Evaluation Report RFP 002/11

Header
Evaluation Report RFP 002/11
Overload of Campbelltown and Woodforde
Substations
EVALUATION REPORT RFP 002/11
Page 1 of 3
Disclaimer
This Evaluation Report has been prepared in accordance with the requirements of Section 4
of ESCOSA Guideline 12 – Demand Management for Electricity Distribution Networks and of
Clause 5.6.2 of the National Electricity Rules. The purpose of the Evaluation Report is to
announce the outcomes of ETSA Utilities evaluation of the proposals it has received in
response to a Request for Proposals it has issued and the network augmentation option
recommended as a result of that evaluation.
This document is not intended to be used by other parties for any purpose, such as making
decisions to invest in generation, transmission or distribution capacity. This document has
been prepared using information provided by, and reports prepared by, a number of third
parties.
While care was taken in the preparation of the information in this report, and it is provided in
good faith, ETSA Utilities accepts no responsibility or liability for any loss or damage that may
be incurred by any person acting in reliance on this information or assumptions drawn from it.
EVALUATION REPORT RFP 002/11
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EXECUTIVE SUMMARY
This Evaluation Report addresses augmentation options developed to resolve the projected
network limitations described in RFP 002/11 Overload of Campbelltown and Woodforde
Substations. This RFP was issued by ETSA Utilities in December 2011 with submissions closing on
2nd March 2012. No submissions were received for RFP 002/11.
Demand Management options that were considered include standby diesel generators,
installation of power factor correction, retrofit commercial lighting with efficient lighting, peak
load control (direct and curtailable load), residential compact fluorescent lamp (CFL)
program, thermal storage systems and energy storage technology. Reasonableness Test RT
005/08 Issue 2.0, evaluated these options and deemed that none of these Demand
Management strategies could be implemented to achieve the demand reduction required
to make project deferral technically and economically viable.
After consideration of the above ETSA Utilities developed the following options for evaluation:

Construct a substation in Glynde including a new 66kV line and 66/11kV Substation
with new 11kV switchboard.

Upgrade Campbelltown Substation with two 32MVA 66/11kV transformers and
construct three express 11kV feeders to the Glynde region, with transfers of load to the
relevant substation via the 11kV network to suit.
These options were subjected to the Reliability Limb of the AER Regulatory Test as explained in
Section 3.1 Evaluation Criteria.
In accordance with the requirements of the evaluation process, market scenarios were
developed to test the robustness of the test to variations in load forecast, capital costs,
discount rate, the cost of electrical losses, and the value of customer reliability (VCR).
The evaluation showed that under all scenarios Option 1 was the most favourable. Least
difference in NPV was found to be under Case 1 with low load growth and most difference in
NPV was under Case 2 with high load growth.
Based on this evaluation, Option 1, New Glynde Substation is the preferred option and is
recommended for implementation with work starting in 2014. This decision is dependent on:

Electricity demand matching forecast growth;

Internal financial approvals;

