘S ASSETS.............................................................................................. 122
MAINTAINING OTAGONET‘S ASSETS............................................................................................ 124
RENEWING OTAGONET‘S ASSETS ............................................................................................... 130
UP-SIZING OR EXTENDING OTAGONET‘S ASSETS ......................................................................... 136
ENHANCING RELIABILITY............................................................................................................. 137
CONVERTING OVERHEAD TO UNDERGROUND ............................................................................... 137
RETIRING OF OTAGONET‘S ASSETS ............................................................................................ 138
NON-NETWORK, MAINTENANCE AND RENEWAL ............................................................................ 138
LIFECYCLE STRATEGIES THAT PROMOTE ENERGY EFFICIENCY ...................................................... 138
LIFE CYCLE MAINTENANCE AND RENEWAL BUDGET .................................................................... 139
LIFE CYCLE BY ASSET CATEGORY .............................................................................................. 139
9. PROCESSES AND SYSTEMS.......................................................................................................... 166
9.1
9.2
9.3
9.4
9.5
9.6
ASSET KNOWLEDGE ................................................................................................................... 166
ASSET MANAGEMENT TOOLS ...................................................................................................... 167
IMPROVING THE QUALITY OF THE DATA AND PROCESSES .............................................................. 168
USE OF THE DATA ...................................................................................................................... 168
DECISION MAKING...................................................................................................................... 169
KEY PROCESSES AND SYSTEMS .................................................................................................. 170
10. RESOURCING THE BUSINESS ....................................................................................................... 172
10.1
FUTURE RESOURCING REQUIREMENTS........................................................................................ 172
A. APPENDIX – AMP DISCLOSURE REQUIREMENTS ...................................................................... 173
B. APPENDIX - CUSTOMER ENGAGEMENT SURVEY ...................................................................... 180
C. APPENDIX – ASSUMPTIONS .......................................................................................................... 185
D.
APPENDIX – EDIDD SCHEDULE 11A ............................................................................................ 186
E. APPENDIX – EDIDD SCHEDULE 11B ............................................................................................. 187
F. APPENDIX – EDIDD SCHEDULE 12A ............................................................................................. 188
G.
APPENDIX – EDIDD SCHEDULE 12B ............................................................................................ 189
H.
APPENDIX – EDIDD SCHEDULE 12C ............................................................................................ 190
I.
APPENDIX – EDIDD SCHEDULE 12D ............................................................................................ 191
J. APPENDIX – EDIDD SCHEDULE 13................................................................................................ 192
K. APPENDIX - APPROVAL BY GOVERNING COMMITTEE.............................................................. 193
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CONTENTS
Enquiries
Enquiries, submissions or comments about this Asset Management Plan (AMP) can be directed
to:
OtagoNet Limited
PO Box 1586
Invercargill, 9840
Phone (03) 418 4950
Email amp@powernet.co.nz
Declaration
OtagoNet Joint Venture (OtagoNet) confirms that they have produced this AMP in accordance
with the requirements of the Commerce Commission and any other legislative requirements.
Liability disclaimer
The information and statements made in this AMP are prepared on assumptions, projections
and forecasts made by OtagoNet JV (OtagoNet) and represent the company‘s intentions and
opinions at the date of issue (31 March 2014). Circumstances may change, assumptions and
forecasts may prove to be wrong, events may occur that were not predicted, and OtagoNet
may, at a later date, decide to take different actions to those that it currently intends to take.
OtagoNet may also change any information in this document at any time.
OtagoNet accepts no liability for any action, inaction or failure to act taken on the basis of this
AMP.
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SUMMARY
0.
Summary of the plan
This section summarises the key points from this Asset Management Plan which
signals a step increase in network expenditure driven off the need to recover the
network condition and meet the network safety, security and reliability objectives. As
discussed in this plan, the indicated increase in expenditure continues a trend of rising
expenditure on the network following the transfer of ownership in 2003 and comes on
the back of historically low and unsustainable levels of expenditure, all as depicted in
Figure 1 below.
Historic and forecast expenditure
(CPI adjusted)
$18,000k
$16,000k
$14,000k
Expenditure ($k)
$12,000k
Total
$10,000k
Capital
Maint.
$8,000k
Total
Capital
$6,000k
Maint.
$4,000k
$2,000k
$0k
Figure 1 Historic and forecast expenditure
In the last financial year (FY2014), a number of assets found to be in poor condition
prompted the commencement of a one-off full network inspection that will continue into
FY2015. As the results of this accelerated surveillance are not complete and may point
to further work not identified in this plan, the costs set out herein may change and a
revision of this plan will be published.
0.1
Background and Objectives
The purpose of the AMP is to provide a governance and management framework that
ensures that OtagoNet:
Meets all safety requirements consistent with regulatory requirements and
recognised industry practice
Sets service levels for its electricity network that will meet customer, community
and regulatory requirements.
Meets the network capacity, reliability and security of supply requirements both
now and in the future.
Have robust and transparent processes in place for managing all phases of the
network life cycle from commissioning to disposal.
Properly considers the classes of risk OtagoNet‘s network business faces and that
there are systematic processes in place to mitigate identified risks.
Makes adequate provision for funding all phases of the network lifecycle.
Makes decisions within systematic and structured frameworks at each level within
the business.
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SUMMARY
Obtains increased levels of information relative to the location, age and condition of
the constituent components of the network.
Implements systems to ensure that the information pertaining to the network assets
is able to be readily utilised to facilitate network planning and efficiently determine
prudent levels of capital and maintenance expenditure and maximise reliability of
customer supply.
OtagoNet works to the below strategies at the corporate and asset level:
Corporate Strategies
Delivery to the customers of an economic, safe, efficient and quality
electricity supply and meets all legislative requirements.
Maintaining and enhancing the long term value of assets, business units,
products and investments.
Deliver a reasonable commercial return on equity.
Achieve a long term reliable electricity supply.
Asset Management Strategies
Sectionalising poorly performing feeders
Continue to expand the meshed area of the network
Manage deteriorating assets through condition inspection and
replacement
Reduce planned SAIDI by employing mobile generation where feasible
and economic
Employ strong capital governance processes
Identifying and managing network health, safety and other risks
Direct investment towards reliability and the more economic sections of
the network
Achieve 100% regulatory compliance
Ensure compliance with internal network standards
This plan covers the period 1 April 2014 to 31 March 2024, and was approved by the
OtagoNet Governing Committee on 31 March 2014.
However, it has to be stated that the provisions of this plan are based on information
currently available and may well change as further information is obtained. The
extensive surveillance of the network provided for in this plan for the year ending 31
March 2015, will enable the current provisions of this plan to be more accurately
determined. Accordingly, it is intended that this plan be reviewed during the year.
Management of the assets is undertaken OtagoNet with support from PowerNet
Limited and Marlborough Lines Limited. OtagoNet uses one main external contractor
to operate, maintain, renew, upsize and expand the network. The processes and
systems used by OtagoNet are described in section 9.
0.2
Details of the network
OtagoNet supplies14,8121 customers in Otago, with a population of 34,791.2 Key
industries within OtagoNet‘s network area include sheep, beef and dairy farming,
extensive meat processing, gold mining, black and brown coal mining, forestry, and
timber processing.
1
As per the FY 2013 information disclosure.
2
From combined Clutha and Central Otago Territorial Authority normal resident population data from the
2013 census. The 2013 census result by town was not available at time of publishing.
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SUMMARY
Figure 2 Overview of OtagoNet Subtransmission Network 2012
As at 31 March 2013 there were a total of 4,394 km of lines and cables comprising:
74 km of 66kV lines and 539 km of 33 kV lines and cables.
35 zone substations to transform High Voltage (HV) to Medium Voltage (MV).
956 km of SWER lines and cables
2,275 km of 11 kV lines (other than SWER) and 21 km of 11 kV cables.
4,197 distribution transformers supplying 14,812 customers.
24 Voltage regulators, controlling local voltage.
499 km of low voltage (230V) lines and 28 km of cable.
The age of the network is relatively old; with the 2013 disclosure (schedule 4(vii))
showing only 46% of expected life remaining for distribution and LV lines and 39% for
subtransmission lines.
Comparative benchmarking, analysis of faults and the
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SUMMARY
management of risk, all points to the continued need for replacement programs
particularly for the line assets.
0.3
Comparative benchmarking
This section considers OtagoNet‘s performance in comparison to all other electricity
distribution businesses (EDBs) in New Zealand using data disclosed in the FY2013
information disclosure. Key findings are:
A comparatively high proportion of faults expenditure indicative of the deteriorating
condition of the network
Direct opex expenditure comparative with other EDBs
Indirect opex also comparative with other EDBs
The lowest customer density of any New Zealand network at three customers per
kilometre.
An average rate of return being achieved on network investment but the second
highest investment value per ICP owing to the low connection density of the
network
Reasonable SAIFI performance but noting a high prevalence of faults attributable
to the quality of the network.
A high proportion of planned SAIDI and high CAIDI although the latter is highly
variable due to the radial nature of the network with long feeders and terrain which
in winter is often inaccessible because of snow.
Transformer utilisation and network losses consistent with the network
characteristics noting OtagoNet‘s single largest customer utilises approximately
50% of the energy delivered over the network and this distorts overall statistics
relative to losses and energy demand.
Has one of the most ‗aged‘ networks in New Zealand, a factor which needs to be
addressed relative to safety and the sustainability of the supply reliability.
Although historical statistics may be utilised for comparison with other networks, going
forward the statistics for OtagoNet can be expected to change. The possible closure of
its largest customer, publicly reported for circa 2017, taking approximately 50% of the
energy, and the need to renew the network whilst minimising the capital burden on
customers results in challenges not faced by other networks of greater customer
density.
It is salient that a significant proportion of OtagoNet‘s lines were built under the
previous government requirements to construct uneconomic lines with the provision of
Rural Electrical Reticulation Council subsidies. A number of these lines remain
uneconomic yet need replacement.
Because OtagoNet does not have a dense urban network to offset the number of
customers it services in the rural areas, it is inevitable the capital investment per
customer will further increase relative to other networks.
The reality is the previous owners of the network deferred maintenance and capital
expenditure and unfortunately the savings of the past now have to be funded to ensure
the safety of the network and to maintain reliability of supply.
0.4
Risk Management
The business is exposed to a wide range of risks. This section examines OtagoNet‘s
risk exposures, describes what it has done and will do about these exposures and its
disaster preparedness
Risk management is used to identify and control risk to within acceptable levels.
Highlighted risks are the potential public safety hazards arising from the deteriorated
network condition, which are being addressed through an accelerated condition
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SUMMARY
inspection programme and addressing some issues identified over the last year around
historic earthing practices on SWER transformers.
0.5
Performance and improvement
The outcome for the 2012-13 annual business plan was a 3% underspend on the
$9.66M capital budget, and a 2% underspend on the $3.5M budgeted for maintenance.
Forecast out-turn for the current 2013-14 year is running at -16% on the capital budget
of $13.3m and +18% on the $3.7m maintenance budget, giving an overall underexpenditure of -9%.
Although this expenditure approximated to budget, it is expected the underspend will
be spent prior to 2015 (2014/15 year).
Performance for duration of faults (SAIDI) and frequency of faults (SAIFI) exceeded
target levels and SAIDI is close to the regulatory threshold for the 2013/14 year. The
network was adversely affected by the winter storms in 2013. However, given the radial
nature of the network and the propensity of the network to be affected by snow, it is
salient to note that the reliability of the network will always be subject to the vagaries of
weather. Further, that when outages occur, snow and inaccessibility can impede
restoration of supply as occurred during the winter of 2013.
The majority of secondary service level target were achieved3. Utilisation was on
target. Network losses were below target due to a change in the metering location of
the network‘s largest load and new targets have been set to recognise this in the
future.
Strategies are planned and described to improve performance particularly in areas of
strengthened capital governance and management, improved processes for recording
and using line condition information and reducing planned outages through the
application of more mobile generation.
0.6
Proposed service levels
The outcome of customer consultation undertaken by a telephone survey, public
meetings and one-on-one meetings showed the majority of customers are content with
the present level of service but the expectations of customers vary depending upon
their individual requirements such as milking, irrigation and their dependency upon
electricity as an essential service in a harsh winter climate.
Irrespective, customers do not want a lesser level of service and have an expectation
going forward that reliability of supply will be at least maintained or improved.
Positive feedback has been received relative to the increased levels of maintenance
and capital expenditure undertaken on the network in recent years.
The surveyed customers have indicated that they value continuity and then restoration
most highly and therefore OtagoNet‘s primary service levels are continuity and
restoration. To measure performance in this area two internationally accepted indices
have been adopted:
SAIDI – system average interruption duration index. This is a measure of how
many system minutes of supply are interrupted per year per customer connected to
the network.
SAIFI – system average interruption frequency index. This is a measure of how
many system interruptions occur per year per customer connected to the network.
Projections of these measures for the next ten years are set out below and are based
on meeting or exceeding the supply quality requirements set out by the Commerce
Commission and enacting the strategies set out in this plan.
3
Unachieved target was percentage of customers recognising OtagoNet as the first call for an outage.
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SUMMARY
Target levels for unplanned outages have been calculated by averaging the values
over the regulatory period (2004/05 – 2008/09) (allowing for normalisation to remove
extreme events as per the Commerce Commission guidelines), and decreasing future
years by 0.5% p.a. However this proposed reduction is an interim target only and will
be reviewed as part of the reassessment of the network to be undertaken this year.
Indeed, recent failures have indicated that unless expenditure is maintained or
increased reliability will diminish. Target levels for planned outages have been
maintained constant acknowledging that OtagoNet remains uncertain of the planned
reliability impacts of its work programme mainly due to the unknown extent of the
condition driven work.
Table 1 – Primary service levels
SAIDI
Year End
Class B
Limit
31/03/15
31/03/16
31/03/17
31/03/18
31/03/19
31/03/20
31/03/21
31/03/22
31/03/23
31/03/24
Class C
148
148
148
148
148
148
148
148
148
148
175
174
173
173
172
171
170
169
168
168
SAIFI
Total
361.08
323
322
321
320
319
318
318
317
316
315
Class B
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
Class C
2.07
2.06
2.05
2.04
2.03
2.02
2.01
2.00
1.99
1.98
Total
3.120
2.70
2.69
2.68
2.67
2.66
2.65
2.64
2.63
2.62
2.61
Class B are planned interruptions on the network and Class C are unplanned
interruptions on the network, commonly known as faults.
0.7
Development Plans
Annual growth of the network energy and demand has been 1.4% to 1.5% over the last
10 years with demand growth relatively flat over the last 5 years. Most growth in energy
delivered has been with the HV (industrial or large commercial) customers. Based on
long run historic trends, the future increase in demand is predicted at a rate of 1.5% per
annum over the larger network. This, however, excludes OtagoNet‘s largest single
customer, for which closure has been announced circa 2017 and which would incur a
one-off drop in demand of 42% and reduce delivered energy by 53% should this occur.
As this customer is essentially supplied via a dedicated 66kV line paid for by the
customer there will be minimal effect to the network in terms of stranded assets should
it close.
Typically domestic customers are reducing demand through the more efficient
utilisation of electricity and consolidation of connections points and growth in total
customer numbers has been generally static in recent years.
Against this background, growth in demand has occurred in specific areas with
increased demand for timber and milk processing and the conversion of sheep farms to
dairying. The latter also has requirements for increased levels of irrigation particularly
in the Maniatoto area where already approximately 1MW of additional capacity has
been requested for later in the year.
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SUMMARY
OJV Historic Energy and Maximum Demand
(showing with and without Macraes Gold Mine Load)
90
450
Base MW (excl. Macraes)
Total MW
80
400
Base GWh (excl. Macraes)
Energy - (GWh)
2012
2010
2008
2006
2004
2002
2000
1998
1996
1994
1992
1990
1988
1986
1984
1982
1980
0
1978
0
1976
50
1974
10
1972
100
1970
20
1968
150
1966
30
1964
200
1962
40
1960
250
1958
50
1956
300
1954
60
1952
350
1950
Maximum Demand - (MW)
Total GWh
70
Figure 3 Historic energy and maximum demand
Network development focuses on completion of the Transpower Palmerston GXP and
110 kV line purchase, projects associated with this to take full advantage of this
network re-configuration to yield improved reliability and projects to meet customer
demand in specific areas. Major projects planned over the next ten years are:
Transpower Palmerston & 110kV line purchase completion
Merton Substation replacement to increase capacity and replace old assets.
North Otago East supply reconfiguration to increase capacity and replace old
assets.
New substation at Puketoi to take up new irrigation load.
Milton Elderlee Street Substation replacement to increase capacity and replace old
assets.
Planned development capital expenditure averages about $4.3 million per annum.
0.8
Managing the asset’s lifecycle
The asset lifecycle used by OtagoNet once assets are built, is: Operation,
Maintenance, Renewal, Up-sizing, Extensions and Retirement.
Analysis will be undertaken to review network condition and performance to check if
any trigger is exceeded and actions planned to maintain target service levels.
A number of pole failures at loads less than design load, including some unassisted
pole failures, have highlighted gaps in both the identification of condition and the
recording and application of the line inspection data. In response to the potential
hazards posed from unknown lines condition, OtagoNet has revised its line inspection
template, streamlined its data capture processes and has commenced a one-off 1-year
accelerated inspection cycle of its full network at a total cost of $1.5m with $967k
allocated for FY2015. This is justified on public safety considerations and to maximise
efficiency of expenditure. An additional $500k is set provisionally in the FY2015
maintenance budget to cover priority maintenance works that are likely to be
discovered during the detailed condition inspections but should the asset assessments
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SUMMARY
determine additional work is necessary to improve the safety of the network or
eliminate potential outages, such work will be undertaken. Condition driven renewal is
budgeted at approximately $6.1m p.a. as detailed further in this plan.
Focus for the longer term is to increase the network performance by progressively
rebuilding the older lines with impaired performance and to reduce the average age of
the network closer to 50% average remaining life. Vegetation control and minor
maintenance will also be targeted to help reduce outages.
Improved network information will result from increased network surveillance and will
enable expenditure to be better targeted to maximise benefit.
0.9
Processes and systems
Asset information resides in three key locations: Geographical Information System
(GIS), Asset Management System (AMS), and Supervisory Control And Data
Acquisition (SCADA).
A review of the information available from these systems has been undertaken and it
has been determined improvements can be made relative to the capture, recording and
accessibility of data.
Because of the importance of the availability of accurate information for maximising
customer reliability, targeting and managing expenditure and ensuring regulatory
compliance, it is intended to invest in the order of $1m in the 2014/15 financial year into
the development of these systems.
This plan highlights needed improvements in the collection and analysis of asset
condition data through the GIS, improvements in the collection and analysis of fault
data and in on-going improvement in the accuracy of the asset locations.
0.10 Resourcing the business
Resourcing an operation such as OtagoNet in rural New Zealand imposes its unique
challenges. Further, because of the relatively small customer base and revenue, it is
imperative all resources are utilised efficiently.
0.11 Regulatory compliance of this plan
This plan is required to comply with the Electricity Distribution Information Disclosure
Determination 2012 (EDIDD) appendix A (Asset Management Plans) which sets out
the required content of the AMPs. Compliance with the EDIDD is tabulated in
Appendix A which maps clause requirements of the EDIDD to the section headings in
this AMP.
Forecast budgets provided in this plan are expressed in FY2014 dollars (real).
0.12 Feedback and comments
Comment on this plan is welcome and should be addressed to the Network Manager
(OtagoNet), OtagoNet Ltd, PO Box 1586, Invercargill or email amp@powernet.co.nz.
The next review of this AMP is planned for publishing in March 2015.
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BACKGROUND AND OBJECTIVES
1.
Background and objectives
OtagoNet Joint Venture (OtagoNet) is the electricity lines business that conveys
electricity throughout the North, South, East and some of central Otago (except for the
majority of Dunedin City) to approximately 14,812 customer connections on behalf of
six energy retailers. The wider OtagoNet entity also includes the following associations:
Owned by three entities:
- 51% by Marlborough Lines Limited (MLL).
- 24.5% by Electricity Invercargill Limited (EIL).
- 24.5% by The Power Company Limited (TPCL).
Supported by PowerNet, an electricity lines management company jointly owned
by TPCL and EIL, for corporate services, financial and commercial management,
enterprise business systems, system control and administrative services.
Supported by Marlborough Lines Ltd for engineering support.
Otago Power Services Ltd, an electrical contracting company based in Balclutha,
which has the same owners as OtagoNet and which is managed by MLL. It
undertakes the majority of OtagoNet capital and maintenance expenditure.
This AMP deals solely with the OtagoNet electricity network assets and non-network
assets as defined by the Electricity Distribution Information Disclosure Determination
2012 (EDIDD).
The OtagoNet‘s Asset Management and Planning Processes are based on previous
AMPs, company standards & processes (e.g. PNM-105).
The objective for OtagoNet‘s Asset Management and Planning Processes is to
maintain and develop the OtagoNet assets to achieve all stakeholders target service
levels.
1.1
History of the Network
The network was largely constructed under the auspices of the former Otago Electric
Power Board, a special purpose entity formed in 1923 under the provisions of the
Electric Power Board Act.
As a requirement of the Electricity Companies Act 1992, the Otago Electric Power
Board was obliged to corporatise. This was achieved following public consultation and
transformed into the customer cooperative Otago Power Limited ("OPL") with shares
allocated to customers. In 1998 OPL was obliged by government regulation to divest
either its line business or its generation and electricity retail business and it elected to
sell the latter.
In 2003 the Board of the cooperative opted to sell the assets of the company by tender
and return the proceeds to the customers connected to the network relative to the
number of shares each were given. A domestic customer typically received a sum in
the order of $5,000 and commercial customers received greater amounts relative to
their electricity payments.
The Otago network is unusual in that it provides supply to a predominantly rural
network and much of its reticulation was constructed with the support of RERC subsidy
because the lines were uneconomic. It is the least dense network in New Zealand.
The construction of such uneconomic lines was required by the legislation of the day.
Because of the low customer density and in an endeavour to minimise costs, the lines
were frequently constructed to a standard below that required today.
The Otago Electric Power Board operated on a minimal cost basis with low levels of
reinvestment and its successor, the cooperative company Otago Power Limited, acted
similarly.
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BACKGROUND AND OBJECTIVES
As a consequence when the current owners of OtagoNet acquired the assets in 2003
they were in a less than ideal condition. A condition of sale was that line charges be
held for three years from 2003 which meant that maintenance and capital expenditure
was constrained and costs were minimised.
In recognition of historic low expenditure on replacement capital and the consequent
poor condition of the lines and substation assets, OtagoNet commenced and continues
a programme of capital investment to reduce the network average age, improve the
network reliability and resilience and meet safety requirements. This programme of
needed capital investment has necessitated increases in line charges noting that
rebuilding lines is considerably more expensive than green fields construction and is
being undertaken without the regime of central government subsidy that most of these
rural lines were initially built under.
Hence from 2006 the capital and maintenance expenditure has been increased as
depicted in the chart below.
Historic and forecast expenditure
(CPI adjusted)
$18,000k
$16,000k
$14,000k
Expenditure ($k)
$12,000k
Total
$10,000k
$8,000k
$6,000k
Capital
Maint.
Total
Capital
Maint.
$4,000k
$2,000k
$0k
The marked increment in expenditure in the above graph is indicative at the time of
preparation of this report. Substantive surveillance work on the network is planned over
the next few months to verify the need for the renewal expenditure together with
finalisation of a potential customer‘s significant requirements requiring network
augmentation. Accordingly it is intended to issue a further revision of this plan when
additional information is available. Revenue levels have already been set for the
coming year based on information previously provided to the Commerce Commission
and from a financial perspective it is preferable to maintain the expenditure at
previously determined levels. Irrespective, OtagoNet is conscious of its obligations in
relation to the delivery of electricity and will increase expenditure as required to meet
its priorities and statutory obligations. The increase in expenditure described in this
plan is reflective of the situation known at the time of publishing this AMP.
1.2
Purpose of the Asset Management Plan
The purpose of the AMP is to provide a governance and management framework that
ensures that OtagoNet:
Assets, systems and procedures meet all regulatory requirements including safety
requirements.
Sets service levels for its electricity network that will meet customer, community
and regulatory requirements.
Understands the network capacity, reliability and security of supply that will be
required both now and in the future and the issues that drive these requirements.
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BACKGROUND AND OBJECTIVES
Have robust and transparent processes in place for managing all phases of the
network life cycle from commissioning to disposal.
Has adequately considered the classes of risk OtagoNet‘s network business faces
and that there are systematic processes in place to mitigate identified risks.
Has made adequate provision for funding all phases of the network lifecycle.
Makes decisions within systematic and structured frameworks at each level within
the business.
Has an ever-increasing knowledge of OtagoNet‘s asset locations, ages, condition
and the assets‘ likely future behaviour as they age.
Status of this AMP is ‗Applying‘ with some processes in use in OtagoNet and Otago
Power Services.
Disclosure of OtagoNet‘s AMP in this format will also assist in meeting the
requirements of Section 2.6 and Schedules 11, 12, and 13 of the Electricity Distribution
Information Disclosure Determination 2012.
This AMP is not intended to be a detailed description of OtagoNet‘s assets (these lie in
other parts of the business), but rather a description of the thinking, the policies, the
strategies, the plans and the resources that OtagoNet uses and will use to manage the
assets.
1.3
Interaction with other goals and drivers
All of the assets exist within a strategic context that is shaped by a wide range of
issues including OtagoNet‘s mission statement and business plan, the prevailing
regulatory environment, government policy objectives, commercial and competitive
pressures and technology trends. OtagoNet‘s assets are also influenced by technical
regulations, codes of practice, asset deterioration, network performance, natural
processes, and risk exposures all independent of the strategic context.
1.3.1 Strategic context
The strategic context includes many issues that range from the state of the local
economy to developing technologies. Issues that OtagoNet considers include:
The prevailing regulatory environment which determines prices, requires no
material decline in reliability and requires that OtagoNet compile and disclose
performance and planning information.
Government policy objectives, such as the promotion of distributed generation
(particularly renewables).
OtagoNet‘s commercial goal to deliver a sustainable earnings stream to its owners
that represent an acceptable rate of return.
Pressure from substitute fuels both at the end-user level (such as substituting
electricity with coal or oil at a facility level) and at bulk generation level (wind farms)
including the utilisation of diesel engines to provide motive power for pumps.
Advancing technologies such as fuel cells, improved batteries and current
technologies of micro-wind and photovoltaic, which could potentially strand some
reticulation.
Local, national and global economic cycles, in particular the trends in global
pastoral commodity prices which can influence the use of land from very passive to
very electro-intensive and the consequent change in the customers need for
capacity and reliability.
Changes in climate that may include more storms and hotter, drier summers
(prompting greater irrigation loads).
The economic climate and interest rates which can influence the rate at which new
customers connect to the network and the shareholders required rate of return.
Aggregation of connection points (ie customer‘s sub-mains replacing individual
connection points on barns and workshops)
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BACKGROUND AND OBJECTIVES
Availability of sufficient resources long term to satisfy OtagoNet‘s service
requirements.
1.3.2 Independence from strategic context
Further factors apply independent of the strategic context including:
Safety requirements such as; the earthing of exposed metal, line clearances,
ensuring the network assets are physically sound and generally ensuring the
network does not impose unacceptable risk to customers, the public, contractors
and staff.
Technical regulations including such matters as limiting harmonics to specified
levels.
Asset configuration, condition and deterioration.
Natural processes and laws which govern such fundamental issues as power
flows, insulation failure and faults.
Physical risk exposures. Exposure to events such as wind, snow, earthquakes and
vehicle impacts are generally independent of the strategic context. Issues in which
risk exposure may depend on the strategic context could be in regard to natural
issues such as climate change increasing the severity and frequency of storms or
regulatory issues -for example if LTNZ were to require all poles to be moved back
from the carriage way.
Landowner agreement for property access.
1.3.3 Annual Business Plan and works plan
In each year, the first year of the AMP is consolidated with any recent strategic,
commercial, asset or operational issues into OtagoNet‘s annual business plan. This
defines the priorities and actions for the year ahead and which contribute to OtagoNet‘s
long-term alignment with its strategic goals.
An important component of the annual business plan is the annual works plan which
scopes and costs each individual activity or project that the company expects to
undertake in the year ahead. A critical activity is to firstly ensure that this annual works
plan accurately reflects the current year‘s projects in the AMP and secondly ensure that
each project is implemented according to the scope prescribed in the works plan.
Fundamental is a need to utilise information relative to the performance of the network
and information gained from surveillance in setting and targeting the expenditure.
1.4
Key planning documents and processes
Interactions of the key planning issues, processes and documents are shown in
Figure 4.
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BACKGROUND AND OBJECTIVES
Issues Dependent on
Strategic Context
Issues Independent from
Strategic Context
Regulatory Environment
Government Policy Objectives
Commercial Goals
Competitive Pressures
Substitute Fuels
Technology Trends
Economic Cycles
Interest Rates
Safety Requirements
Technical Regulations
Asset Configuration
Asset Deterioration
Asset Condition
Natural Processes
Physical Risk Exposures
Asset Management Plan
Annual Business Plan
incl. Works Programme
Performance Review
Varying
Condition
Influences
&
Constraints
Assets
Service Levels
Figure 4 - Interaction of key plans
1.4.1 Vision statement
To operate as a successful business in the distribution of electricity in the Otago region.
1.4.2 Strategic plan
Key asset management drivers from OtagoNet‘s Strategic Plan are:
1. Ensure public, customers, contractors and staff are safe relative to all aspects of
the network operations. This includes adherence to all regulatory requirements and
recognised industry practice.
2. Delivery to the customers of an economic, safe, efficient and quality electricity
supply.
3. Maintaining and enhancing the long term value of assets, business units, products
and investments.
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BACKGROUND AND OBJECTIVES
4. Working with the Commerce Commission to achieve:
-
Regulated prices which enable customers to enjoy a long term reliable and
sustainable network connection and
Result in a reasonable commercial return on equity to the owners to enable
continued support and investment in the business.
1.4.3 Asset strategy
OtagoNet continues to develop its detailed asset strategy to meet its corporate goals
and in response to the performance levels it achieves. The following are our key asset
strategies that are further supported and developed in this plan:
Improve reliability by:
- managing deteriorating assets through condition inspection and replacement;
- sectionalising poorly performing feeders;
- reduce planned SAIDI by greater use of mobile generation where feasible
and economic; and
- expand the meshed area of the network where practical by closing gaps
between radial feeders but noting that options in this regard are extremely
limited.
Control costs and manage economic and regulatory risk by:
- employing strong capital governance and management processes;
- using condition-based assessments in the replacement and maintenance of
assets;
- identifying and managing network risks;
- directing investment towards reliability improvement and the more economic
sections of the network.
Meet safety and environmental standards by:
- identifying and managing network health, safety and other risks including
external review;
- achieving full regulatory compliance;
- ensuring compliance with internal network standards; and
- utilising applicable codes of practice.
1.4.4 Prevailing regulatory environment
OtagoNet‘s assets are subject to a price path threshold established under Part 4 of the
Commerce Act 1986. OtagoNet is subject to information disclosure requirements
(including the requirement to publish an AMP) along with other structural regulations
such as restrictions on generating and retailing energy, and the requirement to connect
embedded generation.
1.4.5 Government objectives
Electricity lines businesses are increasingly required to give effect to many aspects of
government policy, namely:
Facilitating the connection of distributed generation on a regulated basis.
Improving the already high levels of public safety around power lines and
transformers.
Offering variable tariff components to promote demand reduction despite the most
cost reflective tariff structure for a lines business being that of fixed cost.
Continuance of supply regulations that require the provision and maintenance of
existing lines that may be uneconomic.
Price increases in rural areas to be no greater than those prevailing in urban areas.
1.4.6 Annual business plan
An Annual Business Plan (ABP) which is produced by OtagoNet and which contains
the following:
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BACKGROUND AND OBJECTIVES
Vision Statement and Critical Success Factors.
Customer Service and Commercial Objectives, and Action plan.
Annual Capital Works Programme and the Annual Works Plan (AWP) for the
following four years.
Business Plan Financials.
1.4.7 Annual works plan
The Annual Works Plan (AWP) details the works to be undertaken for each financial
year, and is incorporated into the ABP. All of next year‘s works, listed in the AMP, are
included in the AWP.
1.5
Interaction of goals and strategies
The below table shows the linkage between the Corporate and Asset Management
Strategies:
Corporate Strategies
Delivery to the customers of an economic, safe, efficient and quality
electricity supply and meets all legislative requirements.
Maintaining and enhancing the long term value of assets, business units,
products and investments.
Deliver a reasonable commercial return on equity.
Achieve a long term reliable electricity supply.
Asset Management Strategies
Sectionalising poorly performing feeders
Continue to expand the meshed area of the network
Manage deteriorating assets through condition inspection and
replacement
Reduce planned SAIDI by employing mobile generation where feasible
and economic
Employ strong capital governance processes
Identifying and managing network health, safety and other risks
Direct investment towards reliability and the more economic sections of
the network
Achieve 100% regulatory compliance
Ensure compliance with internal network standards
1.6
Period covered by Asset Management Plan
This edition of OtagoNet‘s AMP covers the period 1 April 2014 to 31 March 2024. This
AMP was prepared during January to March 2014, approved by OtagoNet‘s Governing
Committee in March 2014 and publicly disclosed at the end of March 2014.
Uncertainty is a factor in any planning process and accordingly the plans set out in this
AMP include a degree of uncertainty. Customer demand driven by turbulent commodity
markets, public policy trends and possible generation opportunities within OtagoNet‘s
demand profile means the future is perhaps less certain than many other infrastructure
businesses of greater scale. Accordingly, OtagoNet has attached the following
certainties to the timeframes of the AMP:
Timeframe
Residential and Commercial
Large Industrial
Year 1 to 2
Years 3 to 5
Reasonably certain
Less certain
Reasonably certain Reasonable certainty
Little if any certainty Little if any certainty
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Intending Generators
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BACKGROUND AND OBJECTIVES
Years 6 to 10 Little if any certainty
1.7
Little if any certainty Little if any certainty
Stakeholder interests
1.7.1 Stakeholders
A stakeholder is defined as any person or class of persons who:
Has a financial interest in OtagoNet (be it equity or debt).
Is physically connected to OtagoNet‘s network.
Uses OtagoNet‘s network for conveying electricity.
Supplies OtagoNet with goods or services.
Is affected by the existence, nature or condition of the network (especially if it is in
an unsafe condition).
Has a statutory obligation to perform an activity in relation to the OtagoNet
network‘s existence (such as request disclosure data or regulate prices).
1.7.2 Stakeholder interests
The interests of OtagoNet‘s stakeholders are classified in Table 2:
Table 2 – Key stakeholder interests
Interests
Viability
Shareholder
Bankers
Connected customers
Contracted managers (PowerNet and
Marlborough Lines)
Energy retailers
Mass-market representative groups
Industry representative groups
Staff and contractors
Suppliers of goods and services
Public
Land owners
Councils (excluding as a customer)
Transport Agency
Ministry of Economic Development
Energy Safety Service
Commerce Commission
Electricity Authority
Electricity & Gas Complaints Commission
Ministry of Consumer Affairs
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Price
Quality
Safety
Compliance
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BACKGROUND AND OBJECTIVES
Table 3 below demonstrates how stakeholder‘s expectations and requirements are
identified.
Table 3- How stakeholder’s expectations are identified
Stakeholder
Owners
Bankers
Connected Customers
Contracted Managers (PowerNet and
Marlborough Lines)
Energy Retailers
Mass-market Representative Groups
Industry Representative Groups
Staff & Contractors
Suppliers of Goods & Services
Public (as distinct from customers)
Land Owners
Councils (as regulators)
Transport Agency
Ministry of Economic Development
Energy Safety Service
Commerce Commission
Electricity Authority
Electricity & Gas Complaints Commission
Ministry of Consumer Affairs
Asset Management Plan 2014
How expectations are identified
By their approval or required amendment of the
Business Plan.
Regular meetings between the directors and
executive.
Regular meetings between the bankers and
PowerNet‘s Chief Executive and GM Finance.
By adhering to OtagoNet‘s treasury/borrowing
policy
By adhering to banking covenants.
Regular discussions with large industrial
customers as part of their on-going development
needs.
Annual customer surveys and feedback from
OtagoNet Newsletters
Chairman and Management Committee meeting
with the Chief Executive as required.
Annual consultation with retailers.
Informal contact with group representatives.
Informal contact with group representatives.
Regular staff briefings.
Regular contractor meetings.
Regular supply meetings.
Informal discussions.
Feedback from public meetings.
Individual discussions as required.
Formally as necessary to discuss issues such as
assets on Council land.
Formally as District Plans are reviewed.
Formally as required.
Regular bulletins on various matters.
Release of legislation, regulations and discussion
papers.
Analysis of submissions on discussion papers.
Promulgated regulations and codes of practice.
Audits of OtagoNet‘s activities.
Audit reports from other lines businesses.
Regular bulletins on various matters.
Release of discussion papers.
Analysis of submissions on discussion papers.
Conferences following submission process.
Weekly update.
Release of discussion papers.
Briefing sessions.
Analysis of submissions on discussion papers.
Conferences following submission process.
General information on their website.
Reviewing their decisions in regard to other lines
companies.
Release of legislation, regulations and discussion
papers.
General information on their website.
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BACKGROUND AND OBJECTIVES
1.7.3 Meeting stakeholder interests
Table 4 provides a broad indication of how stakeholder interests are met:
Table 4 – Accommodating stakeholder interests
Interest
Description
How OtagoNet meets interests
Safety
Staff, contractors and the
public at large must be
able to move around and
work on the network in
total safety.
Viability
Viability is necessary to
ensure that the
shareholder and other
providers of finance such
as bankers have
sufficient reason to keep
investing in OtagoNet.
Price
Price is a key means of
both gathering revenue
to sustain the business
and signalling the true
underlying costs.
The public at large are kept safe by ensuring that all
above-ground assets are structurally sound, live
conductors are well out of reach, all enclosures are
kept locked and all exposed metal is earthed.
The safety of our staff and contractors is ensured by
providing all necessary equipment, improving safe
work practices and ensuring that they are stood
down in unsafe conditions.
Contractors will use all necessary safety equipment,
improve their safe work practices and ensure that
they stand down in unsafe conditions.
Motorists will be kept safe by ensuring that aboveground structures are kept as far as possible from
the carriage way within the constraints faced in
regard to private land and road reserve.
An improved surveillance program has been
initiated to ensure the network is compliant in these
regards.
Stakeholders‘ needs for long-term viability are
accommodated by delivering earnings that are
sustainable and reflect an appropriate risk-adjusted
return on employed capital. In general terms this
will need to be at least as good as the stakeholders
could obtain from a term deposit at the bank plus a
margin to reflect the ever-increasing risks to the
capital in the business.
Earnings are set by estimating the level of
expenditure that will maintain Service Levels within
targets and the revenue set to provide the required
returns.
OtagoNet‘s total revenue is constrained by the
default price quality path regime. Prices are
controlled with the CPI-X price path with X set at 0%
in the current Price Reset which runs to 1 April
2015. The opportunity exists to apply to the
Commerce Commission for a Customised Price
Path in circumstance where prices are insufficient to
fund the business.
The regulatory regime also applies a building-block
approach for setting allowed revenue based on the
business‘s forecast operating and capital
requirements and where revenue claw-backs in the
next period may be applied if the business fails to
expend those budgets.
OtagoNet‘s pricing methodology is expected to be
cost-reflective, but issues such as the Low Fixed
Charges requirements can distort this.
Supply
quality
Emphasis on continuity
then restoration of supply
and reducing flicker is
essential to minimising
interruptions to
customers‘ businesses.
Asset Management Plan 2014
Stakeholders‘ needs for supply quality will be
accommodated by focusing resources on continuity
and then rapid restoration of supply. The most
recent mass-market survey indicated a general
satisfaction with the present supply quality.
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BACKGROUND AND OBJECTIVES
Interest
Description
How OtagoNet meets interests
Compliance
Compliance is necessary
with many statutory
requirements ranging
from safety to disclosing
information.
All safety issues will be adequately documented and
available for inspection by authorised agencies.
Performance and other regulatory disclosure
information will be provided in a timely and
compliant fashion.
1.7.4 Management of conflicting interests
Conflicts exist in simultaneously meeting all stakeholders interests ie between price,
commercial return and reliability. Priorities for managing conflicting interests are:
Safety. Top priority is given to safety. The safety of staff, contractors and the
public will not be compromised even if budgets are exceeded.
Compliance. Legislative compliance is paramount to proper governance and
operation of any business.
Viability. Third priority is viability of the business (as defined in 1.7.3 above), as the
business needs to sustain itself in order to provide a network service to its
customers.
Pricing. OtagoNet will give forth priority to pricing noting that pricing is also an
aspect of viability. OtagoNet recognises the need to adequately fund its business
whilst ensuring that its customers‘ businesses can operate successfully and there
is not an unjustified transfer of wealth from its customers to its shareholders.
Supply quality is the fifth priority. Good supply quality minimises economic loss to
OtagoNet‘s customers.
1.7.5 Customer consultation
Consultation was undertaken by four methods, firstly a phone survey of 200 customers
was undertaken by external consultants. A copy of the questionnaire used is attached
in appendix B.
The second method was a face to face survey by the survey company with major
customers. Overall customers did not wish to pay more but expected reliability of
supply to improve or at least be maintained.
Thirdly OtagoNet held community consultation meetings at various locations
throughout the network, where direct feedback was obtained.
Lastly, individual customers are consulted as they undertake connection to the network
or consider upgrades. An example was the Greenfields Dairy processing plant near
Clydevale and this has required numerous options and negotiations before the final
solution was agreed.
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BACKGROUND AND OBJECTIVES
Figure 5 Greenfields Substation
1.7.6 Uneconomic connections
Within OtagoNet‘s network there is an inherent level of cross-subsidy between
consumers as the proportion of asset value needed for each connection on the network
is not uniform. A consumer adjacent to Charlotte St zone substation in Balclutha is
supported by the short subtransmission lines between the Balclutha grid exit point and
this zone substation, the Charlotte St zone substation transformation and switching
capacity, and the small length of distribution line to the consumers installation.
Additionally, all of the network assets upstream of this consumer are shared over a
large number of other consumers in Balclutha. In contrast, a consumer on a farm out
of Hindon is supported by much longer subtransmission lines, proportionately more
transformation capacity (due to lower diversity) and long 11 kV or SWER distribution
lines which are shared over a relatively few consumers. Maintenance costs are also
proportionately higher for the rural consumer as these costs scale with network length.
However, both consumers pay uniform capacity charges.
Cross-subsidy exists in all electricity network businesses employing uniform charging
to a greater or lesser extent largely dependent on the connection density of the
network. In OtagoNet‘s case, it has the lowest connection density of all EDBs in New
Zealand.4 Consequently, dealing with uneconomic connections is a substantial issue
for the company.
The extent of the issue is illustrated in the following chart of Figure 6 below. This plots
the cumulative percentage of network connections (x-axis) against the cumulative
percentage of network asset value needed to support those connections. This shows
that approximately 50% of the network value is utilised by the last 22% of the network
connections and highlights the extent of the cross-subsidy inherent in the network
configuration.5
4
FY2013 disclosure has OtagoNet at 3 connections per km of line and this compares to Wellington
Electricity at 36 connections per km.
5
This should be considered a conservative estimate as operational costs are not included and these
approximately scale in proportion to network length.
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BACKGROUND AND OBJECTIVES
Figure 6 Network cross subsidy
Whilst differential charging is not being considered at this time, the issue is highlighted
with generally static growth in urban areas and lower consumer demand from the
impact of energy efficiency and photovoltaic uptake, which will potentially result in a
greater subsidy if network charges continue to be recorded on a variable basis.
In regard to asset management, consideration of the uneconomic nature of some
connections, lines, and even zone substations, requires the prioritisation of capital
works towards the more economic parts of the network. For the avoidance of doubt we
note that any works addressing safety issues do not consider the economic return from
the affected connections.
As measures of reliability such as SAIDI react most to outages on the parts of the
network that affect large customer numbers, there is a natural favouring of the more
economic parts of the network when works are directed based on their impact on
reliability and OtagoNet directs its capital and maintenance expenditure in part through
this mechanism.
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BACKGROUND AND OBJECTIVES
1.8
Accountabilities for asset management
OtagoNet‘s ownership, governance and management structure is depicted below in
Figure 7.
Marlborough Electric
Power Trust
(100%)
Invercargill City Council
(100%)
SEPS Consumer Trust
(100%)
Ownership
Invercargill City
Holdings
(100%)
Marlborough Lines
Board of Directors
(100%)
Electricity Invercargill
Board of Directors
(100%)
The Power Company
Board of Directors
(100%)
Southern Lines
(51%)
Pylon
(24.5%)
Last Tango
(24.5%)
Governance
Otago Joint Venture
Governing Committee
PowerNet
Corporate services; financial and
commercial management;
enterprise business systems;
system control; admin services
Marlborough Lines
Engineering
Management
Figure 7 - Governance and Management Accountabilities
1.8.1 Accountability at governance level
As OtagoNet uses a Governing Committee to represent the multiple owners and
contracts to PowerNet for corporate services, financial and commercial management,
regulatory management, enterprise business systems, system control and
administrative services and Marlborough Lines for engineering support and so it
effectively has a two-tier governance structure as follows:
The first tier of governance accountability is between the Governing Committee
and the Boards of the respective owners with the principal mechanism being the
Statement of Intent (SOI). Inclusion of reliability targets in the SOI makes the
Governing Committee ultimately accountable to the shareholders for these
important asset management outcomes whilst the inclusion of financial targets in
the SOI makes the Governing Committee additionally accountable for overseeing
the price-quality trade-off inherent in projecting expenditure and reliability.
Members of the Governing committee are:
-
Terry Shagin (Chairman)
Alan Harper
Ken Forrest
Neil Boniface
The second tier of governance accountability is between the Governing Committee
and the PowerNet and Marlborough Lines Boards with the principal mechanism
being the management contracts.
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BACKGROUND AND OBJECTIVES
1.8.2 Accountability at executive level
Accountability for corporate services, financial and commercial management,
regulatory management, enterprise business systems, system control and
administrative services rests with the chief executive of PowerNet Limited and
accountability for engineering matters rests with the chief executive of Marlborough
Lines Limited. The mechanism of accountability is through the management contracts
to the OtagoNet Management Committee.
1.8.3 Accountability at operational level
The individual managers who have the most influence over the long-term asset
management outcomes will be the Engineering Manager and Network Manager
(Otago) through their preparation and execution of the AMP which will guide the
activities and direction of others.
1.8.4 Accountability at construction/maintenance level
Otago Power Services Limited is used almost exclusively for all construction,
replacement and maintenance services, as a contractor, except for some specialist
work. The principal accountability mechanism is through a contract between Otago
Power Services and OtagoNet.
