2016 DAPR
UE Network Planning
6 February 2017
United Energy and Multinet Gas
Content
• Overview of UE’s electricity distribution network
• Purpose of Distribution Annual Planning Report (DAPR)
• Demand side engagement framework
• Electricity maximum demand drivers and forecast
• Annual planning process
• Probabilistic planning approach
• Network limitations and opportunities
• Deferred network limitations
• Network limitations map demonstration
• Questions & next steps
United Energy and Multinet Gas
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United Energy (UE) Overview
• UE is a regulated Victorian
electricity Distribution Business
servicing customers throughout
Melbourne’s south east and
Mornington Peninsula
• 664,500 customers
• 11 bulk supply points
• 78 sub-transmission circuits
• 47 zone substations
• 465 distribution feeders
• 13,230 distribution transformers
• 10,100 km overhead lines
• 2,800 km underground cables
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Distribution Annual Planning Report (DAPR)
• Published annually on our website
https://www.unitedenergy.com.au/wp-content/uploads/2016/12/UE-Distribution-Annual-
Planning-Report-2016.pdf
• Outlines outcomes of annual risk assessment review over a five-year period
• Maximum demand forecasts at terminal station, sub-transmission, zone
substation and high-voltage feeder level
• Capacity augmentation plans based on probabilistic planning
• Operational requirements of non-network solutions to defer traditional
network solutions
• RIT-D consultations
• Asset management approach and asset replacement / refurbishment plans
• Other investment plans such as metering / IT / reliability / power quality
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Demand Side Engagement Framework
• Provides UE an opportunity to engage and formalise joint planning
arrangements with non-network service providers
• Provides non-network service providers an opportunity to offer alternative
proposals to defer network investments and work with UE to develop optimal
solutions
• 3 RIT-Ds since its introduction including Dromana, Lower Mornington
Peninsula and Notting Hill supply areas
• Good participation rate of non-network solutions offered in recent RIT-Ds
including detailed proposals from GreenSync, Aggreko and Energy
Developments
• Non-network solutions contracted as a result of lower Mornington Peninsula
supply area RIT-D and other examples used to defer augmentation on
Aspendale (CRM35) and Scoresby (MGE12) distribution feeders
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Maximum Demand Drivers
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• Economic activity
• Population / customer numbers
• Weather (particularly temperature driving air-conditioning)
• Price of electricity
• Energy efficiency
• Distributed generation
• Demand management
• Energy storage
• Electric vehicles
• Price of alternative energy sources
Maximum Demand Growth Forecast
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• The overall UE service area has had no maximum demand growth since 2013
due to slow down of the economy, electricity price rises, and (to a lesser
extent) energy efficiency and solar PV
• Growth projections have reduced with confirmation each year of an ongoing
weak and uncertain economic outlook
• Growth rates however do vary across the UE service area, and it is this
variation that is driving our current augmentation plans
2016 weather-corrected
actual demand
Annual Network Planning Process
United Energy and Multinet Gas
Peak Demand Forecast & Constraints
Publish Distribution Annual Planning Report
(December)
Identify Network and Non-Network Options
RIT-D Assessment & Consultation
(Ongoing as required)
Determine Preferred Option (or Do Nothing)
Public Forum (February)
Joint Planning Activities (Ongoing)
Probabilistic Planning Approach
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A. Energy at risk (MWh pa) = Sum of demand at risk for each hour
(weighted with 10% and 50% PoE maximum demand forecasts)
B. Expected energy at risk (MWh pa) = Energy at risk * Asset unavailability
C. Value of expected energy at risk ($) = Expected energy at risk * VCR
D. Annualised cost of augmentation ($) = Network project cost * WACC
Augmentation becomes economic when C > D Economic Non-network options
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
Hours
Two TF Zone Substation load profile on 17 Jan 2014
Load Duration Curve N-1 rating N rating
N rating
Energy at risk
N-1 rating
Dem
an
d
2016 DAPR – Network Limitations
• Network deferral opportunities
identified:
– 2 sub-transmission systems;
– 2 zone substations;
– 6 high-voltage distribution feeders; and
– 98 distribution substation sites.
• Sub-transmission augmentations are in
the order of $0.5M (RIT-D not
required)
• Zone substation augmentations are in
the order of $7M (RIT-D required)
• High-voltage distribution feeder
augmentations are in the order of
$0.03M to $1.4M (RIT-D not required)
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Network deferral opportunities
Sub-transmission and Zone Substation level
Supply AreaSub-transmission
limitation
Zone substation
limitation
Annual Cost of
preferred solution1
Augmentation
timing
East Burwood SVTS-EB-RD-SVTS - $33,800 2017-18
Doncaster, Box Hill
North and Templestowe- DC $510,000 2019-20
East Malvern, East
Alamein, Carnegie and
Chadstone
- EM $446,000 2022-23
United Energy
111 This cost is an estimate only. It may change to a higher or a lower number when detailed scopes of work is prepared.
Network deferral opportunity 1
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Doncaster / Doncaster East / Doncaster Hill / Templestowe / Box Hill Central /
Box Hill North supply area
• ~30,400 customers are currently supplied by Doncaster (DC) zone substation
• Maximum demand occurs during summer months
• New residential developments (i.e. high-rise
apartments) and existing customer expansions
are expected
Network deferral opportunity 1
United Energy
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Zone substation limitation
• DC zone substation has been operating above its (N-1) rating of 74 MVA
• Loss of one of the zone substation transformers during maximum demand conditions
can lead to supply interruption
• Five of the ten DC feeders are amongst UE’s top 50 ‘rogue’ feeders.