Gaining the relevant development and environmental approvals;
EVALUATION REPORT RFP 002/11
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Contents
Executive Summary..................................................................................................................................... 3
Definitions ...................................................................................................................................................... 6
1.
2.
Network Augmentation Consultation Process ............................................................................... 9
1.1
Background ................................................................................................................................. 9
1.2
ESCOSA Guideline 12 ................................................................................................................. 9
1.3
AER Regulatory Test .................................................................................................................. 10
1.4
Publication History .................................................................................................................... 10
Existing network .................................................................................................................................. 11
2.1
Description ................................................................................................................................. 11
2.1.a
Customer Base Details and list of major customers ....................................................... 13
2.1.b
Committed Distribution Augmentations .......................................................................... 14
2.1.c
Existing and Committed Generation ................................................................................ 14
2.2
Load Forecast and Properties ................................................................................................ 15
2.2.a
Strategic Significance.......................................................................................................... 15
2.2.b
Load Forecast ....................................................................................................................... 15
2.2.c
Pattern Of Use ....................................................................................................................... 15
2.3
ETSA Utilities Planning Criteria ................................................................................................. 18
2.4
Service standards / QOS ......................................................................................................... 18
2.5
Network Constraints ................................................................................................................. 19
2.5.a
Campbelltown and Woodforde Substations overload during peak load periods . 19
2.5.b
11kV feeder overloads during peak load periods ......................................................... 20
2.5.c
Factors Impacting Timing of Required Corrective Action ............................................ 20
2.5.d
Market and Other Network Impacts ................................................................................ 21
OPTIONS FOR REINFORCEMENT .............................................................................................................. 22
2.6
Proposals received in response to RFP ................................................................................. 22
2.7
Demand Management Options ........................................................................................... 22
2.7.a
Standby diesel generators .................................................................................................. 22
2.7.b
Install power factor correction .......................................................................................... 22
2.7.c
Retrofit commercial lighting with efficient lighting. ....................................................... 22
2.7.d
Peak load control – direct load control ........................................................................... 22
2.7.e
Peak load control – curtailable load ................................................................................ 22
2.7.f
Residential compact fluorescent lamp (CFL) program ................................................ 22
2.7.g
Thermal storage systems ..................................................................................................... 22
2.7.h
Energy Storage...................................................................................................................... 23
2.7.i
Conclusion ............................................................................................................................. 23
EVALUATION REPORT RFP 002/11
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2.8
3.
2.8.a
Option 1 – New Glynde Substation ................................................................................... 23
2.8.b
Option 2 – Upgrade Campbelltown Substation ............................................................. 23
Option Evaluation .............................................................................................................................. 24
3.1
4.
Evaluated options .................................................................................................................... 23
Evaluation Criteria .................................................................................................................... 24
3.1.a
ESCOSA Guideline 12 .......................................................................................................... 24
3.1.b
AER Regulatory Test.............................................................................................................. 24
3.2
Evaluation of proposals ........................................................................................................... 25
3.3
Evaluation parameters ............................................................................................................ 25
3.4
Market scenarios evaluated .................................................................................................. 28
3.5
Evaluation Results ..................................................................................................................... 29
Conclusions ......................................................................................................................................... 29
Tables
Table 1: Moderate forecast total electricity demand at summer peak levels for the
Campbelltown 66/11kV Substation and the Woodforde 66/11kV Substation. ............................. 15
Table 2: Campbelltown Substation Load at risk .................................................................................. 19
Table 3: Woodforde Substation Load at risk ........................................................................................ 19
Table 5: NPV Evaluation Results and Rankings .................................................................................... 29
Figures
Figure 1: Campbelltown and Woodforde Electricity Supply System .............................................. 12
Figure 2: Campbelltown Substation Duration Curve for 2010 .......................................................... 16
Figure 3: Woodforde Substation Duration Curve for 2010 ................................................................. 16
Figure 4: Campbelltown Substation maximum load day curve (29/1/2009) ................................ 17
Figure 5: Woodforde Substation maximum load day curve (28/1/2009) ....................................... 17
EVALUATION REPORT RFP 002/11
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DEFINITIONS
Act
Electricity Act 1996
AEMC
Australian Energy Market Commission
AEMO
Australian Energy Market Operator
AER
Australian Energy Regulator
Application Notice
A notice made available to Registered Participants and Interested
Parties pursuant to clause 5.6.6 of the NER
Base Case
The market scenario considered most probable to be realistic when
undertaking the Regulatory Test which is used as the reference case
when considering alternative plausible market scenarios
Demand Management
(DM)
Demand Management is the management of the level or pattern of
energy use on the transmission / distribution network, so as to minimise
the supply cost to customers whilst maintaining or enhancing customer
service levels. Supply costs include costs of projects associated with
the augmentation of, or extension to, the transmission or distribution
network, and include network losses
DNSP
Distribution Network Service Provider
DSM
Demand Side Management – the management of demand on the
power system by means of controlling or reducing the load on the
network
DUOS
Distribution Use Of System charges applicable to Registered
Participants in the NEM
EDC
Electricity Distribution Code (EDC) – as issued by ESCOSA
ESCOSA
Essential Services Commission of South Australia established under the
Essential Services Commission Act 2002
ESDP
Electricity System Development Plan (ESDP) developed annually by
ETSA Utilities and published by 30 June. The ESDP includes details of
projected limitations on the ETSA Utilities Distribution system for at least
the next three year period and provides the information needed for a
party to register as an Interested Party as defined within ESCOSA
Guideline 12
ETSA Utilities
ETSA Utilities is South Australia’s principal Distribution Network Service
Provider (DNSP) and is responsible for the distribution of electricity to all
distribution grid connected customers within the State under a
regulatory framework. ETSA Utilities is a partnership of Cheung Kong
Infrastructure Holdings Ltd (CKI), Hong Kong Electric International Ltd
(HEI) and Spark Infrastructure
EVALUATION REPORT RFP 002/11
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Guideline 12 (GL 12)
ESCOSA Electricity Industry Guideline 12 – Demand Management for
Electricity Distribution Networks. A copy may be found on the ESCOSA
website www.escosa.sa.gov.au
Interested Party
Individuals or organisations registered with ETSA Utilities in accordance
with Guideline 12 that have an interest in ETSA Utilities’ long term
planning, Demand Management initiatives, addressing a particular
constraint, or more generally in addressing Demand Management
issues
Market Benefit Limb
Under version 3 of the AER regulatory test a broad test is applied to the
competing options that includes the evaluation of impact on system
losses and customer reliability where the timing of the options is not
determined by the requirement to resolve a particular constraint; i.e.
the date of the resolution of the constraint is flexible. This test is referred
to as the “Market Benefit” limb.
NEM
National Electricity Market
NER
National Electricity Rules
NPV
Net Present Value
O&M
Operating and Maintenance
OLTC
On Load Tap Changer – a device used to control the output voltage
of a transformer
QoS
Quality of Supply
RDP
Regional Development Plan
Reasonableness Test
Reasonableness Test - as defined in ESCOSA Electricity Industry
Guideline 12
Registered Participant
A person who is registered with AEMO as a Network Service Provider, a
System Operator, a Network Operator, a Special Participant, a
Generator, a Customer or a Market Participant
Regulatory Test
The test promulgated by the AER, which all major network investment
must comply with
Reliability Limb
Under version 3 of the AER regulatory test a strict least cost test is
applied to the competing options where the timing of the options is
mandated by network constraints. This test is referred to as the
“Reliability” limb.
RFP
Request for Proposals
ROA
Return on Asset
Rules
National Electricity Rules (NER)
TUOS
Transmission Use of System charges applicable to Registered
EVALUATION REPORT RFP 002/11
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Participants in the NEM
SAIDI
System Average Interruption Duration Index
SAIFI
System Average Interruption Frequency Index.
SATC
South Australian Transmission Code
VCR
Value of Customer Reliability. The value placed by consumers on loss
of supply of electricity, expressed as $ per MWh
VoLL
Value of Lost Load as measured in the NEM
WACC
Weighted Average Cost of Capital
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1. NETWORK AUGMENTATION CONSULTATION PROCESS
1.1
Background
Prior to undertaking an augmentation of its power system that involves a significant level of
expenditure, ETSA Utilities is required to consult with affected parties, Registered Participants
and Interested Parties under the National Electricity Rules (NER) and ESCOSA Guideline 12.
The consultation process that is being followed by ETSA Utilities has been structured to meet
the needs of both the NER and ESCOSA Guideline 12. It involves:

The annual issue of an Electricity System Development Plan (ESDP) in June of each
year. This report includes descriptions of impending constraints in the sub-transmission
and distribution system forecast to occur within 3 years of the report’s publication.

For proposals to augment the network where the capital cost is less than $10 million,
the ESCOSA mandated Guideline 12 process is followed which includes undertaking
a Reasonableness Test where required and if the Reasonableness Test is met, issuing a
Request for Proposal (RFP) seeking alternative solutions to the forecast network
limitation.

For proposals where the capital cost is greater than $10 million, the NER mandated
AER process is followed and a Request for Proposal (RFP) is usually directly issued.

The RFP requests proposals, both formal and informal, from interested parties on how
the constraint described in the RFP can best be resolved.

Any responses received from Interested Parties to the RFP along with ETSA Utilities
generated options are then evaluated according to either the Guideline 12 or AER
regulatory process.