1.8.5 Key reporting lines
The OtagoNet Governing Committee receives a monthly report that covers the
following items:
Network Safety – safety performance reported and issues highlighted, with
progress to eliminate, mitigate or manage reported
Network reliability – this lists all outages over the last month, and trends regarding
the reliability targets
Network Quality – detail of outstanding voltage complaints and annual statistics on
them
Network Connections – monthly and yearly details of connections to the network
Use of Network – trend of the energy conveyed through the network
Revenue – detail on the line charges and other miscellaneous revenue received
Retailer activity – detail on volumes and numbers per energy retailer operating on
the network
Works Programme – monthly and YTD6 expenditure on each works programme
item and percentage complete, with notes on major variations
Key Performance Indicator measures
Each level of management has defined financial limits in the OtagoNet Financial
Authorities Policy. This requires any new project over $100,000 or variation to the
approved Annual Works Plan by more than +10% or -30%, to have Governing
Committee approval. Generally most projects are approved by the Governing
Committee in the Annual Business Plan process.
1.9
Systems and processes
OtagoNet‘s systems and processes are described in detail in section 9. Specific asset
inspection and network maintenance strategies are described in section 8.3.
6
YTD = Year to date
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OUR NETWORK
2.
Description of network
2.1
Service area
2.1.1 Regions covered
The distribution area covers three geographically distinct areas:
The south and west Otago area that stretches from Lake Waihola to Owaka and
inland to Clinton.
The north Otago coast from Waitati to Shag Point.
The inland north Otago area from Falls Dam south to Hindon.
Figure 8 - Distribution Area
Topography varies as follows:
Flat fertile plains and rolling hills in the south and west Otago area that includes
townships of Milton, Balclutha, Owaka and Clinton.
Rolling countryside along the north Otago coast that includes townships of Waitati,
Waikouaiti and Palmerston.
Dry flat plains, rolling hills and mountainous areas in the inland north Otago area
that includes townships of Naseby and Ranfurly, the Macraes Mine and stretches
as far south as Middlemarch, Clarks Junction and Hindon.
Under the regulatory requirements, OtagoNet treats all areas similarly with no
separated or segmented disclosure as all areas are connected electrically with the
northern and southern MV networks connecting at Lake Mahinerangi.
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OUR NETWORK
2.1.2 Demographics
The normal resident population in the main territorial authorities of Clutha district and
Central Otago district comprise 34,785 residents with a largely static population in
Clutha and a slowly rising population in Central Otago as illustrated in Figure 9 below.7
Figure 9 Territorial population trend
Of note is the distinctly aging nature of the populations in both districts but particularly
in the Central Otago district as evident in the shift in the population mode between the
2006 and 2013 census, which is illustrated in the chart of Figure 10 below.
Figure 10 Population age profile by region
OtagoNet‘s total connections are relatively static as described in Table 5 and Figure 11
following.8 [Note that the increase in ―crop growing‖ connections relates mainly to new
irrigation pump connections often associated with grass growing for dairy farming].
7
Source 2013 Census data. Note this differs to the FY2012 AMP that used the 2006 census for which
populations by towns solely within the OtagoNet area were available.
8
Categorisation based on ANZSIC codes in retailer data; not all classifications included.
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Table 5 - ICP counts by year
Disclosure Year
2008
2009
2010
2011
2012
2013
2014 (estimated)
Total Network
Connections
14,747
14,761
14,768
14,801
14,824
14,812
14,740
Figure 11 Trends in ICPs by type (not all categories included)
Whilst the population in the areas served by OtagoNet is aging, the drop in domestic
connections does not necessarily relate to a fall-off in domestic consumers but mostly
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relates to rural consumers aggregating connection points i.e. avoiding connection
charges on multiple connections by sub-maining barns or workshops into a single nondomestic connection. This reduces the total domestic connections while maintaining (or
sometimes reducing) the number of non-domestic connections. This highlights that
electricity charges are at a level where consumers in particular circumstances are
investing to limit or avoid these charges, which in turn reduces OtagoNet‘s line charge
revenue.
The rise in dairy farm operations, particularly in the Central Otago region, is a notable
feature with an expectation of continued growth in the near term as noted in the dairy
herd and land use statistics published by the dairy industry and as illustrated in Figure
12 following:9
Figure 12 Dairy farming trends by region
The challenge for OtagoNet from these demographics will be in managing its capital
replacement program in the face of a potentially diminishing connection base to
support the network service costs and the increase in the number of dairy farm
connections, which are more sensitive to service outages.10 These challenges are
9
FY2008 to FY2013 annual reports; Dairynz; www.dairynz.co.nz/publications
10
Inability to milk the herd and/or the loss of milk chillers that can result in rejected product.
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addressed through asset management strategies reinforcing capital expenditure
governance processes to maintain or reduce planned and fault outages.
2.1.3 Large Consumers
The largest consumer in the area is a gold mine but other large consumers include
extensive meat and dairy processing and forestry and timber processing and
increasingly dairy farming. Most of the towns in the service area are rural service
towns.
The area‘s economic fortunes will therefore be strongly influenced by:
Market for gold
Markets for basic and specialised meats such as beef, mutton and lamb.
Markets for dairy products.
Markets for processed timber.
Markets for black and brown coal.
Government policies on mining of coal.
Government policies on forestry and
nitrogen-based pastoral farming.
Access to water for crop and stock
irrigation, especially in north and central
Otago.
The impact of these issues is broadly as
described in Table 6.
The recent increase in new connections for
irrigation indicate the farming sector is willing
to invest and create new load points and
OtagoNet responds to this through its network
development and reliability planning.
Major consumers have significant impact on
network operations and asset management
priorities. Significant single loads are::
Oceana Gold‘s 23 MVA of load on the
Oceana Gold’s 66kV line upgrade
Ranfurly substation requires a 66kV line,
large dual rated 33/66kV step-up transformers and two heavy 33kV lines from the
Naseby GXP. [Public announcements
have been made that this mine is due
Mount Stuart Wind Farm
for closure circa 2017 but confirmation is
yet to be received by OtagoNet].
TrustPower‘s
12.25MW
generation
station also requires the 66kV supply at
Ranfurly for an embedded connection to
Oceana Gold.
Pioneer Generation‘s Falls Dam power
station requires enhanced 33kV line
regulation and arrangements at the
Oturehua substation.
PPCS Finegand‘s 7MVA of load
required a dual 33kV line to provide the
required security to it and customers on
three downstream zone substations.
Fonterra‘s Stirling cheese plant has
33kV switching between two supplies to
provide fast recovery of power supply in
the event of a fault on one line.
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The Otago Regional Corrections Facility at Milburn has been provided with two
11kV supplies from different zone substations and automatic change over
switchgear to deliver its required security.
Pioneer Generation‘s Mount Stuart wind farm that connects into the Glenore to
Lawrence 33kV line.
Greenfield‘s Dairy Processing plant at Clydevale.
Table 6 – Impact of regional economic issues
Issue
Visible impact
Impact on OtagoNet’s value drivers
Shifts in market
tastes for beef,
mutton, lamb
Reduced gold price
May lead to a contraction of
demand by these industries.
Reduces asset utilisation.
Possible capacity stranding
Shifting markets for
dairy products
May lead to reduction or
closure of mine
May lead to a contraction of
demand by these industries.
Shifting markets for
timber
May lead to a contraction in
demand by these industries
Shifting markets for
coal
May lead to a contraction in
demand by these industries
Government CO2
Policy
May lead to a contraction in
demand by industries
May create new process
requirement for industries
May lead to contraction of
dairy shed demand.
May lead to contraction of
dairy processing demand.
May lead to increased
irrigation demand.
Little impact because supply assets
largely paid for by mine
Reduces asset utilisation.
Possible capacity stranding
Reduces asset utilisation.
Possible capacity stranding
Reduces asset utilisation.
Possible capacity stranding
Reduces asset utilisation.
Possible capacity stranding
New capacity required
Government policy on
nitrogen-based
farming
Access to water.
Reduces asset utilisation.
Possible capacity stranding
Increases asset utilisation but without
corresponding increase in load factor
2.1.4 Load characteristics
Domestic: Standard household usage with demand peaks in morning (8am) and
evening (7:00pm). The use of heat pumps is increasing electricity usage, with no
noticeable impact over the summer hot period yet. Peaks normally occur in winter.
Farming: In South Otago the predominant farming load is dairy farming with the
milking season between August and May with morning and late afternoon peaks.
The remaining farms normally have very low usage with some pumps and electric
fences, with peak usage during the few days of shearing or crop harvesting. In
North Otago and the Maniototo the predominant load is irrigation with the peak
loads over the summer hot dry periods.
A notable feature of farm irrigation load is its effect on measures of transformer
utilisation as irrigation connections employ distribution transformer capacity but
contribute almost no demand at the time of the network winter peak.
Sawmills: Usage at sawmills due to processing and kiln drying of the product.
There is also some wood-chipping of logs for export and these have some very
large motors with poor starting characteristics.
Dairy Processing: Load characteristic is dependent on milk production and the
movement of milk between processing plants to maximise plant efficiency.
Freezing Works: The load characteristics are similar to the dairy processing but
with the off season 1-2 months later depending on the markets and production.
Mining: The mining load experienced in Otago has a very flat load profile
maintained 24 hours per day all year round.
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The makeup of load in the 2013 year and the percentage changes from 2009 to 2013
are illustrated in the charts of Figure 13 below [which excludes the Macraes gold mine
load which is the dominant load on the network]. This shows a general reduction in non
HV connection loads with the greatest change in domestic loads.11
Figure 13 Load make-up (kWhs) by type (excludes Macraes mine)
2.1.5 Other drivers of electricity use
Other drivers of electricity use include:
Low temperatures during winter (-5°C frosts are not uncommon in the area).
The use of heat pumps as air conditioners in the 26°C summer heat.
Increased energy efficiency due to Government campaigns. (Compact fluorescent
and LED lights, Warm Homes initiatives.)
Fuel switching ie installation of wood pellet fires in response to rising electricity
prices.
2.1.6 Energy and demand characteristics
Key energy and demand figures for the YE 31 March 2013 are as follows:
Table 7 - Key Energy and Demand Figures
Parameter
Value
Long-term trend
Energy conveyed
422 GWh
Max demand
Load factor
Transformer utilisation
60.7 MW
79 %
29.2 %
Losses
-5.1%
Steady increase but mainly from HV
(industrial) loads; domestic loads
reducing.
Steady.
Steady.
Slight reduction with minimum 15kVA
transformer size.
Step drop from -6.9% arising from
change in metering point for Macraes
Gold Mine load
Closure or reduction of the gold mine would have a major impact on the above
statistics for energy conveyed, maximum demand and load factor.
11
Seasonal differences between 2009 and 2013 will also influence this finding. The decrease in domestic
load will also be affected by the consolidation of connections through sub-maining as the single
connection then becomes classified as commercial.
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2.2
Summary of network configuration
To supply OtagoNet‘s 14,812 customers12 the company owns and operates a single
electrical network across three geographically distinct areas described in Section 2.1.1.
The two northern areas are connected by a 33 kV line over the Pig Root13 that can
supply about half of the inland north Otago‘s maximum demand. The southern and
northern MV networks are connected near Lake Mahinerangi.
2.2.1 Bulk supply assets and embedded generation
2.2.1.1 Balclutha Grid Exit Point (GXP)
Balclutha GXP is supplied by a double circuit tower 110 kV diversion (not a tee) from
the Gore – Berwick single circuit 110 kV pole line. Supply is taken through eight 33kV
feeders from the Balclutha GXP.
2.2.1.2 Naseby Grid Exit Point (GXP)
Naseby GXP is supplied off a single circuit 220 kV tower line from Roxburgh to
Livingstone and supplies the Ranfurly zone substation via two 33 kV circuits.
2.2.1.3 Halfway Bush Grid Exit Point (GXP)
The Halfway Bush GXP supplies the coastal area north of Dunedin and Palmerston by
a double circuit 110 kV tower line that splits into two single circuit pole lines just north
of Dunedin. The supply is transformed to 33 kV at Palmerston at the site previously
owned by Transpower. The Palmerston zone substation is supplied by 2km of 33kV
line from this previous GXP site. There are also 33kV lines heading south to
Waikouaiti (Merton zone substation) and west across the Pig Root to Deepdell. Prior to
1 April 2014 Palmerston was supplied at 110 kV from a Transpower GXP at
Palmerston but OtagoNet gained ownership of the Transpower lines from Halfway
Bush and the Transpower Palmerston substation on 31 March 2013 with completion of
the transaction on 1 April 2014. The acquisition of the Transpower assets and
subsequent improvements to the OtagoNet network will result in increased reliability of
supply for the Waitaki coastal area and reduce operational costs.
2.2.1.4 Paerau generation
The 12.25 MW Paerau hydro scheme was built by Otago Power Limited in 1984 and
then sold to TrustPower as a result of the enactment of the Electricity Industry Reform
Act 1998. Paerau‘s generation is injected into the Ranfurly zone substation at 66 kV
and is embedded with the Macraes Gold Mine load.
2.2.1.5 Falls Dam generation
The Pioneer Generation Limited (PGL) 1.25 MW Falls Dam hydro scheme is connected
to the 33 kV network at Oturehua. PGL owns the equipment to enable connection onto
the OtagoNet 33 kV Line.
2.2.1.6 Mt Stuart Generation
The Pioneer Generation Limited (PGL) 7.65MW Mt Stuart wind scheme is connected to
the 33 kV network on the Glenore-Lawrence line. PGL owns the equipment to enable
connection onto the OtagoNet 33 kV line.
12
FY2013 disclosure connections total.
13
Between Palmerston and Ranfurly and yes it is spelt this way… named by John Turnbull Thomson.
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2.2.1.7 Bulk Supply Characteristics
Table 8 – Bulk supply characteristics (highest half-hour)
Supply Point
Balclutha GXP
Naseby GXP
14
Palmerston GXP
Paerau
Falls Dam
Mt Stuart
Voltage
110/33kV
220/33kV
110/33 kV
66 kV
33 kV
33 kV
Rating
60MVA
80MVA
10 MVA
24 MVA
1.25 MVA
8 MVA
Firm Rating
28.1MVA
34.2MVA
10.0 MVA
15
15 MVA
1.25 MVA
15
7 MVA
Peak Load
FY2013
27,182kW (Feb)
24,948kW (April)
9,030 kW (Jun)
12,409 kW
1,281 kW
7,500 kW
2.2.2 Subtransmission network
OtagoNet‘s subtransmission network comprises two electrically separate networks as
depicted in Figure 14.
The subtransmission network comprises 74 km of 66 kV line and 539 km of 33 kV line
and has the following characteristics:
It is almost totally overhead except for short cable runs at GXP‘s and zone
substations.
It is almost totally radial except for a few instances on the south Otago network
where closed rings have been formed.
It includes a large number of lightly loaded zone substations because the long
distances are beyond the reach of 11 kV.
OtagoNet‘s subtransmission network is different to most other electricity distribution
businesses in that it has very little redundancy because of the low load density; it may
be essentially characterised as 33 kV feeders. This impacts on reliability as 33 kV line
faults result in larger customer outages and this focuses the asset management
towards the condition and integrity of these lines.
As poor condition lines are rebuilt they are generally rebuilt with concrete poles,
galvanised steel crossarms and clamp-top insulators to maximise reliability and life.
2.2.3 Zone substations
OtagoNet owns and operates 34 zone substations with a 66/33 kV interconnecting
station (at Ranfurly). A description of each zone and its security level is given in Table
9. Additionally there are eight 33/0.415 kV distribution transformers supplied direct off
the 33kV subtransmission network at Balmoral Water Scheme, Big Sky Dairy,
Cormack, Hore‘s Pump, O‘Malley‘s House, O‘Malley‘s Pump, Rough Ridge and Tisdall.
14
The transfer to halfway Bush GXP is effective from 1 April 2014. The peak load provided here relates to
the configuration existing prior to that.
15
This firm rating is based on the number and capacity of the transformers on site, however, it should be
noted that these sites are connected to the network via a single supply route.
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Figure 14 – Subtransmission network
Table 9 - Zone Substations
Substation
Nature of load
Description of substation
Supply security
Charlotte
Street
(Balclutha)
Urban domestic and
commercial with some
rural loads including
farms and timber mills
Dual 33kV supply to a 33kV indoor
switchboard, with three 33kV feeders.
Dual 5MVA transformers, 11kV
indoor switchboard
No loss of supply after first
contingent event (N-1)
Clarks
Remote
farms
rural
Tee off the 33kV radial line beyond
Middlemarch. 0.5MVA 22kV SWER
substation.
Load restored in time taken
for repair of first contingent
event (N)
Clinton
Small urban township
and rural farms
Radial 33kV from Clifton switches.
2.5MVA transformer and outdoor
11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
isolated
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Substation
Nature of load
Description of substation
Supply security
Clydevale
Small urban township
and rural farms
Alternate 33kV lines supplying
2.5MVA transformer and outdoor
11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Deepdell
Remote
farms
rural
Alternate 33kV lines supplying
0.75MVA transformer and basic 11kV
outdoor substation.
Load restored in time taken
for repair of first contingent
event (N)
Elderlee
Street
(Milton)
Urban domestic and
commercial with some
rural loads including
farms and timber mills
Supplied off a 33kV ring. Dual 5MVA
transformers and 11kV indoor
switchboard.
No loss of supply after first
contingent event (N-1)
Finegand
Rural farming
Meat processing plant
Three supply routes at 33kV. 2.5MVA
transformer and outdoor 11kV
substation.
A
33kV
feed
to
Processing plant.
Load restored in time taken
for repair of first contingent
event (N)
Glenore
Rural farming
Supplied off a 33kV ring. 1.5MVA
transformer and outdoor 11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Greenfield
Dairy processing plant
Single 33kV line with 33kV circuit
breaker and 33kV regulator with three
33kV feeds to the plant.
Load restored in time taken
for repair of first contingent
event (N)
Golden Point
Mining
Teed off the Deepdell to Palmerston
33kV line. 5MVA transformer with
indoor 11kV switchgear.
Load restored in time taken
for repair of first contingent
event (N)
Hindon
Remote
farms
rural
Radial 33kV line to 0.5MVA 22kV
SWER and 0.1MVA 11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Hyde
Rural
farming
irrigation load
with
Alternate 33kV line to a 2.5MVA
transformer and outdoor 11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Kaitangata
Small urban township
and rural farms
Radial 33kV to a 2.5MVA transformer
and outdoor 11kV substation.
Load restored in time taken
to isolate and back-feed
after first contingent event
(N)
Lawrence
Small urban township
and rural farms
Alternate 33kV lines to a 2.5MVA
transformer
and
indoor
11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Macraes
Mining
Gold
mine
processing
and
Radial 66kV line to dual 7.5/15MVA
66/11kV transformers with 66kV
switchyard
and
indoor
11kV
switchboard.
Load restored in time taken
for repair of first contingent
event (N)
Merton
Urban domestic and
commercial with some
rural farms and one large
chicken farm
Teed off the radial 33kV Palmerston
to Waitati. Dual 2.5MVA transformers
and outdoor 11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Middlemarch
Small urban township
and rural farms
Radial 33kV from
2.5MVA transformer
11kV substation.
Deepdell to
and outdoor
Load restored in time taken
for repair of first contingent
event (N)
Milburn
Sawmills and some rural
load transferred off Milton
and Waihola
Teed off the Elderlee to Waihola
33kV line. One 3/5MVA transformer
and one 2.5MVA transformer with
indoor 11kV switchgear.
Load restored within 25
minutes after first contingent
event (N)
North
Balclutha
Urban domestic and
commercial with some
rural
33kV line from Balclutha GXP. 5MVA
transformer and outdoor 11kV
substation.
Load restored in time taken
to isolate and back-feed
after first contingent event
(N)
Oturehua
Rural farming
Teed off the radial 33kV from
Ranfurly to Fall Dam. 0.75MVA
transformer, outdoor 11kV substation
and 33kV regulator for generator
connection.
Load restored in time taken
for repair of first contingent
event (N)
isolated
isolated
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Substation
Nature of load
Description of substation
Supply security
Owaka
Small urban township
and rural farms
Radial 33kV line from Finegand.
2.5MVA transformer and outdoor
11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Paerau
Remote isolated rural
farms and irrigation
Radial 33kV from Ranfurly. 0.75MVA
transformer
and
basic
11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Palmerston
Urban domestic and
commercial with some
rural farms and timber
mills
Radial 33kV to
transformers and
substation.
dual 2.5MVA
outdoor 11kV
Load restored in time taken
for repair of first contingent
event (N)
Patearoa
Rural
farming
irrigation
with
Teed off radial 33kV line to Paerau
2.5MVA transformer and outdoor
11kV substation with 33kV regulator
for the Paerau line.
Load restored in time taken
for repair of first contingent
event (N)
Port
Molyneux
Small seaside township
and rural farms
Teed off radial 33kV line to Owaka.
2.5MVA transformer and outdoor
11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Pukeawa
Rural farming
Alternate 33kV lines to a 0.75MVA
transformer
and
basic
11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Ranfurly
Urban domestic and
commercial with some
rural farms and irrigation
33/66kV step-up and
switching station
Dual heavy 33kV lines from Naseby
GXP to a dual 2.5MVA transformers
and outdoor 11kV substation. Dual
12.5/25MVA 33/66kV transformers,
33 and 66kV outdoor substations.
No loss of supply after first
contingent event (N-1) for
66/33 loads. Other load
restored within 25 minutes
after first contingent event
(N)
Stirling
Fonterra Stirling Cheese
Factory
33kV line and cable switch-able
between two 33kV lines from
Balclutha GXP. 5MVA transformer
and 11kV indoor switchboard.
Load restored in time taken
for repair of first contingent
event (N)
Waihola
Small urban township
and rural farms
Radial 33kV line off the 33kV Ring
that supplies Elderlee St and
Glenore. 1.5MVA transformer and
outdoor 11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Waipiata
Rural
farming
irrigation
with
33kV tee off the 33kV line from
Ranfurly to Deepdell.
1.5MVA
transformer and outdoor 11kV
substation.
Load restored in time taken
for repair of first contingent
event (N)
Waitati
Small urban townships
and rural farms
Radial 33kV line from Palmerston to a
2.5MVA transformer and outdoor
11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Wedderburn
Rural farming
Teed off the 33kV line from Ranfurly
to Falls Dam. 0.75MVA transformer
and outdoor 11kV substation.
Load restored in time taken
for repair of first contingent
event (N)
Table 10 Generation connection points
Generation
Nature of load
Description
Supply security
Mount Stuart
Pioneer Generation Wind
farm
33kV circuit breaker with remote
monitoring and control.
Load restored in time taken
for repair of first contingent
event (N)
Falls Dam
Pioneer
Generation
hydro generation station
No OtagoNet switchgear on site.
Load restored in time taken
for repair of first contingent
event (N)
Paerau Hydro
12.25MW
hydro
generation station
Radial 66kV line from Ranfurly. Dual
7.5/15MVA 66/11kV transformers
with 66kV switchyard and indoor
11kV board.
Load restored in time taken
for repair of first contingent
event (N)
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2.2.4 Distribution network
2.2.4.1 Configuration
In rural areas the configuration is almost totally radial with little interconnection. In
particular, the mountainous topography and the distances in the inland north Otago
area preclude 11kV interconnection which prevents the provision of an 11kV alternative
for load transfer to the 33kV supply from the zone substations.
In urban areas there is a higher degree of meshing or interconnection between 11kV
feeders where possible, although transformer loadings rather than distance tends to
limit the ability to back-feed on the 11kV.
OtagoNet has a small amount of underground distribution cable mainly in newer
housing areas and in special circumstances to avoid clearance issues.
2.2.4.2 Construction
The network construction is largely similar in rural and urban areas, with the main
differences being closer pole spacing in towns, under-built LV and larger transformers
that are often ground-mounted in the towns. OtagoNet also has remote and rugged
areas that are serviced, sometimes at considerable extra cost, even for similar line
types, due to increased travel times and specialised vehicles required to install poles in
rugged terrain. Some of the worst areas require extensive use of helicopter and
tracked vehicles.
Line rebuild standards use concrete poles and hardwood crossarms to ensure long
lives.
2.2.4.3 SWER lines
The network includes 949 km of Single Wire Earth Return (SWER) lines. This is a
cheaper form of line construction applicable for feeding small loads at the fringes of the
network. Regulatory requirements limit the impact on affected telecommunications
circuits which generally requires the high voltage current on this line construction to be
8 amps or less. OtagoNet has identified a number of SWER transformer installations
below current industry guidelines in terms of earthing practice and these are planned
for upgrade as discussed further in the life cycle and risk sections of this plan.
As load requirements build, SWER lines are progressively replaced with the more
normal 2-phase and 3-phase line construction.
2.2.4.4 Per substation basis
The split of the distribution network on a per substation basis is presented in Table 11.
Safety and reliability are the strongest drivers of allocation of resources, with customer
density providing an indication of priority for other works.
Table 11 – Distribution network per substation
Substation /
Feeder
Balmoral
Becks
Line Length
(km)
Cable Length
(km)
Customers
Customer
Density (per
km)
0.00
0.00
1
27.50
0.00
32
Big Sky Dairy
0.00
0.00
1
Brothers Peak
2.15
0.00
2
0.93
70.97
1.09
1532
21.26
134.73
0.00
169
1.25
Charlotte Street
Clarks
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Substation /
Feeder
Clinton
292.28
1.72
718
Customer
Density (per
km)
2.44
Clydevale
282.44
1.21
561
1.98
Cormack
0.00
0.00
1
Craiglynn
3.41
0.00
5
1.47
Deepdell
57.35
0.40
80
1.39
150.26
1.10
1428
9.43
Finegand
95.09
0.72
281
2.93
Glenore
94.26
188
1.99
Elderlee Street
Line Length
(km)
Cable Length
(km)
Customers
Golden Point
0.00
0.00
1
Greenfield
0.00
0.00
1
117.34
0.00
128
1.09
11.81
0.00
16
1.35
0.00
0.00
1
Hyde
38.08
0.01
63
1.65
Kaitangata
99.22
0.01
586
5.91
Lawrence
182.18
0.36
667
3.65
0.00
0.00
1
Merton
124.34
1.62
1319
10.47
Middlemarch
119.14
0.70
314
2.62
40.59
0.69
101
2.45
121.28
0.34
1191
9.79
O'Mally's House
0.00
0.00
1
O'Mally's Pump
0.00
0.00
1
28.19
0.00
79
2.80
Owaka
287.27
1.23
849
2.94
Paerau
26.88
0.00
37
1.38
0.00
0.00
1
168.71
1.12
969
5.71
Patearoa
85.94
0.82
173
1.99
Port Molyneux
36.51
0.14
365
9.96
Pukeawa
42.35
0.51
71
1.66
Ranfurly
202.99
1.42
1089
5.33
Redbank
3.53
0.00
4
1.13
Rough Ridge
0.00
0.00
1
Stirling
0.00
1.08
1
0.93
30.27
0.00
28
0.92
0.00
0.00
1
Waihola
92.77
0.97
551
Waipiata
82.24
0.79
180
2.17
Waitati
67.68
4.38
959
13.31
Wedderburn
35.56
1.02
46
1.26
Unallocated
0.21
0.91
18
16.01
3255.53
24.39
14812
4.52
Hindon
Hills Creek
Hore's Pump
Macraes Mining
Milburn
North Balclutha
Oturehua
Paerau Hydro
Palmerston
Stoneburn
Tisdall
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OUR NETWORK
Note some lines are unallocated to a substation or feeder, and some SWER is cable.
2.2.5 Distribution substations
Just as zone substation transformers form the interface between OtagoNet‘s
subtransmission and distribution networks, distribution transformers form the interface
between OtagoNet‘s 11kV distribution and LV (400/230 V) networks. OtagoNet‘s
distribution substations range from 1-phase 3 kVA pole-mounted transformers with only
minimal fuse protection to 3-phase 1,500 kVA ground-mounted transformers that are
dedicated to single customers as shown in Table 12.
Table 12 – Number of distribution substations
Rating
Pole
Ground
1-phase up to 15 kVA
2668
6
1-phase 30 kVA
401
7
1-phase 50 kVA
144
4
1-phase 75 kVA
3
1-phase 100 kVA
11
1-phase 200 kVA
5
1
3-phase up to 15 kVA
150
3
3-phase 30 kVA
178
1
3-phase 50 kVA
239
6
3-phase 75 kVA
33
1
3-phase 100 kVA
83
10
3-phase 200 kVA
75
21
3-phase 300 kVA
38
41
3-phase 500 kVA
3-phase 750kVA
49
1
10
3-phase 1000 kVA
7
3-phase 1500 kVA
1
Total
4029
168
The voltage regulators are managed and recorded separately from distribution
transformers and details are as follows:
Table 13 - Voltage Regulators
Location
Balmoral
Craiglynn
Dunback
Mahinerangi
Naseby
Redbank
Stoneburn
Tahakopa
Purpose
33/0.4 kV regulation of a low voltage for the local water scheme
Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating
transformer feeding a small remote community.
11 kV regulation at a point 14 km from Palmerston zone substation for a further
20 km of line to Morrisons.
Regulation of a single wire 11 kV circuit from a small isolating transformer
feeding a small remote community.
11 kV regulation for a large holiday destination 11 km from Ranfurly zone
substation.
Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating
transformer feeding a small remote community.
Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating
transformer feeding a small remote community.
11 kV regulation at a point 18 km from Owaka zone substation for a popular
holiday destination and a further 25 km of line into the Chaslands.
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2.2.6 LV network
2.2.6.1 Coverage
OtagoNet‘s LV networks are predominantly clustered around each distribution
transformer. The coverage of each individual LV network tends to be limited by voltdrop to about a 200 m radius from each transformer.
2.2.6.2 Configuration
OtagoNet‘s LV networks are almost solely radial with minimal meshing, even in urban
areas, because of excessive volt-drop which would otherwise occur in the long
conductors.
2.2.6.3 Construction
Construction of OtagoNet‘s LV network varies considerably and can include the
following configurations:
Overhead LV only.
LV under-built on 11 kV.
XLPE or PVC cable (only 19 km in total).
2.2.6.4 Per substation basis
On a per substation basis OtagoNet‘s split of LV network is shown in Table 14. Similar
to the distribution network, safety and reliability is OtagoNet‘s strongest driver of
allocation of resources, with customer density providing an indication of priority for
other works.
Table 14 – LV network per substation
Substation /
Feeder
Line Length
(km)
Cable Length
(km)
Customers
Customer
Density (per
km)
Balmoral
0.00
0.00
1
Becks
0.00
0.00
32
Big Sky Dairy
0.00
0.00
1
Brothers Peak
0.00
0.00
2
27.32
3.31
1532
50.01
Clarks
0.34
0.30
169
267.03
Clinton
8.68
0.19
718
80.97
Clydevale
6.53
0.03
561
85.49
Cormack
0.00
0.00
1
Craiglynn
0.00
0.00
5
Deepdell
2.58
0.00
80
30.99
31.18
0.78
1428
44.68
Finegand
2.94
0.04
281
94.23
Glenore
1.28
0.49
188
105.84
Golden Point
0.00
0.00
1
Greenfield
0.00
0.00
1
Hindon
0.62
0.00
128
Hills Creek
0.00
0.00
16
Charlotte Street
Elderlee Street
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OUR NETWORK
Substation /
Feeder
Line Length
(km)
Cable Length
(km)
Customers
Customer
Density (per
km)
Hore's Pump
0.00
0.00
1
Hyde
1.34
0.00
63
46.90
Kaitangata
14.97
0.10
586
38.88
Lawrence
20.70
1.65
667
29.84
0.00
0.00
1
33.85
3.83
1319
35.00
Middlemarch
7.97
0.06
314
39.11
Milburn
2.02
0.16
101
46.27
North Balclutha
21.53
4.21
1191
46.26
O'Mally's House
0.00
0.00
1
O'Mally's Pump
0.00
0.00
1
Macraes Mining
Merton
Oturehua
0.97
0.08
79
75.20
Owaka
17.28
1.71
849
44.71
Paerau
0.00
0.00
37
Paerau Hydro
0.00
0.00
1
29.82
1.28
969
31.16
Patearoa
3.21
0.55
173
45.97
Port Molyneux
6.30
0.34
365
54.95
Pukeawa
0.13
0.02
71
484.24
Ranfurly
24.82
2.12
1089
40.42
Redbank
0.00
0.00
4
Rough Ridge
0.00
0.00
1
Stirling
0.00
0.00
1
Stoneburn
0.00
0.00
28
Tisdall
0.00
0.00
1
Waihola
11.42
2.99
551
38.24
Waipiata
3.32
0.29
180
49.91
24.08
4.68
959
33.34
Wedderburn
1.15
0.00
46
40.15
Unallocated
199.83
0.31
18
0.09
506.20
29.52
14812
27.65
Palmerston
Waitati
Note that LV line and cable data is not complete.
2.2.7 Secondary assets and systems
2.2.7.1 Load control assets
OtagoNet currently owns and operates the following load control transmitter facilities
for control of ripple relays:
Three 33 kV 492 Hz 100 kVA injection plants at Naseby, Palmerston and Balclutha
points of supply.
One new 33 kV 317 Hz 100 kVA injection plant at Balclutha point of supply which
will gradually take over from the 492 Hz plant as relays are replaced.
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OUR NETWORK
2.2.7.2 Protection and control
2.2.7.2.1 Key protection systems
OtagoNet‘s network protection includes the following broad classifications of systems:
Circuit Breakers
Circuit breakers provide powered switching (usually charged springs or DC coil)
enabling operational control of isolation and fault interruption of all faults.
Circuit breakers protection relays which have always included over-current, earthfault and auto-reclose functions. More recent equipment also includes voltage,
frequency, directional overcurrent, distance and circuit breakers fail functionality in
addition to the basic functions.
Circuit breakers operation may also be triggered by the following to protect
downstream devices:
- Transformer and tap changer temperature sensors.
- Surge sensors.
- Explosion vents.
- Oil level sensors.
Reclosers
Reclosers are compact, self-contained pole mounted circuit breakers complete with
integral protection relay functions. Reclosers are used to provide additional
protection and the ability to sectionalise longer rural lines or isolate urban
customers from rural faults. Many simple substations use reclosers in the place of
circuit breakers as the more modern reclosers have all the attributes of circuit
breakers and protection relays in one simple and cheaper package.
Simple single phase reclosers are used as the protection device on single wire
earth return isolating transformers.
Switches
Switches provide no protection function but allow simple manual operation to
provide control/isolation.
Fuses
Fuses provide fault interruption of some faults and may be utilised to provide
manual isolation.
As fuses are simple over current devices they do not provide reliable earth fault
protection for high impedance faults.
Links
Links provide no protection function but allow manual operation to provide
sectionalising/isolation.
2.2.7.2.2 DC power supplies
Batteries, battery chargers and battery monitors provide the direct current (DC) supply
systems for circuit breakers control and protection functions. This allows continued
operation of plant throughout any power outage.
2.2.7.2.3 Tap changer controls
Voltage Regulating Relays (VRR) provides automatic control of the ‗On Load Tap
Changers‘ (OLTC) on power transformers to regulate the outgoing voltage to within
controlled limits.
2.2.7.3 SCADA and Communications
SCADA is used for control and monitoring of zone substations and remote switching
devices and for activating load control plant. SCADA has the potential to improve
network reliability through the management of network automation including automatic
sectionalising and re-configuration of the network under faults. Installation of more
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OUR NETWORK
automatic reclosers/sectionalisers monitored through the SCADA system is promoted
in this plan to be undertaken as resources allow.
2.2.7.3.1 Master station
OtagoNet‘s SCADA master station is located in the PowerNet Balclutha office with a
link to the PowerNet System Control in Invercargill. The system is an Abbey Systems
―PowerLink‖ SCADA system designed, manufactured and supported in New Zealand.
The master system communicates to 44 remote terminal units at all of the OtagoNet
zone substations and Transpower points of supply.
2.2.7.3.2 Communications links
OtagoNet currently owns and operates the following communications links for SCADA
and VHF voice communications:
Figure 15 - OtagoNet SCADA Radio Network
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Figure 16 - OtagoNet Mobile Radio Network
2.2.7.4 Other assets
2.2.7.4.1 Mobile generation
PowerNet makes a 275 kW and a 350 kW diesel generator available for planned work
and power restoration although these are not owned by the network. However, it is also
planned to purchase additional generators that will be owned by OtagoNet including a
1 MVA step-up transformer to be used with hired generators to provide for zone
substation support, all as part of a strategy to minimise customer service disruption
given the increase in renewal works planned on the network.
2.2.7.4.2 Customer connection assets
OtagoNet has 14,81216 customer connections; the network connection assets are
usually an ICP fuse on a pole as most of the connections are overhead (97%) while the
few underground connections would have the ICP fuse mounted in a pillar box on the
customer‘s boundary. The load control relay mounted in most houses and some
commercial installations is the property of the Retailer.
16
FY2013 disclosure numbers
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OUR NETWORK
2.2.7.4.3 Stand-by generators
None. It is intended to purchase a standby generator to supply the office of OtagoNet
and its primary depot within the next few months.
2.2.7.4.4 Power factor correction
None.
2.2.7.4.5 Mobile substations
None.
2.2.7.4.6 Metering
Time of use (TOU) meters have not been installed at any of the zone substations and
instead OtagoNet relies on the metering information derived from SCADA
measurements and the Retailers‘ TOU meters for the largest 50 customers and the
Grid Exit Point metering, the information from which is available to OtagoNet.
All domestic meters are owned by the retailers (including any smart meters). Given the
incumbent retailer has not installed large numbers of new smart meters, OtagoNet
does not have access to potentially useful information, such as LV voltage levels, and
is considering installing its own smart meters to some of its larger distribution
transformer sites so it can gather more information on its service quality.
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PERFORMANCE BENCHMARKING
3.
Performance Benchmarking
This section examines the current OtagoNet performance in relation to other Electricity
Distribution Businesses (EDBs) using the FY2013 disclosure data.17 The purpose of
the benchmark comparison is to identify any poor or outlier performance in relation to
OtagoNet‘s peers and to direct asset management strategy where performance
improvement is indicated.
3.1
Costs
3.1.1 Opex (operational expenditure)
The following chart summarises OtagoNet‘s FY2013 total opex (direct and indirect) in
relation to other EDBs in New Zealand.
Figure 17 Comparison of opex by category
17
This benchmarking is taken from or developed from the Hyland McQueen Ltd EDB Comparative
Performance Report; November 2013.
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PERFORMANCE BENCHMARKING
Notable features are:
A large proportionate spend on fault maintenance in relation to other opex
compared to the average EDB;
The ratio of fault to preventive opex is one of the highest in the peer grouping;
A total opex per connection (ICP) that is in the upper quartile.
Higher business support expenditure relative to other networks.18
Whilst these findings will vary from year-to-year depending on the extent of the faults
experienced and there are always factors that confound comparisons such as
accounting differences and opex/capex trade-offs, there is an indicative case that
OtagoNet needs to move towards more preventive maintenance work rather than
reactive fault repair. This is addressed in the developed strategy of improving the
condition inspection methods and processes and then driving more maintenance and
replacement off the condition inspection data as discussed further in this plan.
3.1.1.1 Direct Opex
Direct opex is that proportion of opex spent directly on the network assets (eg on asset
maintenance) as opposed to the indirect components of business management and
operations.
The comparative review found that direct opex for each EDB was best related to the
network length of the EDB after allowing different scale multiplication factors for the
different types of network (urban overhead + rural overhead + rugger/remote overhead
+ underground). The regression chart of direct opex with composite length is
presented following and where OtagoNet is marked as the red dot point.19
18
The information disclosure requirements split indirect opex into ―business support‖ and ―system
operations and network support‖. OtagoNet out-source much of its business support to PowerNet with the
control room function is included in the direct costs and this arrangement may affect any comparison with
other businesses in the relationship between operations and business costs. In total, indirect opex
benchmarks below expectation based on the number of ICPs.
19
The blue dotted lines represent the 95% confidence limits of the regression line itself and the orange
dotted lines represent the 95% confidence bounds of the prediction (interpolation) limits of the regression
relationship.
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PERFORMANCE BENCHMARKING
Figure 18 Regression of direct opex
Whilst OtagoNet plots just above the regression line, it plots well within the error
bounds for the relationship between direct opex cost and the scale of its network and
gives no evidence that OtagoNet‘s direct opex costs are excessive in relation to its
peers. Accounting differences also play a part in the variability seen between EDBs
noting that OtagoNet expenses renewal works on a single pole whereas others may
capitalise this work and this will have the effect of accentuating OtagoNet‘s direct opex
costs.
Vegetation management (tree cutting) costs per km of line are also disclosed by some
EDBs and, as the following chart shows, OtagoNet‘s costs benchmark well in this
respect although we would expect this to be the case as vegetation density will be
lower in parts of Otago than other places in New Zealand.
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PERFORMANCE BENCHMARKING
Figure 19 Regression of vegetation control costs
3.1.1.2 Indirect Opex
Indirect opex is that proportion of opex spent on the business itself and on
day operation of the network. It is typically benchmarked on a cost per
basis. The following charts plot indirect opex in relation to both the
connections and to the distribution transformer capacity of the different
where OtagoNet is marked as the red dot point.
the day-toconnection
number of
EDBs and
In both of these measures, OtagoNet benchmarks well, indicating its indirect opex
costs are in line with those of its peers.
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PERFORMANCE BENCHMARKING
Figure 20 Regression of indirect opex
3.1.2 Return on investment (ROI)
As already discussed in this plan, OtagoNet has competing priorities of providing a cost
efficient electricity supply service whilst funding its business and meeting its
shareholder expectations. The following charts identifies OtagoNet in relation to its
percentage rate of return on investment (pre-tax) and the components of its capital
costs where the blue vertical lines represent the industry average.
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PERFORMANCE BENCHMARKING
Figure 21 Comparisons relating to return on investment
This shows OtagoNet to have an average rate of return on investment but has the
second largest ratio of investment value per connection, which arises from the low
number of connections per km of line. Consequently OtagoNet also has a large value
of retained revenue and depreciation per connection to support that capital investment.
This highlights a key characteristic of the OtagoNet service cost make-up; that being
the dominant component of the return of and return on capital that has to be supported
on a low customer base and this arises from OtagoNet having to provide a large
network to service a relatively small number of connections. This situation motivates
the asset management policies of ensuring strong governance and management
processes for justifying capital expenditure; developing comprehensive asset and risk
management processes to lessen the asset holding risk premium for shareholders; and
for seeking long asset lives through condition-based replacement, asset life extension
and appropriate design.
3.2
Reliability
SAIDI is the System Average Interruption Duration Index and represents the average
customers experience of outages in minutes per annum. SAIDI is calculated by the
multiplication of two components; SAIFI being the average number (frequency) of
interruptions and CAIDI being the average duration of any single interruption.
Interruptions may be planned where parts of the network need to be taken out for
maintenance or repair, and unplanned outages due to faults, storm conditions or third
party damage.
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PERFORMANCE BENCHMARKING
3.2.1 SAIDI
Comparative SAIDI for the FY2013 year is described in the following charts, which
shows OtagoNet to have an upper quartile SAIDI performance and for an above
average proportion of planned SAIDI in relation to its peers.
Figure 22 Comparisons of SAIDI
As discussed in section 6 (service levels), the high SAIDI figure derives from a high
CAIDI value and where the SAIFI (or frequency of events) is actually below average in
relation to other EDBs given the scale exposure of the network. The high ratio of
planned SAIDI is also discussed and arises from our increased lines replacement
program combined with inability to back-feed when parts of the network are taken out
for replacement work. This motivates asset strategy initiatives to reduce planned SAIDI
through greater use of mobile generation.
3.2.2 SAIFI
SAIFI is the system averaged interruption frequency index and measures the average
number of interruptions per annum. It is usually only considered within the context of
unplanned interruptions.
The following chart compares the make-up of OtagoNet‘s SAIFI to its peers. Whilst
there will be annual variability in this measure, the general conclusion is that
OtagoNet‘s unplanned SAIFI make-up is not markedly different from other EDBs. The
lower than average vegetation SAIFI is a pleasing result as trimming trees away from
lines has been a focus of network maintenance over recent years.
The SAIFI margin represents the margin between the reported SAIFI and the service
quality threshold mandated by the Commerce Commission and shows OtagoNet is well
within the regulated service quality on this measure.
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PERFORMANCE BENCHMARKING
Figure 23 Comparisons of SAIFI
The following chart identifies the reported SAIFI in relation to the expected SAIFI (blue
line) calculated based on the extent of the network exposed to faults. As shown,
OtagoNet has lower SAIFI than expected but also that this measure carries a wide
range of variability.
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PERFORMANCE BENCHMARKING
Figure 24 Regression of SAIFI
3.2.3 CAIDI
CAIDI measures the duration of the average interruption and is again usually discussed
in relation to unplanned outages. CAIDI = SAIDI/SAIFI and the following chart
illustrates this ratio by plotting SAIDI against SAIFI in comparison to other EDBs and
where OtagoNet is marked as the red dot point. This shows OtagoNet with an outlier
performance arising from a high CAIDI value (as we have already noted that SAIFI is
lower than the regression line expectation in the FY2013 year).
Figure 25 Comparison of CAIDI
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PERFORMANCE BENCHMARKING
The high value of CAIDI in FY2013 largely arises out of the high variability seen in
unplanned CAIDI on OtagoNet‘s and other networks as illustrated in the following chart
that shows the variability in both CAIDI and SAIFI from FY2008 to FY2012 (OtagoNet
marked in red).
Figure 26 CAIDI and SAIFI variation between years
OtagoNet experiences high variability in CAIDI largely because it is a small network
with a wide variety in the types of faults that can affect it. A predominance of faults on
the more remote sections on its network in a particular year will greatly affect the
average fault restoration time in that year. For these reasons OtagoNet does not focus
on CAIDI as a meaningful measure.
OtagoNet‘s response to the reliability benchmarking for unplanned outages, discussed
further in section 5 (performance and improvement) of this plan, is to continue to
address the root causes of faults on the network with a focus on those assets with a
high impact (ie 33 kV sub-transmission faults).
3.3
Technical Efficiency
This section examines OtagoNet‘s comparative performance in the utilisation of its
network assets and in particular the utilisation of its distribution transformer capacity
and the technical load losses on its network. High utilisation is desirable as it indicates
efficient use of capital. High losses are undesirable as it indicates inefficiency for the
load transfers across the network but also unusually low losses may indicate overdesign and capital inefficiency.
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PERFORMANCE BENCHMARKING
3.3.1 Distribution transformer utilisation
The following chart compares OtagoNet distribution transformer utilisation to other
EDBs in the FY2013 year.20 The utilisation is compared on two measures; the
nominal utilisation which just compares the maximum demand to the total distribution
transformer capacity and; the utilisation measured by using just the standard
connection demand (ie removing large commercial and industrial load). The most
useful measure of transformer utilisation is expected to lie between these two
measures.21 These measures have also been corrected for the different energy
densities on the different networks as networks with high energy density (which
OtagoNet is not) have more opportunity to achieve higher utilisation through increased
load diversity.
OtagoNet has above average utilisation on the nominal measure and below average
utilisation on the standard connections measure giving an overall average
performance. We would note that a low performance on the standard connection basis
is unsurprising given 67% of OtagoNet‘s distribution transformers are 15 kVA or less
and where 15 kVA is now a minimum standard size for single service connections. This
measure is therefore limited in its applicability to this largely rural network. No change
in OtagoNet‘s distribution transformer loading practice is required based on these
comparisons.