DC ZS
Network deferral opportunity 1
United Energy
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• Network options
• Option 1
– Install a 4th 20/33 MVA transformer at DC zone substation by 2019-20 @ ~$8M
• Option 2
– Establishing a new 66/22 kV zone substation at Templestowe by 2019-20 @ ~$19M
• Non-Network option requirements
– ~3 MW load reduction in DC supply area by 2019-20
– between the hours of 15:00 to 20:00 on maximum demand days
– Additional 2.0 MW/yr load reduction thereafter
– Post contingent solution preferred
• Demand side engagement
– RIT-D required – expected timing Nov 2017
– Non-Network proposals are welcome
Network deferral opportunity 2
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Alamein / Carnegie / Chadstone and East Malvern supply area
• ~13,400 Customers currently supplied by East Malvern (EM) zone substations
• Maximum demand occurs during summer
months
• New residential developments and existing
customer expansions are expected
Network deferral opportunity 2
United Energy
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Zone substation limitation
• EM a 66/11kV two transformer zone substation has been operating above its (N-1) rating
of 31.9 MVA.
• Loss of one of the zone substation transformers during maximum demand conditions can
lead to supply interruption.
EM ZS
Network deferral opportunity 2
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• Network options
• Option 1
– Install a 3rd 20/33MVA transformer at EM zone substation by 2022-23 @ ~$7M
• Option 2
– Establishing a new 66/22 kV zone substation by 2022-23 (presently no sites
under consideration)
• Non-Network option requirements
– ~2.0 MW load reduction in EM supply area by 2022-23
– between the hours of 16:00 to 22:00 on maximum demand days
– Additional ~1.0 MW/yr load reduction thereafter
– Post contingent solution preferred
• Demand side engagement
– RIT-D required – expected timing Nov 2020
– Non-Network proposals are welcome
Network deferral opportunity 3
United Energy
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Sub-transmission limitation
• The SVTS-EB-RD-SVTS loop is operating above its (N-1) rating of 830A
• System is limited by the SVTS-EB 66 kV line rating, for an outage of the
SVTS-RD 66 kV line during maximum demand conditions.
Network deferral opportunity 3
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• Network option
– Up-rating the SVTS-EB 66 kV line by
2017-18 at an estimated cost of ~ $0.6M
– Will increase SVTS-EB line rating from
830A to 950A
• Non-Network option requirements
– ~2.0 MW load reduction in EB or RD
supply area for summer 2017-18
– between the hours of 15:00 to 20:00 on
maximum demand days
– Additional ~2.0 MW/yr load reduction
thereafter
– Post contingent solutions
• Demand side engagement
– RIT-D not required
– Non-Network proposals are welcome
Distribution Feeder Augmentations
Distribution
FeederFeeder location
Expected
annual cost
of preferred
solution1
Expected demand
reduction
required2 (MW)
Expected
timing
CRM 35
Wells Rd, Chelsea / Chelsea
Heights / Aspendale Gardens /
Bangholme Area
$25,500 ~ 0.5 2018-19
DVY 24
Dandenong Frankston Rd,
Carrum Downs / Dandenong
South / Sandhurst Area
$57,400 ~ 2.0 2018-19
EL 10 Glenhuntly Rd, Elsternwick Area $76,500 ~ 3.5 2018-19
FSH 33
Mt Eliza Way, Mount Eliza /
Frankston Flinders Rd, Frankston
South Area
$21,000 ~ 0.5 2018-19
FTN 23Hall Rd, Carrum Downs / Seaford
/ Skye Area$1,700 ~ 0.5 2017-18
MGE 12Jells Rd / Ferntree Gully Rd,
Wheelers Hill / Scoresby Area $89,200 ~ 3.0 2018-19
United Energy
201 This cost is an estimate only. It may change to a higher or a lower number when detailed scopes of work is prepared.
2 This reduction is a high level estimate only and is subject to change following a detailed RIT-D assessment process.
Last Year’s 2015 DAPR – Deferred Limitations
2015 DAPR
LimitationReason for deferral Revised timing
Carrum Downs / Skye
Supply Area
(Sub-Transmission
and Zone substation
limitation)
By 2017-18, AusNet Transmission Group will be
implementing dynamic ratings for the CBTS-FTS
66kV lines and implementing centralised automatic
load shedding scheme (SOCS) at CBTS for CBTS-
FTS two 66kV lines to ensure that the loading of
these two lines do not exceed their dynamic ratings.
These works are expected to elevate network
limitation beyond 10 years.
Beyond 2028
United Energy
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Next steps……
• Engage in joint planning to develop non-network solutions
• Identify preferred solution
• Feedback on 2016 DAPR
• Constraints Map Demonstration
• Questions & Discussion
United Energy and Multinet Gas
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