The results of the evaluation are then published in an Evaluation Report (this report).
The report will typically recommend a preferred choice of action which ETSA Utilities
will them implement subject to gaining the necessary approvals.
Please note that this process is likely to change in the near future with the release of the
Australian Energy Market Commission (AEMC) Regulatory Investment Test – Distribution (RIT-D)
amendments to the NER.
1.2
ESCOSA Guideline 12
Under ESCOSA Guideline 12, ETSA Utilities prepares an annual Electricity Supply Development
Plan (ESDP) that identifies actual and forecast constraints on the ETSA Utilities power system
for the approaching three year period, organised into 13 regions. It is published on 30th June
each year.
When an eligible project as defined within Guideline 12 is proposed (ie a project with total
expenditure between $2 million and $10 million), the Guideline 12 process requires ETSA
Utilities to peform a screening test (The Reasonableness Test) to determine if there is potential
for a third party or Demand Management solution to resolve the identified constraint. The
result of the Reasonableness Tests are published on the ETSA Utilities website as they are
prepared and Interested Parties are advised accordingly. Details of this process and how to
register as an Interested Party can be found within the ESDP.
If the project passes the Reasonableness Test (i.e. there is some potential for a third party /
Demand Management solution to resolve the identified constraint) a RFP is prepared and
published on the ETSA Utilities website. Notice of the publication of the RFP is sent to all
Interested Parties and is also published on the AEMO website.
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Once the public submission date has passed, ETSA Utilities must evaluate the responses to the
RFP against its own internally generated options on an equal footing. The basis for this
evaluation is described in Section 3.1 - Evaluation Criteria.
Following this evaluation, ETSA Utilities must publish the results of it evaluation of each option
through the issuance of an Evaluation Report.
1.3
AER Regulatory Test
Clause 5.6.2 of the National Electricity Rules (NER) also places obligations on Distribution
Network Service Providers (DNSP) such as ETSA Utilities to consult with Registered Participants
and Interested Parties (as defined in the NER) regarding augmentations and extensions to the
distribution system where the cost of these augmentations is expected to cost more than $10
million.
As is the case under the Guideline 12 rules, ETSA Utilities must prepare and issue a RFP
requesting information from Interested Parties on possible Demand Management or other
non-network solutions to the network constraints outlined in the document.
Once the public submission date has passed, ETSA Utilities must evaluate the responses to the
RFP against its own internally generated options on an equal footing according to the
evaluation criteria specified by the AER Regulatory Test that are in force at the time. The
basis for this evaluation is described in Section 3.1 - Evaluation Criteria.
Following the evaluation process, ETSA Utilities must publish a report which in the words of the
1
NER :
“ (1)
(2)
(3)
(4)
Includes an assessment of all identified options referred to in paragraph (g) or (g1);
includes details of the preferred proposal including:
(i)
its economic cost effectiveness analysis in accordance with paragraph (g) or
(g1); and
(ii)
the consultations conducted for the purposes of paragraph (g) or (g1);
summarises the submissions from the consultations; and
recommends the action to be taken.”
Once published, there is a 40 business day consultation period during which Interested Parties
may challenge the recommendations of the report. This process is set out in clauses 5.6.2 (I)
(j) and (k) of the NER.
1.4
Publication History
Reasonableness Test, published December 2008:
RT/005/08 Overload of Campbelltown and Woodforde Substations
Revised Reasonableness Test, published December 2011:
RT005/11 Overload of Campbelltown and Woodforde Substations
Request for Proposals, published December 2011, submission close date 2 nd March 2012:
RFP002/11 Overload of Campbelltown and Woodforde Substations
1
NATIONAL ELECTRICITY RULES CHAPTER 5 VERSION 49 Section 5.6.2 (h) Page 410
EVALUATION REPORT RFP 002/11
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2. EXISTING NETWORK
2.1
Description
The Campbelltown and Woodforde Substations form part of the Eastern Suburbs meshed
electricity network. Both substations are supplied directly from the 66,000 volt sub-transmission
network and operated at 66,000 volts stepped down to 11,000 volts. The Campbelltown
Substation contains two 24MVA 66/11kV transformers and the Woodforde Substation contains
two 21MVA 66/11kV transformers.
Campbelltown Substation is located on the corner of Gorge Road and Jan Street in
Campbelltown. Campbelltown Substation is supplied via the ETSA Utilities’ Eastern Suburbs
66kV electricity distribution system. Campbelltown Substation has seven 11kV feeders that
supply the predominantly residential load, with a small contribution from the commercial,
educational and light industrial sectors.
Woodforde Substation is located on the corner of Magill Road and Vine Street in Woodforde.
Woodforde Substation is supplied via the ETSA Utilities’ Eastern Suburbs 66kV electricity
distribution system. Woodforde Substation has six 11kV feeders that supply the predominantly
residential load, with a small contribution from the commercial, educational and light
industrial sectors.
Some feeder works are being undertaken to defer the immediate overload of these
Substations by transferring load to adjacent Norwood Substation, however these constraints
will need to be addressed further in 2014.
The overall arrangement of this system is shown in Figure 1.
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Figure 1: Campbelltown and Woodforde Electricity Supply System
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2.1.a
Customer Base Details and list of major customers
Campbelltown and Woodforde Substations supply just over 27,000 customers in the Eastern
region of Adelaide. These are primarily residential customers with a smaller number of
commercial, educational and light industrial customers.
The largest customers in the area are:
Campbelltown Substation

Athelstone Shopping Centre, Gorge Road

R. Premium Foods Pty Ltd, Lewis Road

The Baltic Community Home, Avenue Road

Bi-Lo, Lower North East Road

Bianchini Pty Ltd, Jan Street

Bianco Hiring Service, Gorge Road

BP Campbelltown, Lower North East Road

BP Newton, Gorge Road

Cicchiello Enterprise Pty Ltd, Sunbeam Road

Codan Pty Ltd, Graves Street

Coles, Lower North East Road

Coles, Montacute Road

Coles Express, Hectorville

Glynde Hotel, Glynburn Road

Foodland, Gorge Road

GIC Australia Pty Ltd, Glynburn Road

Horn Furniture, Benjamin Street

John’s Print Centre, Provident Ave

Lifeplan Financial Group, The Grove Retirement Village

Newton Shopping Centre, Montacute Road

Paradise Hotel, Lower North East Road

Paradise Primary School, Silkes Road

Ramsay Health Care Australia Pty Ltd, Campbelltown

Resthaven, Silkes Road

Slape and Sons, Antonio Court

St Joseph’s School, Montacute Road

Telstra Paradise Exchange, Glynburn Road

Volpoly Pty Ltd, Moores Road

Woolworths, Gorge Road

Woolworths, Newton Shopping Centre
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
Robern Menz, Glynburn Road
Woodforde