Figure 27 Comparison of transformer utilisation
20
The charts on the left give the regression and the charts on the right give the corresponding
comparison normalised against that regression trend (ie as if all networks had the same average energy
density).
21
The points marked with orange squares (of which OtagoNet is one) have high ratios of non-standard to
total connections and makes proper assessment of transformer utilisation less reliable for these entities.
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PERFORMANCE BENCHMARKING
3.3.2 Technical losses
The following chart plots the annualised load losses on the different EDB networks and
where the load loss is regressed against the network circuit length in a log-log
relationship. As shown, OtagoNet plots below the expectation line indicating it has a
lower load loss than would be expected based on the size of the network. While this is
a good result from the point of energy efficiency, unduly low losses may also indicate
over-capitalisation of the lines - that is conductor sizes are too large for cost efficiency.
However, conductor sizing for the OtagoNet network is largely based on keeping
voltage drop under 10% and, due to the relatively long lines, load losses become
secondary to this.
After consideration, no change in the network design policy is indicated by this
comparative performance.
Figure 28 Regression of network losses
3.4
Asset base
This section examines the aging of OtagoNet‘s asset base in relation to its peers.
Figure 29 below contrasts the range of expected lives in years (top chart) for the
different network asset classes between the different EDBs and highlights the different
expectations in how long assets will last. This figure also contrasts the consumption of
the expected life in percent for each EDB under each asset class (bottom chart).
Again, OtagoNet is marked with the red dot points.
Variability in the expected life of an asset class arises from both the make-up of that
asset class – for example distribution lines may have different proportions of wood and
concrete poles with different life expectancies – and in each EDBs experience or
expectation of the life of its assets. Variance in the consumption of the expected life
largely arises from the degree to which a network is aged, its growth rate and the
degree of replacement capital that has been undertaken on it.
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PERFORMANCE BENCHMARKING
Figure 29 Comparison of expected lives and consumption of lives
From these benchmark comparisons we conclude:
•
•
•
By-and-large, OtagoNet shows with life expectations for its assets that fall within
the 50 percentile bounds.
OtagoNet has a relatively low expectation of the life of its distribution cables.
Although OtagoNet has only a small quantity of distribution underground cable
(and sub-transmission cables) compared to other more urban networks, a point of
the lifecycle plan for this asset class will be a re-examination of our life
expectations.
OtagoNet has a high expectation on the life of its distribution transformers. This
arises from the long lives seen for these assets particularly in the dry Central
Otago area where corrosion rates are markedly reduced. Nevertheless, continued
aging of OtagoNet‘s distribution switchgear, transformers and cables is inevitable
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PERFORMANCE BENCHMARKING
•
•
and understanding and measuring true life expectancy and achieving means for life
extension will be a focus of the lifecycle management of these assets.
Distribution and sub-transmission lines form the major part of OtagoNet‘s asset
base and the comparisons show these assets are far more aged in average than
most other EDBs. OtagoNet has commenced and will continue to expend capital to
pull back the average age of its network lines assets which will be achieved
through condition based inspection and replacement.
Network other and non-network asset classes are included in the charts for
completeness but comprise a wide variety of asset types from buildings to vehicles
to computers and no meaningful conclusions should be drawn from comparisons of
such wide asset groupings.
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RISK MANAGEMENT
4.
Risk Management
The business is exposed to a wide range of risks. This section examines OtagoNet‘s
risk exposures, describes what it has done and will do about these exposures and how
it prepares for extreme events.
Risk management is used to bring risk within acceptable levels.
4.1
Risk methods
The risk management process as it applies to the electricity network business is
intended to assess exposure and prioritise mitigating actions.
The risk on the network is analysed at the high level, reviewing major network
components and systems to see if possible events could lead to undesirable situations.
4.1.1 Guiding principles
OtagoNet‘s behaviour and decision making is guided by the following principles:
Safety of the public and staff is paramount.
Essential services are the second priority.
Large impact work takes priority over smaller impact work.
Switching to restore supplies prior to repair work.
Plans will generally only handle one major event at a time.
Risks will be removed, mitigated, or lessened, depending on the economics.
4.1.2 Risk Categories
Risks are classified against the following categories:
Weather
- Wind – extreme winds that cause either pole failures or blow debris into lines.
- Snow – impact can be by causing failure of lines or severely limiting access
around the network.
- Flood – while the Regional Council has installed flood protection works, there
is still a risk in the lower Clutha area and so this still needs to be considered.
Physical
- Earthquake – no recent history
of major damage. Large events
may occur and impact the
network. The 15 July 2009 7.8
Richter scale quake 100 km
south-west of Te Anau, caused
no damage to the network. (Ref.
number 3124785/G)
- Liquefaction – post Christchurch
22 February 2011 6.3 quake,
the hazard of liquefaction has
become a risk to be considered.
- Fire
–
transformers
are
insulated with mineral oil that is
flammable and buildings have
flammable materials so fire will
affect the supply of electricity.
Source of fire could be internal or from external sources.
- Tsunami – The OtagoNet network services coastal areas that are potentially
vulnerable to tsunami.
- Terrorism – malicious damage to equipment can interrupt supply.
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Asset Failures – equipment failures can interrupt supply or negate systems
from operating correctly. Failure of security could allow public access to
restricted areas. Asset failures may also harm the public, staff, property and
the environment.
Human
- Health & Safety – harm to public and staff (includes safety clearances).
- Pandemic – impact depends on the virility of the disease. Could impact on
staff work as they try to avoid infection or become unable to work.
- Third Party Accident – most typically car vs. pole; injury to the
driver/passengers and damage and loss of service to the network could be
significant.
- Vandalism – range varies from malicious damage to ‗tagging‘ of buildings or
equipment.
- Theft – gives rise to safety issues both for the thief and potentially for staff and
customers when earthing copper is stolen.
Corporate
- Stranded assets/Bad debt – providing business processes that insure
appropriate contracts and guarantees are agreed prior to undertaking large
investments.
- Loss of revenue – loss of customers through by-pass or economic downturn
could reduce revenue.
- Management contract – failure of Marlborough Lines as OtagoNet‘s asset
manager and PowerNet as OtagoNet‘s administration manager.
- Regulatory – failure to meet regulatory requirements.
- Resource – field staff to undertake operation, maintenance, renewal,
augmentation, extension and retirement of network assets.
- Environmental – release of pollutants into the air, water or soil.
-
4.1.3 Risk Tactics
The following tactics are used to manage risk under the following broad categories:
4.2
Operate a 24hr Control centre.
Provide redundancy of supply to large customer groups.
Spares management
Asset inspections
Design standards
Corporate governance
Locate assets away from risk zone.
Involvement with the local Civil Defence.
Review present sites risk to earthquake and liquefaction.
Risk Details
4.2.1 Weather
Table 15 - Weather Risk
Event
Extreme
Wind
Asset Management Plan
Likelihood
High
Consequence
Can be
considerable
and widespread
Responses
If damage occurs on lines this is remedied
by repairing the failed equipment. Asset
condition inspections and renewal to
manage network resilience.
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Event
Snow
Likelihood
High
Consequence
High but usually
localised
Flood
Very Low
Low
Responses
If damage occurs on lines this is remedied
by repairing the failed equipment.
If access is limited then external plant is
hired to clear access or substitute
generation. Helicopters may be used.
Asset condition inspections and renewal
to maintain and improve network
resilience.
Transformers and switchgear in high risk
areas to be mounted above the flood
level.
Zone substations to be sited in areas of
very low flood risk.
Waitati and Waikouaiti zone substations
are planned to be rebuilt away from their
present flood-prone sites.
4.2.2 Physical
Table 16 - Physical Risk
Event
Earthquake
Likelihood
Very Low
Consequence
Low to major
Tsunami
Very Low
Low to extreme
Liquefaction
Very Low
Low to Medium
Fire
Very Low
High
Terrorism
Very Low
High
Responses
Disaster recovery event.
Review of existing buildings and
equipment for seismic strength is ongoing; transformer assessment and
mitigation all but complete (only Glenore
site remaining)
Most of the network is sited in areas not
vulnerable to tsunami however this is
dependent on the size of the event.
Specify buildings and equipment
foundations to minimise impact. Review of
existing buildings and equipment
foundations for seismic strength is ongoing.
Continue to maintain fire detection and
alarm systems. Identify and replace
deteriorating transformers and switchgear
noting that generally fault levels are low
and most indoor bulk oil switchgear has
now been removed from the network.
Ensure security of restricted sites.
Use alternative routes and equipment to
restore supply where feasible
A total of $750k has been budgeted for seismic upgrades of substation outdoor
structures over the next 5 years.
4.2.3 Equipment Failures
As the impact of this is variable, a central control room is provided, which is manned 24
hours a day by PowerNet staff. Engineering staff are on standby at any time to provide
backup assistance for network issues.
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Table 17 - Equipment Failure Risk
Event
33 kV cable
Likelihood
Low
Consequence
Low
Power
Transformer
Very Low
Low – depends
on supply
security
arrangements
11 kV
Switchgear
Low
Medium
Pole failure
or conductor
breaks
Some
failures
historically
Medium to High
Oil Spill
Very Low
Low to medium
depending on
containment
Security
measures
Very Low
Medium
Batteries
Low
Protection
Very low
Low to medium
(backup zone
protection)
Medium
11 kV cable
Very low
Low to medium
SCADA RTU
Low
Low
SCADA
Masterstation
Very low
Low
Load Control
Low
Low to medium
Asset Management Plan
Responses
Each section of cable has an alternative
33 kV route.
Larger substations have dual transformers
to allow one to be removed from service
due to fault or maintenance.
Continue to undertake annual DGA to
allow early detection of failures.
If prolonged outage or loss of a single unit
then a spare power transformer can be
installed.
Annual inspection. Replacement before
end of life with modern equipment.
The network configuration allows
switchgear to be bypassed at most times.
Most indoor bulk oil switchgear has now
been removed from the network and
switchboards are generally air insulated
(not pitch-filled).
Routine condition inspection with data
capture into GIS. Pole condition
inspections may include X-ray
examination as well as sounding and dig
inspections. On-going process of
inspection and renewal.
Oil spill kits located at the three
contractor‘s depots to be used in event of
an oil leak or spill.
Zone substation transformers have oil
bunding and regular checks to discharge
any clean rain water.
Monthly checks of each restricted site.
Remote monitoring of access doors by
SCADA is being implemented.
Continue monthly check and annual
testing.
Continue regular operational checks.
Mal-operations investigated.
Temporary supply restorations can be
undertaken.
Monitor response of each RTU at the
Master Station and alarm if no response
after five minutes.
If failure then send faults contractor to
restore, if critical events then roster a
contractor onsite.
Continue to independently monitor and
alarm the master station and
communications links to the Invercargill
control centre.
Continue to have a support agreement
with the software supplier and technical
faults contractor to maintain the
equipment.
Manually operate plant with test set if
SCADA controller fails. LSI (Transpower)
peak now different to OtagoNet demand
peak.
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4.2.4 Human
Table 18 - Human Risk
Event
Health &
Safety
Likelihood
Low
Consequence
Low to High
Pandemic
Low
Low to High
Third party
accident
Low to
medium
Low to Medium
Vandalism
Medium
Low to High
Theft
Medium
Medium to High
Responses
Normal business processes followed and
legislative and code requirements
complied with. Regular checks and
inspections to find risks and then control.
Work to the PowerNet Pandemic plan.
Includes details such as working from
home, only critical faults work and provide
emergency kits for offices etc.
Depends on what asset is impacted. Have
resource to bypass and or repair for car
vs. pole.
Six monthly checks of all ground-mounted
equipment.
Faults contractor to report all vandalism
and repair depending on safety then
economics. i.e. tagging/graffiti would
depend on the location and content.
Any safety problems will be made safe as
soon as they are discovered.
Theft of copper earthing conductor has
been reported on the network. Police are
informed when discovered. Theft is
discovered during routine inspection and
earth testing. Safety inspection of ground
mount equipment and earthing located in
public locations is undertaken annually.
4.2.5 Corporate
Table 19 - Corporate Risk
Event
Bad debt /
stranded
assets
Likelihood
Low
Consequence
Low - high
Loss of
Revenue
Very Low
High
Management
Contract
Extremely
low
High
Regulatory
Low
High
Resource
Low
High
Asset Management Plan
Responses
Prudence in network investment. Keep
abreast of new developments in
distributed generation technologies
and costs. New larger contracts
require customer guarantee before
supply is provided.
Continue to have Use of System
Agreements with retailers.
New large investments for individual
customers to have a guarantee.
Strengthen governance on capital
expenditure.
Engage in active risk management.
Continue with management contracts
with PowerNet and Marlborough Lines
noting both organisations operate a
Business Continuity Plan.
Meet regulatory obligations. Engage
with regulator as required.
Continue to enhance relationships with
present contractors.
Continue to recruit appropriate staff
and utilise appropriate resources.
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Event
Environment
al
Likelihood
Low
Consequence
Medium to high
Public
Liability
Low
High
Responses
Monitor likely pollutant sources (noise,
oil, SF6, treated wood, concrete, etc)
Comply with RMA and District Plan
requirements.
Act in a prudent manner and comply
with all legislative and industry code
requirements.
4.2.6 Projects
Projects undertaken by the network are prioritised in accordance with the strategies
expressed in this plan, where safety is the highest priority. Option selection includes
evaluation of over-run costs, achievement of the project goals and other business risks.
4.2.7 Highlighted Risks
The following highlighted risks have been targeted for action in this plan:
Equipment Failure
Recent pole failures at loads less than design have spurred increased condition
inspections with the employment of temporary staff to cover the whole asset over a
shortened inspection cycle. Condition inspection templates have been enhanced as
well as streamlining the capture of the condition data into the GIS/AMS system. This
plan continues and further develops these initiatives including the development of risk
prioritisation leveraged off the condition data.
Whilst this programme is directed at improving safety and reliability on the network, it
has the potential to identify more assets that need immediate replacement than have
been provided within estimated costs.
Earthing Safety
Until they were revoked under the 2011 amendments,22 Single Wire Earth Return
(SWER) systems were covered under code of practice ECP41 cited in the Electricity
(Safety) Regulations 2010. SWER systems are no longer specifically cited in the safety
regulations and any test of competency would fall to the electricity industry best
practice being the EEA Guide for HV SWER Systems – October 2010.
A number of OtagoNet‘s SWER installations include bar joints in the earth continuity
conductors (as is practiced in other HV 3-phase grounded neutral systems) and have
common HV and LV earths both of which are not recommended practice in the guide
and having joints in the HV earth conductor would not have complied with the previous
regulations set out in ECP41. Opening the HV earth joint with the SWER supply in
service would be a safety hazard and is non-compliant with both the previous
regulations and the current guidelines. OtagoNet has therefore commenced a program
to upgrade all its SWER installations to full code compliance as soon as practicable
with priority to ugrading the installations with joints in the HV conductors. An estimated
cost of $1m has been allocated for the FY2015 year with a total cost of $2.5m and this
will be subject to further review as further information becomes known.
Network Resilience
Electricity supply is not only an essential service, it may represent community safety in
such events as prolonged snow storms. OtagoNet has and will continue with its
programme of refurbishing its deteriorated lines with the new replacement standard of
concrete poles, AAAC conductor and clamp-top insulators for subtransmission lines
where that is appropriate.
22
Electricity (Safety) Amendment Regulations 2011, regulation 9 (which revoked clause 21); 33A (which
inserted requirements for limitation of effects on telecommunications circuits) and 46 (which substituted
new schedule 2 removing code of practice ECP41)
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A known risk, particularly with concrete poles with steel crossarms and clamp-top
insulators, is that excessive line loads (for example in extreme snow or ice storms) may
break the poles in cascade failure. Placement of in-line strains or the selected
placement of a number of more load bearing hardwood poles to restore the intended
resilience is considered under a programme of design assessment for which OtagoNet
has already purchased new line design software. The priority is to complete line
design reviews on its 33 kV subtransmission lines as they are refurbished.
4.3
Contingency Plans
OtagoNet has the following contingency plans:
4.3.1 OtagoNet Business Continuity Plan
OtagoNet must be able to continue in the event of any serious business interruption.
Events causing interruption can range from malicious acts through damaging events, to
a major natural disaster such as an earthquake.
The principle objectives of the Business Continuity Plan are to:
Maintain or promptly restore supply to its customers
Eliminate or reduce damage to facilities, and loss of assets and records.
Minimise financial loss.
Provide for a timely resumption of operations in the event of a disaster.
4.3.2 OtagoNet Pandemic Action Plan
OtagoNet must be able to continue in the event of a breakout of any highly infectious
illness which could cause staff to be unable to function in their work.
The plan aims to manage the impact of an influenza pandemic on OtagoNet‘s staff and
contractors through two main strategies:
1. Containment of the disease by reducing spread within OtagoNet. This is achieved
by such measures as reducing risk of infected persons entering OtagoNet‘s
premises and other appropriate measures.
2. Maintenance of essential services if containment is not possible. This is achieved
through identification of the essential activities and functions of the business, the
staff required to carry out these tasks and special measures required to continue
these tasks under a pandemic scenario.
4.3.3 Network Operating Plans
As contingency for major outages on the OtagoNet network PowerNet holds network
operating plans for safe and efficient restoration of services where possible. For
example, an operating order detailing operational steps required to restore supply after
loss of a zone substation.
4.4
Insurance
OtagoNet holds the following insurances:
Material damage and business interruption over Substations, Buildings and the
Macraes 66kV line.
Contracts works
Utilities Industry Liability Programme (UILP) that covers Public, Forest & Rural
Fires and Products liability.
Statutory liability
Marine Cargo.
Employee and Fidelity/Crime
Contractors working on the network are asked to hold Liability Insurance.
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5.
Performance and improvement
This section firstly evaluates OtagoNet‘s performance over the 2012/13 year and
secondly identifies areas where OtagoNet believes it could improve its business
through asset management practices.
5.1
Outcomes against plans
The following tables provide the cost out-turns for financial years FY2010 to FY2013
and cost variance to budget for years FY2012 and FY2013 plus expected out-turn for
the FY2014 year based on accounts to 31 January 2014.
Out-turn costs in FY2013 dollars (000)
FY2010
FY2011
FY2012
FY2013
Capital Expenditure: Customer Connection
Capital Expenditure: System Growth
Capital Expenditure: Reliability, Safety and
Environment
Capital Expenditure: Asset Replacement
and Renewal
Capital Expenditure: Asset Relocations
$874
$622
$278
$1,172
$1,704
$940
$1,523
$2,488
$299
$2,054
$1,927
$610
FY2014
(est)
$
$
$
$4,687
$5,375
$4,535
$5,066
$
$19
$0
$0
$0
$
Capital Expenditure on assets
$6,481
$9,190
$8,844
$9,657
$11,200
Operational Expenditure: Routine and
Preventative Maintenance
Operational Expenditure: Refurbishment
and Renewal Maintenance
Operational Expenditure: Fault and
Emergency Maintenance
Operational Expenditure on assets
$1,184
$1,204
$1,087
$1,329
$
$637
$706
$877
$428
$
$1,446
$1,354
$1,615
$1,742
$
$3,268
$3,264
$3,580
$3,499
$4,300
Total direct expenditure on assets
$9,749
$12,454
$12,424
$13,156
$15,500
Variation to Budget
Capital Expenditure - Customer Connection
System Growth
Asset Replacement and Renewal
Reliability, Safety and Environment
Asset Relocations
Subtotal - Capital Expenditure on asset management
Operational Expenditure: Routine and Preventative
Maintenance
Operational Expenditure: Refurbishment and Renewal
Maintenance
Operational Expenditure: Fault and Emergency
Maintenance
Subtotal - Operational Expenditure on asset
management
Total direct expenditure on distribution network
FY2012
FY2013
50%
-35%
-61%
-29%
Not
defined
-26%
FY2014 (to
31 Jan 14)
35%
69%
-90%
534%
-100%
-3%
-16%
-16%
-12%
1%
-30%
10%
20%
-2%
-2%
+18%
-21%
-3%
-9%
The tables show OtagoNet has been consistent in expending approximately $8m to
$10m p.a. capital and $4m opex in average on its network assets over the last 3
financial years. Variances exist within expenditure categories but total capital and total
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opex remain only marginally under budget in the last two financial years and the forecast
under-expenditure in the current year is anticipated to be made-up early in the next
financial year.
5.2
Performance against targets
5.2.1 Primary service levels
The charts below displays the actual and target SAIDI and SAIFI reliability performance
on the network for the 2012/13 year. Note that class B are planned outages while class
C are fault outages. The out-turn for the current financial year (FY2014) is SAIFI of 2.9
and SAIDI of 360 both of which are above target. This is an increase on the last 3
years and arises from 3 incidents:
•
a snow storm on 20th June 2013 causing approximately 1m customer minutes;
•
a pole fire in September 2013 disrupting power to the township of Waikouaiti that
could not be quickly repaired due to crew safety issues from a prolonged lightning
storm with the incident causing approximately 1.2m customer minutes; and
•
high winds in January that broke an old wooden pole near Clinton causing 300k
customer minutes (noting that this pole was part of a line that had been 90%
renewed in the previous year but this pole was part of a section not replaced due to
land owner consent issues for access at that time).
SAIDI Performance
600
500
Total number of interruption minutes
SAIDI minutes
400
Reliability planned - Class B
300
Reliability unplanned - Class C
Targets for Forecast Year - Class B
200
Targets for Forecast Year- Class C
100
Regulatory threshold
FY2018
FY2017
FY2016
FY2015
FY2014
FY2013
FY2012
FY2011
FY2010
FY2009
FY2008
0
Figure 30 OtagoNet SAIDI trend and forecast target
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SAIFI Performance
4
3.5
SAIFI (frequency)
3
2.5
Total interruption frequency
Reliability planned - Class B
2
1.5
Reliability unplanned - Class C
Targets for Forecast Year - Class B
Targets for Forecast Year - Class C
1
Regulatory threshold
0.5
0
Figure 31 OtagoNet SAIFI trend and forecast target
The charts show target SAIDI and SAIFI for unplanned (class C) outages have risen
and fallen in recognition of the inherent variability of these statistics when applied on a
small network (including faults due to and access under extreme weather), with current
targets set about the average of past experience with a modest future decline to
recognise improvement strategies. OtagoNet has greater control over planned outages
reflected by the closer matching of target and out-turn values. Setting reliability
performance levels is discussed further in section 6.1 of this plan.
5.2.2 Outage composition, trends and targeting
This section examines the composition and trends of the outages occurring on the
network and considers this in relation to the asset strategies and targets.
The following charts of Figure 32 show the average total customer minutes per year for
the years 2009 to 2013 categorised by network voltage and class of outage (plan or
fault). The left hand chart shows the total customer minutes while the right hand chart
shows the customer minutes per km of line. This chart reveals that, while the 11 kV
distribution lines produce the majority of outage minutes, on a per kilometre basis
targeting work on the 33 kV lines is more beneficial for reliability improvement and this
represents one of the key strategies for our reliability improvement expenditure.
Note that while the 33 kV lines only show a small amount of planned outage minutes,
this does not necessarily relate to OtagoNet undertaking less work on these lines but
rather is reflective of OtagoNet‘s recognising the importance of these lines and seeking
portable generation or back–feeding options when taking out these lines to limit the
customer impact.
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Figure 32 Composition of customer outage minutes
The following chart of Figure 33 examines the performance of planned outages in the
period 2009 to 2013 and consists of 4 charts. The top left chart shows the spread of
planned customer minutes per ICP (effectively per zone planned SAIDI) in each year
and by location. This shows that planned work is occurring reasonably uniformly across
all parts of the network and reveals the effect of meshed parts of the network, such as
exist in Milton (Elderlee St sub) and Balclutha (Charlotte St sub) having significantly
reduced outage minutes due to the ability to back-feed customers.
The top right chart plots the distribution of planned outage times by location and where
the blue vertical line is the 4-hour average target and the brown line the 6-hour target.
The bottom left chart highlights the planned outage performance in the 2013 calendar
year and shows the performance was short of meeting 95% of planned outages being
6 hours or less. The revised service level discussed in section 6.1 set 95% of planned
outages to be 6 hours or less, this being a more meaningful measure of the customers
experience of planned outages than the previous average time measurement, and
these charts show this will be a stretch target for OtagoNet to accomplish.
The bottom right chart plots the distribution of the number of affected connections in
each outage. This shows that some 90% of planned outage affect 40 connections or
less and points to the use of mobile generation as a potential means to reduce planned
SAIDI levels and deliver reliability improvement to OtagoNet‘s customers. Whilst this
cannot be applied in all cases and must be economic when it is applied, the increased
use of mobile generation to limit the impacts of planned outages is promoted as an
appropriate reliability improvement strategy in this plan.
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Figure 33 Examination of planned outages
The charts of Figure 34 and Figure 35 following show the make-up of the unplanned
outages for 33 kV lines and for distribution (11 kV) lines with the left-hand charts
showing the composition by fault type, where the predominance of ―defective
equipment‖ faults is clear, and the right-hand charts that further detail the next level
make-up of the defective equipment faults. Both of these charts highlight the reliability
impact of the deteriorated nature of the lines and reinforce the asset strategy of
continuing with condition-based replacement.
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Figure 34 Composition of 33 kV faults
Figure 35 Composition of 11 kV (distribution) faults
The following chart of Figure 36 looks at the fault count per km of line for distribution
lines with the left-hand chart showing the average fault rate by composition and
location and the right-hand chart showing the variation in fault rate by location and
year. This highlights the elevated fault rate of lines in the Waitati area, which arises
from the known poor nature of the lines in this area and the incursion of trees, and the
elevated fault rate of the lines about Port Molyneux - largely caused by the salt
corrosion in this area. Both these regions are targeted in this plan for reliability
improvement works.
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Figure 36 Unplanned outages by density, location, type and variance
OtagoNet has been engaged in increased levels of line refurbishment over the past few
years and the chart of Figure 37 following shows a pleasing trend in decreasing
defective equipment faults per annum from circa 2010. The strategies set out in this
plan are designed to continue to drive down the defective equipment fault rate on the
network.
Figure 37 Distribution defective equipment fault count trend
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5.2.3 Secondary service levels
Results for 2012/13 are shown below. 23
Attribute
Customer Satisfaction:
New Connections
Customer Satisfaction:
Faults
Voltage Complaints
{Reported in Network
report.}
Planned Outages
Measure
YE 31/3/13
Actual
Phone: Friendliness and
24
courtesy. {CSS: Q3(c)}
Phone: Time taken to answer
call. {CSS: Q3(a)}
Overall level of service.
{CSS: Q5}
Work done to a standard which
meet your expectations.
{CSS: Q4(b)}
Power restored in a reasonable
amount of time. {CES: Q4(b)}
Information supplied was
satisfactory. {CES: Q8(b)}
OtagoNet first choice to contact
for faults. {CES: Q6}
Number of customers who have
justified voltage complaints
regarding power quality
Average days to complete
investigation
Period taken to remedy justified
complaints
Provide sufficient information.
{CES: Q3(a)}
Satisfaction regarding amount of
notice. {CES: Q3(c)}
Acceptance of maximum of one
planned outage per year. {CES:
Q1}
Acceptance of planned outages
lasting four hours on average.
{CES: Q1}
>3.5
4.25
23
>3.5
4.09
23
>3.5
4.55
23
>3.5
4.21
23
>60%
88%
23
>60%
88%
23
>20%
13%
<15
6
<30
5
<60
29
>75%
92%
>75%
94%
>50%
97%
>50%
94%
(Reference in parentheses {} indicates where the information is collected/reported
from.)
5.2.4 Other service levels
5.2.4.1 Technical efficiency
The following charts show the target and actual values for the network loss ratio and
the transformer utilisation. As shown, the loss ratio has decreased from 7% to 5%
largely owing to the shift in the metering point to Ranfurly for the 66 kV lines that supply
the Macraes Gold mine load. This change occurred as the mine owner now bears the
cost of losses on what was a heavily loaded line until its upgrade in the FY2012 year
which was funded by the mine owner.
23
Results for the CSS survey are for FY2012 as the next iteration of the survey was not complete at the
time of compiling this AMP
24
CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices.
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The transformer utilisation is substantially on target in the FY2013 year. As shown in
the benchmarking section, the current level of utilisation benchmark satisfactorily in
relation to OtagoNet‘s peers given the load density of the network.
Network loss ratio (%)
9.0%
8.0%
7.0%
6.0%
5.0%
Losses
4.0%
3.0%
2.0%
1.0%
0.0%
Target
Network transformer utilisation (%)
40.0%
38.0%
36.0%
34.0%
32.0%
30.0%
28.0%
26.0%
24.0%
22.0%
20.0%
Transformer Utilisation
FY2018
FY2017
FY2016
FY2015
FY2014
FY2013
FY2012
FY2011
FY2010
FY2009
FY2008
Target
5.2.4.2 Financial
Measure
2012/13 AMP Target
Actual
Comment
Direct costs/km
No target
$796.3
Indirect costs/ICP
$174.94
$210.2
Benchmarking shows direct costs
per km is appropriate compared to
other electricity distribution
businesses
Benchmarking shows indirect
costs per ICP in FY2013
benchmark appropriately (and
lower than the regression
expectation) in comparison to
other electricity distribution
businesses.
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PERFORMANCE AND IMPROVEMENT
The following chart shows the financial performance from FY2010 for the measures of
direct cost per line kilometre and indirect cost per ICP. Direct costs include routine and
preventive maintenance, refurbishment and renewal maintenance, and fault and
emergency maintenance. Indirect costs include business administration and operations
expenditure (Transpower and pass-through costs are excluded).
The chart shows a relatively consistent performance for direct cost per km up to
FY2013. Note that no previous target has been set for this parameter as direct cost per
network replacement cost was used in the FY2013 AMP. However, as replacement
cost is no longer disclosed, this target has been replaced with direct cost per km of
circuit for supply. We note also that in the comparative benchmarking assessments,
OtagoNet showed with a satisfactory performance in the comparison of direct costs on
this basis.
The increase in direct opex cost per kilometre for forecast out-turn FY2014 and budget
FY2015 arises from undertaking the accelerated network surveillance program
discussed later in this plan plus an allowance for renewal maintenance expenditure
expected to arise from that surveillance. Direct cost per kilometre is expected to return
to FY2013 levels by FY2017.
Indirect costs have shown a rising trend above CPI and the FY2013 performance was
marginally above target. The rise in indirect costs relates to a 37% increase in the
PowerNet management fee. Despite the indirect costs becoming fully allocated, the
indirect costs per ICP continue to benchmark well in comparison with other distribution
businesses as shown in section 3.1.1.2. Note also that from and including FY2015 the
system control room costs are shifted from direct to indirect opex to better reflect the
contractual arrangements with PowerNet.
Direct/km and Indirect/ICP
Direct/km
Target direct/km
Indirect/ICP
Target indirect/ICP
1200.0
400.0
Direct cost/km ($ FY2014)
300.0
800.0
250.0
600.0
200.0
150.0
400.0
100.0
200.0
Indirect cost/ICP ($ FY2014)
350.0
1000.0
50.0
0.0
0.0
FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018 FY2019
5.3
Improvement areas and strategies
The following areas are highlighted as gaps in performance that could be improved,
and the strategies proposed to achieve improvements.
OtagoNet plans to improve its AMP in the future not simply by writing a better
document but by improving the asset management processes, systems and activities
that it uses.
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PERFORMANCE AND IMPROVEMENT
5.3.1 Maintenance and Capital Works
Gaps:
Strengthen capital governance and management.
Discussion:
Benchmarking and other analysis shows OtagoNet with the highest capital burden per
connection arising from the low connection density of the network. The nature of the
network also leads to inherent cross subsidy between customers as customers pay
uniform capacity charges. Additionally, prices appear to be at a level that is causing
some customers to avoid multiple connection charges through installing a single point
supply feeding multiple installations. In addition, government policy and the potential of
distributed generation technologies combined with an aging population in the coverage
area, all threaten the revenue base of the network. This reinforces that prudent capital
spending must be a key focus for OtagoNet.
Strategies:
OtagoNet will continue to make safety its first priority combined with enhancing its
capital governance processes through development of standard project assessment
templates and development of project evaluation tools including improved surveillance
and increased utilisation of information.
5.3.2 Condition assessment
Gaps:
Formalised condition assessment process and data capture.
Assessment of condition risks
Discussion:
Pole failures have highlighted improvements can be made, particularly in the capture
and use of condition inspection data. Additionally, condition data exists in isolation and
is not formally linked to the network risks that deteriorated assets pose. This will also
assist with capital governance as it will strengthen the capital expenditure justifications.
Strategies:
We have commenced upgrading the asset inspection templates and the means of
capturing that data into the GIS/AMS system. Other processes are under development
to automate the risk assessment impact of observed condition to better measure total
network risk and help prioritise maintenance and replacement works.
5.3.3 Planned outages
Gaps:
High level of planned outage SAIDI.
Discussion:
Benchmarking and performance analysis shows high levels of planned outage SAIDI
largely driven by the current lines refurbishment programme and the lack of network
meshing to back-feed customers. However, the cost of establishing cross-feeder links
typically outweighs the benefits.
Strategies:
We plan to increase the use of mobile generation to support load during planned
outages where this is feasible and cost effective. This plan includes allocated capital for
the purchase of appropriate step-up transformers to be used with hired or purchased
mobile generation plant.
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SERVICE LEVELS
6.
Proposed service levels
This section describes how OtagoNet sets the various service levels to its stakeholders
as set out in section 1.6 of this plan.
OtagoNet creates a broad range of service levels for all stakeholders, ranging from
capacity, continuity and restoration for connected customers (who pay for these service
levels) to ground clearances, earthing, absence of interference, compliance with the
District Plan and submitting regulatory disclosures, which are mandatory requirements
in the provision of a network service. These service levels are categorise and
described in Figure 38 below. This section describes those service levels in detail and
how OtagoNet justifies the service levels delivered to its‘ stakeholders.
Primary Customer
service levels
Customer service
levels
Paid for by customers for
the benefit of customers
Secondary Customer
service levels
Tertiarary Customer
service levels
Compliance with price
path threshold
Overall bundle of
delivered services
Regulatory service
levels
Compliance with
reliability threshold
Disclosure of financial
and energy delivery
efficiency measures
Paid for by customers for
the benefit of other
stakeholders
Public safety
Other service levels
Amenity value
Electrical interference
Figure 38 Types of service levels
OtagoNet‘s service levels are justified in six main ways:
Positive cost benefit within the revenue capability.
The consequence of meeting regulatory and/or industry best practice for security
levels.
By what is achievable for the business to resource.
By the physical characteristics and configuration of assets which are expensive to
significantly alter but which can be altered if a customer or group of customers
agrees to pay for the alteration.
By a customer‘s specific request and agreement to pay for a particular service
level.
When an external agency or regulation imposes a new service level.
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SERVICE LEVELS
6.1
Customer-oriented service levels
This section describes the service levels expected to be provided to customers which
affect them directly and exclusively.
Customer surveys indicates that customers value continuity and restoration of supply
more highly than other attributes such as answering the phone quickly, fast processing
of new connection applications etc. It has also evident from OtagoNet‘s research that
there is an increasing value placed by customers on the absence of flicker, sags,
surges and brown-outs. Other research indicates that flicker is probably noticed more
when it is usually absent.
6.1.1 Primary service levels
OtagoNet‘s primary service levels are continuity and restoration which recognise its
customer‘s requirements. To measure performance in this area two internationally
accepted indices have been adopted:
SAIDI – system average interruption duration index. This is a measure of how
many minutes of supply are interrupted per year.
SAIFI – system average interruption frequency index. This is a measure of how
many system interruptions occur per year.
The benchmarking results presented in section 2, showed OtagoNet as:
having a lower than expected SAIFI given its network exposure but;
having a high cost of fault relative to preventive maintenance expenditure;
having a modestly high ratio of planned SAIDI (attributed to the current line
refurbishment program and lack of network inter-connection for back-feeding), and;
having a high proportion of its faults arising from failing components (currently
being addressed through condition-based inspection and replacement).
Additionally, the area demographics discussed in section 1 showed increasing
connections of load more sensitive to load outages but that the high capital burden per
ICP for OtagoNet‘s customers requires a high degree of prudence in further capital
expenditure.
The outcome of customer consultation undertaken by a telephone survey, public
meetings and one-on-one meetings showed the majority of customers are content with
the present level of service but the expectations of customers vary depending upon
their individual requirements such as milking, irrigation and their dependency upon
electricity as an essential service in a harsh winter climate.
Irrespective, customers do not want a lesser level of service and have an expectation
going forward that reliability of supply will be at least maintained or improved.
Positive feedback has been received relative to the increased levels of maintenance
and capital expenditure undertaken on the network in recent years.
After consideration of these factors, OtagoNet has set reliability targets to recognise:
an expected slowly decreasing fault outage rate as the network reliability continues
to respond to the lines refurbishment programme;
modest improvement in fault SAIDI as the few economically justified opportunities
for network interconnection are constructed;
modest improvement in fault SAIFI as the economically justified opportunities for
installing additional 11 kV distribution reclosers are enacted;
a greater emphasis on reducing planned SAIDI through the increased use of
mobile generation but;
an increase in planned work requiring outages due to both the planned programme
of work and the unknown work that may be required as data is returned from the
condition inspection surveys.
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SERVICE LEVELS
Target levels for unplanned outages have therefore been calculated by averaging the
values over the regulatory period (2004/05 – 2008/09) (allowing for normalisation to
remove extreme events as per the Commerce Commission guidelines), and decreasing
future years by 0.5% p.a. Target levels for planned outages have been maintained
constant acknowledging that OtagoNet remains uncertain on the planned reliability
impacts of its work programme mainly due to the unknown condition driven work.
OtagoNet also acknowledges that it needs to improve its ability to forecast planned
outages impacts and this also motivates the improvement of our capital governance
and management processes discussed in this plan.
Projections of our reliability targets for the next ten years ending 31 March 2024 are set
out in Table 20 below.
Table 20 – Primary service levels
SAIDI
Year End
Class B
25
Limit1.1
31/03/15
31/03/16
31/03/17
31/03/18
31/03/19
31/03/20
31/03/21
31/03/22
31/03/23
31/03/24
1.2
148
148
148
148
148
148
148
148
148
148
Class C
175
174
173
173
172
171
170
169
168
168
SAIFI
Total
Class B
361.08
1.3
323
322
321
320
319
318
318
317
316
315
Class C
1.4
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
Total
2.07
2.06
2.05
2.04
2.03
2.02
2.01
2.00
1.99
1.98
3.120
2.70
2.69
2.68
2.67
2.66
2.65
2.64
2.63
2.62
2.61
In practical terms this means customers can broadly expect the reliability stated in
Table 21 below where the reliability deteriorates towards the outer extents of the
network where there is no ability to provide backup and there are long single lines
exposed to faults.
Table 21 – Expected unplanned outages by location
General location
Balclutha, Milton, Ranfurly
Towns (dual transformers;
some meshed distribution)
Villages (single
subtransmission lines; no
meshed distribution)
Anywhere else (long rural
feeders)
Expected reliability
One outage per year of about 60 minutes duration
Two outages per year of about 90 minutes duration in
total
Three outages per year of about 120 minutes duration
in total
Four outages per year of about 240 minutes duration
in total
For planned outages OtagoNet has set a new target of undertaking 95% of planned
outages in 6 hours or less, as this is a more meaningful measurement of the customers
experience of planned outages. As shown in the performance and improvement
section, this is a stretch target for OtagoNet and will be used as a driver for closer
management of planned outages and the increased use of mobile generation.
25
Limit calculated by the Commerce Commission Default Price-Quality Path methodology, with reference
data from 1 April 2004 to 31 March 2009. Normalised data must not exceed the limit two out of three
years. Normalisation calculates a boundary value which is used to reduce the daily value when an
extreme event occurs.
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SERVICE LEVELS
6.1.2 Secondary service levels
Secondary service levels are the attributes of service that OtagoNet‘s customers have
ranked below the first and second most important attributes of supply continuity and
restoration. The key point to note is that some of these service levels are process
driven, which has two implications:
They tend to be cheaper than capital asset solutions.
They are heterogeneous in nature i.e. they can be provided exclusively to
customers who are willing to pay more in contrast to fixed asset solutions which will
equally benefit all customers connected to an asset regardless of whether they
pay.
These measures could include:
How satisfied customers are after communication regarding:
- Tree trimming
- Connections
- Faults
Time taken to respond to voltage complaints and time to remedy justified voltage
complaints.
Sufficient notice of planned shutdowns
Targets for our secondary services are set at levels reflective of a good corporate
citizen, that maintain or improve the historic trend and recognise the likely impact of
targeted improvements.
For example: More Public Relations with newsletter and fridge-magnet should increase
OtagoNet as first point of contact for faults. The newsletter will also inform customers
relative to safety issues and energy efficiency.
Table 22 below sets out the targets for these service levels for the next ten years.26
Table 22– Secondary service levels
Year ending
Measure
31/3/15
31/3/16
31/3/17
…
31/3/24
Phone: Friendliness and
27
courtesy. {CSS: Q3(c)}
Phone: Time taken to answer
call. {CSS: Q3(a)}
Overall level of service.
{CSS: Q5}
Work done to a standard
which meets customer
expectations.
{CSS: Q4(b)}
Customer satisfied power
restored in a reasonable
amount of time. {CES: Q4(b)}
>3.5
>3.5
>3.5
…
>3.5
>3.5
>3.5
>3.5
…
>3.5
>3.5
>3.5
>3.5
…
>3.5
>3.5
>3.5
>3.5
…
>3.5
>60%
>62%
>63%
…
>70%
Attribute
Customer
Satisfaction: New
Connections
Customer
Satisfaction: Faults
26
From this plan forward targets of customer satisfaction enquiries and number of customers making a
voltage complaint have been dropped. The first is because the measure was unreliable in that in a
random sample of 200, the number who had made an enquiry of the network was small and resulted in
large variation between years. Additionally; it is often customers who have issues of service who do
make contact so the measure is not unbiased. Voltage complaint has also been dropped noting that it is
only upheld voltage complaints that have an asset management solution and this is the measure that has
been retained.
27
CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices.
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SERVICE LEVELS
Year ending
Measure
31/3/15
31/3/16
31/3/17
…
31/3/24
Information supplied was
satisfactory. {CES: Q8(b)}
OtagoNet first choice to
contact for faults. {CES: Q6}
Number of customers who
have justified voltage
complaints regarding power
quality
Provide sufficient information.
{CES: Q3(a)}
Satisfaction regarding
amount of notice. {CES:
Q3(c)}
Acceptance of maximum of
three planned outages per
year. {CES: Q1}
Acceptance of planned
outages lasting four hours on
average. {CES: Q1}
>60%
>62%
>63%
…
>70%
>35%
>35%
>35%
…
>50%
<15
<15
<15
…
<15
>75%
>75%
>75%
…
>75%
>75%
>75%
>75%
…
>75%
>50%
>50%
>50%
…
>50%
>50%
>50%
>50%
…
>50%
Attribute
Voltage Complaints
{Reported in
network report.}
Planned Outages
{Where the information is collected / reported from.}
6.2
Safety
Various legislation requires OtagoNet‘s assets (and customers‘ plant) to adhere to
certain safety standards which include earthing exposed metal and maintaining
specified line clearances from trees and from the ground:
Health and Safety In Employment Act 1992.
Electricity (Safety) Regulations 2010.
Electricity (Hazards From Trees) Regulations 2003.
Maintaining safe clearances from live conductors (NZECP34:2001).
OtagoNet seeks 100% compliance with all its legislated requirements and industry
codes of practice.
6.3
Other service levels
In addition to the service levels that are of primary and secondary importance to
customers and for which they pay, there are a number of service levels that benefit
other stakeholders such as safety, amenity value, absence of electrical interference
and performance data. In fact most of these service levels are imposed on OtagoNet
by statute and, as such, are service levels for which OtagoNet seeks 100%
compliance.
6.3.1.1 Amenity value
There are a number of Acts and other requirements that limit where OtagoNet can
erect or maintain overhead lines:
The Resource Management Act 1991.
The Operative District Plans.
Relevant parts of the Operative Regional Plan.
Land Transport requirements.
Civil Aviation requirements.
Land owner consent
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SERVICE LEVELS
In general, OtagoNet will need to respond to these circumstances as they arise.
6.3.1.2 Supply quality
Under certain operational conditions assets can interfere with other utilities such as
phone wires and railway signalling or with the correct operation of OtagoNet‘s own
equipment or customers‘ plant. The following codes impose service levels on us:
Voltage levels
Harmonic levels (NZECP36:1993).
Voltages induced into telecommunications circuits from SWER lines (regulation
33A of the Electricity (Safety) Regulations 2010)
OtagoNet recognises that many of its LV lines are in poor condition and often include
small conductor sizes owing to the age of the lines and the low load requirements at
the time the line was built. This may result in poor voltage delivery to customers and
reacting just to voltage complaints is not the best method to manage this service
delivery. As discussed in this plan, OtagoNet intends to progressively upgrade its LV
network not only to restore the condition of the lines but to also ensure that voltage
quality is appropriate.
Variable speed drives often used in conjunction with irrigation pumps emit harmonic
currents. OtagoNet‘s policy is to require customers to limit such harmonics at source as
required under the legislation.
6.4
Regulatory service levels
Various Acts and Regulations require OtagoNet to deliver a range of outcomes within
specified timeframes, such as the following:
Ensure a wide degree of customer satisfaction with both pricing and reliability to
avoid being placed under a restraining regime.
Publicly disclose an AMP each year.
Publicly disclose prescribed performance measures each year including the
Electricity Distribution Information Disclosure Determinations 2012 and subsequent
amendments.
OtagoNet seeks 100% compliance in meeting its regulatory obligations.
6.4.1 Financial efficiency measures
OtagoNet set two financial efficiency measures which are:
Direct costs / km = [Routine and Preventative Maintenance] + [Refurbishment and
Renewal Maintenance] + [Fault and Emergency Maintenance]) / [Total circuit km
for supply]
Indirect costs per ICP = [General Management, Administration and Overheads
expenditure] / [number of ICP‘s at year end].
Values as defined in the Information Disclosure requirements.
OtagoNet‘s target financial efficiency measures are shown below. Note that previously
OtagoNet set a target on the total opex cost per year per replacement cost of the
network. As replacement cost is no longer disclosed it cannot be benchmarked so
OtagoNet has moved to the metric of direct cost per circuit km. Justification for these
service levels arises from the comparative benchmark findings discussed in section 2,
that showed OtagoNet‘s direct and indirect opex costs in line with those of its peers,
together with a short term step increase in direct costs arising from the accelerated
program of condition inspections discussed further in the life cycle section of this plan.
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SERVICE LEVELS
Table 23 - Financial Efficiency
Year ending
Direct costs/km
Indirect costs/ICP
31/3/15
31/3/16
31/3/17
31/3/18
31/3/19
31/3/20
31/3/21
31/3/22
31/3/23
31/3/24
$960
$820
$774
$774
$774
$774
$774
$774
$774
$774
$240
$240
$241
$241
$241
$241
$241
$241
$241
$241
Note that from FY2015, system control room costs have been shifted from direct to
indirect opex.
6.4.2 Energy delivery efficiency measures
The target energy efficiency measures are shown below. These measures are:
Loss ratio - [kWh lost in the network during the year] / [kWh entering the network
during the year].
