Network Load Management (NLM) · arrangements with non-network service providers • Provides non-network service providers an opportunity to offer alternative proposals to defer

2016 DAPR

UE Network Planning

6 February 2017

[email protected]

United Energy and Multinet Gas

mailto:[email protected]

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


2

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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https://www.unitedenergy.com.au/wp-content/uploads/2016/12/UE-Distribution-Annual-Planning-Report-2016.pdf

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


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


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


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



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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


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


United Energy

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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)


– ~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


– RIT-D required – expected timing Nov 2020



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.


United Energy

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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


– ~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


– RIT-D not required


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


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Documents

Network Load Management (NLM) · arrangements with non-network service providers • Provides non-network service providers an opportunity to offer alternative proposals to defer