Ach Group, Sparks Terrace

Bi-Lo Kensington Park, Magill Road

Bi-Lo Rostrevor, St Bernards Road

Clayton Church Homes, Bricknell Street

Dragon Bowl Chinese Takeaway, Magill Road

Fairlux, The Parade

Firle Property Management, Glynburn Road

Foodland, Kensington Road

Foodland, Magill Road

Ker Ching, Kensington Road

Norwood Morialta Middle School, Morialta Road

Norwood Morialta Senior School, The Parade

Magill Training Centre, Glen Stuart Road

Magill Primary School, Magill Road

Magill Winery, Penfold Road

The Oakden Central, Fosters Road

Pioneer Construction Materials, Gully Road

Pribetic Glass, Hender Avenue

Rostrevor College, Glen Stuart Road

Stradbroke Primary School, Koonga Ave

University of South Australia, St Bernards Road
2.1.b
Committed Distribution Augmentations
ETSA Utilities has committed to distribution augmentations that impact on the 11kV distribution
networks (such as additional feeders and load transfers) that service the Campbelltown and
Woodforde areas. These augmentations however do not defer augmentation of the network
post 2014.
2.1.c
Existing and Committed Generation
No known significant embedded generation is currently installed in the Campbelltown and
Woodforde area. ETSA Utilities is not aware of any existing or committed embedded
generation augmentations that will potentially impact on the distribution network that service
the Campbelltown and Woodforde regions.
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2.2
Load Forecast and Properties
2.2.a
Strategic Significance
The electrical load in the Campbelltown and Woodforde region comprises mainly residential
customers, with a small contribution from the commercial, educational and light industrial
sectors. Steady growth has contributed to a moderate load growth rate for the area.
2.2.b
Load Forecast
Demand forecasts issued by ETSA Utilities for Campbelltown Substation provide an overall
load growth in the area at an average rate of 3.0% per annum, which sees the load increase
to 83.5MVA by 2023/24, as shown in Table 1. This growth represents the moderate forecast
which ETSA Utilities uses for planning purposes.
Demand forecasts issued by ETSA Utilities for Woodforde Substation provide an overall load
growth in the area at an average rate of 2.5% per annum, which sees the load increase to
66.0MVA by 2023/24, shown in Table 1. This growth represents the moderate forecast which
ETSA Utilities uses for its planning purposes.
Given the predominance of residential load within the areas serviced by both substation, the
forecast power factor for the region is 0.92 – 0.93. Further power factor correction within the
region is not considered a cost-effective method of reducing the forecasted load.
Table 1: Moderate forecast total electricity demand at summer peak levels for the
Campbelltown 66/11kV Substation and the Woodforde 66/11kV Substation.
Moderate Growth Forecast (Summer)
Year
Campbelltown Sub Load (MVA)
2014/15
64.0
2015/16
65.9
2016/17
67.9
2017/18
70.0
2018/19
72.1
2019/20
74.2
2020/21
76.4
2021/22
78.7
2022/23
81.1
2023/24
83.5
Woodforde Sub Load (MVA)
52.9
54.2
55.5
56.9
58.3
59.8
61.3
62.8
64.4
66.0
The above forecast takes account of any known existing or committed demand
management programmes, and also the presence of any embedded generation that may
reduce the peak demand forecast that needs to be supplied via each substation, provided
these load reduction solutions are continuously available at times of peak load.
2.2.c
Pattern Of Use
The peak electricity demand on Campbelltown and Woodforde Substations occurs during
the summer months of the year, predominantly as a result of air-conditioning load. As the
rating of electrical plant typically decreases with increasing temperature, it can be expected
that the most onerous operating conditions for this network will occur during the summer
period. This therefore represents the most critical period relevant to ensuring that the
distribution network supplying this region of Metropolitan Adelaide remains adequate to
maintain a reliable and secure supply.
The following graphs show the annual load duration curves for Campbelltown Substation and
Woodforde Substation supply areas and the daily load curves for the summer peak load day.
EVALUATION REPORT RFP 002/11
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Campbelltown Substation Duration Curve
Jan 2010 - Dec 2010
100
90
80
% Load
70
60
50
40
30
20
10
0
0
10
20
30
40
50
60
70
80
90
100
90
100
% Time
Figure 2: Campbelltown Substation Duration Curve for 2010
Woodforde Substation Duration Curve
Jan 2010 - Dec 2010
100
90
80
% Load
70
60
50
40
30
20
10
0
0
10
20
30
40
50
60
70
80
% Time
Figure 3: Woodforde Substation Duration Curve for 2010
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Campbelltown Substation Load Curve
29/1/2009
1
0.9
Load (Normalised)
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
12:00 AM
12:00 PM
12:00 AM
Time
Figure 4: Campbelltown Substation maximum load day curve (29/1/2009)
Woodforde Substation Load Curve
28/1/2009
1
0.9
Load (Normalised)
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
12:00 AM
12:00 PM
12:00 AM
Time
Figure 5: Woodforde Substation maximum load day curve (28/1/2009)
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2.3
ETSA Utilities Planning Criteria
As a Network Service Provider (NSP) within the National Electricity Market, ETSA Utilities must
comply with the technical standards in the National Electricity Rules. In addition, as licensed
electricity entities in South Australia, ETSA Utilities is also required to comply with the service
obligations imposed by the EDC. These obligations require ETSA Utilities to operate its power
system within plant ratings and with acceptable quality of supply under reasonably expected
operating conditions.
ETSA Utilities’ uses specific planning criteria to ensure that it meets these requirements in a
cost effective way given the unique climatic conditions of South Australia. These criteria are
documented in Electricity System Development Plan published by ETSA Utilities annually on
30th June. They include:

The peak forecast load carried by a distribution substation in the specified year under
peak system loadings with all plants in service must not be above the distribution
substation’s normal rating (N).