Capacity utilisation - [max demand for the year] / [installed distribution transformer
capacity].
The benchmarking of section 3 showed both the FY2013 loss ratio (5.1%) and the
current capacity utilisation (29.8%) to benchmark satisfactorily given the size and
circumstances of OtagoNet‘s network and justifies the continuation of these service
targets at these levels.
Note that previous AMPs set a service level target for network load factor. However, as
OtagoNet cannot undertake retailing over its network and there are no effective asset
management strategies that OtagoNet could reasonably undertake that would impact
load factor, it has been dropped as a service level target.
Table 24 - Delivery Efficiency
Year ending
Loss ratio
Capacity utilisation
31/3/15
31/3/16
31/3/17
31/3/18
31/3/19
31/3/20
31/3/21
31/3/22
31/3/23
31/3/24
5.00%
5.00%
5.00%
5.00%
5.00%
5.00%
5.00%
5.00%
5.00%
5.00%
30%
30%
30%
30%
30%
30%
30%
30%
30%
30%
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OUR DEVELOPMENT PLANS
7.
Development plans
Development plans are driven primarily by:
7.1
Increasing consumer demand due to growth or new connections or to generation
power transfers over the network.
Asset renewal requirements prompting network re-configuration (ie shifting the
location of a zone substation when it must be rebuilt).
Statutory or code requirements to improve service levels (Security of supply, safety
or environmental compliance.).
Internally generated initiatives to improve service levels.
Planning approach and criteria
7.1.1 Planning detail
OtagoNet has adopted the 22kV or 11kV feeder as OtagoNet‘s fundamental planning
unit which includes either a single large consumer load, a point of generation injection,
a distribution feeder, or other specific customer requirement.
7.1.2 Planning approaches
OtagoNet plans its assets in three different ways; strategically, tactically and
operationally as shown in Table 25 below:
Table 25- Planning approaches
Attribute
Strategic
Asset description
Assets within GXP.
Subtransmission lines
and cables.
Major zone substation
assets.
Load control injection
plant.
Central SCADA and
telemetry.
Distribution
configuration e.g.
decision to upgrade to
22kV.
Number of
consumers
supplied
Impact on
balance sheet
Asset valuation
Anywhere from 500
upwards.
Degree of
specificity in
plans
Level of approval
required
Asset Management Plan
Individual impact is
high.
Aggregate impact is
moderate.
Likely to be included in
very specific terms,
probably accompanied
by an extensive
narrative.
Approved in principle in
annual business plan.
Individual approval by
Governing Committee
Tactical
Operational
Minor zone substation
assets.
All individual
distribution lines
(11kV).
All distribution line
hardware.
All on-network
telemetry and SCADA
components.
All distribution
transformers and
associated switches.
All HV consumer
connections.
Anywhere from one to
about 500.
All 400V lines and
cables.
All 400V consumer
connections.
All consumer
metering and load
control assets.
Individual impact is
moderate.
Aggregate impact is
significant.
Likely to be included in
specific terms and
accompanied by a
paragraph or two.
Individual impact is
low.
Aggregate impact is
moderate.
Likely to be included
in broad terms on a
program basis
Approved in principle in
annual business plan.
Individual approval by
the Engineering
Approved in principle
in annual business
plan.
Individual approval
Anywhere from one
to about 50.
Page 88 of 193
OUR DEVELOPMENT PLANS
Attribute
Characteristics of
analysis
Strategic
and possibly
shareholders.
Tends to use one-off
models and analyses
involving a significant
number of parameters
and extensive
sensitivity analysis.
Tactical
Operational
Manager.
by Network Manager.
Tend to use established
models with some
depth, a moderate
range of parameters
and possibly one or two
sensitivity scenarios.
Tends to use
established models
based on a few
significant
parameters that can
often be embodied in
procedural rules.
OtagoNet has developed the following ―investment strategy matrix‖ shown in Figure 39,
which broadly defines the nature and level of investment and the level of investment
risk implicit in different circumstances of growth rates and location of growth.
Predominant Capital expenditure (CAPEX) modes are:
Large industrial loads such as a new factory which involves firstly extension and
then usually up-sizing sit in Quadrant 4 which has desirable investment
characteristics. This mode of investment does however carry the risk that if
demand growth doesn‘t occur as planned, asset stranding can occur and the
investment slips into Quadrant 3 which has less desirable investment
characteristics.
Dairy conversions involve extensions and then sometimes up-sizing but due to the
lumpy nature of constructing line assets these may fall into Quadrant 3 which
carries some risk of stranding or delayed recovery of investment.
Residential subdivisions around urban areas tend to have large up-front capital
costs but recovery of costs through line charges often lags well behind. The size of
the subdivision will dictate whether it falls in Quadrant 1 or 3, neither of which has
particularly desirable investment characteristics. Hence some form of developer
contribution is almost certain to be required.
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OUR DEVELOPMENT PLANS
Quadrant 4
Quadrant 3
Outside of
existing
network
footprint
Location of
demand growth
Capital Expenditure will be
dominated by new assets that
require both connection to existing
assets and possibly upstream
reinforcement.
Likely to absorb lots of cash – may
need capital funding.
Easily diverts attention away from
legacy assets.
Likely to result in low capacity
utilisation unless modular
construction can be adopted.
May have high stranding risk.
Capital Expenditure will be
dominated by new assets that
require both connection to existing
assets and possibly upstream
reinforcement.
Likely to absorb lots of cash – may
need capital funding.
Easily diverts attention away from
legacy assets.
Need to confirm regulatory
treatment of growth.
May have a high commercial risk
profile if a single consumer is
involved.
Quadrant 2
Quadrant 1
Within
existing
network
footprint
Capital Expenditure will be
dominated by enhancement rather
than renewal (assets become too
small rather than worn out).
Regulatory treatment of additional
revenue arising from volume thru’
put as well as additional
connections may be difficult.
Likely to involve tactical upgrades
of many assets
Capital Expenditure will be
dominated by renewals (driven by
condition).
Easy to manage by advancing or
deferring straightforward Capital
Expenditure projects.
Possibility of stranding if demand
contracts.
Lo
Prevailing load
growth
Hi
Figure 39 - Investment strategy matrix
7.1.3 Trigger points for planning new capacity
As new capacity has valuation, balance sheet, depreciation and ROI implications for
OtagoNet, endeavours are made to meet demand by other, less investment-intensive
means, first.
The first step in meeting future demand is to determine if the projected demand will
exceed any of OtagoNet‘s defined trigger points for asset location, capacity, reliability,
security or voltage. These points are outlined for each asset class in Table 26.
If a trigger point is exceeded OtagoNet will then move to identify a range of options to
bring the asset‘s operating parameters back to within the acceptable range of
operation. These options are described in section 7.2 which also embodies an overall
preference for avoiding new capital expenditure particularly given OtagoNet‘s the high
capital burden per ICP identified in the benchmarking section.
Table 26 - Summary of capacity "trigger points"
Asset class
Type
Trigger
Extension
Location
Asset Management Plan
LV lines and cables
Existing LV lines and
cables don‘t reach the
required location.
Distribution
substations
Distribution lines and
cables
Load cannot be
reasonably
supplied by LV
configuration
therefore requires
new distribution
lines or cables and
distribution
Load cannot be
reasonably supplied by
LV configuration
therefore requires new
distribution lines or
cables and substation.
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Asset class
Type
Up-sizing
Trigger
LV lines and cables
Distribution
substations
Capacity
Tends to manifest as
fuse blowing when
current exceeds circuit
rating.
substation.
Where fitted, MDI
reading exceeds
90% of nameplate
rating.
Reliability
Not applicable. Normally a Maintenance or Operational trigger, as
reliability is not an indicator for up-sizing.
Excursion beyond triggers specified in the EEA security guidelines and
discussed further in section 7.2.2
Voltage at consumers‘
Voltage at
Voltage at MV
boundary consistently
consumers‘
terminals of
boundary
transformer
drops below 0.94pu.
consistently drops consistently drops
below 0.94pu that
below 10.45kV and
cannot be
cannot be
remedied by LV
compensated by local
up-sizing.
tap setting.
Asset deteriorated to an unsafe condition or poses an undue risk as
discussed further in the life cycle section of this plan.
Third party requests work.
Neighbouring assets being replaced.
Security
Voltage
Renewal
Condition
Distribution lines and
cables
Analysis calculates
that the peak current
exceeds the thermal
rating of the circuit
segment.
Asset class
Type
Trigger
Zone substations
Extension
Location
Up-sizing
Capacity
Load cannot be
reasonably supplied
by distribution
configuration
therefore requires
new subtransmission
lines or cables and
new zone substation.
Max demand
consistently exceeds
100% of nameplate
rating.
Reliability
Security
Voltage
Renewal
Condition
Asset Management Plan
Subtransmission
lines and cables
Network equipment
within GXP
Load cannot be
Load cannot be
reasonably supplied
reasonably supplied
by distribution
by new or extended
configuration
Subtransmission or
therefore requires
substation therefore
new subtransmission requires new GXP
lines or cables and
equipment.
new zone substation.
Analysis calculates
Max demand
that the peak current consistently exceeds
exceeds the thermal
80% of nameplate
rating of the circuit
rating.
segment.
Not applicable. Normally a Maintenance or Operational trigger, as
reliability is not a trigger for up-sizing.
Excursion beyond triggers specified in the EEA security guidelines
and discussed further in section 7.2.2
Voltage at MV
Voltage at HV
Not applicable.
terminals of
terminals of
transformer
transformer
consistently drops
consistently drops
below 10.45kV and
below 0.87pu and
cannot be
cannot be
compensated by
compensated by
OLTC.
OLTC.
Asset deteriorated to an unsafe condition.
Third party requests work.
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7.1.4 Quantifying new capacity
The two major issues surrounding constructing new capacity are:
How much capacity to build? This comes back to the trade-off between cost and
building in extra capacity for security and safety (risk-avoidance).
When to build the new capacity? The obvious theoretical starting point for timing
new capacity is to build just enough, just in time, and then incrementally add more
over time but this is not economical for feasible.
OtagoNet therefore recognises the following practical issues:
The need to avoid risks associated with over-loading and catastrophic failure.
The need to limit investment to what can be recovered under the price-path
threshold and the ODV valuation methodology.
The standard sizing steps of many components (which makes investment lumpy).
The one-off costs of construction, consenting, traffic management, access to land and
reinstatement of sealed surfaces which make it preferable to install large lumps of
capacity and not go back to the site.
Selection of the right capacity to build is based on the following:
Overhead lines:
- MV routes between zone substations, a minimum of Helium conductor.
- Usually set by voltage drop limits and strength requirements
- MV laterals Chlorine conductor
- LV allow 20% growth
Cables
- Allow 100% growth
Distribution transformers
- Individual consumers, size to consumer capacity.
- Domestic consumers based on following diversity:
Maximum
consumers
Transformer Size
2
15 kVA
6
30 kVA
10
50 kVA
20
100 kVA
50
200 kVA
80
300 kVA
150
500 kVA
[Note that this clearly depends on the individual load and network configuration
circumstances. In most rural supply situations it is typically infeasible to connect
other than a single property to a standard 15 kVA transformer because of voltage
considerations].
Line equipment
- Use standard ratings (e.g. ABS 400A, Recloser 400A)
Power transformers
- Allow expected area growth over 20 years
Substation equipment
- Use standard ratings
Subtransmission lines
- Allow expected area growth over 20 years
OtagoNet‘s guiding principle is therefore to minimise the level of investment ahead of
demand, then minimising the costs associated with doing the work.
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7.2
Prioritisation methodology
7.2.1 Options for meeting demand
Table 26 defines the trigger points at which the capacity of each class of assets needs
to be increased. In a broad order of preference, actions to increase the capacity of
individual assets within these classes can take the following forms:
Do nothing and simply accept that one or more parameters have exceeded a
trigger point. In reality, do nothing options would only be adopted if the benefit-cost
ratios of all other reasonable options were unacceptably low and if assurance was
provided to the Governing Committee that the do nothing option did not represent
an unacceptable increase in risk to OtagoNet. An example of where a do nothing
option might be adopted is where the voltage at the far end of a remote rural feeder
is unacceptably low for a short period at the height of the holiday season – the
benefits of correcting such a constraint may be simply too low in relation to the
cost.
Operational activities, in particular switching on the distribution network to shift load
from heavily-loaded to lightly-loaded feeders to avoid new investment or winding
up a tap changer or installing voltage regulators to mitigate a voltage problem. The
downside to this approach is that it may increase line losses, reduce security of
supply or compromise protection settings.
Influence consumers to alter their consumption patterns so that assets perform at
levels below the trigger points. Examples might be to shift demand to different time
zones, negotiate interruptible tariffs with certain consumers so that overloaded
assets can be relieved or assist a consumer to adopt a substitute energy source to
avoid new capacity. OtagoNet notes that the effectiveness of line tariffs in
influencing consumer behaviour is dampened by the retailers‘ practice of
repackaging fixed and variable charges.
Construct distributed generation so that an adjacent asset‘s performance is
restored to a level below its trigger points. Distributed generation would be
particularly useful where additional capacity could eventually be stranded or where
primary energy is going to waste e.g. Waste steam from a process.
Modify an asset so that the asset‘s trigger point will move to a level that is not
exceeded e.g. by adding forced cooling. This is essentially a subset of the above
approach but will generally involve less expenditure. This approach is more suited
to larger classes of assets such as power transformers.
Retrofitting high-technology devices that can exploit the features of existing assets
including the generous design margins of old equipment. An example might
include using advanced software to thermally re-rate heavily-loaded lines, using
remotely switched air-break switches to improve reliability or retrofit core
temperature sensors on large transformers to allow them to operate closer to
temperature limits.
Install new assets with a greater capacity that will increase the assets trigger point
to a level at which it is not exceeded. An example would be to replace a 200kVA
distribution transformer with a 300kVA so that the capacity criterion is not
exceeded.
In identifying solutions for meeting future demands for capacity, reliability, security and
satisfactory voltage levels, OtagoNet considers options that cover the above range of
categories. The benefit-cost ratio of each option is considered including estimates of
the benefits of environmental compliance and public safety and the option yielding the
greatest benefit is adopted. OtagoNet uses the model in figure 40 to broadly guide
adoption of various approaches:
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Install new
assets
Hi
Modify
existing
asset
Rate of payback
Retrofit hitech
Construct
DG
Lo
Influence
consumer
demand
Operational
changes
Do nothing
Lo
Hi
Prevailing load
growth
Figure 40 - Options for meeting demand
7.2.2 Meeting security requirements
A key component of security is the level of redundancy that enables supply to be
restored independently of repairing or replacing a faulty component.
Typical
approaches to providing security to a zone substation include:
Provision of an alternative substation-transmission circuit into the substation,
preferably separated from the principal supply by a 66kV or 33kV bus-tie.
Provision to back-feed on the 22kV or 11kV from adjacent substations with
sufficient 22kV or 11kV capacity and interconnection. This obviously requires
those adjacent substations to be operated at less than nominal rating.
Use of local generation.
Use of interruptible load (water heating, irrigation).
Generally security of supply is greater in the urban areas or for larger customers where
there are a lesser number of components in the supply chain and/or the revenue
justifies a greater level of investment.
7.2.2.1 Prevailing security standards
The commonly adopted security standard in New Zealand is the EEA Guidelines which
reflect the UK standard P2/5 that was developed by the Chief Engineers‘ Council in the
late 1970‘s. P2/5 is a strictly deterministic standard i.e. it states that ―this amount and
nature of load will have this level of security‖ with no consideration of individual
circumstances. OtagoNet applies this standard for its network security.
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7.2.2.2 Issues with deterministic standards
Deterministic standards are now beginning to give way to probabilistic standards in
which the value of lost load and the failure rate of supply components is estimated to
determine an upper limit of investment to avoid interruption. OtagoNet will have the
opportunity to consider such an approach as further information is gained relative to the
network.
A key characteristic of deterministic standards such as P2/5 and the EEA Guidelines is
that rigid adherence generally results in at least some degree of over investment.
Accordingly the EEA Guidelines recommend that individual circumstances be
considered which is the approach adopted by OtagoNet.
7.2.2.3 Contribution of local generation to security
From a security perspective, ideally local generation would need to have 100%
availability which is unlikely from small undiversified plant and even less likely where
the primary energy is run-of-the-river hydro, wind or solar. For this reason, the
emerging UK standard P2/6 provides for minimal contribution of such generation to
security requirements. In practical terms OtagoNet will always seek to ensure the
network has the ability to receive all available generation capacity.
7.2.2.4 OtagoNet security standards
Table 27 below describes the security standards adopted by OtagoNet, whilst Table
28, lists the level of security at each zone substation (noting the security level using the
codes listed in Table 28 and justifies any shortfall. In setting target security levels the
following guiding principles are used:
Where a substation is for the sole benefit of a single consumer, their preference for
security will be considered in that individual line services agreement.
The preferred means of providing security to rural zone substations will be backfeeding on the 11kV subject to interconnection, line ratings and surplus capacity at
adjacent substations but noting that the low connection density of the network
means such opportunities are not common.
The preferred means of providing security to urban zone substations will be by
secondary subtransmission assets with any available back-feeding on the 22kV or
11kV providing a third tier of security.
Table 27 - Minimum security levels required
Description
Load type
Security level
AAA
Greater than 12MW or 6,000
consumers.
No loss of supply after the first
contingent event.
AA
Between 5 and 12MW or 2,000
to 6,000 consumers.
All load restored within 25 minutes of
the first contingent event.
A(i)
Between 1 and 5MW
All load restored in the time necessary
to isolate and back-feed following the
first contingent event.
A(ii)
Less than 1MW
All load restored in the time necessary
to repair after the first contingent event.
Table 28 - Substation security levels
Substation
Balmoral
Becks
Big Sky Dairy
Asset Management Plan
Min. Reqt
A(ii)
A(ii)
A(ii)
Actual Now
A(ii)
A(ii)
A(ii)
Remarks
One pump
One pump
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Substation
Brothers Peak
Charlotte Street
Clarks
Min. Reqt
A(ii)
AA
A(ii)
Actual Now
A(ii)
AAA
A(ii)
Clinton
A(i)
A(ii)
Clydevale
A(i)
A(ii)
Cormack
Craiglynn
Deepdell
A(ii)
A(ii)
A(ii)
A(ii)
A(ii)
A(ii)
Elderlee Street
AA
AAA
Finegand
A(i)
A(ii)
Glenore
A(ii)
A(ii)
Golden Point
A(i)
A(ii)
Greenfields
A(ii)
A(ii)
Hindon
A(ii)
A(ii)
Hyde
A(i)
A(ii)
Kaitangata
A(i)
A(i)
Lawrence
A(i)
A(ii)
Macraes Mine
AA
A(ii)
Merton
A(i)
A(ii)
Middlemarch
Milburn
A(ii)
AA
A(ii)
AA
Mount Stuart
A(i)
A(i)
North Balclutha
O'Mally's House
O'Mally's Pump
Oturehua
A(i)
A(ii)
A(ii)
A(ii)
A(i)
A(ii)
A(ii)
A(ii)
Owaka
A(i)
A(ii)
Paerau
A(ii)
A(ii)
Paerau Hydro
AA
A(ii)
Palmerston
A(i)
A(ii)
Asset Management Plan
Remarks
One radio repeater
One 33 kV line and limited 11kV back
feed, spare transformer to be purchased
and stored here
Dual 33 kV lines available but single
transformer and limited 11kV back feed
Load increasing. Long term plan to
make closed 33 kV ring + dual
transformers.
One house
Long term plan to establish higher
capacity installation on new site.
Multiple 33 kV feeds, single transformer
and limited 11 kV back feed
Multiple 33 kV feeds, single transformer
and limited 11 kV back feed
Now a single consumers back-up supply
only
Single 33 kV customer with limited back
up on 11 kV
Most customers can be back fed
through 11 kV lines, except Macraes
pumps where loss of supply is only an
issue if the pond storage is low
Single 33 kV supply; Restoration via 11
kV backfeeds
Multiple 33 kV feeds, single transformer
(new incl. 11 kV swgr) and limited 11 kV
back feed
No backup available with single
consumers agreement off single 66 kV
line.
Single 33 kV line with dual transformers
and limited 11kV backup. Plan to
provide dual 33 kV supplies.
Single Customer only required N
reliability
Security via 11 kV backfeed.
One house
One pump
Single 33 kV line and single
transformer. Limited 11kV back feed
No backup available with single
consumers agreement
Single short (2km) 33 kV line dual
transformers and limited 11kV back
feed. Long term plan to relocate to
Transpower GXP site after land
purchase
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Substation
Min. Reqt
Actual Now
Patearoa
A(i)
A(ii)
Port Molyneux
Pukeawa
Ranfurly
Ranfurly 66/33
Redbank
Rough Ridge
A(ii)
A(ii)
A(i)
AA
A(ii)
A(ii)
A(ii)
A(ii)
AA
AAA
A(ii)
A(ii)
Stirling
A(i)
A(ii)
Stoneburn
Tisdall
A(ii)
A(ii)
A(ii)
A(ii)
Waihola
A(i)
A(ii)
Waipiata
A(i)
A(ii)
Waitati
A(i)
A(ii)
Wedderburn
A(ii)
A(ii)
Remarks
Increasing load requires 11kV
reinforcement.
One telecom repeater
Limited 11kV back feed with single
consumers agreement
One pump
Some 11kV back feed from adjacent
substations
Single (new) transformer; limited 11 kV
back feed.
Limited 11kV back feed from one distant
substation. Plan to provide dual 33 kV
after Palmerston GXP re-configuration
7.2.3 Choosing the best option to meet demand
Each of the possible approaches to meeting demand that are outlined in section 7.2.1
will contribute to strategic objectives in different ways. OtagoNet uses a number of
decision tools to evaluate options depending on their cost:
Cost & nature of option
Up to $50,000, commonly
recurring, individual projects
not tactically significant but
collectively add up.
Up to $250,000, individual
projects of tactical
significance.
Up to $1,000,000 occurs
maybe once every few years,
likely to be strategically
significant.
Over $1,000,000 occurs
maybe once in a decade,
likely to be strategically
significant.
Decision tools
OtagoNet standard rules.
Industry common practice.
Manufacturer‘s tables and
recommendations.
Simple spreadsheet model based on a
few parameters.
Spreadsheet model to calculate NPV
that might consider 1 or 2 variation
scenarios.
Extensive spreadsheet model to
calculate NPV, Payback that will
probably consider several variation
scenarios.
Extensive spreadsheet model to
calculate NPV, Payback that will
probably consider several variation
scenarios.
Organisational
level of evaluation
Network Manager
Network Manager
Engineering
Manager
(Marlborough Lines)
Governing
Committee approval
7.2.4 Project prioritisation
Designers and planners use the ‗decision tools‘ on projects to enable prioritisation and
rationing of our resources.
OtagoNet prioritises the work based on its needs to meet service standards and
network condition assessment. It is the intent to be proactive and eliminate potential
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faults before they occur. Some abnormal situations28 do distort results and these are
considered in meeting both targets and budgets. Note all known expenditure for any
year is included in the business plan which is approved by the Governing Committee.
7.3
OtagoNet’s demand forecast
7.3.1 OtagoNet’s current demand
Maximum demand (MD) is considered in 3 ways:
the individual any-time half-hour maximum demands at each site (which will not
necessarily occur at the same time) and which define the engineering
considerations of load at the sites;
the maximum demands co-incident with the Transpower regional peak (with
OtagoNet being in the Lower South Island (LSI) region); and
the average of the 100 half-hourly maximum demands at each site occurring coincident with the 100 top LSI demands – this determines the Transpower demand
charges at the GXPs.29
The individual maximum demands and the LSI coincident demands and average 100
demands (in { }) are shown in Table 29.
Table 29 – OtagoNet’s GXP and Generation Maximum Demands
GXP
Balclutha GXP
30
Palmerston GXP
Naseby GXP
Total Transpower
Paerau Generation
Falls Dam Generation
Mt Stuart Wind Farm
Total System
Anytime Maximum Demand
Between 1/4/12 and 31/3/13
(MW)
LSI Coincident Demand
On 11 Sept 2012 at 0830
(MW) {+ 100 avg}
27.182 (February)
9.030 (June)
31
24.948 (April)
26.518 {22.426}
7.644 {7.180}
12.704 {13.973}
46.866
11.688
1.270
0.000
59.824
12.409
1.281
7.500
60.719
Because the Lower South Island regional peaks are dominated by the Tiwai smelter
load, there is very little correlation between the LSI peaks and the OtagoNet load
peaks. Compounding this is the unpredictability of the LSI peaks that makes the use of
load control for demand minimisation through operation of the ripple plant almost
ineffectual. However, this has also allowed OtagoNet to relax load control during the
year providing customers with less restricted supply on an off-peak rate.
28
Abnormal situations: Major storms, snow, significant planned outages, dry year rationing, external party
major equipment failures.
29
Allocation of Transpower costs are based on the share of the average of the top 100 peaks for all loads
in the Lower South Island (LSI) region. See http://www.ea.govt.nz/industry/transmission/transmissionpricing/transmission-pricing-methodology/ for details.
30
Configuration prior to completion of the transfer to Halfway Bush.
31
This is net of Paerau generation; the regional load peak occurred in December driven by holiday
residences and irrigation.
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Each zone substation recorded the maximum demands as listed in Table 30.
Table 30 substation demand
Zone Substation
Charlotte Street
Clarks Junction
Clinton
Clydevale
Deepdell
Elderlee Street
Finegand
Glenore
Golden Point
Greenfield
Hindon
Hyde
Kaitangata
Lawrence
Macraes Mine
Merton
Middlemarch
Milburn
North Balclutha
Oturehua
Owaka
Paerau
Paerau Hydro
Palmerston
Patearoa
Port Molyneux
Pukeawa
Ranfurly
Ranfurly 66/33 kV
Stirling
Waihola
Waipiata
Waitati
Wedderburn
Installed Capacity
MVA
2013 Maximum
Demand MVA
2013 Capacity
Utilisation
10.0
0.5
2.5
2.5
0.8
10.0
2.5
1.5
5.0
2.3
0.5
2.5
2.5
2.5
30.0
5.0
2.5
7.5
5.0
0.8
2.5
0.8
30.0
5.0
2.5
2.5
0.8
5.0
50.0
5.0
1.5
2.5
2.5
0.8
6.1
0.4
2.0
2.7
0.1
6.4
1.1
0.7
4.2
1.7
0.2
1.2
1.4
1.5
22.4
2.4
0.7
2.4
2.8
0.2
1.5
0.3
12.8
2.2
1.7
0.7
0.4
2.2
25.3
3.9
1.2
1.3
1.5
0.2
61%
80%
78%
110%
17%
64%
43%
44%
83%
72%
48%
49%
56%
62%
75%
49%
30%
31%
56%
19%
60%
36%
43%
44%
67%
27%
48%
43%
51%
78%
80%
53%
62%
26%
In practical terms the utilisation of substations is a function of customer demand,
standard transformer size and provision for future load over the long life of the
substation.
7.3.2 Drivers of future demand
Key drivers of demand growth (and contraction) are likely to include the issues
depicted in Figure 41.
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Demographics & lifestyle
Convenience of
electricity compared
to other fuels
Increasing
energy use
per customer
Migration into
urban areas
Climatic effects
Increasing
rural
irrigation
Increasing
ambient
temp.
Climate
change
initiatives
Economic activity
Economic
up-turns
Ascending
commodity
cycles
Industry &
technology
trends
Local growth
initiatives
Distributed
generation
Low NZ$
New industrial
plants
All these factors increase
demand
Localised
demand
growth
Aggregate
demand
growth
All these factors decrease
demand
Conservation
Demographics & lifestyle
Declining
overall local
population
Declining
affordability
Increasing
conservation
Economic decline
End of useful
life of major
industrial plant
Economic
down-turn
High NZ$
Increasing
energy
efficiency
Descending
commodity
cycle
Plant closure
for other
reasons
Figure 41 - Drivers of demand
At the residential and light commercial feeder level, three or four of these issues may
predominate, be predictable and manageable on a statistical basis however experience
is that large consumers give little if any warning of increases or decreases in demand.
The residential and light commercial demand projections can be aggregated into a
potentially more predictable zone substation demand forecast but previous growth is
not always indicative of the future. Industrial demand will always remain more
unpredictable. OtagoNet‘s estimates of future demand are described in section 7.3.4
below.
Historically, OtagoNet has experienced an average annual demand growth of about
1.6% for the last 10 years. Whilst the company expects this long-run average rate of
growth to decline and to influence the revenue aspects of OtagoNet‘s business (as
discussed in the background section of this plan), it must be acknowledged that actual
demand growth at localised levels (which will influence costs) can vary anywhere from
negative to highly positive. The following sections examine in detail the predicted
significant drivers of OtagoNet‘s network configuration over the next 5 to 10 years.
7.3.2.1 Connection of Distributed Generation
In December 2010 OtagoNet connected Pioneer Generation‘s 7.65MW wind farm at
Mount Stuart with a 33kV connection into the Glenore to Lawrence line.
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Wind generation up to 2MW can be connected to some 11kV feeders. Generation
greater than 2MW, or if a number of small generators are installed in an area, will
require the generation to be connected to the subtransmission network.
There have previously been enquiries about other hydro generation in the OtagoNet
area, but to date there have been no formal applications received.
Distributed Generation (DG) of under 10kW is occurring at a slow rate on the network,
and is normally connected on existing LV installations. The connection of distributed
generation has the potential to increase voltage above regulatory levels.32
Any larger wind farms will need to connect to the Transpower Transmission network at
110kV or 220kV.
No changes are included in the OtagoNet network peak demand forecasts based on
currently known generation schemes.
7.3.2.2 Milling of local forests
This could involve expansion of existing mills (Figure 39 Quadrant 2), or could involve
new mills (Figure 39 Quadrant 2 or 4 depending on location). Key drivers of
investment will include global timber prices, the eventual outcome of the Kyoto
Protocol, the strength of the NZ dollar and any decisions to process locally as opposed
to export.
A new mill was connected at Milburn in FY2012, with negligible impact on peak
demand.
7.3.2.3 Irrigation
Dry areas in north Otago and the Maniototo have an increasing demand for irrigation
driven from an increasing trend in dairying land conversion in these areas as discussed
in the background section of this plan. Generally other areas in South Otago have a
more constant rainfall with little or no irrigation required although dairying has
necessitated some irrigation in the Clydevale area.
An allowance for up to 4% annual demand increase has been made on the relevant
substations in the Maniototo.
7.3.2.4 Dairy conversions
While there was an early uptake in dairy conversions in South Otago this appears to be
levelling off. However, there is still a larger land area that could be converted or used
with irrigation for feed supply, particularly in Central Otago. We are now seeing more
irrigation on existing dairy farms in south Otago (particularly around Clydevale) and
new loads in the Maniototo.
7.3.2.5 Mining closure
The gold mine at Macraes underwent a step change in load in 2007, with their
underground mining operations. However, recent announcements have suggested the
mine is due for closure in circa 2017 but this is yet to be confirmed to OtagoNet.
There are other gold prospects in the Otago area, but to date there have been no
serious enquiries for new loads.
32
It is important that distributed generation is connected the network via equipment which meets network
standards. The situation is compounded if several generators are in close proximity. It is salient electricity
networks are designed with voltage regulation on the high voltage side of transformers to compensate for
increased load. Distributed generation has the potential to elevate voltage to unacceptable levels at times
of low load.
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Coal mining continues in Kaitangata and although there are other coal fields no load
increases are expected in the planning period.
7.3.3 Load forecast trend
Analysis of historic demand and energy usage over the last 10 years to 31 March 2013
shows a 10 year average demand growth of 1.6%. Figure 42 shows the data since
1949 and the drop in demand in circa 1996 when computerised load control was
introduced. The chart also shows the significant effect of the Macraes Flat gold mine
load which is the single largest load on the network and which may close circa 2017
according to recent statements but such has not been confirmed to OtagoNet.
OJV Historic Energy and Maximum Demand
(showing with and without Macraes Gold Mine Load)
90
450
Base MW (excl. Macraes)
Total MW
80
400
Base GWh (excl. Macraes)
Energy - (GWh)
2012
2010
2008
2006
2004
2002
2000
1998
1996
1994
1992
1990
1988
1986
1984
1982
1980
0
1978
0
1976
50
1974
10
1972
100
1970
20
1968
150
1966
30
1964
200
1962
40
1960
250
1958
50
1956
300
1954
60
1952
350
1950
Maximum Demand - (MW)
Total GWh
70
Figure 42 – Historic energy and maximum demand
7.3.4 Estimated zone substation demands
As outlined in detail in the remainder of section 7, OtagoNet‘s demand is expected to
increase from that described in section 7.3.1 as follows:
Standard natural growth of 1.0%, with some decline of small rural communities.
On-going dairy conversions and associated new irrigation load growth particularly
in central Otago with an estimated growth rate of 2%.
Long term growth rates are uncertain so budgets beyond 5 years carry a high
margin of error
Experience strongly indicates that it would be rare to ever see more than a few months
confirmation, sufficient to justify significant investment, of definite changes in an
existing or a new major consumer‘s demand. This is because most of these
consumers operate in fast-moving consumer markets and often make capital
investment decisions quickly themselves and they generally keep such decisions
confidential until the latest possible moment. Probably the best that OtagoNet can do
is to identify in advance where OtagoNet‘s network has sufficient surplus capacity to
supply a large chunk of load but, as experience shows, industrial siting decisions
rarely, if ever, consider the location of energy supply – they tend to be driven more by
land-use options, raw material supply and transport infrastructure.
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Table 31 identifies the rate of growth projected to zone substation level for a 10 year
horizon, along with the provision expected to be made for future growth.
Table 31 Substation demand growth rates
Design
Capacity
2013
Maximum
Demand
2013
MVA
Annual
Growth
Rate
%
Projected
Demand
2023
MVA
Charlotte Street
Clarks Junction
Clinton
Clydevale
Deepdell
10.0
0.5
2.5
2.5
0.8
6.1
0.4
2.0
2.7
0.1
0.0%
0.0%
1.5%
5.0%
0.0%
6.1
0.4
2.3
4.1
0.1
Elderlee Street
10.0
6.4
0.0%
6.4
Finegand
Glenore
2.5
1.5
1.1
0.7
0.0%
1.0%
1.1
0.7
Golden Point
5.0
4.2
0.0%
4.2
Greenfield
Hindon
Hyde
Kaitangata
Lawrence
Macraes Mine
2.3
0.5
2.5
2.5
2.5
30.0
1.7
0.2
1.2
1.4
1.5
22.4
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
1.7
0.2
1.2
1.4
1.5
22.4
Merton
5.0
2.4
0.0%
2.4
Middlemarch
Milburn
North Balclutha
Oturehua
Owaka
Paerau
Paerau Hydro
Palmerston
Patearoa
Port Molyneux
Pukeawa
Ranfurly
Ranfurly 66/33 kV
Stirling
Waihola
Waipiata
Waitati
Wedderburn
2.5
7.5
5.0
0.8
2.5
0.8
30.0
5.0
2.5
2.5
0.8
5.0
50.0
5.0
1.5
2.5
2.5
0.8
0.7
2.4
2.8
0.2
1.5
0.3
12.8
2.2
1.7
0.7
0.4
2.2
25.3
3.9
1.2
1.3
1.5
0.2
0.0%
0.0%
0.0%
0.0%
0.5%
0.0%
0.0%
1.0%
5.0%
0.0%
5.0%
1.0%
0.0%
0.0%
1.0%
5.0%
1.0%
0.0%
0.7
2.4
2.8
0.2
1.6
0.3
12.8
2.4
2.5
0.7
0.6
2.4
25.3
3.9
1.3
2.0
1.7
0.2
Zone
Substation
Provision for Growth
Over N-1 but load transfer available
Approaching capacity, need to monitor
Increase capacity for 2014
Load transfered to Milburn,
replacement planned
Load transferred to Macraes end of
2013
Near N-1 capacity, replacement
planned
Near N-1 capacity, replocation planned
Monitor and plan to ncrease capacity
Monitor growth
Discussions with Fonterra re security
Monitor and plan to ncrease capacity
The red highlighted values indicate when the initial trigger point for capacity is
exceeded based on the present equipment, configuration and security requirement.
7.3.4.1 Demand model assumptions
The impact of Distributed Generation (DG) has been ignored due to the estimated low
connection rate of DG and the probability that only a small percentage of the capacity
will be available during peaks.
Increased monitoring of heavily load sites if data indicates capacity will be exceeded.
Annual revision of this data will highlight sites that vary from the above model and the
planned works adapted for each situation, with some upgrades delayed or brought
forward, due to uncertainty of load changes within the network. This occurs when
customers add additional plant and equipment without applying to OtagoNet.
Depending upon the circumstances OtagoNet can use various methods to maintain
supply until equipment is upgraded, should unexpected growth occur:
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Load Management.
Mobile generator(s).
Load transfers to neighbouring substations.
Utilisation of voltage boosters.
Temporary substations.
Overall significant new loads will be dependent on new equipment being installed or
built.
Load Management is used when substation equipment is nearing overload, and during
load transfers for maintenance, and hasn‘t been considered in the projected demands
above. Load control can also be undertaken at a Retailer‘s request or during Dry-year
rationing.
7.3.5 Estimated demand aggregated to GXP level
Table 32 shows the aggregated effect of substation demand growth for a 10 year
horizon at the three GXP‘s, Paerau scheme and Falls Dam.
Table 32 GXP demand growth
2013 MD
(MW)
27.2
Growth
(%)
0.75%
2024 MD
(MW)
29.8
Provision for Growth
No further work required
9.0
0.00%
8.5
None after GPT shutdown
24.9
1.50%
31.7
Paerau
12.4
0.00%
12.4
Falls Dam
1.3
0.00%
1.3
Mt Stuart
7.5
0.00%
7.5
No further work required
No generation increase
expected
No generation increase
expected
No generation increase
expected
GXP
Balclutha GXP
Palmerston
GXP
Naseby GXP
7.3.6 Issues arising from estimated demand
The significant issues arising from the estimated demand in section 7.3.4 and 7.3.5
are:
7.4
The short term capacity of Clydevale is already exceeded and a number of dairy
conversions and irrigators are expected for the 2014/2015 season.
At Patearoa, the known dairying and irrigation load increases for the 2014/2015
season will necessitate increases in substation capacity.
Elderlee Street and Charlotte Street‘s capacity is above their required N-1 capacity,
but some load transfer to other substations is possible.
OtagoNet network constraints
OtagoNet‘s network includes the following constraints:
Constraint
Description
Intended remedy
Milton 33kV
The loads of Lawrence, Glenore,
Elderlee Street and Waihola
exceed single 33kV line capability
Rebuild of the western 33kV line to
Milton is in progress with larger
conductor and automatic switching
to be improved
Patearoa
2.5MVA capacity will be reached
by 2015-16.
Establish a new zone substation in
the west of Patearoa with temporary
11 kV reinforcement in 2014
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Constraint
Description
Intended remedy
Patearoa
11 kV line capacity and low
voltage to the west of Patearoa
Establish a new zone substation in
the west of Patearoa, 11 kV line
upgrades and regulators
Clydevale
2.5MVA capacity has been
reached
Add a second larger transformer into
spare transformer bay
Clydevale
11 kV line voltage low at
Popotunoa and Wharetoa
Upgrade line sections and install
regulators
Clinton
2.5MVA capacity may be reached
by 2018 with increased dairying or
irrigation.
Consider further tie line upgrades
and load transfers towards the
increased capacity at Clydevale
Owaka
Unreliable 11 kV switchgear and
safety clearance issues
Outdoor to Indoor conversion with
modular switch room
Port Molyneux
Unreliable 11 kV switchgear in
harsh seaside environment
Outdoor to Indoor conversion with
modular switch room
Waitati &
Waikouaiti
Single long 33 kV line with
maintenance and reliability issues
Take 33 kV supply from Halfway
Bush and provide alternate 33 kV
feed at Waitati
Environmental –
Oil
Expectation of no significant oil
spills from any substation
Install oil bunding and separation
systems at remaining substations
Quality of Supply
- Voltage
In some growth areas the LV lines
are inadequate to supply the new
loads
Upgrade LV lines in towns as
required and consider the size and
location of transformers
Options including non-asset, considered and found to be uneconomic or unsupported:
7.5
Distributed generation into the 33kV from Mount Stuart wind farm is not constant
enough to remove the need of the upgrade of the western Milton 33kV line.
Load control of irrigation at Patearoa is unlikely to receive support.
Change to ‗green‘ oil is higher cost than oil interception systems.
Upgrade to covered ‗spacer cable‘ for vegetation problem locations found to be
expensive in a trial at Shag Point.
Policies for distributed generation
The value of distributed generation is clearly recognised in the following ways:
Reduction of peak demand at Transpower GXP‘s.
Reducing the effect of existing network constraints.
Avoiding investment in additional network capacity.
Making a very minor contribution to supply security where the consumers are
prepared to accept that local generation is not as secure as network investment.
Making better use of local primary energy resources thereby avoiding line losses.
Avoiding the environmental impacts associated with large scale power generation.
It is also recognised that distributed generation can have the following undesirable
effects:
Increased fault levels, requiring protection and switchgear upgrades.
Increased line losses if surplus energy is exported through a network constraint.
Stranding of assets or, at least, of part of an asset‘s capacity.
Increase in voltage variation on lightly loaded lines from LV connected generation.
The development of distributed generation is actively encouraged subject to
compatibility with the network and ensuring the generation does not impact adversely
on those receiving supply.
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The key requirements for those wishing to connect distributed generation to the
network broadly fall under the following headings, with a guideline and application
forms available on the OtagoNet web site under Customer Information – Distributed
Generation; see http://www.otagonet.co.nz/index.php?pageLoad=116&par=251
7.5.1 Connection terms and conditions (commercial)
Connection of up to 10kW of distributed generation to an existing connection to the
network will not incur any additional line charges. Connection of distributed
generation greater than 10kW to an existing connection may incur additional costs
to reflect network up-sizing.
Distributed generation that requires a new connection to the network will be
charged a standard connection fee as if it was a standard off-take consumer.
An application fee will be payable by the connecting party.
Installation of suitable metering (refer to technical standards below) shall be at the
expense of the distributed generator and its associated energy retailer.
Any benefits of distributed generation that arise from reducing OtagoNet‘s costs,
such as transmission costs or deferred investment in the network, and, provided
the distributed generation is of sufficient size to provide real benefits, will be
recognised and shared.
Those wishing to connect distributed generation must have a contractual
arrangement with a suitable party in place to consume all injected energy –
generators will not be allowed to ―lose‖ the energy in the network.
7.5.2 Safety standards
A party connecting distributed generation must comply with any and all safety
requirements promulgated by OtagoNet.
OtagoNet reserves the right to physically disconnect any distributed generation that
does not comply with such requirements.
7.5.3 Technical standards
7.6
Metering capable of recording both imported and exported energy must be
installed if the owner of the distributed generation wishes to share in any benefits
accruing to OtagoNet. Such metering may need to be half-hourly.
OtagoNet may require a distributed generator of greater than 10kW to demonstrate
that operation of the distributed generation will not interfere with operational
aspects of the network, particularly such aspects as protection and control.
All connection assets must be designed and constructed to technical standards not
dissimilar to OtagoNet‘s own prevailing standards.
Use of non-asset solutions
As discussed in section 7.2.1 the company routinely considers a range of non-asset
solutions and indeed OtagoNet‘s preference is for solutions that avoid or defer new
investment.
Effectiveness of tariff incentives is lessened with Retailers repackaging line charges
that sometimes removes the desired incentive. ‗Use of System‘ agreements include
lower tariffs for controlled, night-rate and other special channels.
Load control is utilised to control:
The load on individual GXP‘s when they exceed the capacity of that GXP.
The load on feeders during outage situations.
As noted in section 7.3.1, it has become infeasible to manage Transpower demand
charges as the LSI peak is determined by the Tiwai load and has consequently
become uncoupled from the OtagoNet peak demand times.
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If an Engineer considers that adoption of non-asset options may be sufficient to
overcome a constraint, a business case would be prepared to get approval from the
Network Manager (OtagoNet) or Governing Committee, to proceed.
The approval would be given if the likelihood of success is acceptable and the cost /
benefit ratio is positive.
Suggestions of non-asset options can come from other staff and external parties with
these allocated to an Engineer to investigate.
7.7
Network development options
7.7.1 Identifying options
When faced with increased demand, reliability, security or safety requirements,
OtagoNet considers the broad range of options described in Section 7.2.1. The range
of options for each issue varies due to:
Stakeholder interests
Section 1.7 lists stakeholder interests and the engineer considers these areas in
planning and ranking an option.
Size of the project
Different issues have differing resource requirements, and so the level of analysis
and the breadth of options vary. A simple issue like connecting a new customer
next to an existing low voltage pillar box would only have a single option analysed,
whereas a new industrial plant would have multiple options considered.
Creativity and knowledge of the Engineer
Breadth of options is also dependent on the Engineer undertaking the planning.
Options are developed by the Engineer and critiqued by the Chief Engineer and/or
Network Manager (Otago). Network standards are utilised but innovation is
supported where alternative optimum solutions result.
Resource
The other higher priority projects may limit the resources available for each option.
This could be a limitation of finances (uneconomic), workforce (to plan, design,
manage, build or operate), materials (unavailability or long lead-time of equipment.)
or legal (need Resource Consent or Easements.)
Standardisation
Standards that apply to the network are given in the PowerNet Network Design
standard.
Some of the standardisation is listed below:
Component
Standard
Justification
Conductor
All Aluminium Alloy Conductor
(AAAC): Chlorine, Helium,
Iodine, Neon, Oxygen.
Low corrosion and improved
impedance
Conductor
Aluminium Conductor Steel
Reinforced (ACSR): Magpie,
Squirrel, Flounder, Snipe.
Higher strength for long spans
or snow loading
Low Voltage
Aerial Bundled Cable (ABC): 35,
50 & 95mm² Al / two & four core.
Safety, visual impact, lower cost.
Cable
Cross-linked Polyethylene
(XLPE)
Rating, ease of use.
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Component
Standard
Justification
Suppliers
Normally one or two suppliers
for each component
Reduce spare requirements.
Improved contractor familiarity.
Poles
Concrete
Long life, good strength
Crossarms
Solid hardwood or steel
Long life, good strength
Distribution
Transformers
Standardised sizes, e.g.
minimum size 15kVA except for
specific applications
Reduce spare requirements.
Improved contractor familiarity.
Note: Where particular conditions apply such as access or strength, hardwood poles
and steel crossarms are used.
Standardised design is used for line construction using Network Standards.
7.7.2 Identifying the best option
Once the best broad option has been identified using the principles embodied in Figure
40, OtagoNet will use a range of analytical approaches to determine which option best
meets OtagoNet‘s investment criteria. As set out in Section 7.2.3, OtagoNet uses
increasingly detailed and comprehensive analytical methods for evaluating the more
expensive projects.
Simple Spreadsheet: Cost calculation with standardised economic benefit values.
Risk analysis: More comprehensive and complexity for larger projects.
Net Present Value (NPV) model: Time series model of future costs and benefits.
Payback calculation: Financial calculation of the time estimated to recover cost of
undertaking that option.