The peak forecast load carried by a distribution substation in the specified year under
peak system load must not exceed the short term emergency capacity of the
substation (N-1) with one item of plant out of service following transfer of load to
adjoining substations and installation of a mobile substation.

The firm delivery capacity of a substation is defined as being the lesser of the
distribution substation’s N capacity and its N-1 + available load transfers + mobile
substation capacity.
2.4
Service standards / QOS
The relevant region of South Australia covered by this report is categorised as “Major
Metropolitan Area” for the purposes of the Service Standards contained within the EDC (refer
to clause 1.2 of the Code). The following service standards are applicable to this area:

Average minutes off supply per annum (SAIDI) – 130

Average number of supply interruptions per customer (SAIFI) – 1.45
ETSA Utilities must ensure that its distribution system meets the voltage and quality of supply
limits specified in Section 1.2.4 of the EDC, that is:
“ETSA Utilities must ensure that its distribution network is designed, installed, operated and
maintained so that:
 at the customer‟s supply address:

the voltage is as set out in AS 60038;

the voltage fluctuations that occur are contained within the limits as set out in AS/NZS
61000 Parts 3.3 and 3.5 and AS2279 Part 4; and

the harmonic voltage distortions do not exceed the values in AS/NZS 61000 Part 3.2
and AS 2279 Part 2 and as set out in the schedule to the standard connection and
supply contract; and
 the voltage unbalance factor in 3 phase supplies does not exceed the values set out in the
schedule to the standard connection and supply contract.
ETSA Utilities must ensure that any interference caused by its distribution network is less than the
limits set out in AS/NZS 61000 Part 3.5 and AS/NZS 2344.”
EVALUATION REPORT RFP 002/11
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2.5
Network Constraints
2.5.a
Campbelltown and Woodforde Substations overload during peak load periods
Campbelltown Substation is forecast to overload during forecast peak summer load times in
2014/15. The firm delivery capacity of Campbelltown Substation is 59.0MVA while the 2014/15
peak load at the Campbelltown Substation is forecast to be 64.0MVA producing an overload
of 5.2MVA.
Woodforde Substation is forecast to overload during forecast peak summer load times in
2014/15. The firm delivery capacity of Woodforde Substation is 47.6MVA while the 2014/15
peak load at the Woodforde Substation is forecast to be 52.9MVA producing an overload of
5.3MVA.
The following table provides an indication of the level and period of load reduction required.
Table 2: Campbelltown Substation Load at risk
Moderate Growth Forecast
Year
Campbelltown
Substation
(MVA)
Load at Risk
Load
Firm
Delivery
Capacity
of
Campbelltown Substation (MVA)
Load at Risk
(MVA)
Duration at Risk per
annum
(Hrs)
2014/15
64.0
58.8
5.2
14.5
2015/16
65.9
58.2
7.7
25.5
2016/17
67.9
57.7
10.2
40.5
2017/18
70.0
57.2
12.8
52.0
2018/19
72.1
56.7
15.4
65.0
2019/20
74.2
56.2
18.0
76.5
2020/21
76.4
55.7
20.7
93.0
2021/22
78.7
55.3
23.4
99.0
2022/23
81.1
54.8
26.3
118.5
2023/24
83.5
54.4
29.1
148.0
Table 3: Woodforde Substation Load at risk
Moderate Growth Forecast
Year
Woodforde Substation
Load (MVA)
Load at Risk
Firm
Delivery
Capacity
Woodforde Substation (MVA)
of
Load at Risk
(MVA)
Duration at Risk per
annum
(Hrs)
2014/15
52.9
47.6
5.3
31.0
2015/16
54.2
47.4
6.8
38.5
2016/17
55.5
47.1
8.4
50.0
2017/18
56.9
46.9
10.0
60.0
2018/19
58.3
46.6
11.7
76.5
2019/20
59.8
46.4
13.4
89.0
2020/21
61.3
46.2
15.1
106.0
2021/22
62.8
46.0
16.8
137.0
2022/23
64.4
45.7
18.7
190.0
2023/24
66.0
45.5
20.5
224.0
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Power factor improvement in the Campbelltown and Woodforde region in the past has
improved the power factor to its existing level of 0.92-0.93. Further power factor correction
within the region is not considered a cost-effective method of reducing the forecasted load.
2.5.b
11kV feeder overloads during peak load periods
The following 11kV feeders in the Glynde area are forecast to be overloaded during peak
summer load times within the next five years (by summer 2016/17):

Newton 11kV feeder (supplied from Campbelltown Substation)

Paradise 11kV feeder (supplied from Campbelltown Substation)

Montacute 11kV feeder (supplied from Campbelltown Substation)

Clairville 11kV feeder (supplied from Campbelltown Substation)

Hectorville 11kV feeder (supplied from Woodforde Substation)

Rostrevor 11kV feeder (supplied from Woodforde Substation)

Payneham 11kV feeder (supplied from Norwood Substation)

Firle 11kV feeder (supplied from Norwood Substation)
These overloads are mainly due to typical feeder lengths to the Glynde area of 3.5km, which
is 150% of the typical Adelaide 11kV feeder length. Reducing the feeder lengths reduce issues
of low voltage, declining quality of supply and reliability.
Solution providers and respondents should note that there is limited 11kV feeder offload
capacity between Campbelltown and Woodforde Substation feeders and adjacent
Substation feeders which are used together with the mobile Substation to supply customers
during Substation plant outages.
2.5.c
Factors Impacting Timing of Required Corrective Action
Assumed Electricity Demand
The primary driver of these projected network limitations is the forecast growth in electricity
demand in the area. The timing conclusion is based on a load growth forecast that assumes
peak summer conditions and moderate economic growth, and takes into account a
consideration for practical implementation times for system augmentation. Sensitivity analysis
has shown that the annual load growth is of sufficient magnitude to make the need for
augmentation relatively insensitive to these assumptions and would not alter the required
timing for corrective action.
Conclusion
Any timing recommendation requires a balance of the risks associated with variations in
electricity demand, temperature, and other assumptions. ETSA Utilities concludes that the
capability of Campbelltown and Woodforde Substations must be addressed by the summer
of 2014/15, if supply reliability and system security are to be maintained.
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2.5.d
Market and Other Network Impacts
The need for augmentation is driven primarily by existing load locations, their forecast growth
and existing plant limitations.
Market participants may wish to consider the following when developing alternative solutions:

Any new local embedded generation option will be required to operate at certain
times and under contract with ETSA Utilities. This will be essential for reliability purposes,
and such operation will be required regardless of the pool price at the time noting
that the National Electricity Rules prevents a generator that is providing grid support
from setting the market price;

Due to of the service obligations imposed by ETSA Utilities criteria, it will be necessary
to pre-dispatch a generation solution to ensure that no customer load (other that that
which has been contracted as interruptible) is lost as the result of a credible
contingency event occurring; and

A demand management initiative (e.g. programme to reduce electricity usage
during the relevant peak period) must provide positive proof that it is capable of
reducing flows on the relevant network elements to below the emergency ratings of
ETSA Utilities plants and equipment during single network contingencies. Similar to a
generation solution, it will be necessary to pre-dispatch demand side management to
ensure that no customer load (other than that which has been contracted as
interruptible) is lost as the result of a credible contingency event occurring. If the
required reduction is not achieved, the consequence is likely to be forced and
extensive customer load-shedding of prolonged duration during single contingencies,
which does not meet the reliability requirements of the EDC.
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OPTIONS FOR REINFORCEMENT
2.6
Proposals received in response to RFP
No submissions were received for RFP 002/11
2.7
Demand Management Options
Various Demand Management technologies were considered to determine their viability to
assist in reducing the demand in the constrained area. These DM options were evaluated for
both technical feasibility as well as cost effectiveness.
2.7.a
Standby diesel generators
Establish contracts with customers who have standby diesel generators on their premises and
utilise the generators at peak load times when. A review of customers in the vicinity showed
that there appear to be no customers with suitably sized units. As a result, this option is
deemed not suitable.
2.7.b
Install power factor correction
Customer power factor correction was considered at a cost of about $100/kVAR which
results in a kVA reduction at a cost of about $370/kVA. The list of qualifying customers (that
could benefit from power factor correction) was reviewed. The potential demand reduction
through customer power factor correction could amount to 795kVA (assuming all relevant
customers are willing to participate). This is not enough to address the substation constraints.
2.7.c
Retrofit commercial lighting with efficient lighting.
Upgrade existing commercial fluorescent lighting to T5 lighting. Based on the upgrade of a
400W fluorescent bank with a 2x 80W efficient bank provides the equivalent lumen output.
The demand saving per bank is 240W
There may be a number of suitable commercial customers, with a potential demand
reduction of up to 300kVA in the area. The estimated cost for this option is $2,500/kVA.
Significant disruption to the customer while the retrofit is carried out can be expected, which
may influence the number of willing participants.
2.7.d
Peak load control – direct load control
Direct load control technology is available where (via a power line carrier) tripping many
small air conditioning units supplied from a single distribution transformer can be performed.
Recent experiences have shown the costs to range from $300 to 800/kVA.
2.7.e
Peak load control – curtailable load
No suitable large customers were identified for turning power supply off to part of their
business during peak load times.
2.7.f
Residential compact fluorescent lamp (CFL) program
Demand Management trials using residential metering and control devices indicate take-up
rates vary depending on the area. From this response and the expected percentage of
suitable air conditioning units residential direct load control is estimated to cost between $335
and $600/kVA.
2.7.g
Thermal storage systems
A recent installation at a suitable site revealed a saving in load of 150kVA. The expected cost
for this type of installation is between $1,000 to $1,600 per kVA. Smaller scale installations
EVALUATION REPORT RFP 002/11
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have also been trialled, and are still very much in the development stage (More expensive
per kVA).
2.7.h
Energy Storage
Use of energy storage technology such as flow batteries is typically in the order of $6,000 per
kVA.
2.7.i
Conclusion
Based on the Demand Management options considered it is not possible that sufficient
Demand Management strategies could be implemented to achieve the demand reduction
required to make project deferral technically and economically viable.
2.8
Evaluated options
2.8.a
Option 1 – New Glynde Substation
This option requires the construction of a 66kV line from the existing Campbelltown-Magill
66kV line to the new Glynde Substation site in 2014. The Substation would be comprised of
one 66/11kV 32MVA transformer, 66kV bus work, a new masonry control building housing an
11kV switchboard and site civil works that include earthing and substation screening. Minimal
11kV feeder work will be required to establish four initial 11kV feeders as nearby are several of
the constrained 11kV feeders as described in 2.5.b.
This option will solve the N and N-1 constraints at Campbelltown and Woodforde as well as
future 11kV feeder N and N-1 constraints as described in 2.5.b until the forecast summer of
2021/22. At this point Campbelltown Substation will again be forecast to be constrained for
an N condition, exceeding its normal rating of 59MVA. Upgrading Campbelltown Substation
in 2021 by replacing the two 24MVA 66/11kV transformers with two 32MVA 66/11kV
transformers will solve this constraint.
After this solution, no further constraints are present in the 10 year evaluation period of this
report.
The option to establish a new Glynde substation in 2014 is a practical solution to the N and N1 constraints at Campbelltown and Woodforde Substations. Load from both Campbelltown
and Woodforde Substations can be easily transferred to the new substation via the existing
11kV network without extensive 11kV work. Constructing four new 11kV feeder exits in the
Glynde area will result in the shortening of many of the existing 11kV feeders in the
surrounding area. This leads to reduced load, reduced customer numbers and general
increased reliability for all 11kV feeders involved.
2.8.b
Option 2 – Upgrade Campbelltown Substation
This option requires the acquisition of the neighbouring land to install a third 25MVA 66/11kV
transformer at Campbelltown Substation. In addition, a new masonry control building, new
11kV switchboard and 66kV bus work will be required. The establishment of three new 11kV
feeder exits into the Glynde area will require extensive 11kV feeder works, using
approximately 9km of feeder exit cable to enable the physical dissection several of the
constrained 11kV feeders as described in 2.5.b.
This option will solve the N and N-1 constraints at Campbelltown and Woodforde as well as
future 11kV feeder N and N-1 constraints as described in 2.5.b until the forecast summer of
2022/23. At this point the both Campbelltown and Woodforde substations will again be
forecast to be constrained for N conditions, with Campbelltown exceeding its new upgraded
normal rating of 88.5MVA and Woodforde exceeding its normal rating of 50.4MVA. The
solution to solve this constraint will be the construction of a 66kV line from the existing
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Campbelltown-Magill 66kV line to a new Glynde Substation site in 2022. The Substation would
be comprised of one 66/11kV 32MVA transformer, 66kV bus work, a new masonry control
building housing an 11kV switchboard and site civil works that include earthing and
substation screening.
After this solution, no further constraints are present in the 10 year evaluation period of this
report.
The option to upgrade the Campbelltown Substation in 2014 is not the most practical solution
to solve the N and N-1 constraints at Campbelltown and Woodforde Substations. The
likelihood of acquiring neighbouring land is very low and costs to purchase such land would
be expected to be high. The increased capacity at Campbelltown as a result of this upgrade
will only defer the need for a new substation in the Glynde area until 2022. Also the extensive
lengths of 11kV feeder exits required to successfully divide up the load on existing constrained
11kV feeders is a more complex solution than if the substation was built in the Glynde area in
the first place. These long 11kV feeder exits will require more planning and approvals and will
become redundant once the new Glynde Substation is constructed in 2022.
3. OPTION EVALUATION
3.1
Evaluation Criteria
3.1.a
ESCOSA Guideline 12
Under the Guideline 12 regulations, ETSA Utilities must rank the options according to:
“1.
Options (and where necessary groups of options) are evaluated and ranked on the
basis of the „total net annualised costs of system support incurred by ETSA Utilities‟,
plus the cost or benefits of changes to transmission and distribution losses. “Total net
annualised costs of system support incurred by ETSA Utilities” includes all capital,
fixed, variable and operating costs of securing the specified level of system support;
2.
System support is measured in terms of kVA of constrained peak capacity, $/kVA of
constrained peak capacity and the period of constraint;”
In addition, ETSA Utilities must also assess:
“5.
The relative intrinsic risks, including the likely impact on system reliability and quality
of supply, of specific options and technologies have been assessed in accordance
with normal commercial practice.”
ETSA Utilities has traditionally interpreted this last clause as inferring that it should include within
its assessment, the monetary value to customers of changes in the Value of Customer
Reliability.
Note: that this is a different but equivalent measure to that contained in the AER test below.
3.1.b
AER Regulatory Test
The current AER Regulatory Test (version 3) specifies two types of test with the choice of test
being determined by the reason for the network augmentation. Where the augmentation is
required to meet a forecast breach of service standards linked to the technical requirements
contained in Schedule 5.1 of the NER or applicable regulatory instruments, then the
“Reliability Limb” of the test should be used. This limb is therefore to be used where there is no
option but to either perform remedial works or shed load in order for operation of the network
to remain within code.
In all other cases the second type of test, the “Market Benefits limb”, is to be used.
EVALUATION REPORT RFP 002/11
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Note that a new regulatory test, the RIT-D, is under development and is likely to replace
version 3 in the future.
Reliability Limb
Under the Reliability Limb of the Test, ETSA Utilities is only allowed to consider:

Costs incurred in constructing or providing the option;

Operating and maintenance costs over the operating life of the option; and

The cost of complying with laws, regulations and applicable administrative requirements
in relation to the option.
The preferred option under this limb of the Test, is the option that minimises the direct costs of
meeting the code requirements when compared with alternative options in a majority of
reasonable scenarios. It is therefore a strict least cost test and all considerations of broader
benefits such as changes in system losses or customer reliability are explicitly excluded.
Market Benefits Limb
The Market Benefits Limb of the Test is broader than the Reliability Limb as in addition to the
direct costs of the options considered within the Reliability Limb, this limb of the Test includes:

Changes in system losses;

Changes in reliability of the network as assessed by the impact that these changes
have on consumers of electricity;

Impacts on the generation of electricity such as displacing existing generators with
higher / lower cost producers including changes in the fuel mix;

Anything else that may impact the change in economic surplus accruing to
producers and consumers of electricity in the market – essentially a measure of the
efficiency of the market seen as a whole.
The preferred option under this Test is the option that maximises the net economic benefit to
all those who produce, transport and consume electricity in the National Electricity Market
when compared with the likely alternative options in a majority of reasonable scenarios.
The net economic benefit is to be expressed as the Net Present Value of the costs minus the
benefits over the period of the study.
Certain elements are explicitly excluded from consideration under either limb by the
regulations:
3.2

Non financial impacts such as visual amenity or greenhouse gas emissions, except
where these are mandated by regulation – such as planning approvals or taxation.

Economic transfers between market participants. This includes the impact on profits /
losses made by ETSA Utilities or any other specific party in the electricity market.
Evaluation of proposals
All proposals to resolve the constraints identified within RFP 002/11 have been evaluated
against the Reliability Limb of the AER Regulatory Test.
3.3
Evaluation parameters
Evaluation period
The evaluation period should be long enough to allow the fair comparison of all options
under consideration taking into account the size and complexity of the proposed
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expenditure. ETSA Utilities uses periods of 10, 15, 20 or 25 years with generally only the largest
and most complex of projects requiring the longer periods.
For this evaluation a period of 10 years has been used.
Discount Rate
The Regulatory Test requires the NPV analysis to use a discount rate appropriate for the
analysis of a private enterprise investment in the electricity sector. From a review into the
Regulatory Test for network augmentation, the AER concluded that:

“the regulatory WACC might reasonably be considered the lower boundary of the
discount rate but not the mean value around which sensitivity testing is conducted”;
and