Customer consultation: If solution impacts on a customer and changes the service
level provided, the customer must be consulted to obtain their support. i.e.
disconnecting remote customers by replacing connection with a RAPS33.
7.7.3 Implementing the best option
Having determined that a fixed asset (CAPEX) solution best meets OtagoNet‘s
requirements and that OtagoNet‘s investment criteria will be met (and if they won‘t be
met, ensuring that a consumer contribution or some other form of subsidy will be
forthcoming), a project will proceed through the following broad steps:
Perform detail costing and re-run cost-benefit analysis if detail costs exceed those
used for investment analysis.
Address resource consent, land owner and any Transpower issues.
Perform detail design and prepare drawings, construction specifications and if
necessary tender documents.
Tender out or Assign construction.
Close out and de-brief project after construction.
Ensure that contractors pass all necessary information back to OtagoNet including
as-builts and commissioning records.
Ensure that learning experiences are examined, captured and embedded into
PowerNet‘s culture.
33
RAPS = Remote Area Power System: A stand-alone energy network of alternative energy sources
(Solar, Photovoltaic, Wind turbine, Micro-hydro, LPG, Diesel, etc…) so that a connection to the electricity
network is not required.
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7.8
Development programme
The following table sets out the network development programme for the next 5 years.
Individual projects are then discussed separately.
Network Development Capex
Projects
Year 1
2014-15
Milton - Elderlee Street Substation Replacement
Milton 33 kV ring protection upgrade
Waitati substation relocation
Waikouaiti (Merton) substation relocation
Glenore substation relocation
Clydevale transformer upgrade and indoor
switchgear
Clydevale 33 kV Ring protection
Palmerston GXP purchase & conversion to 33 kV
Palmerston 33 kV sub and feeder to ex TPNZ
substation
Palmerston area ripple injection plant replacement
11 KV Reclosers and SCADA for automation
New Puketoi substation, prob. off 66 kV line in
Wilson Road
Patearoa - Paerau - Puketoi 11 kV line upgrade;
regulators first
Substation Land Purchase and Safety
Improvement
Subtotal projects
New Connections (on-going)
Ongoing & new substation work
33 kV Line Upgrades
11 kV Line Upgrades
Clydevale - Popotunoa line upgrade + regulator
Clydevale - Hall Road line upgrade
Clydevale - Hall Road to Camp Hill Road Tie line Yr 1
Subtotal 11 kV line upgrades
LV Voltage Quality (on-going)
Easements (on-going)
Total Network Development Capex
Year 3
2016-17
Year 4
2017-18
$100k
$50k
$100k
$0k
$360k
$750k
Year 2
201516
$1,900k
$200k
$700k
$50k
$40k
$250k
$0k
$0k
$0k
$1,000k
$0k
$0k
Year 5
201819
$0k
$0k
$0k
$800k
$0k
$0k
$600k
$0k
$500k
$100k
$0k
$0k
$50k
$300k
$0k
$200k
$150k
$50k
$0k
$200k
$0k
$2,600k
$250k
$1,300k
$1,950k
$400k
$1,000k
$0k
$140k
$550k
$0k
$350k
$300k
$0k
$50k
$0k
$250k
$990k
$900k
$0k
$200k
$0k
$100k
$200k
$50k
$400k
$200k
$300k
$0k
$200k
$1,000k
$500k
$1,000k
$1,350k
$100k
$0k
$0k
$0k
$0k
$100k
$300k
$0k
$0k
$0k
$0k
$300k
$3,740k
$1,000k
$0k
$2,240k
$1,000k
$0k
$2,550k
$1,000k
$600k
$2,050k
$1,000k
$1,200k
$800k
$120k
$9k
$0k
$120k
$9k
$0k
$120k
$9k
$0k
$120k
$9k
$0k
$120k
$9k
$4,239k
$4,869k
$3,369k
$4,279k
$4,379k
$2,310k
$1,000k
$0k
Life
Cost
$500k
$200k
$100k
7.8.1.1 Milton (Elderlee Street) Substation
7.8.1.1.1 Description
This substation feeding Milton is approaching its N-1 capacity and is not in an ideal
situation being in a residential area with potential noise issues and limited room for
expansion or renewal. The future growth in Milburn will also require additional
switchgear and lines from this substation. Rather than trying to develop the existing
substation in the domestic area of town and crossing the railway corridor with multiple
33kV lines a new site on the industrial land on the other side of the railway has been
proposed. The project is to secure that land and then develop final plans for 33kV
switchgear, 11kV indoor switchgear and dual transformers. Consideration will be given
to refurbishing and reusing the existing 5MVA transformers while there is sufficient
transfer capacity to Millburn and Glenore substations.
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7.8.1.1.2 Issues
The present substation is reaching the N-1 capacity of the 5MVA transformers and the
400 Amp limit of the 11kV switchboard.
The substation is bounded by residential houses and the transformers on the boundary
have potential noise issues.
The existing substation building is too small for new switchgear and has been identified
as below current building seismic strength requirements.
The existing 33kV lines cross industrial land and the railway and future 33kV line
easements for the Milburn ring extension will be difficult to obtain.
7.8.1.1.3 Options
Redevelop on a new site away from the residential area.
Redevelop on the existing site with a new substation and indoor sound proofed
transformers
Partially offload Elderlee Street substation to Milburn and Glenore to defer
overloading.
Replace the transformers only with 7.5MVA units and add bus protection.
No non-asset solutions are available.
7.8.1.1.4 Option selection
Replacement on a new site is the best strategic solution with the lowest risk.
7.8.1.1.5 Cost and type
$2.6m for the whole project; Asset Replacement and Growth
7.8.1.1.6 Goal / Strategy
Allow for load growth and load transfer. Minimise the environmental impact. Complete
the project by 2017.
7.8.1.2 Milton 33 kV Ring Protection Upgrade
7.8.1.2.1 Description
The 33kV ring feed switching design from Balclutha through Glenore and Kiness only
provides N-1 reliability to Elderlee Street but not to other substations t‘ed off it and is an
early basic system that can be improved to provide N-1 reliability to the Glenore
substation on the ring and the downstream substations of Lawrence, Milburn, Waihola
and the Mt Stuart wind farm. The project will involve additional 33kV circuit breakers at
Glenore and communication and signalling between the replacement protection
systems around the ring.
7.8.1.2.2 Issues
The present ring protection only provides an N-1 protection for Elderlee Street substation
and that is compromised by a remote circuit breaker at Kiness.
The present protection only uses directional protection relays and there have been some
spurious openings of the ring in association with other faults. A replacement system will
have greater selectivity using end to end communications.
The load and importance in the adjacent substations has grown and now includes the
7.65MW wind farm connection and the new Milburn substation which will benefit from an
enhanced protection scheme.
7.8.1.2.3 Options
Wait and install distance relays only at the new Elderlee Street replacement
substation.
Do nothing and accept nuisance tripping‘s that reduce reliability and result in
voltage disturbances if not actual loss of supply.
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No non-asset solutions available.
7.8.1.2.4 Option selection
The enhanced protection system will yield the full reliability potential from the line
assets employed which alternative options will not.
7.8.1.2.5 Cost and type
$250k for the whole project; Asset Replacement and Renewal, Reliability Improvement
7.8.1.2.6 Goal / Strategy
Improve reliability to 33 kV line faults. Complete the project by 2016.
7.8.1.3 Waitati Zone Sub Relocation
7.8.1.3.1 Description
The Waitati substation is in a flood prone location within a residential area. The
condition of the transformer and switchgear is poor and both have reached end of life
7.8.1.3.2 Issues
Reliability for customers off the Waitati substation is the poorest on the network.
The existing substation is flood prone and is located within a residential area.
The supply security is below the EEA guidelines as there is insufficient 11kV backfeeds available for loss of the single 33kV supply.
Reconfiguration of the Palmerston GXP supply allows for redundant 33kV line circuits
to be provided into Waitati.
7.8.1.3.3 Options
Do nothing and continue with poor reliability due to 33kV line faults
Redevelop on the existing site to allow for the dual 33kV circuits.
Redevelop on a new site.
7.8.1.3.4 Option selection
Redeveloping on a new site is the best strategic solution with the lowest future risk.
7.8.1.3.5 Cost and type
$1.3m; Asset Renewal; Reliability Improvement
7.8.1.3.6 Goal / Strategy
Improve reliability to 33kV line faults in the Waitati area. Complete the project by 2016.
7.8.1.4 Merton Substation (Waikouaiti)
7.8.1.4.1 Description
This substation feeding the Waikouaiti area is approaching its N-1 capacity and the
outdoor structure and transformers are both in poor condition. A better location than
beside a flood prone river and the State Highway 1 is also desirable.
A further opportunity exists with purchase of the Transpower 110kV lines that run past
this substation, allowing for improved security and reduced losses with more direct
supply than the existing configuration.
7.8.1.4.2 Issues
The present substation is reaching the N-1 capacity of the 5MVA transformers and the
11kV and 33kV structures have deteriorating wooden poles and components.
The supply security is below the EEA guidelines as there is insufficient 11kV backfeeds available for loss of the single 33kV supply.
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The substation is low lying alongside the Waikouaiti River and is prone to flooding and
is at risk from tsunami or liquefaction following a seismic event.
The substation is beside SH1 to the north of Waikouaiti, its major load centre, meaning
there is only one line route to the main loads.
Inefficiency and lower reliability of the existing single circuit 33kV arrangement.
7.8.1.4.3 Options
Redevelop on the existing site with a new transformers and indoor switchgear,
raised above possible flood levels.
Build a second substation on the south side of Waikouaiti to provide greater
reliability and less dependence on this substation.
Redevelop the substation on a more secure site closer to the load
No non-asset solutions available.
7.8.1.4.4 Option selection
Redeveloping on a new site is the best strategic solution with the lowest future risk.
7.8.1.4.5 Cost and type
$1.95m; Asset Replacement and Renewal; Reliability Improvement.
7.8.1.4.6 Goal / Strategy
Allow for load growth and greater security. Maximise the opportunity from the
Transpower purchase of the 110kV lines. Minimise the environmental impact.
Complete the project by 2017.
7.8.1.5 Glenore Transformer, Oil Containment and Overhead Structure
7.8.1.5.1 Description
Install the new replacement 2.5MVA transformer into a new site to allow on-going load
growth in the area, load transfers to Milton, Kaitangata and Lawrence and to remove
the risk of oil spills into the nearby waterway.
Replace the overhead 11kV structure with indoor circuit breaker and cable to the lines.
Make provision for additional circuit breakers on the 33kV ring around Balclutha and
Milton [this integrates with the Milton ring protection project].
7.8.1.5.2 Issues
Ageing transformer and associated overhead switching structure.
Capacity of the existing transformer and increasing loads in the area as well as
increasing loads in the adjacent substations that can be shared by Glenore.
Performance of the 33 kV Milton ring with the introduction of the wind farm.
Proximity of the substation transformer to a waterway with consequent risk of an oil
spill.
7.8.1.5.3 Options
Replace the transformer with 1.5MVA only and replace it early in the transformer‘s life
and during the 10 planning period. Cost differential between units small, so not
supported.
Upgrade the interconnecting 11kV lines from Lawrence, Milton and Kaitangata and
provide additional voltage regulation. Implementation costs similar but lower benefits
with higher losses and worst reliability.
Rebuild the overhead structure and replace the outdoor circuit breakers on the same
site. Cost likely to be higher than standardised indoor solution, with no increased safety
or environmental benefits.
Rebuild on a new site (which has been identified) away from the river.
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No non-asset solutions.
7.8.1.5.4 Option selection
Rebuild on new site.
7.8.1.5.5 Cost and type
$400k (Transformer already purchased), Asset Replacement and Renewal; Growth.
7.8.1.5.6 Goal / Strategy
Allow for load growth and load transfer. Minimise the risk of oil contamination of the
environment. Complete the project by year end 2014.
7.8.1.6 Clydevale transformer upgrade
7.8.1.6.1 Description
Increasing loads from new irrigation are now pushing the load capacity of the existing
single transformer. In addition there are concerns with the condition and reliability of
the old KF outdoor circuit breakers. The project is to install a new 5 MVA transformer
and place new indoor 11 kV switchgear. The existing 2.5 MVA transformer will be left
on site as a warm spare.
7.8.1.6.2 Issues
The supply security is below the EEA guidelines as there is insufficient 11 kV backfeeds available for loss of the single 33 kV supply.
The load is approaching the capacity of the existing transformer and there is limited
load transfer ability away from the substation.
The existing KF outdoor 11 kV circuit breakers are old and in poor condition.
7.8.1.6.3 Options
Replace the transformer but keep the existing switchgear.
Place dual transformers to meet the security criteria.
No non-asset solutions.
7.8.1.6.4 Option selection
A replacement transformer is required for load growth. Replacing the old 11 kV CBs at
the same time as the transformer replacement is the lowest cost option in the long
term.
7.8.1.6.5 Cost and type
$1.0 m; Growth and Asset Renewal.
7.8.1.6.6 Goal / Strategy
Cater for future load growth in the region. Complete the project by 2016.
7.8.1.7 Clydevale Ring
7.8.1.7.1 Description
Upgrade the switching configuration and ring protection around the Clydevale and
Greenfield dairy factory to make the network more robust to single 33 kV line faults.
7.8.1.7.2 Issues
The load and customer numbers in this area are increasing with highlighted importance
on a reliable supply to the individual dairy farms and the Gardians diary factory.
There two 33 kV lines to Clydevale from Balclutha passing through Greers and Clifton
with tee offs to supply the Greenfield and Pukeawa substations. The second line is in
poor condition, is not reliable as a backup and only has basic manual switching
involving hours of driving to achieve restoration after a fault on one line.
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7.8.1.7.3 Options
•
Replace manual switches at Clifton, Greers, Clydevale and Greenfield with SCADA
operated circuit breakers for timely restoration, one line at a time.
•
Extend the circuit breaks with additional directional protection and run the ring
closed for resilience to the first fault.
•
Do nothing and accept worsening SAIDI and SAIFI figures and increasingly
unhappy customers
•
No non-asset solutions available.
7.8.1.7.4 Option selection
Upgrading the ring protection yields the most reliability from the existing 33 kV network
in the area. Network performance will be increased with better SAIDI and SAIFI
results. The closed ring will reduce losses and improve quality of supply to all
customers in the area.
7.8.1.7.5 Cost and type
$250 k; Asset replacement; Reliability Improvement.
7.8.1.7.6 Goal / Strategy
Complete by 2016.
7.8.1.8 Transpower Palmerston – 33 kV conversion
7.8.1.8.1 Description
The Transpower Palmerston Point of Supply has only N capacity due to the single
transformer although there are two 110 kV lines from Halfway Bush. The current
Transpower charging makes this substation the most expensive per ICP and the least
reliable on the Otago network.
An opportunity arose to purchase the Transpower assets at a fair price to enable
OtagoNet to further develop or modify the supply to increase reliability and efficiency,
both of this point of supply and the downstream 33 kV network and zone substations by
shifting the point of supply to Halfway Bush and converting the 110kV lines to 33 kV
then providing second 33 kV circuits into the zone substations along the line route at
Waitati and Waikouaiti.
The first stage is to convert one of the 110 kV lines to 33 kV and this work has already
commenced. The second stage is to convert the second line to 33 kV.
7.8.1.8.2 Issues
The present single transformer arrangement is below the standard of security required
and peak load is at 90% of the firm capacity. In 2012 there were two planned outages
of this point of supply that have required the establishment of major generation to keep
the power on to 3,000 customers during these 9-12 hour outages.
The high cost of the Palmerston GXP connection from Transpower reflected the asset
value of the 110 kV lines as this is a 110 kV spur substation.
The configuration of the existing 33 kV network back towards Dunedin that is less than
optimal with the lowest reliability being effectively at the end of the OtagoNet network,
yet is the closest point to the Halfway Bush point of supply.
The conversion to 33 kV must be undertaken in two stages as until Transpower
upgrade the Halfway Bush 33 kV bus capacity, scheduled for 2017, there is insufficient
firm capacity at 33 kV to supply both the Aurora and OtagoNet loads.
7.8.1.8.3 Options
The options post purchase of the Transpower assets that were considered
included: continue with the present set up, keep the 110 kV voltage and install a
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second 110/33 kV transformer, move the 110/33 kV substation to Waikouaiti, run
the lines at 33 kV from Halfway Bush.
Continue with the expensive and lower reliability from the present arrangement.
No non-asset solutions available.
7.8.1.8.4 Option selected
Convert the 110 kV lines to 33 kV in two stages.
7.8.1.8.5 Cost and type
$1.0m spread over 5 years; Reliability, Safety and Environmental.
7.8.1.8.6 Goal / Strategy
Allow greater reliability and security. Maximise the opportunity from the purchase of
the 110kV lines and substation. Reduce the cost of supply and maximise the efficiency
and reliability.
7.8.1.9 Palmerston Substation Feeder Alteration
7.8.1.9.1 Description
The Palmerston substation has dual transformers but only a single 33 kV circuit form
the GXP and will benefit from dual 33 kV lines to give it full N-1 reliability which can be
achieved in association with changes to the 110/33 kV Palmerston substation. The 11
kV feeders arrangements are also sub optimal and on an old and difficult to maintain
outdoor structure. This project is to shift the Palmerston zone substation to the recently
purchased GXP site with new 33 and 11 kV switchgear but utilising the existing 33/11
kV transformers.
7.8.1.9.2 Issues
Old outdoor structure using wooden cross arms and concrete poles is at the end of its
life and has minimal clearances to maintain and operate without adjacent feeder
shutdowns.
Structure and transformers are close to the existing contractor‘s depot building with
clearance safety issues.
The supply security is below the EEA guideline due to the single 33 kV incomer
(although it is a short length)
Substation controls and ripple injection plant are within the contractor‘s depot building.
7.8.1.9.3 Options
•
•
Relocate Palmerston zone substation to newly acquired Palmerston 110 kV
substation.
Keep the existing substation and route a second 33 kV incomer.
7.8.1.9.4 Option selected
Relocating the substation allows for increasing the supply security to meet the
guidelines as well as dealing with the condition and safety issues of the existing
substation.
7.8.1.9.5 Cost and type
$900k; Asset replacement and renewal; Security and Reliability.
7.8.1.9.6 Goal / Strategy
Complete the project by 2017 in conjunction with the Palmerston 33 kV supply
reconfiguration.
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7.8.1.10 Palmerston Area ripple Injection Plant
7.8.1.10.1
Description
Replace the aging 33 kV ripple injection plant, both transmitter and coupling cells at a
new location.
7.8.1.10.2
Issues
The plant is at the end of its service life with spares are no longer being supported and
reliability is compromised.
The value of load control to OtagoNet is doubtful given the change to the lower South
Island regional demand grouping as discussed earlier, however, the ripple receivers
are owned by the retailer and are required for day/night rate switching, limiting other
options.
Palmerston zone substation, structure and buildings are old and in poor condition.
The 33 kV reconfiguration means the ripple signal will be too attenuated towards the
Halfway Bush 33 kV bus and so the ripple plant injection point must be re-located.
7.8.1.10.3
7.8.1.10.4
Options
Consider if replacement is justified as the main benefactor is the Retailer with their
receivers being used more to control tariff options rather than the Network
controlling load.
Consider alternatives to ripple injection for load control in association with Smart
Meters. Consider daylight switches for the main network use to control street
lights.
Consider replacement in the newly acquired Palmerston 110 kV substation, along
with the Palmerston zone substation.
No non-asset solutions.
Option selected
The preferred option has not been identified. Provision of expenditure in 2017 is to
coincide with the substation relocation works.
7.8.1.10.5
Cost and type
$500k; Asset replacement and renewal; Consequential works with 33kV reconfiguration
projects.
7.8.1.10.6
Goal / Strategy
Complete the investigations and recommendation for the project by 31 March 2015
with installation and commissioning completed by 2017.
7.8.1.11 Puketoi + interim voltage regulators
7.8.1.11.1
Description
Load growth in the Maniototo from irrigation/dairy conversion places load that it is
inefficient to supply from Patearoa, Ranfurly or Waipiata zone substations. Confirmed
new load is to be supported off Patearoa using additional 11 kV voltage regulators but
if load continues to develop in this region a new zone substations at Puketoi supplied
off the 66 kV or 33 kV line between Ranfurly and Paerau Hydro appears the best
option.
7.8.1.11.2
Issues
Continuing load growth in the region from dairy conversion and new spray irrigation.
The location of the new load makes it inefficient to support at 11 kV from existing
substations.
Head-works costs may need to be supported by irrigation/farm owners.
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7.8.1.11.3
Options
•
Support the load from the existing substations (but the ability for this is limited)
•
Develop a new zone substations at or near Puketoi off the 66 of 33 kV lines.
•
No non-asset solutions.
7.8.1.11.4
Option selection
Place new voltage regulators to support the confirmed new load as an interim measure.
Make provision of a new substation at Puketoi.
7.8.1.11.5
Cost and type
$1.75 m; Growth.
7.8.1.11.6
Goal / Strategy
Install voltage regulators in 2014 and 2015 as interim measure. Provisional expenditure
set for FY2018 an FY2019 for new zone substations.
7.8.1.12 11 kV Reclosers and SCADA automation
7.8.1.12.1
Description
Reliability improvement may be economically provided by the installation of line
reclosers that automatically sectionalise lines under fault conditions thereby restoring
service to unaffected parts with only momentary interruption.
7.8.1.12.2
Issues
The 11 kV network is radial with few feeder interconnections and any faults on the
feeder interrupt all customers on the feeder until the fault is found and repaired.
The costs of reclosers is approximately $50k ea. which provides relatively cheap
reliability improvement.
OtagoNet needs to establish a dollar value range for its customers value of lost load to
properly establish the financial benefits of recloser installations.
7.8.1.12.3
Options
•
Do nothing and continue with the current reliability performance.
•
Install reclosers where they are economically viable.
•
No non-asset solutions available.
7.8.1.12.4
Option selection
Install reclosers where they are economically viable including SCADA modifications.
7.8.1.12.5
Cost and type
$2.5m over 5 years but dependent on business cases. Reliability Improvement.
7.8.1.12.6
Goal / Strategy
Identify economic locations during FY2015.
7.8.1.13 Land Purchases
Expenditure of $300k for purchase of land ahead of zone substation relocations or new
developments.
7.8.1.14 Subtransmission Line Upgrades
No subtransmission line upgrades are currently planned in the next 5 years.
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7.8.1.15 Distribution Line Upgrades
The following 11 kV line upgrades are planned:
•
Clydevale – Popotunoa line upgrade and voltage regulator due to load growth.
Cost $500k in FY2015.
•
Clydevale – Hall Rd. line upgrade due to load growth. Cost $200k in FY2015.
•
Clydevale – Hall Rd to Camp Hill Rd tie line to improve load transfer and reliability.
Cost $360k spread over FY2015 and FY2016.
7.8.1.16 Quality Remedies
Various works to remedy poor power quality usually identified from voltage complaint
investigations and where an appropriate solution is identified including.
Installation of 11kV regulators.
Up-sizing of components (conductor, transformer).
Demand side management.
Power factor improvements. (Ensuring consumer loads are operating effectively.)
Harmonic filtering / blocking. (Ensuring consumers are not injecting harmonics.)
Motor starter faults / settings remedied. (Ensuring consumer equipment is working
and configured appropriately.)
Cost of $120k p.a. on-going, System Growth.
7.8.1.17 New connections and easements
Allowance for new connections to the network. Each specific solution will depend on
location and consumer requirements.
Some subdivision developments are occurring but we receive little or no prior
notification of these. Request to Developers and Regional Authorities provided only
minimal information on subdivisions occurring. The budgeted cost of $1.0 m p.a. is
based on past experience and known development has been included in the plan.
A modest allowance has been made to connect Distributed Generation to the network.
A budgeted cost of $9k p.a. is made for new easements and is based on past
experience.
7.8.2 Considered projects
Expected projects for year six to ten (YE 31 March 2019 to 2025) are as follows.
These projects have little if any certainty.
Note that some projects that are on-going through-out this period are detailed above.
7.8.2.1 33kV Transformer Circuit Breakers
Three out of seven 5MVA transformers do not have 33kV circuit breakers for
transformer protection at present, and rely on 33kV fuses only. None of the 15 smaller
2.5MVA transformers have circuit breakers.
Single transformers may be damaged by slow fuse clearing times with little protection
for earth faults and dual transformer sites may be vulnerable to additional damage from
back feeding into a transformer fault.
This project looks to install 33kV circuit breakers to protect the larger transformers,
(5MVA) initially then the 2.5 MVA transformers.
$300k per year depending on individual solutions, Reliability.
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7.8.2.2 Network automation
Continue to install reclosers and sectionalisers, controlled through the SCADA system
to enhance the network reliability.
7.8.3 Contingent projects
There are no known contingent projects, however some customer related work may be
expected from our largest current customers, for example requests for increased
transformer or subtransmission line capacity. These have been excluded from
OtagoNet‘s spend plans until they been requested by the customer and have become
certain.
7.8.4 Network Development Capital Forecast
The estimated 10-year network development capital budget for OtagoNet is given
below in Table 33 – Network development (capex) budget (Years FY2015 to FY2024).
7.8.4.1 Assumptions
The budgeted amounts are based on our best estimates and may vary by ±20% due to
wage settlements, material costs movements or unforeseen site conditions.
Projects may be delayed or accelerated if new information is discovered or priorities
change. Most developers do not always give more than one year‘s notice of significant
load changes and resource may be diverted onto these projects to meet customer
expectations.
2015 to 2024 Network Development CAPEX Budget
Table 33 – Network development (capex) budget (Years FY2015 to FY2024)
Development
expenditure
Customer connections
System growth
Reliability, safety,
environment
Asset replacement &
renewal
Network development
capex total
7.9
2014-15
2015-16
2016-17
2017-18
2018-19
2019-20
2020-21
2021-22
2022-23
2023-24
$1,000k
$1,779k
$1,260k
$1,000k
$679k
$790k
$1,000k
$179k
$340k
$1,000k
$429k
$550k
$1,000k
$1,129k
$250k
$1,000k
$129k
$0k
$1,000k
$129k
$0k
$1,000k
$129k
$0k
$1,000k
$129k
$0k
$1,000k
$129k
$0k
$200k
$2,700k
$1,850k
$2,300k
$2,000k
$3,000k
$3,000k
$3,000k
$3,000k
$3,000k
$4,239k
$5,169k
$3,369k
$4,279k
$4,379k
$4,129k
$4,129k
$4,129k
$4,129k
$4,129k
Non-network development
OtagoNet receives IT and management services support through its management
services contract with PowerNet. Whilst it does not directly develop the GIS
(Intergraph) or AMS (Maximo) systems, it does in conjunction with PowerNet develop
interfaces and processes around these systems. In particular, it is currently developing
both inspection templates for condition assessment, the IT tools to efficiently implement
inspections in the field and automatically upload that data, and the processes for using
and updating that data. These systems and processes are considered critical to
progressing its asset management strategies and strengthening its risk management
and capital governance systems.
7.9.1.1 Mobile Generation
To manage the planned reliability impacts of the increase programme of line renewals
and to rectify the below average benchmarking of the company on its proportion of
planned SAIDI, expenditure on a trailer or truck mounted generator in the size range of
300kVA is planned. In addition, the purchase of a mobile 1000 kVA 0.4/11 stepAsset Management Plan
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up/earthing transformer is planned to be used in conjunction with leased generators for
large zone substation outages.
Cost $350k in FY2015; Reliability Improvement.
7.10 Development strategies that promote energy efficiency
Line losses are considered in the decisions to undertake load transfers within the
network and in the location of new assets and the sizing of the conductors that connect
them.
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ASSET LIFECYCLE
8.
Managing the assets’ lifecycle
All physical assets have a lifecycle. This section describes how OtagoNet manages
assets over their entire lifecycle from ―commissioning‖ to ―retirement‖.
8.1
Lifecycle of the assets
The lifecycle of OtagoNet‘s existing assets is outlined in Figure 43 below:
Start here with
existing asset base
Yes
Make
operational
adjustments
Are any
operational triggers
exceeded ??
No
Yes
Are any
maintenance triggers
exceeded ??
Perform
maintenance
No
Yes
Are any
renewal triggers
exceeded ??
Undertake
renewals
No
Yes
Are any
extension or augmentation
triggers exceeded ??
Add new
capacity
No
Yes
Retire
assets
Are any
retirement triggers
exceeded ??
No
Figure 43 - Asset lifecycle
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ASSET LIFECYCLE
Table 34 below provides some definitions for key lifecycle activities:
Table 34 – Definition of key lifecycle activities
Activity
Operations
Maintenance
Renewal
Up-sizing
Extensions
Retirement
8.2
Detailed definition
Involves altering the operating parameters of an asset such as
closing a switch or altering a voltage setting without any physical
change to the asset.
Involves replacing consumable components like the seals in a
pump, the oil in a transformer or the contacts in a circuit breaker.
There may be a significant asymmetry associated with
maintenance such as lubrication in that replacing a lubricant may
not significantly extend the life of an asset but not replacing a
lubricant could significantly shorten the assets life.
Generally involves replacing a non-consumable item like the
housing of a pump with a replacement item of identical
functionality (usually capacity). Such replacement is generally
regarded as a significant mile-stone in the life of the asset and
may significantly extend the life of the asset.
Renewal tends to dominate the Capital expenditure in low growth
networks like OtagoNet because assets will generally wear out
before the load exceeds their capacity.
Typical criteria for renewal occur when the capitalised costs of ongoing maintenance exceed the cost of renewal or the condition
deteriorates to where the risk of failure becomes significant and
the consequence of that failure is material. A key issue with
renewal is technological advances that generally make it
impossible to replace assets such as SCADA with equivalent
functionality.
Generally involves replacing a non-consumable and existing item
like a conductor, busbar or transformer with a similar item of
greater capacity.
Involves building a new asset where none previously existed
because a location or growth trigger e.g. building several spans
of line to connect a new factory to an existing line.
Notwithstanding any surplus capacity in upstream assets,
extensions will ultimately require the up-sizing of upstream assets.
Generally involves removing an asset from service and disposing
of it. Typical guidelines for retirement will be when an asset is no
longer required and cannot be re-located, creates an
unacceptable risk exposure or when its costs exceed its revenue.
Operating OtagoNet’s assets
Operations mainly involve switching by remote command or in the field to configure the
network to distribute line loadings, undertake maintenance on sections of the network
or configure back-feeds during the repair of a fault. As outlined in Figure 43 the first
efforts to relieve excursions beyond trigger points are operational activities with typical
activities listed in Table 35.
Table 35 Typical responses to operational triggers
Asset class
GXP
Asset Management Plan
Trigger event
Voltage is too high or
low on 33kV or 11kV.
Demand exceeds
allocated Transpower
limit.
Response to event
Approach
Automatic operation of tap
changer.
Activate ripple injection plant to
switch off load control relays.
Transfer loads between GXP‘s
to relieve load from highly
Proactive
Reactive
No facility
in network
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ASSET LIFECYCLE
Asset class
Trigger event
Response to event
Approach
loaded GXP.
Transition from day to
night.
On-set of off-peak tariff
periods.
Zone substation
transformers
Distribution reclosers
Distribution ABS‘s
Distribution
transformers
LV distribution
Voltage is too high or
low on 11kV.
Demand exceeds
rating.
Fault current exceeds
threshold of set level.
Component current
rating exceeded.
Fault has occurred.
Voltage is too high or
low on LV.
Fuses keep blowing.
Voltage is too low at
customers‘ board.
Activate ripple injection plant to
switch street lights on or off.
Activate ripple injection plant to
switch controlled loads on or
off.
Automatic operation of tap
changer.
Move tie points to relieve load
from zone sub.
Automatic operation of recloser.
Open & close ABS‘s to shift
load.
Open & close ABS‘s to restore
supply.
Manually raise or lower tap
where fitted.
Shift load to other transformers
by cutting and reconnecting LV
jumpers
Supply from closer transformer
if possibly by cutting and
reconnecting LV jumpers.
for this
response
Proactive
Proactive
Proactive
Reactive.
Limited
ability
within
network
Reactive
Proactive
or reactive
Reactive
Reactive
Reactive
Reactive
Table 36 outlines the key operational triggers for each class of OtagoNet‘s assets.
Note that whilst temperature triggers will usually follow demand triggers, they may not
always e.g. an overhead conductor joint might get hot because it is loose or rusty
rather than overloaded.
Table 36 - Operational triggers
Asset category
LV lines and cables
Distribution
substations
Asset Management Plan
Voltage trigger
Voltage routinely drops
too low to maintain at
least 0.94pu at
customers
switchboards.
Voltage routinely rises
too high to maintain no
more than 1.06pu at
customers
switchboards.
Voltage routinely drops
too low to maintain at
least 0.94pu at
customers
switchboards.
Voltage routinely rises
too high to maintain no
more than 1.06pu at
customers
switchboards.
Demand trigger
Temperature
trigger
Customers‘ pole or
pillar fuse blows
repeatedly.
Infra-red survey
reveals hot joint.
Load routinely
exceeds rating where
MDI‘s are fitted.
LV fuse blows
repeatedly.
Short term loading
exceeds guidelines in
IEC 354.
Infra-red survey
reveals hot
connections.
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ASSET LIFECYCLE
Asset category
Voltage trigger
Distribution lines and
cables
Zone substations
Voltage drops below
level at which OLTC
can automatically raise
or lower taps.
Subtransmission
lines and cables
Alarm from SCADA that
voltage is outside of
allowable setpoints.
Alarm from SCADA that
voltage is outside of
allowable setpoints.
OtagoNet equipment
within GXP
8.3
Demand trigger
Alarm from SCADA
that current has
exceeded a setpoint.
Load exceeds
guidelines in IEC
354.
Alarm from SCADA
that current is over
allowable setpoint.
Alarm from SCADA
that current is over
allowable setpoint.
Temperature
trigger
Infra-red survey
reveals hot joint.
Top oil temperature
exceeds
manufacturers‘
recommendations.
Core hot-spot
temperature
exceeds
manufacturers‘
recommendations.
Infra-red survey
reveals hot joint.
Infra-red survey
reveals hot joint.
Maintaining OtagoNet’s assets
8.3.1 Overview
As described in Table 34 maintenance is primarily about replacing consumable
components. Examples of the way in which consumable components ―wear out‖
include the oxidation or acidification of insulating oil, pitting or erosion of electrical
contacts and wearing of pump seals. Continued operation of such components will
eventually lead to failure. Durability of such components is usually based on physical
characteristics and exactly what leads to failure may be a complex interaction of
parameters such as quality of manufacture, quality of installation, age, operating hours,
number of operations, loading cycle, ambient temperature, previous maintenance
history and presence of contaminants.
Exactly when maintenance is performed will be determined by the need to avoid failure
or unwarranted loss of life and is based on manufacturer‘s recommendations,
operational experience, condition assessments, operational history and risk
assessment.
Like all OtagoNet‘s other business decisions, maintenance decisions are made on
cost-benefit criteria with the principal benefit being avoiding supply interruption. The
practical effect of this is that assets supplying large customers or numbers of
customers will be extensively condition monitored to avoid supply interruption whilst
assets supplying only a few customers such as a 10kVA transformer supplying a single
residence will more than likely be run to breakdown. The maintenance strategy map in
Figure 44 broadly identifies the maintenance strategy adopted for various ratios of
costs and benefits.
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ASSET LIFECYCLE
Design out
Condition
based
Event based
Benefits
(avoiding loss
of supply)
Time based
Breakdown
Cost of mtce
activities relative to
asset value
Figure 44 - Maintenance strategy map
This map indicates that where the benefits are low (principally there is little need to
avoid loss of supply) and the costs of maintenance are relatively high, an asset should
be run to breakdown. As the value of an asset and the need to avoid loss of supply (or
other failure consequences) both increase, the company relies less on easily
observable proxies for actual condition (such as calendar age, running hours or
number of trips) and more on actual component condition (through such means as
dissolved gas analysis (DGA) for transformer oil).
Component condition driven off periodic inspection is the key trigger for maintenance;
however the precise conditions that trigger maintenance are very broad, ranging from
oil acidity to dry rot. Table 37 describes the inspection cycles and maintenance triggers
adopted:
Table 37 - Maintenance triggers
Asset category
LV lines and cables
Five yearly inspection
Ten yearly scan of
wooden poles
Components
Poles, arms, stays and
bolts
Pins, insulators and
binders
Conductor (repairable)
Distribution
substations
yearly
rolling
inspection
Six monthly for sites
>150kVA
Poles, arms and bolts
Five
Enclosures
Transformer
Switches and fuses
Distribution lines and
cables
Asset Management Plan
Poles, arms, stays and
bolts
Maintenance trigger
Evidence of dry-rot.
Loose bolts, moving stays.
Displaced arms.
Obviously loose pins.
Visibly chipped or broken insulators.
Visibly loose binder.
Visibly splaying or corrosion or broken
conductor strands.
Evidence of dry-rot.
Loose bolts, moving stays.
Displaced arms.
Visible rust.
Cracked or broken masonry.
Excessive oil acidity (500kVA or greater).
Visible signs of oil leaks.
Excessive moisture in breather.
Visibly chipped or broken bushings.
Visible rust.
Oil colour.
Visible signs of oil leak.
Evidence of dry-rot.
Loose bolts, moving stays.
Displaced arms.
Page 125 of 193
ASSET LIFECYCLE
Asset category
Components
Five yearly rolling
inspection
Ten yearly scan of
wooden poles
Pins, insulators and
binders
Conductor
Ground-mounted
switches
Regulators
Zone substations
Fences and enclosures
Monthly checks
Buildings
Bus work and conductors
33kV switchgear
Transformer
11kV switchgear
Instrumentation/protection
Electromechanical
three yearly
Electronic five yearly
Maintenance trigger
Loose tie wire.
Chipped or cracked insulator.
Loose or pitted strands.
Visible rust.
Visible rust.
Oil colour.
Visible signs of oil leak.
Visible rust.
Oil colour.
Visible signs of oil leak.
Excessive moisture in breather.
High Dissolved Gas Analysis results.
Weeds.
Visible rust.
Gaps in fence.
Flaking paint.
Timber rot.
Cracked or broken masonry.
Hot spot detected by Infrared detector.
Corrosion of metal or fittings.
Visible rust.
Operational count exceeded.
Low oil breakdown.
Visible rust.
High Dissolved Gas Analysis results
(Annual test).
Low oil breakdown.
High oil acidity.
Visible rust.
Operational count exceeded.
Low oil breakdown.
Maintenance period exceeded.
Possible mal-operation of device.
Discharge test or Impedance test.
Batteries
Six monthly test
Substationtransmission lines
and cables
Poles, arms, stays and
bolts
Annual fly-over inspection
Five yearly inspection
Ten yearly scan of
wooden poles
Pins, insulators and
binders
Conductor
Cable
Annual check
Our equipment within
GXP
Injection plant
Evidence of dry-rot.
Loose bolts, moving stays.
Displaced arms.
Loose tie wire.
Chipped or cracked insulator.
Loose or pitted strands.
Visible rust.
High Partial discharge detected.
Sheath insulation short.
Oil pressure declining.
Alarm from failure ripple generation.
Period exceed for checks.
Monthly check
Typical maintenance policy responses to these trigger points are described in Table 38.
Table 38 Typical responses to maintenance triggers
Asset class
Subtransmission
lines
Asset Management Plan
Trigger point
Loose or displaced
components
Response to trigger
Tighten or replace
Approach
Condition as revealed
by ongoing surveillance
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ASSET LIFECYCLE
Asset class
Trigger point
Rotten or spalled
poles
Cracked or broken
insulator
GXP and zone
substation
transformers
Distribution lines
Distribution
ABS‘s
Distribution
transformers
Repair conductor unless
renewal is required
Filter oil
Excessive moisture
in breather
Weighted number of
through faults
General condition of
external components
Loose or displaced
components
Rotten or spalled
poles
Filter oil
Splaying or broken
conductor
Weighted number of
light and heavy faults
Loose or displaced
supporting
components
Seized or tight
Asset Management Plan
Filter oil, possibly detank and refurbish
Repair or replace as
required
Tighten or replace
Brace or bandage pole
unless renewal is
required
Replace as required
Repair conductor unless
renewal is required
Repair or replace
contacts, filter oil if
applicable
Tighten or replace
unless renewal is
required
Lubricate or replace
components as required
Loose or displaced
supporting
components
Rusty, broken or
cracked enclosure
where fitted
Oil acidity
Tighten or replace
unless renewal is
required
Make minor repairs
unless renewal is
required
Filter oil
Excessive moisture
in breather where
fitted
Visible oil leaks
Filter oil
Chipped or broken
bushings
LV lines
Brace or bandage pole
unless renewal is
required
Replace as required
Splaying or broken
conductor
Oil acidity
Cracked or broken
insulator
Distribution
reclosers
Response to trigger
Loose or displaced
components
Remove to workshop for
repair or renewal if
serious
Replace
Tighten or replace
Approach
Condition as revealed
by five yearly inspection
or ten yearly scan
Breakdown unless
revealed by five yearly
inspection
Condition as revealed
by five yearly inspection
Condition as revealed
by annual test
Condition as revealed
by monthly inspection
Event driven
Condition as revealed
by monthly inspection
Condition as revealed
by five yearly inspection
Condition as revealed
by five yearly inspection
or ten yearly scan
Breakdown unless
revealed by five yearly
inspection
Condition as revealed
by five yearly inspection
Event driven
Condition as revealed
by five yearly inspection
Breakdown unless
revealed by five yearly
inspection
Condition as revealed
by five yearly inspection
Condition as revealed
by five yearly inspection
Remove from service
for full overhaul every
15 years
Condition as revealed
by five yearly inspection
Condition as revealed
by five yearly inspection
Breakdown or condition
as revealed by five
yearly inspection
Breakdown unless
revealed by five yearly
inspection
Page 127 of 193
ASSET LIFECYCLE
Asset class
Trigger point
Rotten or spalled
poles
Cracked or broken
insulator
Splaying or broken
conductor
Response to trigger
Brace or bandage pole
unless renewal is
required
Replace as required
Repair conductor unless
renewal is required
Approach
Five yearly inspection
Ten yearly scan
Breakdown unless
revealed by five yearly
inspection
Breakdown unless
revealed by five yearly
inspection
The inspection cycles detailed in the above table have been taken from last year‘s
Asset Management Plan. However as part of the asset management program for the
year ending 2015 it is intended to undertake surveillance of all parts of the network:
•
To ensure the network meets safety requirements.
•
To enable population of the GIS database with accurate information.
•
To establish an accurate database of the condition of all parts of the network. This
information will then be utilised to maximise the benefit of expenditure and improve
reliability of supply.
Following an assessment of the information gained from the 2015 asset survey the
inspection cycles and trigger points for all assets will be reassessed.
The frequency and nature of the response to each of the above triggers are embodied
in OtagoNet‘s policies and work plans.
8.3.2 Maintenance budget
The life cycle maintenance budget for the next 5 years is set out in the following table.
Life Cycle Maintenance (opex)
Connection Maintenance
Substations Maintenance
Load Control Equipment
Radio Equipment
SCADA Equipment
Zone Sub Faults
Zone Sub Minor Maintenance
System Control Services
Subtotal substations maintenance
Lines Maintenance
Vegetation Control
Voltage Complaint Investigation
Transmission Line Minor Maintenance
Line Condition Survey and GIS update
Maintenance identified in line condition survey
Network chargeable Maintenance
Transformer Refurbishment (workshop)
Distribution Faults
Distribution Minor Maintenance
Sub Transmission Line Faults
Earth Testing
Subtotal lines maintenance
Total Life Cycle Maintenance
Year 1
2014-15
$6k
Year 2
2015-16
$6k
Year 3
2016-17
$6k
Year 4
2017-18
$6k
Year 5
2018-19
$6k
$6k
$24k
$1k
$48k
$400k
$479k
$6k
$24k
$1k
$48k
$400k
$479k
$6k
$24k
$1k
$48k
$400k
$479k
$6k
$24k
$1k
$48k
$400k
$479k
$6k
$24k
$1k
$48k
$400k
$479k
$850k
$12k
$24k
$967k
$500k
$60k
$50k
$500k
$650k
$60k
$60k
$3,733k
$850k
$12k
$24k
$500k
$350k
$60k
$50k
$500k
$650k
$60k
$60k
$3,116k
$850k
$12k
$24k
$300k
$350k
$60k
$50k
$500k
$650k
$60k
$60k
$2,916k
$850k
$12k
$24k
$300k
$350k
$60k
$50k
$500k
$650k
$60k
$60k
$2,916k
$850k
$12k
$24k
$300k
$350k
$60k
$50k
$500k
$650k
$60k
$60k
$2,916k
$4,218k
$3,601k
$3,401k
$3,401k
$3,401k
As noted in section 5.1 (Outcomes against plans), the total life cycle maintenance in
FY2013 was $3,499k and expected outcome in FY2014 is $4,288k, with the forecast
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ASSET LIFECYCLE
levels in total expected to return towards historic levels after a step increase for FY2014
and FY2015 due to the accelerated network surveillance programme plus provision for
renewal maintenance work expected to arise out of that surveillance.
8.3.2.1 Connection maintenance
This is a provisional annual sum for non-capitalised work associated with new
connections and includes minor costs in responding to faults with ICP fuses and
customer connections.
Cost $6k p.a.
8.3.2.2 Substations maintenance
This comprises recurring maintenance on the substation assets including battery
changes, oil changes, grounds maintenance etc. It is budgeted based on the average
out-turn from previous years.
Cost $768k p.a.
8.3.2.3 Lines maintenance
This comprises recurring inspection and maintenance on the distributed network. Main
components are managing trees, finding and repairing faults, condition inspections and
undertaking preventive repairs driven off the condition inspections.
Cost $3.733m for FY2015 reducing to $2.916m p.a. from FY2017.
8.3.2.3.1 Vegetation
Electricity (Hazards from Trees) Regulations 2003, put the requirement on OtagoNet to
undertake the first trim of trees free, and this budget is the on-going undertaking of this
requirement. While some customers have received their first free trim, some are
disputing the process and additional costs are occurring to resolve those situations.
The forecast costs are $850k p.a.
8.3.2.3.2 Line condition survey and GIS update
Monitoring of the distribution network includes the following areas:
Network condition surveys.
Wooden pole x-ray scanning.
Earthing checks.
Infrared survey of major distribution equipment.
Supply quality checks.
Inspections are carried out on a planned basis in accordance with the frequencies
listed in Table 37. However, a number of pole failures at loads less than design load,
including several unassisted pole failures over the last few years, have highlighted
gaps in both the identification of line condition and the recording and application of that
data. In response to the potential hazards posed from unknown lines condition,
OtagoNet has revised its line inspection template and streamlined its data capture
processes and has commenced an accelerated one-off inspection cycle of its full
network at a total cost of $1.5m with $967k allocated for FY2015. This is justified on
public safety considerations.
8.3.2.3.3 Maintenance identified from line condition surveys
An additional $500k is set provisionally in the FY2015 maintenance budget followed by
$350k p.a. to cover priority maintenance works that are likely to be discovered during
the detailed condition inspections.
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ASSET LIFECYCLE
8.3.2.3.4 Distribution minor maintenance
This covers on-going maintenance of assets and includes:
Lubrication of ABS‘s.
Cleaning of air insulated switchgear.
Battery replacements.
Rust repairs and painting.
TCOL and CB service.
Minor customer connections.
8.3.2.3.5 Faults (distribution and subtransmission)
Fault and emergency maintenance provides for the provision of staff, plant and
resources to be ready for faults and/or emergencies. This resource attends and makes
the area safe, then may isolate the faulty section so other customers are restored or
undertake quick repairs to restore supply to all customers. Note all repairs after three
hours are then covered in the routine maintenance budget.
The forecast budget for faults restoration and repair is $710 k p.a. Expending this sum
clearly depends on the number and nature of the faults impacting the network in the
forecast year so this budget has a high degree of variability and is set based on the
average costs from previous years.
8.3.2.4 Systemic faults
Systemic faults are where a class of component or installation practice is identified as
causing failures or hazards. Examples of past investigations and outcomes are:
Kidney strain insulators: Replaced with new polymer strains.
DIN LV fuses: Sourced units that can be used outdoor.
Parallel-groove clamps: Replaced with compression joints.
Non-UV stabilised insulation: Exposed LV now has sleeve cover, with new cables
UV stabilised.
Opossum faults: Extended opossum guard length
Currently OtagoNet has identified the earthing arrangements on 750 SWER
transformers as being below current recommended practice and has planned for their
upgrade at a cost of approximately $1.1m p.a. over two years. This is covered under
renewal.
8.3.3 OtagoNet maintenance policies
OtagoNet‘s maintenance policies are embodied in the PowerNet standards PNM-99,
PNM-97 and PNM-105 which broadly follow manufacturers‘ recommendations but
modified by industry experience.
8.4
Renewing OtagoNet’s assets
Work is classified as renewal if there is no change (and such change would usually be
an increase) in functionality i.e. the output of the asset doesn‘t change. OtagoNet‘s key
criterion for renewing an asset is when the capitalised operations and maintenance
costs exceed the renewal cost or the assessed hazard of failure must be mitigated.
Examples include:
Operating costs become excessive e.g. addition of inputs to a SCADA system
requires an increasing level of manning.
Spares for the current asset are no longer available.
Maintenance costs begin to accelerate.
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ASSET LIFECYCLE
Supply interruptions due to component failure become excessive; what constitutes
―excessive‖ is a matter of judgment which will include the number and nature of
customers affected.
Renewal costs decline, particularly where costs of new technologies for assets like
SCADA or protection devices decrease with capitalised benefits of lower on-going
operation and maintenance costs.
Failure hazard has become unacceptable (ie deteriorated pole near a school).
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ASSET LIFECYCLE
Table 39 below lists OtagoNet‘s renewal triggers for key asset classes.
Table 39 – Renewal triggers
Asset category
LV lines and cables
Components
Poles
Pins, insulators and binders
Conductor
Distribution substations
Poles
Enclosures
Transformer
Distribution lines and
cables
Switches and fuses
Poles
Pins, insulators and binders
Conductor
Ground-mounted switches
Regulators
Zone substations
Fences and enclosures
Buildings
Bus work and conductors
33kV switchgear
Transformer
11kV switchgear
Bus work and conductors
Instrumentation/Protection
Batteries
Subtransmission lines
and cables
Poles
Pins, insulators and binders
Conductor
Cables
Asset Management Plan
Renewal trigger
Fails pole scan.
Failure due to external force.
Done with pole renewal.
Excessive failures.
Multiple joints in a segment
Multiple corrosion sites
Fails pole scan.
Failure due to external force.
Installation below seismic strength
Uneconomic to maintain.
Excessive rust.
High standing losses, ie pre-1970
core.
Not economical to maintain.
Not economical to maintain.
Fails pole scan.
Failure due to external force.
Done with pole renewal.
Excessive failures.
Multiple joints in a segment.
Not economical to maintain.
No source of spare parts.
If not able to be remote controlled.
Not economical to maintain.
No spare parts.
Greater than Standard Life and
maintenance required.
Not economical to maintain.
Not economical to maintain.
Not economical to maintain.
Not economical to maintain.
No spare parts.
Greater than Standard Life and
maintenance required.
Not economical to maintain.
No spare parts.
Greater than 1.2 Standard Life and
maintenance required.
Not economical to maintain.
No spare parts.
Greater than Standard Life and
maintenance required.
Not economical to maintain.
Not economical to maintain.
No spare parts.
Greater than Standard Life and
maintenance required.
Prior to manufacturers‘ stated life.
On failure of testing.
Not economical to maintain.
Fails pole scan.
Failure due to external force.
Not economical to maintain.
Not economical to maintain.
Excessive joints in a segment
Not economical to maintain.
Page 132 of 193
ASSET LIFECYCLE
Asset category
Components
Renewal trigger
Not economical to maintain.
Our equipment within
GXP
Broad polices for renewing all classes of assets are:
When an asset is likely to create an operational or public safety hazard.
When the capitalised operations and maintenance costs exceed the likely renewal
costs.
When continued maintenance is unlikely to result in the required service levels.
8.4.1 Current Renewal projects
Capital renewal programs and projects planned over the next 5 years are set out in the
following table:
Life Cycle Renewal Capex
Projects
Owaka indoor switchgear
Port Molyneux indoor switchgear
Substation outdoor structure seismic upgrades if not
indoor switchgear
Replacement reclosers for SWER lines (with
automation)
SWER Earth upgrades to current best practice
Clifton - Clydevale 33 kV line rebuild
Ranfurly - Deepdell 33 kV line refurbishment
Subtotal projects
Identified line renewal works
Ongoing 33 kV line rebuild
Ongoing 11 kV line rebuild
Ongoing LV line rebuild
Ongoing transformer refurbishment
Year 1
2014-15
$250k
$0k
$100k
Year 2
2015-16
$150k
$150k
$50k
Year 3
2016-17
$0k
$100k
$300k
Year 4
2017-18
$0k
$0k
$200k
Year 5
2018-19
$0k
$0k
$100k
Life
Cost
$400k
$250k
$750k
$150k
$150k
$150k
$50k
$0k
$500k
$1,000k
$200k
$250k
$1,950k
$5,205k
$0k
$0k
$0k
$0k
$1,000k
$500k
$0k
$2,000k
$6,160k
$0k
$0k
$0k
$0k
$250k
$0k
$0k
$800k
$760k
$750k
$3,300k
$1,560k
$600k
$0k
$0k
$0k
$250k
$1,010k
$750k
$3,300k
$1,560k
$600k
$0k
$0k
$0k
$100k
$1,010k
$750k
$3,300k
$1,560k
$600k
$2,250k
$700k
$250k
$5,100k
Total Life Cycle Renewal Capex
$7,155k
$8,160k
$7,770k
$7,470k
$7,320k
Recent expenditure in this category has been approximately $5m per annum so this represents
a step increase.
8.4.1.1.1 Owaka switchgear
This project replaces the existing old outdoor 11 kV circuit breakers with an indoor
switchboard. The outdoor switchgear and bus arrangement has seismic strength and
clearance issues and may require additional land for the substation to give adequate
clearance to the fences if it was retained. Redevelopment on a different site is not
warranted. Cost $400 k.
8.4.1.1.2 Port Molyneux switchgear
This project replaces the existing old outdoor 11 kV circuit breakers with an indoor
switchboard. The proximity of the substation to the coast means the outdoor equipment
suffers accelerated corrosion and salt pollution on the equipment bushings.
Redevelopment on a different site is not warranted. Cost $250 k
8.4.1.1.3 Seismic strength
A structural report has identified a number of substation buildings and outdoor
structures that do not meet current building structural requirements under earthquake.
There will be a range of work required at many substations, with the work prioritised
and planed for completion over the next five years.
More detailed engineering work is required to prioritise and plan the remedial work
noting that:
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ASSET LIFECYCLE
There will be options for improving the building and structure integrity and each
substation will require investigation and recommendations for consideration.
As well as improving the strength of existing structures, consideration must be
given to the age of the structures and their possible future replacements with
indoor equipment.
No non-asset solutions are available.
Cost $750k over 5 years.
8.4.1.1.4 Replacement reclosers for SWER lines
The existing hydraulic reclosers on SWER lines are old and unsupported. This renewal
projects will replace, remove or replace in a different location reclosers on SWER lines
to achieve improved reliability.
Cost $500k over 4 years.
8.4.1.1.5 SWER earthing
Until they were revoked under the 2011 amendments, Single Wire Earth Return
(SWER) systems were covered under code of practice ECP41 cited in the Electricity
(Safety) Regulations 2010. SWER systems are no longer specifically cited in the safety
regulations and any test of competency would fall to the electricity industry best
practice being the EEA Guide for HV SWER Systems – October 2010.
A number of OtagoNet‘s SWER installations include bar joints in the earth continuity
conductors (as is practiced in other HV 3-phase grounded neutral systems) and have
common HV and LV earths both of which are not recommended practice in the guide
(and having joints in the HV earth conductor would not have complied with the previous
regulations set out in ECP41). Opening the earth joint with the SWER supply in service
would be a safety hazard and is non-compliant under the previous regulations and the
current guidelines. OtagoNet has therefore commenced a program to upgrade all its
SWER installations to full code compliance as soon as practicable with priority to
upgrading the installations with joints in the HV earth conductors. An estimated cost of
$1m has been allocated for the FY2015 year with a total cost of $2.5m and this will be
subject to further review.
Cost $2.25m over 3 years.
8.4.1.1.6 Clifton – Clydevale 33 kV line rebuild
This section of line has been identified from condition inspection to warrant line rebuilding as opposed to individual pole replacements.
Cost $700k over 2 years
8.4.1.1.7 Ranfurly - Deepdell 33 kV line rebuild
This section of line has been identified from condition inspection to warrant line rebuilding as opposed to individual pole replacements.
Cost $250k in FY2015
8.4.1.2 Identified line works
The following projects have been previously identified through condition assessment
and are either on-going or planned over the next 5 years. Completion of this work is
dependent on customer requirements, land access permission and priority reassignment as further network condition information becomes available.
General
Distribution Minor Capital Work
Network Chargeable Capital
Replacement of O/H structures with Ground Subs
Pole or conductor replacements on minor spur lines
Asset Management Plan
180,000
60,000
80,000
200,000
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ASSET LIFECYCLE
Balclutha:
Clifton-Old Lake 33kV pole replacement
Milton 33 kV line completion
Finegand - Owaka 33 kV conductor replacement
Hunt Road 11 kV line rebuild on road side
Summerhill Rd Wangaloa
Clutha leader - TX 2586 replacement on ground
Tuapeka Mouth 11 kV Line rebuild on road
Chrystalls Beach E/R Lines
Mill View Rd Tuapeka West
Farquhar Rd SWER Owaka Valley.
Puketi E/R - Stage 2
Glenomaru Valley Rd Spur Lines
Estate Rd, Clinton
Silverpeaks 22 kV
Titri Rd, Waihola
Fella Burn Road 11kV Project
Puerua SWER: Part A
North Foreland Street, Waihola. Replace overloaded
200kVA at TX Site 22108
SH-8 Beaumont - Raes Junction
Shannon - Matarae 22kV ER (Clarks 22kV)
400,000
800,000
600,000
600,000
270,000
116,000
120,000
321,600
41,200
213,500
451,500
188,000
40,000
135,000
266,000
39,500
306,000
58,000
67,500
216,000
Palmerston
Palmerston - Deepdell 33kV pole replacements
Deepdell - Middlemarch 33kV Refurbishment
Kilmog 11 kV feeder stage 2
Horse Range E/R - Part 1
Bushey Park Road
Dunback Footbridge
Sweetwater Creek
Puketapu Road
Hughes Rd Palmerston
250,000
300,000
300,000
80,500
53,000
16,000
32,000
64,000
54,000
Ranfurly
McHardy Rd, Sutton
Ngapuna - SH87 spurs
Three O'Clock - Mt Stoker
Ranfurly Spur Lines
Ida Valley Station
265,000
171,000
208,000
45,500
157,500
8.4.2 Planned renewal projects
Planned renewal projects for years 5 to 10.
The majority of the renewal projects for OtagoNet are 11kV line renewals as the poles,
cross arms and or conductors have reached the end of their economic life. Because of
the small loads and minimal load growth most of these projects are all renewals with
the few growth projects for lines being reported in section 7. Similarly, parts of the
OtagoNet LV and sub transmission lines are planned to be renewed as they reach the
end of their economic life noting that renewal of LV lines is generally more expensive
than 11 kV feeder lines.
Longer term renewal budgeting is based on Poles have a life expectancy of 65 years
noting that deterioration of headgear (crossarms, insulators, binders etc.) may be the
driver that replaces a deteriorated but serviceable pole given the costs of establishing a
work crew at the pole and the economics of doing extended works so that the pole is
good for a number of years. By way of the example, the following charts shows the
age profile for the hardwood poles together with a hazard curve that give a 10%
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replacement probability at 70 years age. This indicates approximately 240 pole
replacements per annum when applied against the age profile.
Hardwood Poles
Age profile
Replacement hazard
600
0.4
0.3
Pole count
400
0.25
300
0.2
200
0.15
0.1
100
0.05
0
0
10
20
30
-100
40
50
60
70
80
90
Age (years)
100
Replacement hazard (per year)
0.35
500
0
-0.05
After including for other asset category renewals (ie transformers, regulators etc.) this
gives a long-run renewal budget of approximately $6.7 m p.a. Future projections of
long-run renewal levels will improve as better information becomes available from both
the condition surveillance data and process improvements in the recording of failure
causes.
8.5
Up-sizing or extending OtagoNet’s assets
If any of the capacity triggers in Table 26 are exceeded consideration is given to either
up-sizing or extending OtagoNet‘s network. This is discussed fully under the network
development section of this plan.
8.5.1 Designing new assets
OtagoNet uses a range of technical and engineering standards to achieve an optimal
mix of the following outcomes:
Meet likely demand growth for a reasonable time horizon including such issues as
modularity and scalability.
Minimise over-investment.
Minimise risk of long-term stranding.
Minimise corporate risk exposure commensurate with other goals.
Maximise operational flexibility.
Maximise the fit with soft organisational capabilities such as engineering and
operational expertise and vendor support.
Comply with sensible environmental and public safety requirements.
Given the fairly simple nature of OtagoNet‘s network standardised designs are adopted
for all asset classes with minor site-specific alterations. These designs, however, will
embody the wisdom and experience of current standards, industry guidelines and
manufacturers recommendations.
8.5.2 Building new assets
OtagoNet uses external contractors to augment or extend assets. As part of the
building and commissioning process OtagoNet‘s information records are ―as-built‖ and
all testing documented.
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8.6
Enhancing reliability
Reliability is a service product of the network that is managed through appropriate
network configuration, managing the condition of the network, minimising the
environmental exposures (ie tree trimming and fitting possum guards), and responding
to the faults that do occur.
As noted in the performance and benchmarking sections of this plan, a high proportion
of faults relate to the deteriorated lines condition and where the inability to inter-mesh
the networks leads to long restoration times and inability to back-feed during planned
outages. Also, as described in the background and objectives, whilst customers prefer
improved reliability they are also price sensitive, so OtagoNet must balance the cost of
any reliability improvement initiatives with the expected benefit through the value that
customers place on continuous supply.
There are many factors that will lead to a decline in reliability over time including:
Tree re-growth.
Declining asset condition.
Extensions to the network that increase its exposure to trees and weather.
Changes in the frequency of extreme weather events
Increased customer numbers that increase the lost customer-minutes for a given
fault.
Installation of customer requested asset alterations that can reduce reliability (e.g.
needing to lock out reclosers on feeders that have embedded generation).
Declining asset condition is being addressed through the lines and assets renewal
programme, which is driven firstly by safety and maintaining reliability. However,
reliability improvement is also considered through targeted maintenance or treetrimming programmes, installation of automatic sectionalisers that limit the impact of
line faults and in employing more mobile generation to support load during planned
outages. OtagoNet evaluates these initiatives on a case-by-case basis using the
following steps:
Identifying the customer-minutes lost for each outage by cause.
Identifying the scope and likely cost of reducing those lost customer-minutes
against the customer value of doing so.
Calculating the cost per customer-minute of each enhancement opportunity.
Prioritising the enhancement opportunities from lowest cost to highest.
Budgeted plans in FY2015 (discussed in the development section of this plan) include
purchase of another trailer or truck mounted generator and purchase of a larger
generator step-up and earthing transformer to support load during planned outages
and a budget of $200 k in FY2015 for the installation of 11 kV reclosers with a total
provisional budget of $1 m over 5 years for automatic network sectionalising.
8.7
Converting overhead to underground
Conversion of overhead lines to underground cable is an activity that doesn‘t fit within
the asset life-cycle as described because it tends to be driven more by amenity value
or to remove overhead obstructions rather than for asset-related reasons. As such,
conversion tends to rely on other utilities cost sharing or local communities funding the
work.
Asset relocations planned in the near term are:
Network Chargeable Capital
Balclutha Main Street LV underground
Milton Main Street LV undergrounding
John Street - TX 2590 OH lines to underground
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60,000
400,000
300,000
40,000
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Telecom - TX 2591 OH lines to Underground
8.8
80,000
Retiring of OtagoNet’s assets
Retiring assets generally involves doing most or all of the following activities:
De-energising the asset.
Physically disconnecting it from other live assets.
Curtailing the assets revenue stream.
Removing it from the ODV.
Either physical removal of the asset from location or abandoning in-situ (typically
for underground cables).
Disposal of the asset in an acceptable manner particularly if it contains SF6, oil,
lead or asbestos.
Key criteria for retiring an asset include:
8.9
Its physical presence is no longer required (usually because a customer has
reduced or ceased demand).
It creates an unacceptable risk exposure, either because its inherent risks have
increased over time or because emerging trends of safe practice reveal unknown
hazards. Assets retired for safety reasons will not be re-deployed or sold for reuse.
Where better options exist to create similar outcomes (e.g. replacing lubricated
bearings with high-impact nylon bushes) and there are no suitable opportunities for
re-deployment.
Where an asset has been augmented and no suitable opportunities exist for redeployment.
Non-network, maintenance and renewal
OtagoNet owns offices in the township of Balclutha, which provide workspaces for the
OtagoNet employees whose time is predominantly devoted to the OtagoNet area.
The maintenance and renewal policies applicable to these buildings are much the
same as those applied to zone substation buildings.
8.10 Lifecycle strategies that promote energy efficiency
Energy efficiency through reducing network losses is mainly considered during the
design of new or up-rated assets or in the component standards for renewal works.
Although the cost of losses fall to the network retailers, OtagoNet include costs of
losses in its business cases at the retail energy rate.
Many of the older SWER lines are constructed with steel conductor. Where SWER
conductor is being replaced, modern aluminium, or aluminium/steel-based conductors
are used, which for the same diameter offer reduced transmission losses per unit
length. In certain situations the replacement of SWER with a single phase circuit
generates a further reduction in transmission losses.
Energy efficiency is a factor considered when new transformers are purchased to
ensure maximum efficiency is gained over the transformer‘s life.
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8.11 Life Cycle Maintenance and Renewal Budget
Table 40 Life cycle budget (FY2015 to 2024)
Lifecycle expenditure
2014-15
Fault & emergencies
Vegetation management
Routine & corrective
maintenance
Renewal & replacement
opex
Lifecycle opex total
Asset replacement &
renewal
Asset relocations
Reliability, safety,
environment
Lifecycle capex total
$1,658k
$850k
$1,094k
Total lifecycle
20152016201716
17
18
$1,658k $1,658k $1,658k
$850k
$850k
$850k
$627k
$427k
$427k
201819
$1,658k
$850k
$427k
201920
$1,658k
$850k
$427k
202021
$1,658k
$850k
$427k
202122
$1,658k
$850k
$427k
202223
$1,658k
$850k
$427k
202324
$1,658k
$850k
$427k
$616k
$466k
$466k
$466k
$466k
$466k
$466k
$466k
$466k
$466k
$4,218k
$4,320k
$3,601k
$6,150k
$3,401k
$6,760k
$3,401k
$6,660k
$3,401k
$6,610k
$3,401k
$6,610k
$3,401k
$6,610k
$3,401k
$6,610k
$3,401k
$6,610k
$3,401k
$6,610k
$1,405k
$1,430k
$60k
$1,650k
$60k
$950k
$60k
$750k
$60k
$650k
$60k
$550k
$60k
$550k
$60k
$550k
$60k
$550k
$60k
$550k
$7,155k
$7,860k
$7,770k
$7,470k
$7,320k
$7,220k
$7,220k
$7,220k
$7,220k
$7,220k
$11,373
k
$11,461
k
$11,171
k
$10,871
k
$10,721
k
$10,621
k
$10,621
k
$10,621
k
$10,621
k
$10,621
k
8.12 Life Cycle by Asset Category
This section includes a detailed description of the network assets including age
profiles.
8.12.1 Assets installed at non-OtagoNet bulk electricity supply points
OtagoNet owns assets at the three Transpower-owned GXPs, and on easements near
the Mt Stuart and Paerau Hydro sites. There are no OtagoNet assets installed at Falls
Dam. The assets involved are:
•
•
•
Balclutha, Naseby, Palmerston GXPs: Each site has an OtagoNet-owned check
meter and a SCADA terminal connected to Transpower-owned circuit breakers.
Paerau Hydro: All substation assets at this site are owned by OtagoNet.
Mt Stuart: OtagoNet owns an outdoor bus with metering unit, relays, and a 33kV
CB protecting customer-owned cable. This equipment is physically located on
private land approx. 1km from the wind farm.
8.12.2 Subtransmission network
The natural split of this group is into overhead pole line circuits and cable circuits. Any
particular circuit from A to B may be a mixture of these forms. Overhead lines may be
multi circuit or be common with under-built lower voltage circuits. Maintenance
planning differences are more a function of circuit form than circuit voltage.
Subtransmission includes all circuits ―upstream‖ of a zone substation. Effectively these
circuits carry greater load and are therefore more critical than distribution circuits
particularly when they are in a radial configuration where loss of the circuit means loss
of the supply. The arrangement of these circuits is very much dependent on load
density, geography and history. The required reliability varies according to the security
available with the associated network configuration. Supply security and reliability are
defined in the Network Design Standard.
The OtagoNet subtransmission consists mainly of overhead pole lines with some short
lengths of cable to enter or exit the confined areas around substations. Only Charlotte
Street, Finegand, Elderlee Street and Ranfurly have full duplication of subtransmission
circuits. The tie between Palmerston and Ranfurly offers multiple paths to Deepdell,
Hyde and Waipiata zone substations between them.
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8.12.2.1 Pole line circuits
8.12.2.1.1
Description and capacity
Pole overhead lines form the majority of subtransmission circuits within rural Otago.
These consist of unregulated 33kV or 66kV circuits of a capacity specifically chosen for
the anticipated load. The dominant design parameters are voltage drop and losses.
Almost exclusively the current loading is well below the thermal capacity of the
conductor. Voltage drop is a problem due to the small conductor size and long circuit
lengths. EHV regulators are needed on the OtagoNet system partly because the
subtransmission system is also used as distribution. On a voltage and loss basis most
circuits operate between 80% and 150% of optimum level.
Most subtransmission line circuits are routed cross-country to minimise cost and
length. More recent circuits tend to be constructed along road reserves due to the
nature of recent legislation. Poles are a mixture of concrete, hardwood and softwood,
chosen by the relative economics at the time of construction. Rural lines are typically
sagged to a maximum operating temperature of 50C to minimise the installation
(capital) cost.
Whilst some of the circuits have substantial design drawings and route plans, many do
not. In particular, the GIS pole positions have been taken from original plans using, for
example, road centre-line off-sets. As such, the terrestrial position in the GIS may be
incorrect by a few or several meters. More importantly the ground profile under the line
is not precisely known in a number of cases so the line design in terms of loads, sags
and clearances cannot be fully checked. OtagoNet is undertaking a progressive
programme of updating its line data in GIS and undertaking line design checks using its
new CTAN software to close this gap. This is also prompted by the line renewal
programme that replaces with concrete poles, clamp-top insulators, steel cross-arms
and AAAC conductor with incumbent issues of potential resilience under extreme
loads.
8.12.2.1.2
Condition, age, and performance
Only part of the original subtransmission network remains. Upgrading, rebuilding and
piecewise maintenance has replaced many of the circuits originally installed before
1950.
Figure 45 and Figure 46 summarises the length and age of the subtransmission
network poles and conductor respectively. Since most transmission circuits are of
overhead line construction these graphs gives a good indication of overall circuit ages.
Note however that many circuits have poles and other hardware replaced as and when
needed; so the age of a circuit is not necessarily the age of individual components
within that circuit.
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Figure 45 - Subtransmission poles
Figure 46 - Subtransmission conductor
There are a large number of poles past their standard life although environmental
conditions in the OtagoNet area are generally very good, with excellent wood pole life
in the Maniototo. However, total line refurbishment is indicated where work must be
done on the pole tops due to deteriorated crossarms or broken insulator binders and
where the pole condition is markedly deteriorated as it is uneconomic not to replace a
deteriorated pole given the high work site set-up costs quite apart from the pole
climbing risks.
The subtransmission fault rate averaged 1.6 faults/100km/annum in 2013 with a
variable trend in total faults as shown in the chart of Figure 47 below.
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Figure 47 Trend in subtransmission equipment defect faults
8.12.2.1.3
Monitoring and procedures
Dominant failure modes are pole and crossarm deterioration, tree contact, conductor
corrosion, ties/clamps, joints and insulator cracking.
Visual inspection is conducted annually to locate obvious problems.
rectified dependent on the urgency.
These are
Defect inspection is carried out five yearly, and pole scanning at ten yearly intervals, on
a rolling basis. This inspection includes checks of foundation, pole integrity, crossarm
condition, faulty hardware and insulator condition. The scanning uses x-rays to inspect
the internal condition of wooden poles and thermal imaging to highlight hot spots.
A more detailed description of the inspection processes is given at section 8.12.5.1.3.
These inspections are the prime driver for maintenance planning.
Fault data is used for abnormal problems. Protection relay data (distance to fault) is
used where available to help locate faults and subsequently identify fault cause.
Detailed analysis of outages and their cause using Root Cause Analysis (RCA)
identifies target areas for maintenance programs.
8.12.2.1.4
Maintenance plan
A program to replace cross arms and insulators on certain lines is in place as
appropriate on those lines that do not require capital replacement.
8.12.2.1.5
Replacement plan
Refer to the life cycle renewal plan for details of subtransmission circuit replacement.
8.12.2.1.6
Disposal plan
There are no plans for any disposal of pole circuit assets.
8.12.2.2 Cable circuits
8.12.2.2.1
Description and capacity
The Otago network has only 1.6km of 33kV cable, these are around the Transpower
Balclutha and Charlotte Street substations where the overhead line congestion requires
it. These cables are 240mm² AL XLPE installed in 1977 near the Balclutha sub, and
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95mm² AL XLPE installed in 1997 at Charlotte Street. Additional cables were installed
in 2007 with the installation of the 33kV switchboard.
There is also a section of 95mm2 AL XLPE cable installed 2003/4 on the Patearoa
33kV line to bypass an irrigation system.
8.12.2.2.2
Condition, age, and performance
There are no known problems associated with the cables. The cable sizes match the
associated lines and substations to which they connect, and so are well utilised. The
age profile of the cables is displayed graphically in Figure 48.
8.12.2.2.3
Monitoring and procedures
Dominant failure modes for cables are joint or termination faults, sheath damage,
overheating and external mechanical damage. Generally cables are very stable and
require little attention, particularly these protected short lengths without any in line
joints.
8.12.2.2.4
Maintenance plan
There are no plans for any significant cable maintenance.
8.12.2.2.5
Replacement plan
There are no plans for any replacement of subtransmission cables.
8.12.2.2.6
Disposal plan
There are no plans for any disposal of cables.
Figure 48 - Subtransmission Cables
8.12.3 Zone substations
8.12.3.1 Substations General
8.12.3.1.1
Description and capacity
There are 34 zone substations in the OtagoNet network and these are listed in Table 9.
These stations vary considerably from installations with indoor switchgear and dual
transformers to single outdoor circuit breaker and transformer rural substations.
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The prime general functions of the stations are to house the transformers, switchgear
and associated controls.
8.12.3.1.2
Monitoring and procedures
The stations consist of buildings, fences, yards and similar exposed items similar to
other industrial sites. Monitoring consists of monthly checks to identify obvious
problems such as broken windows, weeds, damaged security fencing. Routine
maintenance such as spraying is
conducted in conjunction with
monitoring.
Yearly inspections are undertaken
for forward planning, at which
time such activities as painting,
spouting, rust repairs etc. are
identified. The standard required
is as would be expected for
domestic or industrial building.
Station batteries are checked
yearly and are replaced as per the
manufacturers recommendation
or at 10 years of age, based on
the assumption that failure rates
start to climb significantly after this age.
Protection relays are tested at intervals of no greater than three years, to detect
general drift and wear of the mechanical bearings etc. They are also being replaced
with electronic relays in conjunction with circuit breaker replacement. The preferred
relays are the Schweitzer Engineering Laboratories (SEL) range, which were chosen
on a reliability, flexibility and functional basis. Electronic relays are tested at least every
six years.
SCADA is generally maintained on a repair basis due to the random pattern of failure.
Outdoor structures are checked as part of the monthly inspections. Yearly visual
inspections are undertaken to assess overall condition and list any action required.
Yearly ultrasonic and thermal imaging tests are done to identify failed insulation or high
contact resistance.
8.12.3.1.3
Maintenance and replacement plans
Maintenance is of a routine nature with no significant activity expected. There are no
plans to replace any existing buildings or sites.
8.12.3.2 Transformers
8.12.3.2.1
Description and capacity
OtagoNet power transformers vary significantly in both size and detail. They range
from the 12.5/25MVA 33/66kV three phase units complete with On Load Tap Changers
(OLTC) at Ranfurly to simple 750kVA fixed tap transformers at rural substations.
The zone substation transformers have two main purposes. Firstly they are required to
―transform‖ the higher subtransmission voltages to more usable distribution voltage and
secondly they are required to regulate the highly variable higher voltages to a more
stable voltage at distribution levels. At simple substations with fixed tap transformers
there is an associated voltage regulator, usually on the 11kV output of the transformer.
Several issues should be noted. The rating is obviously important as the transformers
must be suitable to withstand the load imposed upon them. This is generally stated as
the ONAN (Oil Natural, Air Natural) level at which losses are optimised and no special
cooling is required. To allow for maintenance or faults, transformers are often installed
in pairs but only at sites with high load as set out in the supply security requirements
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discussed in section 7.2.2. Typically they share the load and operate within their
economic ONAN rating. Should one transformer not be in service then the remaining
transformer can carry the total load which may require the operation of fans and pumps
to dissipate heat and the life of the transformer may be reduced. The rating at this
level is called OFAF and may be twice the ONAN rating. Transformers are often
relocated to optimise use as load varies at the various sites. Consequently the
transformers are well utilised.
Phasing of the transformers is important to allow paralleling of the network. All of the
transformers therefore have a Dyn11 vector for 33/11kV and Yyn0 for 33/66kV.
For larger transformers, On Load Tap Changers provide a less
expensive regulation method than separate regulators.
Therefore regulators are only used on the smallest substations
that use a simple 33/11kV transformer up to 1.5 MVA.
The high cost of the larger transformers has driven the
installation of comprehensive protection systems for them.
The OtagoNet zone transformers are also well utilised at
around 85%.
8.12.3.2.2
Condition, age, and performance
Figure 49 summarises the number and age of the power
transformers and Figure 50 the regulator transformers.
Figure 49 - Power Transformers
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Figure 50 Regulator Transformers
8.12.3.2.3
Monitoring and procedures
Most transformer deterioration is considered to be time based, with the exception that
tap changing equipment wears proportionately to the number of operations. Monthly
visual inspection is undertaken to check for obvious problems such as oil leaks. Yearly
inspections are done to check fan control operation, paint condition and obtain oil
samples for Dissolved Gas Analysis testing.
Routine transformer maintenance is done on a 5 yearly basis. This covers protection
relay operation, insulation levels and instrumentation checks.
Tap Changer maintenance is done on a time and/or count of operations basis, as per
manufacturer‘s recommendations.
Dissolved Gas Analysis results are checked for trend changes and against industry
standard absolute levels. Action is taken as recommended by the testing agency.
Insulation trend is used to trigger further more specific action.
Transformers are sometimes moved as part of utilisation planning.
8.12.3.2.4
Maintenance plan
There are no plans for any significant transformer maintenance. All work consists of
routine inspection and maintenance.
8.12.3.2.5
Replacement plan
The regulators at Oturehua and Waihola are to be replaced in the coming planning
period, with power transformer replacements at Pateraoa, Clinton, Finegand, Waitati,
Oturehua, and Owaka planned over the next five years.
8.12.3.2.6
Disposal plan
Transformers displaced by replacement will have their oil drained and recycled, and the
tank and windings will be competitively tendered to scrap metal dealers.
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8.12.3.3 Circuit Breakers
8.12.3.3.1
Description and capacity
Four general group types of switchgear
are in use in the networks covered by
OtagoNet:
The majority of 33kV and 66kV circuit
breakers are outdoor units mounted
on stands in conjunction with
associated
current
transformers.
Many types and ratings are in use.
This equipment is purchased on a
case-by-case basis, generally to a
lowest price tender offer. Minimum
oil, vacuum and SF6 units are in use.
Ratings vary from 200A to 2000A,
although load is typically in the range
of 20A to 630A. Most operating mechanisms are dc motor wound spring to allow
operation de-energised. There are a number of ―recloser‖ type units in service in
circumstances where lower fault interruption ratings may be used.
Charlotte Street has an indoor 33kV Schneider switchboard with seven circuit
breakers and a bus section switch.
Three 11kV indoor switchboards are Reyrolle of various vintages and two smaller
substations, Patearoa and Lawrence, have Holec Xiria and SVS units for their
2.5MVA single transformers.
Most 11kV outdoor circuit breakers consist of pole mounted outdoor units with
integral current transformers. Many of these are solenoid operated reclosers.
Note that current transformers are generally assumed to form part of the switchgear,
but outdoor isolators etc. are
lumped in with the general
structure.
The dominant circuit breaker
rating is 630A continuous and
12kA or 13kA fault break
capacity. Few circuit breakers
are loaded over 200A due to
the nature of the network.
The main purpose of a circuit breaker is to allow switching of high energy circuits and
more specifically to switch open (i.e. break) faulted circuits automatically by the use of
associated protection devices. A few circuit breakers at the source ends of lines would
be adequate to protect the lines from a safety point of view.
Unfortunately faults are bound to occur on lines no matter how well maintained the
lines are. If a large length of line were protected by a very limited number of circuit
breakers then the reliability at any particular installation would be completely
unacceptable. The OtagoNet network therefore contains a number of circuit breakers
outside zone substations, as described in section 8.12.4.1.
8.12.3.3.2
Condition, age, and performance
Figure 51 summarises the number and age of the high voltage circuit breakers in the
zone substations.
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Figure 51 - Circuit Breakers
8.12.3.3.3
Monitoring and procedures
Circuit breakers are considered to deteriorate in a time based
fashion with regard to general corrosion and mechanical faults.
Experienced has indicated that circuit breakers with oil based arc
quenching require significant maintenance following relatively
few fault clearing operations. Literature and manufacturer
recommendations suggest that vacuum and SF6 devices are not
affected so severely by fault breaking current.
OtagoNet does not have significant data on the current breaking
levels for individual switching operations. Consequently routine
maintenance is carried out at two yearly intervals for oil-based
circuit breakers and five yearly intervals for vacuum and SF6.
Some circuit breakers are maintained following a specific
number of operations.
Routine substation inspections are used to check for corrosion, external damage and
the like.
Maintenance is specific to the requirements. Outdoor units may require sand blasting
and painting as determined from inspections. Time based maintenance generally
covers checking for correct operation, timing tests, insulation levels and determination
of contact life. Contacts or vacuum bottles are replaced as per the manufacturer‘s
recommendations.
8.12.3.3.4
Maintenance plan
There are no plans for any significant switchgear maintenance. All work consists of
routine inspection and maintenance.
8.12.3.3.5
Replacement plan
No individual units are planned for early replacement.
8.12.3.3.6
Disposal plan
Oil and SF6 gas are reclaimed. Useful spare parts are retained. The contractor scraps
the remainder.
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8.12.3.4 Protection and control
Most of the protection is integrated with the circuit breakers described in Section 0, age
profiles and condition would be similar except for the protection relays at Ranfurly and
Deepdell which were replaced in 2005.
As DC batteries are essential to the safe operation of protection devices, regular
checks are carried out and each battery is replaced prior to the manufacturer‘s
recommended life.
8.12.3.5 SCADA and Communications
OtagoNet‘s SCADA system was installed in 2000 with computer and software updates
every one or two years to keep the system fully up to date with the manufacturer‘s
latest product. When the new OtagoNet SCADA system was installed, most
communications links were also updated. This equipment is checked and maintained
annually by the agents.
Figure 52 - Communication radios age profile
All SCADA RTU‘s are no older than 15 years with the majority installed in 2000.
8.12.3.6 Ripple control injection plants
8.12.3.6.1
Description and capacity
―Ripple Control‖ controls a large proportion of
demand side load directly or indirectly. Ripple
control is a communication signal superimposed
on the network which is picked up by ripple
receiver relays installed in consumers premises
which then switch day/night load tariffs or hot
water load. The ripple receivers are owned by the
retailers. OtagoNet also utilise the ripple system to
switch street lights.
Modern systems utilise 217Hz or 317Hz as the
carrier signal.
Ripple systems consist of three basic sections.
Firstly the load must be monitored such that appropriate control actions can be
undertaken. This is done with separate SCADA equipment.
Secondly a signal must be injected onto the 50Hz network. This is done with Injection
Plants. And finally the signal must be detected by a Receiver that undertakes control
at the individual installations. One, two or three relays control equipment such as hot
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water heating, night store heaters and meters.
receivers is intricately tied to meters.
The maintenance and control of
The central part of ripple control that is discussed here is injection plant. They all
consist of a generator and a coupling cell. The generator was traditionally a
motor/generator set. Modern generators use electronic components to convert 50Hz
firstly to direct current and then to the required frequency. A typical rating is 100kVA at
around 200V.
The coupling cells vary. Those in use in the OtagoNet networks consist of: (a) LV side
inductor/capacitor tuning, (b) coupling transformer and (c) HV capacitors. These
operate well under a large range of network configurations.
The systems within OtagoNet all inject at 33kV on or near to Transpower Grid Exit
Points. The signal propagates quite satisfactorily down to the zone substations on to
individual LV installations.
Injection plants are located at Ranfurly, Palmerston and Balclutha. They are all 33kV
100kVA.
The typical signal level is 2%. The system works adequately at injection levels down to
approximately 1.4%.
Ripple control has been instrumental in increasing load factor and reducing demands
on the network and Transpower Grids Exit Points although changes in the manner in
which OtagoNet is charged for GXP capacity and a shift in the time of maximum
demand has meant that use of the ripple system for load control is no longer as
important. Its main function now is as a service to the retailers for tariff switching.
8.12.3.6.2
Monitoring and procedures
The electronics of the plants are located indoors and here is little that can deteriorate.
Inspection is limited to locating obvious signs of failure. Spare parts or duplicate
systems are available as backup in the case of faults. Most work involves tuning and
signal level investigation that is largely influence by the network configuration, not the
injection plant.
8.12.3.6.3
Maintenance, replacement and disposal
No maintenance is planned other than routine inspection.
Figure 53 - Remote Terminal Units (RTU) age profile
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8.12.4 Distribution Switchgear
8.12.4.1 Description and capacity
Distribution switchgear can be classified into five forms. There are the distribution
network circuit breakers, which generally consist of pole mounted 11kV outdoor units
with integral current transformers. Many of these are solenoid operated reclosers.
To achieve reasonable reliability on the network OtagoNet have adopted a guideline
such that no more than 40km of line is connected between circuit breakers for circuits
near the coast. This figure increases to 100km inland where fault density is less. The
large length of lowly loaded line circuits in the Otago hinterland has resulted in a large
number of lightly loaded field circuit breakers being installed.
Based on load capacity the circuit breakers are
very much underutilised. However, in terms of the
more important safety and reliability parameters,
there are areas where more circuit breakers should
be installed and this is currently being planned.
The most common form of switch is in fact a fuse
that can be used to switch, isolate and protect
equipment. Around 10,000 individual MV fuses
are in service in sets of 1, 2 or 3. The most
common fuse is the Drop Out fuse rated up to
100A. These are the preferred type because of
fault rating and clearly visible break point. A
number of glass fuses and sand filled porcelain are
still in use, but are generally replaced during
significant maintenance work. Fuses are fitted at
transformers, on MV service mains and at quite a
number of lateral circuits.
The majority of true switches, generally in rural
areas, are pole mounted Air Break Switches
(ABS). There are approximately 300 switches in
service. They are generally rated 200A continuous
capacity or 400A. Most are in fact more correctly
called isolators because their load breaking
capacity is in the range of 10A to 20A. 10% of
these switches have load break heads that allow
the switch to break rated load.
10 outdoor Ring Main Unit switches are in service
manufactured by ABB (SDAF series) and Merlin
Gerin (Ringmaster series). These are associated
with transformers and located with them.
At present there is only one example of an indoor ring main unit, the Xiria ring main unit
manufactured by Holec. This is mounted within a customer‘s substation building.
8.12.4.2 Condition, age, and performance
The outdoor MV circuit breaker age profile is shown in Figure 54, with the oldest units
installed in 1968.
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Figure 54 - MV Circuit Breakers
8.12.4.3 Monitoring and procedures
Experience has shown that indoor Ring Main Units require little maintenance. Routine
visual inspections are conducted in conjunction with line surveys. The dominant
maintenance requirement is protective painting of outdoor equipment.
Outdoor Air Break Switches are also visually assessed. Major switchgear is
periodically inspected with Infrared thermal cameras, which are the main method of
identifying joint or contact heating problems. Unfortunately, for the majority of
switchgear, failure during operation is the first indication of a maintenance requirement.
8.12.4.4 Maintenance, replacement, and disposal plans
Maintenance and disposal of distribution network circuit breakers is the same as for the
circuit breakers in the substations (refer sections 8.12.3.3.4 and 8.12.3.3.6). A small
budget is set aside for the replacement of the old glass fuses with modern 11kV
dropout fuses. There are no other specific plans for replacement of distribution
switchgear – they are replaced as and when required, and the displaced items are
scrapped.
8.12.5 Distribution network
8.12.5.1 Pole line circuits
8.12.5.1.1
Description and capacity
Overhead lines form the backbone of the rural networks and account for the largest
proportion of rural network costs and interference to customer supply.
Most lines are rated at 11kV phase to phase. This is the most common voltage utilised
for distribution within New Zealand and has been the standard used in most of Otago
since the inception of reticulated electrical supply. A few circuits have been built at
22kV. This voltage has four times the capacity of 11kV and greatly reduces voltage
drop and losses. Increasingly it can be expected that this voltage will be used in the
future.
There are a few other voltages used specifically in conjunction with SWER.
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The majority of feeder lines are three wire three phase with all connections phase to
phase. A significant part of the OtagoNet lines reduce to two wire single phase circuits.
Single Wire Earth Return (SWER) is used on the more remote parts of the OtagoNet
system. SWER accounts for a large proportion of the Otago rural line length.
Our standard pole is now 11m concrete with a transverse top load capacity of 22kN. A
typical softwood pole is 11m 9kN symmetric top load capacity. 12m, 6kN and 12kN
poles are also relatively common. Conductors previously used are relative small such
as: Squirrel, Dog, Mink, Dog and Cockroach. The present AAAC standard allows for
five conductors for most situations:
Table 41 – Standard conductor sizes
Conductor Name
Chlorine
Helium
Iodine
Neon
Oxygen
8.12.5.1.2
Current Rating
Resistance
150A
250A
350A
500A
700A
0.86/km
0.38/km
0.24/km
0.12/km
0.09/km
Condition, age, and performance
Electrical distribution within Otago generally commenced around 1923. Lines are up to
70 years old. Most construction was undertaken in the 1930‘s and then in the 1950‘s
and 1960‘s. The 1970‘s and 1980‘s extensions were generally to transmit larger levels
of energy into the existing reticulated areas. New construction levels are presently very
low.
As a consequence of the wide time frame over which the network was constructed
there is a wide range of material and construction types. Hardwood poles gave way
firstly to concrete and then largely softwood until early 2008 when the standard was
changed to a commercially manufactured pre-stressed concrete pole. Copper
conductor was very common but this has generally been replaced by AAC and ACSR
conductor (All Aluminium Conductor and Aluminium Conductor Steel Reinforced)
based on a lesser cost. The present standard is AAAC1120 (All Aluminium Alloy
Conductor) based on price and resistance to corrosion. Maintenance requirements
vary by material.
Poles are the critical and most expensive component of line support. Most construction
in the 1930‘s utilised hardwood poles because of their availability and strength.
Hardwood poles cannot be effectively treated and are therefore prone to rot. Rot is
worst in the biologically active ground area. Rot is often not visible, such that many
poles that appeared healthy are in fact prone to failure. Typical life expectance of
hardwood poles varies from 30 years to 70 years. Around 20% of poles are hardwood.
Structurally the poles are very good, but cost and life expectancy limit hardwood pole
usefulness.
Concrete poles became prevalent in the 1950‘s. The strength of these poles was very
limited and failure from abnormal overload such as snow loading can be a problem.
They do not suffer from significant deterioration so maintenance requirements tend to
be limited.
From 1991 to 2008 softwood poles were introduced based on cost and strength.
These are treated timber with a minimum life expectancy of 50 years. Long term
durability has yet to be confirmed.
New concrete poles became the standard from 2008.
improved strength and expected long life.
The new design provides
Cross arms are generally hardwood and can suffer from deterioration. Life expectancy
varies, but since they are not in contact with the ground a minimum life of 40 years is
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expected. A few lines have been constructed in armless format, but generally this form
does not have acceptable mid span clearance. For most distribution lines hardwood
cross arms remain the preferred form as it enables longer spans.
Conductor life is limited by vibration (usually as the result of excessive tension) and
corrosion. Copper conductor is robust, but very expensive relative to aluminium.
ACSR conductor is prone to corrosion especially in coastal areas. All Aluminium Alloy
Conductor has been chosen as a standard conductor and is expected to limit the future
maintenance requirements of line conductor.
Figure 55 shows the age and length of distribution conductor on the network, while
Figure 56 shows the number and age of poles supporting the distribution lines on the
network. The wooden poles used for the 15 years to end 2008 are predominantly CCA
treated softwoods, while a small number of recent wooden poles will be traditional
hardwood where the additional strength is required. The majority of poles since late
2008 are the 11m standard Busck concrete pole.
Figure 55 - Distribution conductor
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Distribution Poles
1200
Concrete
Wood
1000
Steel
Unknown
Number of Poles
800
600
400
200
2012
Unknown
2010
2008
2006
2004
2002
2000
1998
1996
1994
1992
1990
1988
1986
1984
1982
1980
1978
1976
1974
1972
1970
1968
1966
1964
1962
1960
1958
1956
1954
1952
1950
1948
1946
1944
1942
1940
1938
1936
1934
1932
1930
1928
1926
1924
0
Commissioning Year
Figure 56 - Distribution Poles
8.12.5.1.3
Monitoring and procedures
The following specific procedures were included in the previous Asset Management
Plan and provided for information. As detailed earlier it is planned to undertake an
accelerated program of surveillance of all aspects of the network in the current year.
Following completion of this surveillance program the ongoing inspection and
surveillance program will be determined relative to safety requirements and driven by
information specific to the various components of the network.
General
Inspections of all the equipment listed, including 5 yearly circuit inspections, 6 monthly
transformer inspections/MDI recording and earth testing. Upgrading of earths is not
included in the scope but may be added at a later date.
Annual inspections of certain circuits selected due to their low reliability and/or high
importance.
Methodology
The SAIFI and SAIDI performance of each 11kV feeder and 33/66kV circuit is analysed
quarterly and classified as being either Level 1, 2 or 3, with Level 1 representing the
worst performance.
Those circuits in Level 1 are passed to a team consisting of OtagoNet and Contractor
staff for a detailed root cause analysis and to establish an inspection and maintenance
strategy. Those in Level 2 will be discussed by the team to reach an agreed
maintenance strategy and will then be closely monitored by PowerNet System Control.
The bullet points and table below provide an indication of the inspection and
maintenance regime.
Network Safety Inspection
Routine inspection to ensure public safety and earthing system integrity.
Defect Inspection
Detailed route and equipment inspection, generally conducted from ground level
and including an ultra-sound inspection. 20% of the feeders/circuits in the Contract
Area are inspected every year, so as to provide a five-yearly inspection cycle.
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Targeted Inspections
Selected feeders/circuits, including those in Level 1 and those supplying important
single customer loads and industrial areas, may require more frequent inspections.
The frequency of these inspections is decided on a reliability basis.
Annual Inspections
These inspections are rapid patrol generally achieved by a drive-by. The object is
to identify any obvious defects that may impact network reliability in the short term
(two years).
Thermal Inspections
Generally carried out at times of peak load on the network in order to identify hot
connections. A thermal inspection of connections on industrial and urban feeders
may be required within three days of a heavy fault near a substation.
Ultra-Sound Inspections
To be carried out in conjunction with Defect Inspections and Thermal Inspections.
Wood Pole Tests
Wood poles are assessed using industry standard methods.
Pole Top Inspections
This inspection is to identify any defects in the pole head, crossarm, insulators, tie
wire and associated hardware, connections and terminations, as required.
Table 42 – Inspection and maintenance regime
Level 1
Level 2
CBD and
Major
Industrial
Thermal inspection on fault
route
< 7 day response and
correction of urgent defects
< 3 month correction of
non-urgent defects
No loss of 11kV supply
All incidents Level 1
Industrial
Thermal, ultra sound and
defect inspection
< 1 month response and
correction of urgent defects
live line (LL)
< 3 month correction of
non-urgent defects
No loss of 11kV supply
Thermal, ultra sound and
defect inspection
< 1 month response and
correction of urgent defects
LL
< 3month correction of nonurgent defects
Defect inspection
< 2 month response and
correction of urgent defects
LL
< 6month correction of nonurgent defects
All incidents Level 1
Urban
Rural
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Thermal inspection
following heavy fault
Defect inspection
Defect correction LL
< 6month correction of
non-urgent defects
Defect inspection
< 2 month response
and correction of urgent
defects LL
< 6month correction of
non-urgent defects
Level 3
Annual thermal inspection at
peak loads, including link
boxes
Annual cable route inspection
5 yearly defect inspection
< 6 month correction of nonurgent defects
No loss of 11kV supply
Annual thermal inspection at
peak loads
5 yearly defect inspection, LL
pole top inspection and pole
test
< 6 month correction of nonurgent defects
Annual Inspection
5 yearly thermal and defect
inspection and pole test
10 year LL pole top
inspection
12 month correction of nonurgent defects
Annual Inspection
5 yearly defect
inspection/pole test
12month correction of nonurgent defects
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8.12.5.1.4
Maintenance plan
Maintenance of distribution lines makes up a large proportion of the annual
maintenance spend. Defects found in the pole head, crossarm, insulators, tie wire and
associated hardware, connections, or terminations are to be repaired as required.
8.12.5.1.5
Replacement plan
The high set-up costs for lines replacement works means that it is more economical to
renew sections of line at a time where specific poles or hardware require replacement
and the general state of the remaining poles is poor. After the initial renewal
programmes are completed, it is anticipated that renewal will shift towards individual
pole replacement or pole top refurbishment.
8.12.5.1.6
Disposal plan
There are no plans for disposal of any circuits under maintenance.
8.12.5.2 Distribution cables
8.12.5.2.1
Description and capacity
Most cables in the OtagoNet network tend to be one or three core aluminium
conductor, XLPE insulated, medium duty copper screen and HDPE sheath. Because
of the very short circuit lengths generally associated with cable supply, voltage drop is
seldom a problem so design limits tend to be that of the cable current rating. XLPE
cables operate acceptably at significantly higher temperatures to paper insulated
cables therefore giving a more economic cable form.
The standard sizes and typical ratings of cables are listed below.
Table 43 – Standard cable sizes
Cable type
2
1 x 3C 35mm Al XLPE
2
1 x 3C 95mm Al XLPE
2
1 x 3C 185mm Al XLPE
2
3 x 1C 300mm Al XLPE
Current Rating
Resistance
135A
240A
320A
420A
0.868/km
0.320/km
0.164/km
0.100/km
Cable rating is very much affected by the thermal parameters of the surrounding
media. Most distribution cables are direct buried to limit the temperature rise
associated with installation in ducts. Backfill material is almost always the removed
material, so no control is available over thermal resistively. Most backfill tested
appears to have similar characteristics to the standard quoted figures upon which the
nominal cable ratings are determined.
Lightning protection (surge diverters) is fitted where cables terminate to overhead lines.
Lightning is a dominant cause of cable failure.
8.12.5.2.2
Condition, age, and performance
The OtagoNet network is predominately overhead distribution with limited short lengths
of 11kV cable being installed in recent years.
Failure of cable is very rare. The most common failure modes are joints, terminations,
lightning and external mechanical damage. Consequently little proactive maintenance
is deemed necessary on the cables themselves.
The MV cable age profile is shown in Figure 57.
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Figure 57 - MV Cables
8.12.5.2.3
Monitoring and procedures
Condition monitoring is not considered to be cost-effective for solid insulated cables.
Cables will generally be left undisturbed unless maintenance or upgrade is required.
Upgrades may be required due to increased loading or rearrangement of circuits.
Failure analysis is the prime tool utilised to identify possible maintenance or remedial
action.
8.12.5.2.4
Maintenance plan
Several types of cable termination have been identified as a common cause of failure.
The breakout arrangements on these terminations are being replaced.
8.12.5.2.5
Replacement plan
There are no plans to replace existing cables.
8.12.5.2.6
Disposal plan
No cables have been identified for disposal.
8.12.6 Distribution transformers
8.12.6.1 Description and capacity
The concept of electrical transformers was central to the development of the present
integrated electricity systems found throughout the world. Transformers provide a
relatively economic means to convert voltage and so limit electrical losses and volt
drop and thereby allow distribution of electricity over large areas. Distribution
transformers are the present devices used to convert distribution level voltages to
reticulation level voltages directly usable by customers.
The majority of rural transformers supply one or two customers in close proximity.
Since many rural properties are spaced kilometres apart there are a great number of
customers supplied from an individual transformer.
The most common rural
transformer sizes are 10kVA to 30kVA. The most economic electrical supply
arrangement typically tends to have around 50 domestic customers connected via LV
circuits to a single common transformer. Consequently the most common urban
transformer ratings are 200kVA to 300kVA.
The primary side voltage ratings must match the distribution voltages. Consequently
most distribution transformers have a primary rating of 11kV phase to phase. A few
connect directly to 33kV subtransmission and are therefore rated at 33kV. There are a
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significant number of Single Wire Earth Return (SWER) transformers in the systems in
the OtagoNet region. These are generally rated at 11kV or 22kV phase to ground.
As a result of the different optimum ratings and number of phases to the suit the
connected loads OtagoNet employs a variety of transformer configurations and ratings.
This has significant implications for stocking levels and replacement availability. Most
transformers are purchased with Off Load Tap Change (FLTC34) systems to allow
some adjustment of voltage.
There are four general forms of transformers. Most rural transformers in the range of
5kVA to 50kVA are pole hanger mounted. These have brackets that allow easy
installation of the transformer near the pole top, giving a very economic installation.
Some large outdoor transformers are still in service, mounted on specially made two
pole structures but these carry the risks from seismic strength requirements and oil
spills under car vs pole accidents and so these units are being replaced with ground
mounted transformers over time.
A third form of transformer is the kiosk unit. These are freestanding ground mount
transformers that have cubicles included to enclose associated switches and
terminations. These are the most common form of urban transformer. A similar form is
a cable entry transformer that has no cubicles for switchgear. Cables are terminated in
small termination boxes.
Transformers are fairly robust devices. It is economic to overhaul many units for reuse
on the system. Consequently there are quite a number of old units still in use as
shown in the age profile graph.
Transformers have for many years been purchased on a total cost economic basis.
This includes capitalization of losses. Losses now form part of the MIPS legislation
that specifies maximum allowable equipment losses.
Earthing at the transformer supply is an important safety system and earthing costs are
significant. Earthing comes in two general forms. In urban areas with close proximity
between transformers the prime format is to ensure interconnection of earth systems to
create a large low resistance grid. In rural areas the main purpose is to create a
connection to earth that has a sufficiently low resistance to ensure that protection will
operate to clear any fault.
Urban design targets limiting earth potential rise (EPR) to 650V and ensuring Touch
Voltages are acceptable. 70mm2 earth conductor is used to allow for the relatively
large fault currents.
Rural design attempts to achieve a 10 earth resistance. 25mm2 conductor is used,
suitable for the lower fault currents.
8.12.6.2 Condition, age, and performance
The following chart shows the age and size of the distribution transformers on the
network grouped by both size and age.
The age profile of earth system is similar to that of transformers but earths are tested
on an ongoing basis.
34
On Load Tap Changer is OLTC, so use FLTC for Off Load.
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Figure 58 - Distribution Transformers
8.12.6.3 Monitoring and procedures
As transformer failure (other than through lightning
damage) is not a major cause of outages most
maintenance is based on inspections. Age of assets is
deemed to have greater impact on maintenance
requirements and inspection strategies are adjusted to
allow for this. Small rural transformers are inspected
together with line circuits on a five year basis. Urban
transformers and large rural transformers are inspected
on a six monthly basis and Maximum Demand Indicators
are read where fitted.
The typical maintenance requirement is for limited tank and bushing repair or full
refurbishment. This can usually be determined from visual inspection. A five year
cycle of inspection is well within typical deterioration rates. Catastrophic failure is very
random in nature and no economic means are available to proactively determine risk of
failure. The six monthly inspections are largely to check for overload and problems
with miscellaneous equipment such as fuse or cable connection heating.
Transformers are replaced on site with new or refurbished transformers. Removed
transformers are individually assessed for repair, refurbishment or retirement.
A five yearly earthing inspection regime is in place. The results are stored in the GIS
system and maintenance is planned around the sites with the worst results.
Rewirable HV fuses are replaced with standard drop-out cartridge types to improve
future reliability as circumstances allow (ie the linesman is at the transformer for other
work).
8.12.6.4 Maintenance Plan
There are no plans for any large scale maintenance of transformers. All work consists
of routine inspection and maintenance.
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8.12.6.5 Replacement Plan
There are no specific plans to replace transformers
although we expect to replace on average 100
transformers per annum giving an average transformer
life of 45 years. Older small units (<10kVA) are replaced
in association with line replacements or maintenance.
8.12.6.6 Disposal Plan
Oil is removed from scrapped transformers and the
remainder of the transformer is sold as scrap metal.
Bushings are sometimes kept where these may prove useful as spares. High loss, old,
small and non-standard transformers removed from service are invariably scrapped.
8.12.7 LV network
8.12.7.1 Pole line circuits
8.12.7.1.1
Description and capacity
Construction is a mix of underbuilt (on 11 kV lines) and flat top construction with 2 to 5
wires. Copper was the dominant conductor but LV lines are now constructed in
Aluminium. The conductor size is relatively small in the older lines due to the typically
low loading of the time and this often results in poor voltage delivery at times of higher
network loading.
Underground reticulation became dominant for new urban extensions from the 1960‘s,
but overhead reticulation has remained in most urban areas noting there has been little
new subdivision development across the network. A change in overhead construction
has been the limited use of Aerial Bundled Conductor (ABC) since around 1990 which
is sometimes applied in circumstances of light load and generally with a view to avoid
tree contact problems.
The dominant bare wire conductor sizes range from 14mm2 (7/16 Cu) to 40mm2
(19/16Cu). ABC uses aluminium conductor of 35mm2, 50mm2 and 95mm2 crosssectional-areas. Some bare aluminium conductor was used prior to the introduction of
ABC.
8.12.7.1.2
Condition, age, and performance
Most overhead reticulation is relatively old, undersized and in poor condition.
Information on the age profile of the LV lines is incomplete; however the data that does
exist within the information system is shown in Figure 59 and Figure 60 for the LV
conductor and LV poles respectively.
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Figure 59 – Low voltage conductor
Figure 60 - Low voltage poles
Significant renewal and upgrading is planned to maintain or remedy customer supplies
to meet regulatory voltage levels.
8.12.7.1.3
Monitoring and procedures
LV line inspections are carried out in the same manner as for distribution lines – refer
section 8.12.5.1.3.
8.12.7.1.4
Maintenance plan
There are no plans for any large scale maintenance. All work consists of routine
inspection and maintenance. LV overhead reticulation is managed on a similar basis to
the MV distribution, although with a lesser priority.
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8.12.7.1.5
Replacement plan
There are no plans for large scale overhead line replacements or undergrounding.
8.12.7.1.6
Disposal plan
See overhead distribution.
8.12.7.2 Cable circuits
8.12.7.2.1
Description and capacity
New reticulation in urban areas is now undertaken using underground cable circuits.
Cable is generally aluminium conductor with a copper neutral screen. Standard sizes
are 95mm2, 185mm2 with a small amount of 300mm2 as the maximum size. The
dominant selection criterion is to limit voltage drop. Typically cables are loaded to 30%
of their current capacity.
The combination of aluminium cable and copper based switchgear requires rigid
adherence to proper termination procedures, generally utilising bimetal compression
joints.
8.12.7.2.2
Condition, age, and performance
Few problems are experienced with underground cable. Most faults are due to joints
and external mechanical damage. The cable network is relatively young.
The LV cable age profile is shown in Figure 61. It should be noted that age profile
information on LV cables is incomplete.
Figure 61 – Low Voltage cables
8.12.7.2.3
Monitoring and procedures
Little monitoring is conducted on cables. Failure analysis is the prime tool utilised to
identify possible maintenance or remedial action.
8.12.7.2.4
Maintenance plan
Minor works only.
8.12.7.2.5
Replacement plan
No planned replacements.
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8.12.7.2.6
Disposal plan
No cables have been identified for disposal.
8.12.8 Other system fixed assets
8.12.8.1 Customer connection assets
OtagoNet has 14,812 customer connections; all of OtagoNet‘s ―other assets‖ convey
energy to these customer connections and essentially are a cost to OtagoNet that has
to be matched by the revenue derived from the customer connections. These
customer connections generally involve assets ranging in size from a simple fuse,
mounted on a pole or in a distribution pillar, to dedicated lines and transformer
installations supplying single large customers. The connection type and number are
shown in Table 4435.
In most cases the fuse forms the demarcation point between OtagoNet‘s network and
the customer‘s assets (the ―service main‖) and this is usually located at or near the
physical boundary of the customer‘s property.
Table 44 - Connections
Connection type
1 (residential)
2 (commercial)
3 (commercial – max.
demand)
4 (commercial – major
customers)
5 (unmetered)
6 (street lights)
7&8 (low user)
Total
Total
Percent
8394
3384
56.7%
22.8%
46
0.3%
23
0.2%
88
9
2868
14,812
0.6%
0.1%
19.4%
100.0%
8.12.8.2 Service Mains
8.12.8.2.1
Description and capacity
Service mains are generally the responsibility of individual customers with the
demarcation point at the local pillar box. However a large proportion of rural service
mains are MV. MV circuits are generally not a specialty of customers or their
electricians and consequently ownership of most MV service mains now resides with
OtagoNet.
Typical MV service mains will be of 2 or 3 wire squirrel conductor, possibly 2 to 5 spans
long. In many cases there will be drop out fuses protecting both the line and the
transformer.
8.12.8.2.2
Condition, age, and performance
There is not enough information available to comment on the age of service mains; this
information was lost amidst past ownership changes.
8.12.8.2.3
Monitoring and procedures
A five yearly inspection regime is in place, as required for safety and forward planning.
Similar methods are used as with the distribution circuits. This inspection is limited to
circuits identified as being owned by OtagoNet.
35
Connection type codes as per FY2013 Information Disclosure
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ASSET LIFECYCLE
8.12.8.2.4
Maintenance, replacement and disposal
Little maintenance is planned. OtagoNet have a policy of replacing rewirable service
fuses with standard cartridge types as circumstances allow.
8.12.9 Mobile generation and mobile substations
None – but PowerNet makes a 275kW and/or a 350kW diesel generator available for
rent when necessary for planned work. OtagoNet has plans to purchase its own
additional mobile generator and larger generator step-up transformer in the FY2015
year as discussed in the development section of this plan.
8.12.10
Other assets
None that are known.
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OUR PROCESSES AND SYSTEMS
9.
Processes and systems
The engine of OtagoNet‘s asset management activities lie with the detailed processes
and systems that reflect its thinking, manifest in its policies and strategies, plan and
manage the execution of its works and record the cost and performance of the
services, all of which ultimately shape the nature and configuration of the fixed assets.
OtagoNet‘s processes and systems exist within a hierarchy of value illustrated in Figure
62 which describes the typical sorts of information residing within the business
including the intellectual capital of its employees.
Wisdom
Hard to codify
Understanding
Knowledge
Information
Easier to codify
Data
Figure 62 - Hierarchy of Data
The bottom two layers of the hierarchy tend to relate strongly to the asset and
operational data which reside in the GIS, SCADA, outage database, and works
management systems and where the summaries of this data form one part of the
decision making process.
The third layer - knowledge - tends to be more broad and general in nature and may
include such things as technical standards that codify accumulated knowledge into a
single useful document.
The top two layers tend to be very broad and often quite fuzzy. It is at this level that
key organisational strategies and planning processes reside. As indicated in Figure 62,
these are generally hard to codify, and thus correct application is heavily dependent on
employing skilled people within the organisation.
9.1
Asset knowledge
OtagoNet has considerable knowledge on its assets location (although not to sufficient
accuracy), what they are made of, the asset capacity and generally how old they are
(but mostly installation ages rather than both manufactured date and last installation
date which is preferable). However, it lacks sufficient detail on the current condition and
fitness for purpose, particularly for the distributed network assets, and this is a current
focus for both system and process development (as well as the physical process of
populating this data through field inspection)
OtagoNet‘s asset data resides in three key locations:
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OUR PROCESSES AND SYSTEMS
Some asset description, location, age and condition information of lines, cables
and field devices resides in the Geographical Information System (GIS). This also
includes links/layers for land ownership and use data derived from Land
Information NZ.
Asset descriptions, details, age, cost and works history of identifiable components
resides in the Asset Management System (AMS).
Asset operational data such as loadings, voltages, temperatures and switch
positions reside in the Supervisory Control and Data Acquisition (SCADA).
Reliability performance is collected in the outages database
An additional class of data (essentially commercial in nature) includes such data as
customer details, consumption and billing history.
All data systems are connected through key fields.
9.2
Asset management tools
A variety of tools and procedures are utilised by OtagoNet to best manage the assets.
GIS and AMS software packages are used to store, map and evaluate asset data and
manage the work undertaken on them.
Technical, operational and business
procedures are managed under a document quality system. The outputs of these
systems combine to produce both long and medium term plans and the on-going day to
day planning and control of the business.
9.2.1 GIS
An Intergraph based Geographic Information System is utilised to store and map data
on individual components of the network. This focuses primarily on cables, conductors,
poles, transformers, switches, fuses and similar geographically dispersed items. Large
composite items such as substations are managed by more traditional techniques such
as drawings and individual item test reports.
Equipment capacity, age and condition are listed by point or segment. The data is
used to provide base maps of existing equipment, for extensions to the network, for
maintenance scheduling and similar functions. The system allows overlays of terrestrial
maps and land information.
9.2.2 AMS
WASP (Works, Assets, Scheduling, Purchasing) has been replaced by Maximo in
FY2013 as the asset management system (AMS). Maximo has links to the financial
management system and is also linked to the GIS system. Maximo consolidated asset
management information from WASP and a range of smaller databases, to offer
improved data validation functionality. Maximo tracks major assets and is the focus for
work packaging and scheduling.
Data for the AMS is collected by the Network Movement Notice that records every
movement of serial numbered assets. Some updating of data is obtained when sites
are checked, maintained or upgraded and during other processes like collecting and
verifying data for valuations.
Most day to day operations are managed using Maximo. Maintenance regimes
(including time-based maintenance and testing work), field inspections and customer‘s
orders produce tasks and/or estimates, that are sometimes grouped, and a ‗work
package‘ issued from Maximo.
9.2.3 Faults Database
All outages are logged into a database which is used to provide regulatory information
and statistics on networks performance. Reports from this system are used to highlight
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OUR PROCESSES AND SYSTEMS
poorly performing feeders, which are then analysed to determine if it is a maintenance
issue or if reliability may be enhanced by other means.
9.3
Improving the quality of the data and processes
Because of the importance of the availability of accurate information for maximising
customer reliability and efficiency of expenditure and ensuring regulatory compliance it
is intended to invest in the order of $1m in the 2014/15 financial year into the
development of these systems.
9.3.1 Asset condition
Condition information on the distributed assets is not presently reliable or fully useful
and a revision of both the inspection templates, the means of automatically up-loading
the captured data, and the processes for recovering and applying that data are being
re-developed by OtagoNet. Condition information is crucial to both network safety and
capital governance and past systems have been found wanting with assets discovered
in very poor condition or expressed through unassisted pole failures.
OtagoNet has therefore commenced a re-development of the condition inspection
regime including revision of it inspection templates, the means of automatic uploading
of the collected data, and the processes for data analysis that will support both the
measurement of risk and the prioritisation of work.
9.3.2 Attribute location
The initial population of the GIS data was through uplifting asset locations off existing
drawings and maps and where asset locations may have been noted as being off-set
from road centre lines etc. This results in assets being generally placed but the location
accuracy is poor with assets showing on the wrong side of roads or off roads in private
land when this is not the case. Asset location is being progressively improved as the
new condition inspections use field GPS locating devices to verify location.
9.3.3 Attribute description
Some delays occur between job completion (eg a new connection) and updating into
the GIS/AMS. Not all low voltage lines and cables have been captured and
improvement of this data is on-going.
9.3.4 Attribute age
Some old components are missing age information altogether. Additionally, a number
of assets only list the last installation date rather than both an installation date and a
manufactured date making determination of the true age unreliable.
9.3.5 Faults data
Presently there is no link between the GIS and the recording of faults so fault locations
cannot be plotted and hence fault density/clustering cannot be illustrated.
9.4
Use of the data
Data is used for either making decisions within the business or providing data to
external entities – for example regulatory disclosure. This data is almost always
aggregated and processed in order to make decisions e.g. a decision to replace a zone
substation transformer will be based on an aggregation of loading data for the
formation of trends, age and condition of the transformer, maintenance cost history etc.
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OUR PROCESSES AND SYSTEMS
9.5
Decision making
For efficiency, compliance and consistency, many lower level processes are codified
into such documents as technical standards, policies, processes, operating
instructions, templates, spreadsheet models etc., much as listed in section 0 following.
Higher level strategy and business and asset management planning is undertaken less
systematically as it requires assessment of conflicting interests, in-depth analysis of
comparative performance and the setting of targets and budgets that drive the
business towards the corporate objectives.
The source, roles and interaction of each component of the overall information
processes are illustrated below in Figure 63.
Commercial
info –
customer
number,
consumption
etc
Customer
initiated
change load
Parallel
“information
asset”
Externally
initiated
change –
weather,
faults,
generators
Operational
info – switch
status, faults,
load, voltage
etc
Repositories –
paper, PCs,
servers, brains
etc
Network
assets
Asset info –
description,
age, location,
condition,
history etc
Internally initiated change
– operational,
maintenance, capital
Internal decision
processes
Guides to decision making
– policies, procedures,
manuals, standards,
regulations, legislation,
codes, plans etc
Info to
external
parties
Figure 63 - Key information systems and processes
Asset Management Plan
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OUR PROCESSES AND SYSTEMS
9.6
Key processes and systems
Procedures and process documentation available to OtagoNet are listed following.
9.6.1 Operating processes and systems
Commissioning Network Equipment
Network Equipment Movements
Planned Outages
Network Faults, Defects and Supply Complaints
Major Network Disruptions
Use of Operating Orders (O/O)
Control of Tags
Access to Substations and Switchyards
Operational Requirements for Confined Space Entry
Operating Authorisations
Radio Telephone Communications
Operational Requirements for Live Line Work
Control of SCADA Computers
Machinery Near Electrical Works
Customer Fault Calls/Retail Matters
Site Safety Management Audits
Meter/Ripple Receiver Control
PNM-61
PNM-63
PNM-65
PNM-67
PNM-69
PNM-71
PNM-73
PNM-75
PNM-76
PNM-77
PNM-79
PNM-81
PNM-83
PNM-85
PNM-87
PNM-88
PNM-121
9.6.2 Maintenance processes and systems
Control of Network Spares
Transformer Maintenance
Maintenance Planning
Network Lines Equipment Replacement
PNM-97
PNM-99
PNM-105
PNM-106
Other maintenance is to manufacturers‘ recommendations or updated industry
practice.
9.6.3 Renewal processes and systems
Network Development
Design and Development
PNM-113
PNM-114
9.6.4 Up-sizing or extension processes and systems
Network Development
Design and Development
Processing Installation Connection Applications
Easements
PNM-113
PNM-114
PNM-123
PNM-131
9.6.5 Retirement processes and systems
Disconnected and/or Discontinued Supplies
PNM-125
9.6.6 Performance measuring processes and systems
9.6.6.1 Faults
All faults are entered into the faults database and reported monthly to the Governing
Committee, together with details of all the planned outages.
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OUR PROCESSES AND SYSTEMS
9.6.6.2 Financial
Monthly reports out of the Finance One (F1) financial system provide measurement of
revenues and expenses for the OtagoNet line business unit. Project costs are
managed through the accounting systems with project managers managing costs
through the AMS. Interfaces between F1 and AMS track estimates and costs against
assets.
9.6.6.3 Customer
Customer statistics are monitored by a Customer Database system, developed by ACE
computers, which interfaces with the National Registry to provide and obtain updates
on customer connections and movements. Customer consumption is monitored by
another ACE Computers system ‗BILL‘. BILL receives monthly details from retailers
and links this to the customer database.
9.6.6.4 Service levels
Customers that have had work done are sent a survey form at the end of the job.
Results are monitored and any comments given are reviewed and responded to.
9.6.7 Other business processes
In addition to the above processes that are specific to life cycle activities, OtagoNet has
a range of general business processes available to it that guide activities such as
evaluating tenders and closing out contracts:
Setting Up the Contract
Tender Evaluation
Contract Formation
Construction Approval
Materials Management
Contract Control
Contract Close Out
Customer Satisfaction
External Contracting
Drawing Control
Network Operational Diagram/GIS Control
Control of Operating and Maintenance Manuals
Control of External Standards
Control of Power Quality Recorders
Quality Plans
Health and Safety
Accidents and Incidents
Design and Development
Network Purchasing
Network Pricing
Customer Service Performance
Incoming and Outgoing Mail Correspondence
Asset Management Plan
PNM-10
PNM-15
PNM-20
PNM-25
PNM-30
PNM-35
PNM-40
PNM-50
PNM-60
PNM-89
PNM-91
PNM-93
PNM-95
PNM-103
PNM-107
PNM-109
PNM-111
PNM-114
PNM-115
PNM-117
PNM-119
PNM-129
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RESOURCING OUR BUSINESS
10. Resourcing the business
Resourcing an operation such as OtagoNet in rural New Zealand imposes its unique
challenges.Because of the relatively small customer base and revenue, it is imperative
all resources are utilised efficiently.
It is intended to increase the level of OtagoNet staff in Balclutha in the 2015 year to
better serve the interests of OtagoNet and its customers.
OtagoNet has agreements with PowerNet and Marlborough Lines to provide
administration, accounting and IT services (including control room services) and
engineering support respectively and OPSL to provide Network Contractor services.
Should workload be beyond what OPSL can provide then other contractors will be
contracted for specific projects.
Provision of these services is secured through the management services contracts
which is monitored and managed by the OtagoNet governing committee.
10.1 Future resourcing requirements
OtagoNet‘s main contractor, OPSL has adequate resources for the present work
program requirements The forecast budget for FY2015 is approximately $16m capital
and $4.5m maintenance and is forecast to continue at these levels for a number of
years. This expenditure represents a step increase on previous capital expenditure as
described within this plan. However, OtagoNet have no reason to believe the works set
out in this plan for the next forecast year cannot be achieved and sets plans for both
the execution and management of that work including the contracting of resources as
required.
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A.
Appendix – AMP Disclosure Requirements
The following table sets out the Commerce Commission requirements for disclosed
asset management plans and identifies where these requirements are met within this
plan.
Clause
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
3
3.1
3.2
3.3
3.3.1
3.3.2
3.3.3
3.3.4
3.3.5
3.4
3.5
3.6
3.6.1
3.6.2
3.6.3
3.6.4
3.7
Requirement
The core elements of asset management—
A focus on measuring network performance, and managing the assets to
achieve service targets;
Monitoring and continuously improving asset management practices;
Close alignment with corporate vision and strategy;
That asset management is driven by clearly defined strategies, business
objectives and service level targets;
That responsibilities and accountabilities for asset management are
clearly assigned;
An emphasis on knowledge of what assets are owned and why, the
location of the assets and the condition of the assets;
An emphasis on optimising asset utilisation and performance;
That a total life cycle approach should be taken to asset management;
That the use of ‗non-network‘ solutions and demand management
techniques as alternatives to asset acquisition is considered.
Contents of the AMP
3. The AMP must include the followingA summary that provides a brief overview of the contents and highlights
information that the EDB considers significant
Details of the background and objectives of the EDB‘s asset
management and planning processes
A purpose statement whichmakes clear the purpose and status of the AMP in the EDB‘s
asset management practices. The purpose statement must also
include a statement of the objectives of the asset management
and planning processes
states the corporate mission or vision as it relates to asset
management
identifies the documented plans produced as outputs of the
annual business planning process adopted by the EDB
states how the different documented plans relate to one another,
with particular reference to any plans specifically dealing with
asset management
includes a description of the interaction between the objectives
of the AMP and other corporate goals, business planning
processes, and plans
Details of the AMP planning period, which must cover at least a projected
period of 10 years commencing with the disclosure year following the
date on which the AMP is disclosed
The date that it was approved by the directors
A description of stakeholder interests (owners, consumers etc) which
identifies important stakeholders and indicateshow the interests of stakeholders are identified
what these interests are
how these interests are accommodated in asset management
practices
how conflicting interests are managed
A description of the accountabilities and responsibilities for asset
management on at least 3 levels, including-
Asset Management Plan
AMP Response
Section(s)
3, 5, 6
3, 5, 6, 9
1
5, 6
1.8,
2, 8
3, 5
8,
7.7
0.
1.
1.1
1.2,
1.3, 1.4
1.3.3, 1.4.7
1.4,
1.5,
1.6,
1.6,
1.7,
1.7.1,
1.7.2,
1.7.3,
1.7.4,
1.8,
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3.7.1
3.7.2
3.7.3
3.8
3.8.1
3.8.2
3.8.3
3.8.4
3.8.5
3.9
3.10
3.11
3.12
3.13
3.13.1
3.13.2
3.13.3
3.14
governance—a description of the extent of director approval
required for key asset management decisions and the extent to
which asset management outcomes are regularly reported to
directors
1.8.1, 1.8.5
executive—an indication of how the in-house asset management
and planning organisation is structured
1.8.2,
field operations—an overview of how field operations are
managed, including a description of the extent to which field
work is undertaken in-house and the areas where outsourced
contractors are used
1.8.3, 1.8.4
All significant assumptions
1.6, Apx C
quantified where possible
7.8.4.1, Apx C
clearly identified in a manner that makes their significance
understandable to interested persons, including
a description of changes proposed where the information is not
based on the EDB‘s existing business
the sources of uncertainty and the potential effect of the
uncertainty on the prospective information
Apx C
the price inflator assumptions used to prepare the financial
information disclosed in nominal New Zealand dollars in the
Report on Forecast Capital Expenditure set out in Schedule 11a
and the Report on Forecast Operational Expenditure set out in
Schedule 11b.
A description of the factors that may lead to a material difference
between the prospective information disclosed and the corresponding
actual information recorded in future disclosures
1.6, Apx C
An overview of asset management strategy and delivery
1.4, 1.5
An overview of systems and information management data
9, 9.5, 9.6
To support the AMMAT disclosure and assist interested persons
to assess the maturity of systems and information management,
the AMP should describe- the processes used to identify asset
management data requirements that cover the whole of life cycle
of the assets; the systems used to manage asset data and
where the data is used, including an overview of the systems to
record asset conditions and operation capacity and to monitor
the performance of assets; the systems and controls to ensure
the quality and accuracy of asset management information; and
the extent to which these systems, processes and controls are
integrated.
A statement covering any limitations in the availability or completeness of
asset management data and disclose any initiatives intended to improve
the quality of this data
9,
A description of the processes used within the EDB for1.8,
managing routine asset inspections and network maintenance
9.5.7, 8.3
planning and implementing network development projects
9.5.7, 7,
measuring network performance.
9.5.6, 3
An overview of asset management documentation, controls and review
processes
9,1.4
To support the AMMAT disclosure and assist interested persons
to assess the maturity of asset management documentation,
controls and review processes, the AMP should- (i) identify the
documentation that describes the key components of the asset
management system and the links between the key components;
(ii) describe the processes developed around documentation,
control and review of key components of the asset management
system; (iii) where the EDB outsources components of the asset
management system, the processes and controls that the EDB
uses to ensure efficient and cost effective delivery of its asset
management strategy; (iv) where the EDB outsources
components of the asset management system, the systems it
uses to retain core asset knowledge in-house; and (v) audit or
review procedures undertaken in respect of the asset
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RESOURCING OUR BUSINESS
management system.
3.15
3.16
3.17
4
4.1
4.1.1
4.1.2
4.1.3
4.1.4
4.2
4.2.1
4.2.2
4.2.3
4.2.4
4.2.5
4.2.6
4.3
An overview of communication and participation processes
To support the AMMAT disclosure and assist interested persons to
assess the maturity of asset management documentation, controls and
review processes, the AMP should- (i) communicate asset management
strategies, objectives, policies and plans to stakeholders involved in the
delivery of the asset management requirements, including contractors
and consultants; (ii) demonstrate staff engagement in the efficient and
cost effective delivery of the asset management requirements.
The AMP must present all financial values in constant price New Zealand
dollars except where specified otherwise;
The AMP must be structured and presented in a way that the EDB
considers will support the purposes of AMP disclosure set out in clause
2.6.2 of the determination.
Assets covered
The AMP must provide details of the assets covered, includinga high-level description of the service areas covered by the EDB and the
degree to which these are interlinked, includingthe region(s) covered
identification of large consumers that have a significant impact
on network operations or asset management priorities
description of the load characteristics for different parts of the network
peak demand and total energy delivered in the previous year, broken
down by sub-network, if any.
a description of the network configuration, includingidentifying bulk electricity supply points and any distributed
generation with a capacity greater than 1 MW. State the existing
firm supply capacity and current peak load of each bulk
electricity supply point;
a description of the subtransmission system fed from the bulk
electricity supply points, including the capacity of zone
substations and the voltage(s) of the subtransmission
network(s). The AMP must identify the supply security provided
at individual zone substations, by describing the extent to which
each has n-x subtransmission security or by providing alternative
security class ratings;
a description of the distribution system, including the extent to
which it is underground;
a brief description of the network‘s distribution substation
arrangements;
a description of the low voltage network including the extent to
which it is underground; and
an overview of secondary assets such as protection relays,
ripple injection systems, SCADA and telecommunications
systems.
To help clarify the network descriptions, network maps and a
single line diagram of the subtransmission network should be
made available to interested persons. These may be provided in
the AMP or, alternatively, made available upon request with a
statement to this effect made in the AMP.
If sub-networks exist, the network configuration information referred to in
subclause 4.2 above must be disclosed for each sub-network.
Asset Management Plan
1.7.5,
0.11
Complies
2,
2.1,
2.1.1,
2.1.3,
2.1.4, 2.1.5,
2.1.6,
2.2,
2.2.1,
2.2.2, 2.2.3,
2.2.4,
2.2.5,
2.2.6,
2.2.7,
2.2.3,
Not applicable
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4.4
4.4.1
4.4.2
4.4.3
4.4.4
4.5
4.5.1
4.5.2
4.5.3
4.5.4
4.5.5
4.5.6
4.5.7
4.5.8
4.5.9
4.5.10
4.5.11
5
6
7
7.1
7.2
8
9
10
11
11.1
The AMP must describe the network assets by providing the following
information for each asset categoryvoltage levels;
description and quantity of assets;
age profiles; and
a discussion of the condition of the assets, further broken down
into more detailed categories as considered appropriate.
Systemic issues leading to the premature replacement of assets
or parts of assets should be discussed.
The asset categories discussed in subclause 4.4 above should include at
least the followingSub transmission
Zone substations
Distribution and LV lines
Distribution and LV cables
Distribution substations and transformers
Distribution switchgear
Other system fixed assets
Other assets;
assets owned by the EDB but installed at bulk electricity supply
points owned by others;
EDB owned mobile substations and generators whose function is
to increase supply reliability or reduce peak demand; and
other generation plant owned by the EDB.
Service Levels
The AMP must clearly identify or define a set of performance indicators
for which annual performance targets have been defined. The annual
performance targets must be consistent with business strategies and
asset management objectives and be provided for each year of the AMP
planning period. The targets should reflect what is practically achievable
given the current network configuration, condition and planned
expenditure levels. The targets should be disclosed for each year of the
AMP planning period.
Performance indicators for which targets have been defined in clause 5
above must include SAIDI and SAIFI values for the next 5 disclosure
years.
Performance indicators for which targets have been defined in clause 5
above should also includeConsumer oriented indicators that preferably differentiate between
different consumer types;
Indicators of asset performance, asset efficiency and effectiveness, and
service efficiency, such as technical and financial performance indicators
related to the efficiency of asset utilisation and operation.
The AMP must describe the basis on which the target level for each
performance indicator was determined. Justification for target levels of
service includes consumer expectations or demands, legislative,
regulatory, and other stakeholders‘ requirements or considerations. The
AMP should demonstrate how stakeholder needs were ascertained and
translated into service level targets.
Targets should be compared to historic values where available to provide
context and scale to the reader.
Where forecast expenditure is expected to materially affect performance
against a target defined in clause 5 above, the target should be
consistent with the expected change in the level of performance.
Network Development Planning
AMPs must provide a detailed description of network development plans,
including—
A description of the planning criteria and assumptions for network
development;
Asset Management Plan
8.12,
8.12,
8.12,
8.12
8.12
8.12.2,
8.12.3,
8.12.5, 8.12.7,
8.12.5,
8.12.6,
8.12.4,
8.12.8,
8.12.10,
8.12.1,
8.12.9,
8.12.10,
6,
6.5.1,
6.1.2,
6.3,
3, 4, 6.1.1, 6.1.2,
6.3.2
5.1, 5.2.1, 5.2.3
6.1.1
7
7.1,
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Planning criteria for network developments should be described logically
and succinctly. Where probabilistic or scenario-based planning
techniques are used, this should be indicated and the methodology
11.2
briefly described;
A description of strategies or processes (if any) used by the EDB that
promote cost efficiency including through the use of standardised assets
11.3
and designs;
The use of standardised designs may lead to improved cost efficiencies.
11.4
This section should discuss11.4.1
the categories of assets and designs that are standardised;
11.4.2
the approach used to identify standard designs.
A description of strategies or processes (if any) used by the EDB that
11.5
promote the energy efficient operation of the network.
A description of the criteria used to determine the capacity of equipment
11.6
for different types of assets or different parts of the network.
A description of the process and criteria used to prioritise network
development projects and how these processes and criteria align with
11.7
the overall corporate goals and vision.
Details of demand forecasts, the basis on which they are derived, and
the specific network locations where constraints are expected due to
11.8
forecast increases in demand;
explain the load forecasting methodology and indicate all the
11.8.1
factors used in preparing the load estimates;
provide separate forecasts to at least the zone substation level
covering at least a minimum five year forecast period. Discuss
how uncertain but substantial individual projects/developments
that affect load are taken into account in the forecasts, making
clear the extent to which these uncertain increases in demand
11.8.2
are reflected in the forecasts;
identify any network or equipment constraints that may arise due
to the anticipated growth in demand during the AMP planning
11.8.3
period; and
discuss the impact on the load forecasts of any anticipated levels
of distributed generation in a network, and the projected impact
11.8.4
of any demand management initiatives.
Analysis of the significant network level development options identified
and details of the decisions made to satisfy and meet target levels of
11.9
service, includingthe reasons for choosing a selected option for projects where
11.9.1
decisions have been made;
the alternative options considered for projects that are planned to
start in the next five years and the potential for non-network
11.9.2
solutions described;
consideration of planned innovations that improve efficiencies
within the network, such as improved utilisation, extended asset
11.9.3
lives, and deferred investment.
A description and identification of the network development programme
including distributed generation and non-network solutions and actions to
be taken, including associated expenditure projections. The network
11.10
development plan must includea detailed description of the material projects and a summary
description of the non-material projects currently underway or
11.10.1
planned to start within the next 12 months;
a summary description of the programmes and projects planned
11.10.2
for the following four years (where known); and
an overview of the material projects being considered for the
11.10.3
remainder of the AMP planning period.
For projects included in the AMP where decisions have been made, the
reasons for choosing the selected option should be stated which should
include how target levels of service will be impacted. For other projects
planned to start in the next five years, alternative options should be
discussed, including the potential for non-network approaches to be
Asset Management Plan
7.7, 7.1.3,
7.7.1,
7.7.1,
7.7.1,
7.7.1,
7.10,
7.1.4,
7.2,
7.3,
7.3.2, 7.3.3
7.3.4
7.4
7.5, 7.6
7.8,
7.7.1, 7.8.1
7.8.1
7.8.1, 7.10
7.8,
7.8, 7.8.1
7.8.1
7.8.2
Page 177 of 193
RESOURCING OUR BUSINESS
more cost effective than network augmentations.
A description of the EDB‘s policies on distributed generation, including
the policies for connecting distributed generation. The impact of such
11.11
generation on network development plans must also be stated.
11.12
A description of the EDB‘s policies on non-network solutions, includingeconomically feasible and practical alternatives to conventional
network augmentation. These are typically approaches that
would reduce network demand and/or improve asset utilisation;
11.12.1
and
the potential for non-network solutions to address network
11.12.2
problems or constraints.
Lifecycle Asset Management Planning (Maintenance and Renewal)
The AMP must provide a detailed description of the lifecycle asset
12
management processes, including—
12.1
The key drivers for maintenance planning and assumptions;
Identification of routine and corrective maintenance and inspection
policies and programmes and actions to be taken for each asset
category, including associated expenditure projections. This must
12.2
includethe approach to inspecting and maintaining each category of
assets, including a description of the types of inspections, tests
and condition monitoring carried out and the intervals at which
12.2.1
this is done;
any systemic problems identified with any particular asset types
12.2.2
and the proposed actions to address these problems; and
budgets for maintenance activities broken down by asset
12.2.3
category for the AMP planning period.
Identification of asset replacement and renewal policies and programmes
and actions to be taken for each asset category, including associated
12.3
expenditure projections. This must includethe processes used to decide when and whether an asset is
replaced or refurbished, including a description of the factors on
which decisions are based, and consideration of future demands
12.3.1
on the network and the optimum use of existing network assets;
a description of innovations made that have deferred asset
12.3.2
replacement;
a description of the projects currently underway or planned for
12.3.3
the next 12 months;
a summary of the projects planned for the following four years
12.3.4
(where known); and
an overview of other work being considered for the remainder of
12.3.5
the AMP planning period.
The asset categories discussed in subclauses 12.2 and 12.3 above
12.4
should include at least the categories in subclause 4.5 above.
Non-Network Development, Maintenance and Renewal
AMPs must provide a summary description of material non-network
13
development, maintenance and renewal plans, including—
13.1
a description of non-network assets;
13.2
development, maintenance and renewal policies that cover them;
a description of material capital expenditure projects (where known)
13.3
planned for the next five years;
a description of material maintenance and renewal projects (where
13.4
known) planned for the next five years.
Risk Management
AMPs must provide details of risk policies, assessment, and mitigation,
14
including—
14.1
Methods, details and conclusions of risk analysis;
Asset Management Plan
7.5,
7.6,
7.5
8
8.3,
8.1, 8.3
8.3.1, 8.3.3
8.3.2.4,
8.11,
8.4,
8.4
8.4
8.4.1
8.4.2
8.4.3
8.12
7.9, 8.9,
8.12.9, 8.12.10
7, 8
7, 8
7, 8
4,
4.1, 4.2,
Page 178 of 193
RESOURCING OUR BUSINESS
14.2
14.3
14.4
15
15.1
15.2
15.3
15.4
16
16.1
16.2
Strategies used to identify areas of the network that are vulnerable to
high impact low probability events and a description of the resilience of
the network and asset management systems to such events;
A description of the policies to mitigate or manage the risks of events
identified in subclause 16.2;
Details of emergency response and contingency plans.
Asset risk management forms a component of an EDB’s overall risk
management plan or policy, focusing on the risks to assets and
maintaining service levels. AMPs should demonstrate how the EDB
identifies and assesses asset related risks and describe the main risks
within the network. The focus should be on credible low-probability, highimpact risks. Risk evaluation may highlight the need for specific
development projects or maintenance programmes. Where this is the
case, the resulting projects or actions should be discussed, linking back
to the development plan or maintenance programme.
Evaluation of performance
AMPs must provide details of performance measurement, evaluation,
and improvement, including—
A review of progress against plan, both physical and financial;
referring to the most recent disclosures made under Section 2.6 of this
determination, discussing any significant differences and highlighting
reasons for substantial variances; commenting on the progress of
development projects against that planned in the previous AMP and
provide reasons for substantial variances along with any significant
construction or other problems experienced; commenting on progress
against maintenance initiatives and programmes and discuss the
effectiveness of these programmes noted.
An evaluation and comparison of actual service level performance
against targeted performance;
in particular, comparing the actual and target service level
performance for all the targets discussed under the Service Levels
section of the AMP in the previous AMP and explain any significant
variances;
An evaluation and comparison of the results of the asset management
maturity assessment disclosed in the Report on Asset Management
Maturity set out in Schedule 13 against relevant objectives of the EDB‘s
asset management and planning processes.
An analysis of gaps identified in subclauses 15.2 and 15.3 above. Where
significant gaps exist (not caused by one-off factors), the AMP must
describe any planned initiatives to address the situation.
Capability to deliver
AMPs must describe the processes used by the EDB to ensure thatThe AMP is realistic and the objectives set out in the plan can be
achieved;
The organisation structure and the processes for authorisation and
business capabilities will support the implementation of the AMP plans.
Asset Management Plan
4.2,
4.2,
4.3,
5
5.1,
5.2,
5.3
5.3,
10
10, 10.1
10, 10.1
Page 179 of 193
APPENDIX - CONSUMER ENGAGEMENT SURVEY
B.
Appendix - Customer Engagement Survey
PowerNet Consumer Engagement Telephone Survey: OtagoNet
© Gary Nicol Associates
Phone
Date
Interviewer
Good afternoon/evening my name is _____. I am conducting a brief customer survey
on behalf of OtagoNet.
May I please speak to a person in your home who is responsible for paying the
electricity account?
(Reintroduce if necessary) May I trouble you for a few minutes of your time?
A1: Do you know who Yes
OtagoNet is?
No
1
Go to A2
2
Go to A3
A2: Using a 1 to 5 rating
scale where 1 is Poor and
5 is Excellent can you rate
the
performance
of
OtagoNet over the last 12
months for:
Caring for customers
1 2 3 4 5 X
Sensitive to the environment
1 2 3 4 5 X
Supporting the community
1 2 3 4 5 X
Safety conscious
1 2 3 4 5 X
Go to D1
Efficiency
1 2 3 4 5 X
A3: OtagoNet maintains the local electricity lines and substations that supply power to
your premises.
D1: Do you live in a mainly rural or Urban
urban area?
Rural
5
D2: Are you a commercial or residential Commercial
customer?
Residential
1
Question 1: OtagoNet is proposing a Yes
maximum of one planned interruption to
your power supply, on average, every
No
year in order to carry out maintenance
or upgrade work on its electricity
network.
Don‘t know/unsure
Do you consider this number of planned
interruptions to be reasonable?
2 years
Question 1(a): How many years
between planned interruptions do you 3 years
Asset Management Plan
6
2
1
Go to Q 2
2
Go to Q 1(a)
3
Go to Q 2
1
2
Page 180 of 193
APPENDIX - CONSUMER ENGAGEMENT SURVEY
consider to be more reasonable?
3
4 years
Question 2: OtagoNet expects such Yes
planned interruptions will on average
No
last up to four hours each.
Do you consider this amount of time to
Don‘t know/unsure
be reasonable?
1
Go to Q 3
2
Go to Q 2(a)
3
Go to Q 3
1 hour
Question 2(a): What length of time
would you consider to be more 2 hours
reasonable? (Specify hours)
3 hours
1
Yes
Question 3: Have you received advice
of a planned electricity interruption No
during the last 6 months?
Don‘t know/unsure
1
Go to Q 3(a)
2
Go to Q 3(e)
3
Go to Q 3(e)
Yes
Question 3(a): Were you satisfied with
the amount of information given to you No
about this planned interruption?
Unable to recall
1
Go to Q 3(c)
2
Go to Q 3(b)
3
Go to Q 3(c)
2
3
Question 3 (b): What additional information would you have liked?
Yes
Question 3(c): Do you feel that you
were given enough notice of this No
planned interruption?
Don‘t know/unsure
1
Go to Q 3(e)
2
Go to Q 3(d)
3
Go to Q 3(e)
Question 3(d): How much notice of
1 day
planned interruptions would you prefer
3 days
to be given? (Specify days/weeks)
1
1 week
4
2
2 weeks
5
(Do not prompt)
3
Other
6
5 days
Question 3(e): Do you have a preferred Yes
day and time(s) for a planned
interruptions?
No
Asset Management Plan
1
Go to Q 3(f)
2
Go to Q 4
Page 181 of 193
APPENDIX - CONSUMER ENGAGEMENT SURVEY
Question 3 (f): What is your preferred day and time(s)?
1 Go to Q 4(a)
Yes
Question 4: Have you had an
unexpected interruption to your power No
supply during the last 6 months?
Unable to recall
Question 4(a): Thinking about the most
recent unexpected interruption to your
electricity supply, how long did it take
for your supply to be restored?
(Specify hours/days)
2 Go to Q 5
3 Go to Q 5
Within 45 min
1
3 hours
5
1 hour
2
4 hours
6
11/2 hours
3
12 hours
7
2 hours
4
Don‘t know
8
Other
9
(Do not prompt)
Yes
Question 4(b): Do you consider your
electricity supply was restored within a No
reasonable amount of time?
Unable to recall
Question 4(c): What do you consider 30 minutes
would have been a more reasonable
amount of time? (Specify hours/days) 45 minutes
1
Go to Q 5
2
Go to Q 4(c)
3
Go to Q 5
1
11/2 hours
4
2
2 hours
5
3
Other
(Do not prompt)
Go to Q5(a)
Question 5: In the event of an
unexpected
interruption
to
your
electricity supply, what do you consider
would be a reasonable amount of time
before electricity supply is restored to
your home?
(Specify hours/days)
(Do not prompt)
1 hour
5 minutes
1
2 hours
10
10 minutes
2
3 hours
11
15 minutes
3
4 hours
12
20 minutes
4
5 hours
13
30 minutes
5
6 hours
14
40 minutes
6
12 hours
15
45 minutes
7
1 day
16
1 hour
8
Unsure
17
11/2 hours
9
Other
18
Question 5(a): OtagoNet is reviewing Yes
the level of service provided to its
customers
and
options
include
increasing spending. Presently there is No
an average of four interruptions each
Asset Management Plan
6
1
2
Page 182 of 193
APPENDIX - CONSUMER ENGAGEMENT SURVEY
year. If this was reduced to three
interruptions per year would you be
happy to pay an additional $10 per Don‘t know/unsure
month on your electricity bill?
3
Meridian Energy
1
Contact Energy
2
3
Question 6: Who would you contact in Mighty River Power
the event of the power supply to your
TrustPower
home being unexpectedly interrupted?
(Do not prompt)
4
PowerNet
5
OtagoNet
6
Genesis Energy
7
Other
8
Yes
Question 7: Have you made such a call
No
within the last 6 months?
Unable to recall
Question 8: Were you satisfied that the Yes
system worked in getting you enough
No
information
about
the
supply
interruption?
Don‘t know/unsure
1
Go to Q 8
2
Go to Q 8(d)
3
Go to Q 8(d)
1
Go to Q 8(b)
2
Go to Q 8(a)
3
Go to Q 8(b)
Question 8 (a): What, if anything, do you feel could be done to improve this system?
Yes
Question 8 (b): Were you satisfied with
No
the information that you received?
Don‘t know/unsure
1
Go to Q 8(d)
2
Go to Q 8(c)
3
Go to Q 8(d)
Question 8 (c): What, if anything, do you feel could be done to improve this
information or the way in which it is delivered?
time
when
Question 8 (d): What is the most Accurate
1
important information you wish to power will be restored
receive when you experience an
2
Reason for fault
unplanned supply interruption?
(Do not prompt)
Asset Management Plan
Other
3
Page 183 of 193
APPENDIX - CONSUMER ENGAGEMENT SURVEY
Question 8(e): Are you aware of
Yes 1
OtagoNet‘s 0800 faults number?
Question 9: Have you contacted Yes
OtagoNet regarding any other issues
No
relating to your electricity supply during
the last 6 months?
Unable to recall
No
2
1
Go to Q 9(a)
2
Go to Q 9(e)
3
Go to Q 9(e)
1
Voltage complaints
Question 9(a): What did your enquiry Safety disconnections
relate to?
New or altered supply
(Do not prompt)
2
3
Trees near lines
4
Other
5
Yes
Question 9 (b): Were you satisfied with
the performance of the OtagoNet staff No
member(s) who handled your enquiry?
Don‘t know/unsure
1
Go to Q 9(d)
2
Go to Q 9(c)
3
Go to Q 9(e)
Question 9 (c): Specifically what were you dissatisfied with?
Question 9 (d): Was there anything that OtagoNet did well?
Question 9 (e): What if anything do you feel could be done to improve the service
provided by OtagoNet staff?
This concludes our survey - Thank you for your time
Asset Management Plan
Page 184 of 193
APPENDIX - ASSUMPTIONS
C.
Appendix – Assumptions
When developing this plan we have made the following key assumptions:
No major developments in the region, unless specifically identified.
- Developers don‘t always let OtagoNet know of their plans with large projects
kept confidential until the last minute.
Growth trends will be similar to historic trends.
- No step changes considered as none are certain but noting the announced
possible closure of the Macraes gold mine circa 2017 is considered within this
plan.
No change in present regulations that would impact planned expenditures.
Distributed generation will develop slowly with little impact within the planning
period.
The standard life of assets is based on the ODV asset life, with actual replacement
done on a condition basis.
- Some areas exceed standard lives (Inland North Otago) and others fail to
reach standard lives (Coastal regions).
No decline in meat and wool markets.
- Closure of any large customer would have a significant a small rural network.
Continuation of trend for increased use of spray irrigation.
No major development in coal extraction and/or processing.
The Plan will be reviewed following the completion of the accelerated network
surveillance program to be undertaken.
Asset management plan
Page 185 of 193
APPENDIX – EDIDD SCHEDULES
D.
Appendix – EDIDD Schedule 11a
Company Name
AMP Planning Period
OtagoNet Joint Venture
1 April 2014 – 31 March 2024
SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE
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.
sch ref
1
7
8
9
for year ended
11a(i): Expenditure on Assets Forecast
10
Consumer connection
11
System growth
12
Asset replacement and renewal
13
Asset relocations
14
Reliability, safety and environment:
15
Quality of supply
16
17
Legislative and regulatory
Other reliability, safety and environment
18
19
Expenditure on network assets
21
1.084
1.151
1.201
1.239
1.269
1.301
1.348
1.397
1.447
CY+1
CY+2
CY+3
CY+4
CY+5
CY+6
CY+7
CY+8
CY+9
CY+10
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
$000 (in nominal dollars)
Total reliability, safety and environment
20
1
Current Year CY
822
1,000
109
1,779
736
206
515
1,399
164
168
174
180
187
4,685
4,520
9,593
9,910
10,761
10,668
12,195
12,503
12,954
13,425
13,906
1,405
65
69
72
74
76
78
81
84
3,441
600
813
391
661
310
-
-
-
-
-
695
2,090
1,832
1,093
901
805
698
716
741
768
796
4,136
2,690
2,645
1,485
1,561
1,115
698
716
741
768
796
9,796
11,394
14,123
12,821
14,111
14,495
14,402
14,765
15,298
15,855
16,422
44
1,084
1,151
1,201
1,239
1,269
1,301
1,348
1,397
1,447
87
Non-network assets
-
-
-
-
-
-
-
-
-
-
-
Expenditure on assets
9,796
11,394
14,123
12,821
14,111
14,495
14,402
14,765
15,298
15,855
16,422
22
23
plus
24
less
25
26
plus
27
Cost of financing
Value of capital contributions
573
1,352
750
796
831
857
878
900
933
967
1,001
9,223
10,042
13,373
12,024
13,279
13,638
13,524
13,865
14,366
14,888
15,421
Value of vested assets
Capital expenditure forecast
28
29
Value of commissioned assets
9,223
30
for year ended
32
Consumer connection
34
System growth
35
Asset replacement and renewal
36
Asset relocations
37
Reliability, safety and environment:
38
Quality of supply
39
40
Legislative and regulatory
Other reliability, safety and environment
41
Total reliability, safety and environment
42
Expenditure on network assets
43
44
12,024
13,279
13,638
13,524
13,865
14,366
14,888
15,421
CY+2
CY+3
CY+4
CY+5
CY+6
CY+7
CY+8
CY+9
CY+10
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
822
1,000
1,000
1,000
109
1,779
679
179
429
1,129
129
129
129
129
129
4,685
4,520
8,850
8,610
8,960
8,610
9,610
9,610
9,610
9,610
9,610
1,405
60
60
60
60
60
60
60
60
3,441
600
750
340
550
250
-
-
-
-
-
695
2,090
1,690
950
750
650
550
550
550
550
550
4,136
2,690
2,440
1,290
1,300
900
550
550
550
550
550
9,796
11,394
13,029
11,139
11,749
11,699
11,349
11,349
11,349
11,349
11,349
11,349
11,349
11,349
11,349
11,349
44
1,000
1,000
Non-network assets
-
-
-
-
-
-
Expenditure on assets
9,796
11,394
13,029
11,139
11,749
11,699
1,000
1,000
1,000
1,000
1,000
60
Subcomponents of expenditure on assets (where known)
47
Energy efficiency and demand side management, reduction of energy losses
48
Overhead to underground conversion
49
Research and development
57
58
59
13,373
CY+1
31 Mar 14
$000 (in constant prices)
33
45
46
10,042
Current Year CY
Current Year CY
for year ended
Difference between nominal and constant price forecasts
CY+1
31 Mar 14
$000
CY+2
31 Mar 15
CY+3
31 Mar 16
CY+4
31 Mar 17
CY+5
31 Mar 18
CY+6
31 Mar 19
CY+7
31 Mar 20
CY+8
31 Mar 21
CY+9
31 Mar 22
CY+10
31 Mar 23
31 Mar 24
60
Consumer connection
-
-
84
151
201
239
269
301
348
397
61
System growth
-
-
57
27
86
270
35
39
45
51
58
62
Asset replacement and renewal
-
-
743
1,300
1,801
2,058
2,585
2,893
3,344
3,815
4,296
63
Asset relocations
-
-
5
9
12
14
16
18
21
24
447
64
Reliability, safety and environment:
27
65
Quality of supply
-
-
63
51
111
60
-
-
-
-
-
66
67
Legislative and regulatory
Other reliability, safety and environment
-
-
142
143
151
155
148
166
191
218
246
-
-
205
195
261
215
148
166
191
218
246
-
-
1,094
1,682
2,362
2,796
3,053
3,416
3,949
4,506
5,073
68
Total reliability, safety and environment
69
Expenditure on network assets
70
Non-network assets
71
72
Expenditure on assets
-
for year ended
74
-
-
73
Current Year CY
31 Mar 14
-
-
CY+1
31 Mar 15
-
1,094
CY+2
31 Mar 16
-
1,682
CY+3
31 Mar 17
2,362
CY+4
31 Mar 18
-
-
-
-
-
-
2,796
3,053
3,416
3,949
4,506
5,073
CY+5
31 Mar 19
11a(ii): Consumer Connection
75
Consumer types defined by EDB*
76
New Connections
$000 (in constant prices)
822
1,000
1,000
1,000
1,000
1,000
822
1,000
1,000
1,000
1,000
1,000
563
650
650
650
650
650
259
350
350
350
350
350
77
78
79
80
81
*include additional rows if needed
82
83
Consumer connection expenditure
less
84
85
Capital contributions funding consumer connection
Consumer connection less capital contributions
11a(iii): System Growth
86
Subtransmission
65
87
Zone substations
1
750
250
50
300
1,000
88
Distribution and LV lines
43
1,029
429
129
129
129
89
Distribution and LV cables
90
Distribution substations and transformers
91
92
Distribution switchgear
Other network assets
109
1,779
679
179
429
1,129
109
1,779
679
179
429
93
94
System growth expenditure
less
95
Capital contributions funding system growth
System growth less capital contributions
103
104
105
for year ended
11a(iv): Asset Replacement and Renewal
106
Subtransmission
107
Zone substations
108
Distribution and LV lines
109
Distribution and LV cables
110
Distribution substations and transformers
111
112
114
CY+2
CY+3
CY+4
CY+5
31 Mar 15
31 Mar 16
31 Mar 17
31 Mar 18
31 Mar 19
$000 (in constant prices)
779
2,000
1,650
750
750
750
218
220
2,720
1,870
2,320
2,020
3,688
2,150
4,330
5,240
5,240
5,240
-
-
600
600
less
600
150
150
150
50
-
4,520
8,850
8,610
8,960
8,610
4,675
4,520
8,850
8,610
8,960
8,610
36
60
60
60
60
60
8
1,345
-
-
-
-
Asset relocations expenditure
44
1,405
60
60
60
60
Capital contributions funding asset relocations
Asset relocations less capital contributions
44
702
703
42
18
42
18
42
18
42
18
200
200
200
200
200
50
200
Asset replacement and renewal expenditure
115
116
117
CY+1
31 Mar 14
Distribution switchgear
Other network assets
113
1,129
Current Year CY
4,685
Capital contributions funding asset replacement and renewal
10
Asset replacement and renewal less capital contributions
11a(v):Asset Relocations
Project or programme*
118
Chargeable capital
119
Overhead to underground projects
120
121
122
123
124
*include additional rows if needed
All other asset relocations projects or programmes
125
126
127
less
128
129
11a(vi):Quality of Supply
130
Project or programme*
131
Reclosers and SCADA automation
132
Clydevale 33 kV ring protection
133
Milton 33 kV ring protection
134
Palmerston GXP purchase and conversion to 33 kV
135
Distribution ties
136
137
*include additional rows if needed
All other quality of supply projects or programmes
138
139
-
-
200
-
-
-
150
140
350
50
3,441
600
750
340
550
250
3,441
600
750
340
550
250
-
-
-
-
-
-
-
-
-
-
-
572
Quality of supply expenditure
less
140
-
50
300
2,869
Capital contributions funding quality of supply
Quality of supply less capital contributions
141
142
11a(vii): Legislative and Regulatory
143
Project or programme*
144
145
146
147
148
149
150
*include additional rows if needed
All other legislative and regulatory projects or programmes
151
152
Legislative and regulatory expenditure
less
153
Capital contributions funding legislative and regulatory
Legislative and regulatory less capital contributions
-
161
162
for year ended
163
Current Year CY
31 Mar 14
CY+1
31 Mar 15
CY+2
31 Mar 16
CY+3
31 Mar 17
CY+4
31 Mar 18
CY+5
31 Mar 19
11a(viii): Other Reliability, Safety and Environment
164
Project or programme*
165
Zone substation safety and environmental protection
166
Overhead distribution subs to groundmount
167
SWER earth upgrades to best practice
$000 (in constant prices)
656
390
400
200
100
80
300
300
300
300
1,000
1,000
250
250
250
695
2,090
1,690
950
750
650
695
2,090
1,690
950
750
650
-
-
-
-
-
-
Atypical expenditure
-
-
-
-
-
-
Non-network assets expenditure
-
-
-
-
-
-
39
1,010
168
169
170
171
*include additional rows if needed
All other reliability, safety and environment projects or programmes
172
173
174
175
176
177
178
179
180
Other reliability, safety and environment expenditure
less
Capital contributions funding other reliability, safety and environment
Other reliability, safety and environment less capital contributions
11a(ix): Non-Network Assets
Routine expenditure
Project or programme*
181
182
183
184
185
186
187
188
189
190
*include additional rows if needed
All other routine expenditure projects or programmes
Routine expenditure
Atypical expenditure
Project or programme*
191
192
193
194
195
196
197
198
*include additional rows if needed
All other atypical projects or programmes
199
200
Asset management plan
Page 186 of 193
Asset management plan
Operational Expenditure Forecast
Routine and corrective maintenance and inspection
Asset replacement and renewal
12
13
Routine and corrective maintenance and inspection
Asset replacement and renewal
24
25
Direct billing*
Research and Development
Insurance
34
35
36
Vegetation management
Routine and corrective maintenance and inspection
Asset replacement and renewal
43
44
45
Non-network opex
Operational expenditure
50
System operations and network support
Business support
49
47
48
Network Opex
Service interruptions and emergencies
46
Difference between nominal and real forecasts
42
$000
31 Mar 14
41
Current Year CY
for year ended
40
-
-
-
-
-
-
-
7,386
3,098
188
2,910
4,288
625
1,758
775
1,130
39
38
37 * Direct billing expenditure by suppliers that direct bill the majority of their consumers
Energy efficiency and demand side management, reduction of
energy losses
33
32
Subcomponents of operational expenditure (where known)
Operational expenditure
30
31
Non-network opex
System operations and network support
Business support
29
27
28
Network Opex
Vegetation management
23
26
Service interruptions and emergencies
22
$000 (in constant prices)
31 Mar 14
21
Current Year CY
for year ended
7,386
20
Operational expenditure
18
3,098
188
2,910
4,288
625
1,758
775
1,130
19
Non-network opex
System operations and network support
Business support
17
15
16
Network Opex
Vegetation management
11
14
Service interruptions and emergencies
10
1
$000 (in nominal dollars)
31 Mar 14
9
Current Year CY
8
for year ended
7
sch ref
CY+1
7,750
3,532
2,025
1,507
4,218
-
-
-
-
-
-
-
7,750
3,532
2,025
1,507
4,218
1,094
616
850
1,658
31 Mar 15
CY+1
850
1,094
616
31 Mar 15
CY+1
1
1,658
31 Mar 15
CY+2
1.035
CY+2
CY+2
31 Mar 16
204
78
45
33
126
22
16
30
58
7,133
3,532
2,025
1,507
3,601
627
466
850
1,658
31 Mar 16
7,337
3,610
2,070
1,540
3,727
649
482
880
1,716
31 Mar 16
CY+3
1.072
CY+3
CY+3
31 Mar 17
409
164
94
70
245
31
34
61
119
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 17
7,342
3,696
2,119
1,577
3,646
458
500
911
1,777
31 Mar 17
CY+4
1.113
CY+4
CY+4
31 Mar 18
637
253
145
108
384
48
53
96
187
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 18
7,570
3,785
2,170
1,615
3,785
475
519
946
1,845
31 Mar 18
CY+5
1.155
CY+5
CY+5
31 Mar 19
871
344
197
147
527
66
72
132
257
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 19
7,804
3,876
2,222
1,654
3,928
493
538
982
1,915
31 Mar 19
CY+6
1.199
CY+6
CY+6
437
250
187
677
85
93
169
330
1,114
31 Mar 20
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 20
8,047
3,969
2,275
1,694
4,078
512
559
1,019
1,988
31 Mar 20
CY+7
1.245
CY+7
CY+7
532
305
227
833
105
114
208
406
1,366
31 Mar 21
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 21
8,299
4,064
2,330
1,734
4,234
532
580
1,058
2,064
31 Mar 21
CY+8
8,549
4,162
2,386
1,776
4,387
1,616
630
361
269
986
124
135
247
481
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 22
CY+8
551
601
1,097
31 Mar 22
CY+8
1.29
2,139
31 Mar 22
CY+9
CY+9
CY+9
143
157
286
557
1,872
730
418
312
1,143
31 Mar 23
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 23
8,805
4,262
2,443
1,819
4,544
570
623
1,136
2,215
31 Mar 23
1.336
1.385
CY+10
CY+10
164
179
327
638
2,141
832
477
355
1,309
31 Mar 24
6,933
3,532
2,025
1,507
3,401
427
466
850
1,658
31 Mar 24
9,074
4,364
2,502
1,862
4,710
591
645
1,177
2,296
31 Mar 24
CY+10
OtagoNet Joint Venture
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.
SCHEDULE 11b: REPORT ON FORECAST OPERATIONAL EXPENDITURE
Company Name
E.
AMP Planning Period
APPENDIX – EDIDD SCHEDULES
Appendix – EDIDD Schedule 11b
Page 187 of 193
APPENDIX – EDIDD SCHEDULES
F.
Appendix – EDIDD Schedule 12a
Company Name
AMP Planning Period
OtagoNet Joint Venture
1 April 2014 – 31 March 2024
SCHEDULE 12a: REPORT ON ASSET CONDITION
This schedule requires a breakdown of asset condition by asset class as at the start of the forecast year. The data accuracy assessment relates to the percentage values disclosed in the asset condition columns. Also required is a forecast of the percentage of units to be
replaced in the next 5 years. All information should be consistent with the information provided in the AMP and the expenditure on assets forecast in Schedule 11a. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths.
sch ref
7
Asset condition at start of planning period (percentage of units by grade)
8
Units
Grade 1
Grade 2
Grade 3
Grade 4
Grade unknown
% of asset forecast
to be replaced in
next 5 years
Data accuracy
(1–4)
Voltage
Asset category
Asset class
9
10
All
Overhead Line
Concrete poles / steel structure
No.
1.86%
0.69%
19.22%
5.84%
72.39%
3
5.14%
11
All
Overhead Line
Wood poles
No.
1.04%
1.00%
11.81%
2.88%
83.27%
3
34.52%
12
All
Overhead Line
Other pole types
No.
13
HV
Subtransmission Line
Subtransmission OH up to 66kV conductor
km
0.04%
0.02%
0.86%
0.51%
98.57%
3
28.69%
14
HV
Subtransmission Line
Subtransmission OH 110kV+ conductor
km
N/A
15
HV
Subtransmission Cable
Subtransmission UG up to 66kV (XLPE)
km
100.00% N/A
16
HV
Subtransmission Cable
Subtransmission UG up to 66kV (Oil pressurised)
km
N/A
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
23
HV
Subtransmission Cable
Subtransmission submarine cable
km
24
HV
Zone substation Buildings
Zone substations up to 66kV
No.
25
HV
Zone substation Buildings
Zone substations 110kV+
No.
26
HV
Zone substation switchgear
22/33kV CB (Indoor)
No.
27
HV
Zone substation switchgear
22/33kV CB (Outdoor)
No.
28
HV
Zone substation switchgear
33kV Switch (Ground Mounted)
No.
29
HV
Zone substation switchgear
33kV Switch (Pole Mounted)
No.
30
HV
Zone substation switchgear
33kV RMU
No.
N/A
31
HV
Zone substation switchgear
50/66/110kV CB (Indoor)
No.
N/A
32
HV
Zone substation switchgear
50/66/110kV CB (Outdoor)
No.
33
HV
Zone substation switchgear
3.3/6.6/11/22kV CB (ground mounted)
No.
16.67%
27.78%
55.55%
3
13.89%
34
HV
Zone substation switchgear
3.3/6.6/11/22kV CB (pole mounted)
No.
22.86%
72.86%
4.28%
3
17.14%
N/A
N/A
N/A
2.94%
58.82%
23.53%
14.71%
3
N/A
100.00%
24.14%
65.52%
4
10.34%
3
13.79%
3
7.00%
N/A
12.80%
78.40%
8.80%
100.00%
42
43
3
Asset condition at start of planning period (percentage of units by grade)
Units
Grade 1
Grade 2
Grade 3
Grade 4
Grade unknown
% of asset forecast
to be replaced in
next 5 years
Data accuracy
(1–4)
Voltage
Asset category
Asset class
45
HV
Zone Substation Transformer
Zone Substation Transformers
No.
46
HV
Distribution Line
Distribution OH Open Wire Conductor
km
47
HV
Distribution Line
Distribution OH Aerial Cable Conductor
km
48
HV
Distribution Line
SWER conductor
km
49
HV
Distribution Cable
Distribution UG XLPE or PVC
km
100.00% N/A
50
HV
Distribution Cable
Distribution UG PILC
km
100.00% N/A
51
HV
HV
Distribution Cable
Distribution switchgear
Distribution Submarine Cable
km
52
3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers
No.
53
HV
Distribution switchgear
No.
54
HV
Distribution switchgear
3.3/6.6/11/22kV CB (Indoor)
3.3/6.6/11/22kV Switches and fuses (pole mounted)
55
HV
Distribution switchgear
3.3/6.6/11/22kV Switch (ground mounted) - except RMU
No.
56
HV
Distribution switchgear
3.3/6.6/11/22kV RMU
No.
57
HV
Distribution Transformer
Pole Mounted Transformer
No.
58
HV
Distribution Transformer
Ground Mounted Transformer
No.
59
HV
Distribution Transformer
Voltage regulators
No.
60
HV
Distribution Substations
Ground Mounted Substation Housing
No.
61
LV
LV Line
LV OH Conductor
km
62
LV
LV Cable
LV UG Cable
km
63
LV
LV Streetlighting
LV OH/UG Streetlight circuit
km
64
Connections
Protection
OH/UG consumer service connections
No.
65
LV
All
Protection relays (electromechanical, solid state and numeric)
No.
12.64%
52.45%
34.91%
66
All
SCADA and communications
SCADA and communications equipment operating as a single system
Lot
3.77%
62.27%
33.96%
67
All
Capacitor Banks
Capacitors including controls
No.
68
All
Load Control
Centralised plant
Lot
69
All
Load Control
Relays
No.
N/A
70
All
Civils
Cable Tunnels
km
N/A
44
Asset management plan
9.52%
76.19%
14.29%
3.60%
1.96%
24.99%
2.68%
2.07%
0.30%
3.09%
1.50%
66.77%
3
7.14%
3
17.93%
3
14.47%
N/A
93.04%
5.88%
N/A
7.70%
46.15%
46.15%
3
53.85%
N/A
No.
25.19%
72.55%
2.26%
3
N/A
100.00%
1.56%
10.00%
3
0.79%
20.55%
2.00%
11.76%
64.71%
23.53%
75.10%
3
10.00%
3
17.65%
2
2.96%
3
5.00%
100.00% N/A
N/A
1.06%
0.75%
6.51%
0.35%
1.06%
0.75%
6.51%
0.35%
91.33%
100.00% N/A
91.33%
100.00% N/A
3
2.26%
3
18.86%
3
50.00%
N/A
50.00%
25.00%
25.00%
Page 188 of 193
Asset management plan
2.0
2.7
0.1
6.4
1.1
0.7
4.2
1.7
0.2
1.2
1.4
1.5
2.4
0.7
2.4
2.8
0.2
1.5
0.3
Clinton
Clydevale
Deepdell
Elderlee St
Finegand
Glenore
Golden Point
Greenfield
Hindon
Hyde
Kaitangata
Lawrence
Macraes Mine
Merton
Middlemarch
Milburn
North Balclutha
Oturehua
Owaka
Paerau
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
36
35
34
32
33
31
30
29
1.7
0.7
0.4
2.2
Patearoa
Port Molyneux
Pukeawa
Ranfurly
1.2
1.3
1.5
0.2
Waihola
Waipiata
Waitati
Wedderburn
Zone substation transformer capacity
Total distribution transformer capacity
Distribution transformer capacity (EDB owned)
Distribution transformer capacity (Non-EDB owned)
12b(ii): Transformer Capacity
(MVA)
158
205
163
42
¹ Extend forecast capacity table as necessary to disclose all capacity by each zone substation
3.9
Stirling
25.3
2.2
Palmerston
Ranfurly 66/33 kV
12.8
Paerau Hydro
22.4
0.4
Clarks Junction
11
9
10
Current Peak Load
(MVA)
6.1
12b(i): System Growth - Zone Substations
Existing Zone Substations
Charlotte St
8
7
sch ref
Security of Supply
Classification
(type)
0.8 N
2.5 N
2.5 N
1.5 N
5.0 N
50.0 N-1
5.0 N-1 switched
0.8 N
2.5 N
2.5 N
5.0 N
30.0 N
0.8 N
2.5 N
0.8 N
5.0 N
7.5 N
2.5 N
5.0 N
30.0 N
2.5 N
2.5 N
2.5 N
0.5 N
2.3 N
5.0 N
1.5 N
2.5 N
10.0 N-1
0.8 N
2.5 N
2.5 N
0.5 N
10.0 N-1
Installed Firm
Capacity
(MVA)
Transfer Capacity
(MVA)
25%
60%
52%
80%
78%
51%
44%
50%
28%
68%
44%
43%
38%
60%
25%
56%
32%
28%
48%
75%
60%
56%
48%
40%
74%
84%
47%
44%
64%
13%
108%
80%
80%
61%
Utilisation of
Installed Firm
Capacity
%
0.8
2.5
2.5
1.5
5.0
50.0
5.0
0.8
2.5
2.5
5.0
30.0
0.8
2.5
0.8
5.0
7.5
2.5
5.0
30.0
2.5
2.5
2.5
0.5
2.3
5.0
2.5
2.5
10.0
0.8
5.0
2.5
0.5
10.0
Installed Firm
Capacity +5 years
(MVA)
Installed Firm Capacity
Constraint +5 years
(cause)
84% Transformer
78% Transformer
46% Transformer
48% Transformer
75%
14%
69% Transformer
86% Transformer
61% Transformer
Utilisation of
Installed Firm
Capacity + 5yrs
%
This schedule requires a breakdown of current and forecast capacity and utilisation for each zone substation and current distribution transformer capacity. The data provided should be consistent with the information provided in the AMP. Information provided in this
table should relate to the operation of the network in its normal steady state configuration.
SCHEDULE 12b: REPORT ON FORECAST CAPACITY
Company Name
Monitor - 1% growth rate
Discuss reliability requirement with single customer
Near N-1 capacity (on transformers). Site to be relocated
Near N-1 capacity (on transformers) Low growth rate
Possible closure
New 2.5 MVA transformer with new site
New 5.0 MVA transformer and existing 2.5 for on-site spare
Monitor
Explanation
Over N-1 capacity but load transfer available
OtagoNet Joint Venture
1 April 2014 – 31 March 2024
G.
AMP Planning Period
APPENDIX – EDIDD SCHEDULES
Appendix – EDIDD Schedule 12b
Page 189 of 193
OtagoNet Joint Venture
1 April 2014 – 31 March 2024
Asset management plan
Commercial
Maximum Demand Contract
14
Installed connection capacity of distributed generation (MVA)
21
Demand on system for supply to consumers' connection points
Net transfers to (from) other EDBs at HV and above
Maximum coincident system demand
GXP demand
Distributed generation output at HV and above
Losses
Load factor
Loss ratio
39
40
Total energy delivered to ICPs
Electricity entering system for supply to ICPs
37
38
36
less
plus
less
33
34
35
Electricity exports to GXPs
32
Electricity supplied from distributed generation
Net electricity supplied to (from) other EDBs
Electricity supplied from GXPs
less
31
Electricity volumes carried (GWh)
less
plus
Maximum coincident system demand (MW)
30
29
28
27
25
26
24
12c(ii) System Demand
Number of connections
20
22
23
Distributed generation
19
17
18
Connections total
*include additional rows if needed
Domestic
13
15
16
Consumer types defined by EDB*
12
Number of ICPs connected in year by consumer type
12c(i): Consumer Connections
11
8
9
10
7
sch ref
for year ended
for year ended
5.0%
79%
21
402
423
83
340
61
61
48
13
Current Year CY
31 Mar 14
59
1
26
32
Current Year CY
31 Mar 14
79%
21
402
423
83
340
61
61
48
13
104
4
20
80
5.0%
CY+1
31 Mar 15
CY+1
31 Mar 15
80%
21
404
425
83
342
61
61
48
13
5.0%
CY+2
31 Mar 16
104
4
20
80
79%
21
406
427
83
344
62
62
49
13
104
4
20
80
5.0%
CY+3
31 Mar 17
Number of connections
CY+2
CY+3
31 Mar 16
31 Mar 17
79%
21
408
429
83
346
62
62
49
13
104
4
20
80
5.0%
CY+4
31 Mar 18
CY+4
31 Mar 18
78%
22
409
431
83
348
63
63
50
13
104
4
20
80
5.0%
CY+5
31 Mar 19
CY+5
31 Mar 19
This schedule requires a forecast of new connections (by consumer type), peak demand and energy volumes for the disclosure year and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the
assumptions used in developing the expenditure forecasts in Schedule 11a and Schedule 11b and the capacity and utilisation forecasts in Schedule 12b.
SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND
Company Name
H.
AMP Planning Period
APPENDIX – EDIDD SCHEDULES
Appendix – EDIDD Schedule 12c
Page 190 of 193
Asset management plan
OtagoNet Joint Venture
1 April 2014 – 31 March 2024
0.63
2.03
0.63
2.04
0.63
2.05
0.63
2.06
0.63
2.07
0.57
2.35
Class B (planned interruptions on the network)
Class C (unplanned interruptions on the network)
14
15
SAIFI
172.0
173.0
173.0
174.0
13
148.0
148.0
148.0
148.0
175.0
CY+5
31 Mar 19
148.0
CY+4
31 Mar 18
199.0
CY+3
31 Mar 17
151.0
CY+2
31 Mar 16
Class C (unplanned interruptions on the network)
CY+1
31 Mar 15
Class B (planned interruptions on the network)
Current Year CY
31 Mar 14
12
SAIDI
for year ended
11
sch ref
8
9
10
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.
SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION
Company Name
I.
AMP Planning Period
Network / Sub-network Name
APPENDIX – EDIDD SCHEDULES
Appendix – EDIDD Schedule 12d
Page 191 of 193
APPENDIX – EDIDD SCHEDULES
J.
Appendix – EDIDD Schedule 13
Summary of Asset Management Maturity Assessment Tool.
Question
No.
Function
3
Asset management
policy
10
Asset management
strategy
11
Asset management
strategy
26
Question
To what extent has an asset management policy been documented, authorised and
communicated?
Score
Evidence—Summary
3
The asset management policy is authorised by top management, is widely and effectively communicated to all
relevant employees and stakeholders, and used to make these persons aware of their asset related obligations.
3
Asset management
plan(s)
What has the organisation done to ensure that its asset management strategy is
consistent with other appropriate organisational policies and strategies, and the needs
of stakeholders?
In what way does the organisation's asset management strategy take account of the
lifecycle of the assets, asset types and asset systems over which the organisation has
stewardship?
How does the organisation establish and document its asset management plan(s) across
the life cycle activities of its assets and asset systems?
27
Asset management
plan(s)
How has the organisation communicated its plan(s) to all relevant parties to a level of
detail appropriate to the receiver's role in their delivery?
3
29
Asset management
plan(s)
How are designated responsibilities for delivery of asset plan actions documented?
3
31
Asset management
plan(s)
What has the organisation done to ensure that appropriate arrangements are made
available for the efficient and cost effective implementation of the plan(s)?
2
33
Contingency
planning
37
Structure, authority
and responsibilities
40
Structure, authority
and responsibilities
42
Structure, authority To what degree does the organisation's top management communicate the importance of
and responsibilities meeting its asset management requirements?
3
Top management communicates the importance of meeting its asset management requirements to all relevant
parts of the organisation.
45
Outsourcing of
asset management
activities
Training, awareness
and competence
Where the organisation has outsourced some of its asset management activities, how
has it ensured that appropriate controls are in place to ensure the compliant delivery of
its organisational strategic plan, and its asset management policy and strategy?
How does the organisation develop plan(s) for the human resources required to
undertake asset management activities - including the development and delivery of asset
management strategy, process(es), objectives and plan(s)?
Training, awareness How does the organisation identify competency requirements and then plan, provide and
and competence
record the training necessary to achieve the competencies?
3
Training, awareness How does the organization ensure that persons under its direct control undertaking
and competence
asset management related activities have an appropriate level of competence in terms of
education, training or experience?
Communication,
How does the organisation ensure that pertinent asset management information is
participation and
effectively communicated to and from employees and other stakeholders, including
consultation
contracted service providers?
Asset Management What documentation has the organisation established to describe the main elements of
System
its asset management system and interactions between them?
documentation
Information
What has the organisation done to determine what its asset management information
management
system(s) should contain in order to support its asset management system?
3
Evidence exists to demonstrate that outsourced activities are appropriately controlled to provide for the
compliant delivery of the organisational strategic plan, asset management policy and strategy, and that these
controls are integrated into the asset management system
The organisation can demonstrate that plan(s) are in place and effective in matching competencies and
capabilities to the asset management system including the plan for both internal and contracted activities.
Plans are reviewed integral to asset management system process(es).
Competency requirements are in place and aligned with asset management plan(s). Plans are in place and
effective in providing the training necessary to achieve the competencies. A structured means of recording the
competencies achieved is in place.
Competency requirements are identified and assessed for all persons carrying out asset management related
activities - internal and contracted. Requirements are reviewed and staff reassessed at appropriate intervals
aligned to asset management requirements.
Two way communication is in place between all relevant parties, ensuring that information is effectively
communicated to match the requirements of asset management strategy, plan(s) and process(es). Pertinent
asset information requirements are regularly reviewed.
The organisation has established documentation that comprehensively describes all the main elements of its
asset management system and the interactions between them. The documentation is kept up to date.
63
Information
management
3
64
Information
management
How does the organisation maintain its asset management information system(s) and
ensure that the data held within it (them) is of the requisite quality and accuracy and is
consistent?
How has the organisation's ensured its asset management information system is
relevant to its needs?
69
Risk management
process(es)
3
79
Use and
maintenance of
asset risk
information
Legal and other
requirements
How has the organisation documented process(es) and/or procedure(s) for the
identification and assessment of asset and asset management related risks throughout
the asset life cycle?
How does the organisation ensure that the results of risk assessments provide input into
the identification of adequate resources and training and competency needs?
What procedure does the organisation have to identify and provide access to its legal,
regulatory, statutory and other asset management requirements, and how is
requirements incorporated into the asset management system?
How does the organisation establish implement and maintain process(es) for the
implementation of its asset management plan(s) and control of activities across the
creation, acquisition or enhancement of assets. This includes design, modification,
procurement, construction and commissioning activities?
How does the organisation ensure that process(es) and/or procedure(s) for the
implementation of asset management plan(s) and control of activities during
maintenance (and inspection) of assets are sufficient to ensure activities are carried out
under specified conditions, are consistent with asset management strategy and control
cost, risk and performance?
How does the organisation measure the performance and condition of its assets?
3
How does the organisation ensure responsibility and the authority for the handling,
investigation and mitigation of asset-related failures, incidents and emergency
situations and non conformances is clear, unambiguous, understood and
communicated?
3
What has the organisation done to establish procedure(s) for the audit of its asset
management system (process(es))?
3
48
49
50
53
59
62
82
88
Life Cycle Activities
91
Life Cycle Activities
95
Performance and
condition
monitoring
Investigation of
asset-related
failures, incidents
and
nonconformities
Audit
99
105
(Note this is about resources and enabling support)
What plan(s) and procedure(s) does the organisation have for identifying and
responding to incidents and emergency situations and ensuring continuity of critical
asset management activities?
What has the organisation done to appoint member(s) of its management team to be
responsible for ensuring that the organisation's assets deliver the requirements of the
asset management strategy, objectives and plan(s)?
What evidence can the organisation's top management provide to demonstrate that
sufficient resources are available for asset management?
3
3
3
3
3
3
3
3
3
3
2
3
3
Appropriate emergency plan(s) and procedure(s) are in place to respond to credible incidents and manage
continuity of critical asset management activities consistent with policies and asset management objectives.
Training and external agency alignment is in place.
The appointed person or persons have full responsibility for ensuring that the organisation's assets deliver the
requirements of the asset management strategy, objectives and plan(s). They have been given the necessary
authority to achieve this.
An effective process exists for determining the resources needed for asset management and sufficient resources
are available. It can be demonstrated that resources are matched to asset management requirements.
The organisation has determined what its asset information system should contain in order to support its asset
management system. The requirements relate to the whole life cycle and cover information originating from
both internal and external sources.
The organisation has effective controls in place that ensure the data held is of the requisite quality and
accuracy and is consistent. The controls are regularly reviewed and improved where necessary.
The organisation has developed and is implementing a process to ensure its asset management information
system is relevant to its needs. Gaps between what the information system provides and the organisations
needs have been identified and action is being taken to close them.
Identification and assessment of asset related risk across the asset lifecycle is fully documented. The
organisation can demonstrate that appropriate documented mechanisms are integrated across life cycle phases
and are being consistently applied.
Outputs from risk assessments are consistently and systematically used as inputs to develop resources,
training and competency requirements. Examples and evidence is available.
Evidence exists to demonstrate that the organisation's legal, regulatory, statutory and other asset management
requirements are identified and kept up to date. Systematic mechanisms for identifying relevant legal and
statutory requirements.
Effective process(es) and procedure(s) are in place to manage and control the implementation of asset
management plan(s) during activities related to asset creation including design, modification, procurement,
construction and commissioning.
The organisation is in the process of putting in place process(es) and procedure(s) to manage and control the
implementation of asset management plan(s) during this life cycle phase. They include a process for confirming
the process(es)/procedure(s) are effective and if necessary carrying out modifications.
2
The organisation is developing coherent asset performance monitoring linked to asset management objectives.
Reactive and proactive measures are in place. Use is being made of leading indicators and analysis. Gaps and
inconsistencies remain.
The organisation have defined the appropriate responsibilities and authorities and evidence is available to
show that these are applied across the business and kept up to date.
Corrective &
How does the organisation instigate appropriate corrective and/or preventive actions to
Preventative action eliminate or prevent the causes of identified poor performance and non conformance?
3
113
Continual
Improvement
2
115
Continual
Improvement
Asset management plan
Asset management plan(s) are established, documented, implemented and maintained for asset systems and
critical assets to achieve the asset management strategy and asset management objectives across all life cycle
phases.
The plan(s) are communicated to all relevant employees, stakeholders and contracted service providers to a
level of detail appropriate to their participation or business interests in the delivery of the plan(s) and there is
confirmation that they are being used effectively.
Asset management plan(s) consistently document responsibilities for the delivery actions and there is adequate
detail to enable delivery of actions. Designated responsibility and authority for achievement of asset plan
actions is appropriate.
The organisation has arrangements in place for the implementation of asset management plan(s) but the
arrangements are not yet adequately efficient and/or effective. The organisation is working to resolve existing
weaknesses.
2
109
How does the organisation achieve continual improvement in the optimal combination
of costs, asset related risks and the performance and condition of assets and asset
systems across the whole life cycle?
How does the organisation seek and acquire knowledge about new asset management
related technology and practices, and evaluate their potential benefit to the
organisation?
All linkages are in place and evidence is available to demonstrate that, where appropriate, the organisation's
asset management strategy is consistent with its other organisational policies and strategies. The organisation
has also identified and considered the requirements of relevant stakeholders.
The asset management strategy takes account of the lifecycle of all of its assets, asset types and asset systems.
3
The organisation can demonstrate that its audit procedure(s) cover all the appropriate asset-related activities
and the associated reporting of audit results. Audits are to an appropriate level of detail and consistently
managed.
Mechanisms are consistently in place and effective for the systematic instigation of preventive and corrective
actions to address root causes of non compliance or incidents identified by investigations, compliance
evaluation or audit.
Continuous improvement process(es) are set out and include consideration of cost risk, performance and
condition for assets managed across the whole life cycle but it is not yet being systematically applied.
The organisation actively engages internally and externally with other asset management practitioners,
professional bodies and relevant conferences. Actively investigates and evaluates new practices and evolves its
asset management activities using appropriate developments.
Page 192 of 193
APPENDIX - APPROVAL BY GOVERNING COMMITTEE
K. Appendix - Approval by Governing Committee
Certification for Year-beginning Disclosures
We, Terry Michael Shagin and, Kenneth John Forrest being Directors of companies which are
parties to the OtagoNet Joint Venture certify that, having made all reasonable enquiry, to the
best of our knowledgea) The following attached information of OtagoNet Joint Venture prepared for the
purposes of clause 2.6.1 and subclauses 2.6.3(4) and 2.6.5(3) of the Electricity
Distribution Information Disclosure Determination 2012 in all material respects
complies with that determination.
b) The prospective financial or non-financial information included in the attached
information has been measured on a basis consistent with regulatory requirements or
recognised industry standards.
____________________
T M Shagin
____________________
K J Forrest
Date: 31 March 2014
Asset management plan
Page 193 of 193
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