“the discount rate adopted for the purpose of the regulatory test evaluation should
be a commercial discount rate in order to ensure network and non-network
investments are compared on a competitively neutral basis”.
ETSA Utilities has determined that the appropriate real pre-tax weighted average cost of
capital for non regulated investment in utility infrastructure is between 10 and 15 percent. In
assessing whether a rate at the lower or higher end of that range should be used,
consideration should be given to elements such as the period of the investment,
counterparty risk, size, complementary business opportunities and other risk strategies and
adjustments.
In ETSA Utilities’ view it would be reasonable to use a range between the regulatory WACC,
currently 8.95%, and 12% as real pre-tax weighted average cost of capital.
Project costs
ETSA Utilities has prepared cost estimates for the work it would have to undertake for each
augmentation option based on a set of standard costs denominated in 2012 dollars. These
costs are based on an analysis of previous actual project costs and do not include any
allowances for risks or contingencies. Where the work is non standard, ETSA Utilities has used
its best efforts to estimate a mid range cost again excluding any allowances for risks and
contingencies.
To reflect the degree of uncertainty in using high level costs for future projects, sensitivity
analysis of ± 20% for ETSA Utilities’ construction costs has been used uniformly across all options
to capture systematic variations.
Third party costs that are subject to a fixed price contract have not been varied as variation
in these costs are borne by the third party and not by the electricity market as a whole.
Operating and Maintenance Costs
Operating and maintenance costs have been derived as a fixed proportion of capital cost
for all ETSA Utilities owned substation and line assets. Given the low applied rate of 1.5% per
annum, even large variations of ± 50% in this rate will have no material impact on the result.
Therefore this element has not been subjected to sensitivity analysis.
In the case of other ETSA Utilities owned assets, specific O&M costs are applied as
appropriate to the asset class. For example, environmental license fees for embedded
generators are specifically included.
For third party assets, O&M costs as paid by ETSA Utilities and specified by the third party are
applied. Examples of these costs would be an annual facilities or availability fee for a
Network Support Agreement.
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Depreciation
In all cases, the capital cost was depreciated in a straight line over the regulatory life of each
asset. Each project was split into three cost components and each component was
depreciated according to the following asset lives:

Lines = 55 years

Substations = 45 years

Generators = 20 years
The residual value of each asset at the end of the evaluation period was added back into
the NPV calculation to represent the remaining life of the asset. This enables the evaluation
to fairly compare options with differing asset lives.
Electricity forecast
The ETSA Utilities medium growth rate forecast has been used as the base case. This forecast
is explained in Section 2.2 - Load Forecast and Properties.
The high load forecast is a variation of the medium growth rate forecast. It uses the medium
growth rate and increases this rate by 20%.
The low load forecast is a variation of the medium growth rate forecast. It uses the medium
growth rate and decreases this rate by 20%.
Cost of losses
Both the ESCOSA Guideline L12 and AER Market Benefits test require the cost of electrical
losses to be considered when evaluating options. Network analysis has been utilised to
estimate the electrical losses associated with each augmentation option under consideration
relative to the existing supply arrangement.
Losses have been valued at the estimated average long run cost of electricity production in
South Australia rather than the average pool price as transfers to market participants (ie
profit) are explicitly excluded under the regulations. A sensitivity range of ± 40% ($20, $35 and
$50 per MWh) has been applied to capture the considerable uncertainty in this figure.
Value of Customer Reliability (VCR)
Changes in customer reliability come from changes in network architecture, for instance
adding a second transformer to a substation so that supply is maintained if one of the
transformers fails (an increase in reliability), or transferring load from an overloaded
networked substation to another substation supplied by a single sub-transmission line (a
decrease in reliability). These changes are evaluated in a probabilistic manner using
standard measures of equipment reliability and result in an outage rate per annum for a
group of customers. When this is multiplied by the average customer load and an average
repair time, this results in a value for expected lost customer load in MWh per annum.
The value that customers themselves put on a reliable power supply depends on a variety of
factors. This may include; the type of customer, duration of the outage, time of day, season
or frequency of outages. As any outage invariably impacts a wide range of customers, this
value is also statistical in nature.
Also outages themselves are unpredictable, with the likelihood of occurrence highly
dependent on weather conditions. Consequently, there is not a strong correlation between
estimated and actual measures of lost load.
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In light of these points, ETSA Utilities uses the average VCR value for South Australia as
published by AEMO as its base value. This value is $50,000 per MWh of estimated change in
customer load due to changes in network reliability, irrespective of the type of economic
activity being undertaken in the geographical area impacted by the constraints. Sensitivity
analysis is undertaken using a wide margin of error of ± 50% of the base value to capture the
inherent uncertainties in this measure.
3.4
Market scenarios evaluated
In order to determine the augmentation option that satisfies the Regulatory Test, a total of 11
credible market scenarios have been developed including the Base Case and ten variations
thereof. The scenarios considered are:
Base Case scenario
The Base Case market scenario was developed to represent the most likely state of the world.
It uses the following evaluation parameters:

Medium Load Forecast;

Discount Rate = 10%;

VCR = $50,000 /MWh;

The cost of losses = $35/MWh;

Network capital and operating costs as estimated.
Case 1: Low Load Growth
Case 1 is identical to the Base Case but uses the low load forecast.
Case 2: High Load Growth
Case 2 is identical to the Base Case but uses the High load growth scenario.
Case 3: Low VCR
Evaluation is based purely on a strict least cost scenario therefore, N/A.
Case 4: High VCR
Evaluation is based purely on a strict least cost scenario therefore, N/A
Case 5: Low Value of Losses
Evaluation is based purely on a strict least cost scenario therefore, N/A
Case 6: High value of Losses
Evaluation is based purely on a strict least cost scenario therefore, N/A
Case 7: Low Capital costs
Case 7 is identical to the Base Case but uses a capital cost of 80% of the estimated value.
Case 8: High Capital costs
Case 8 is identical to the Base Case but uses a capital cost of 120% of the estimated value.
Case 9: Low cost of capital
Case 9 is identical to the Base Case but uses a WACC of 8.95% which is the current regulated
rate of return allowed to ETSA Utilities by the AER.
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Case 10: High cost of capital
Case 9 is identical to the Base Case but uses a WACC of 12%.
3.5
Evaluation Results
Table 4: NPV Evaluation Results and Rankings
Case
Option 1
Option2
Difference
NPV ($k)
Ranking
NPV ($k)
Ranking
($k)
Base Case
$11,939
1
$14,750
2
$2,811
1. Low Load Growth
$11,718
1
$13,858
2
$2,139
2. High Load Growth
$12,179
1
$15,719
2
$3,541
7. Low Capital Costs
$9,551
1
$11,800
2
$2,249
8. High Capital Costs
$14,327
1
$17,701
2
$3,374
9. Low Cost of Capital
$11,523
1
$14,255
2
$2,732
10. High Cost of Capital
$12,795
1
$15,762
2
$2,967
As can be seen by the table above, for all scenarios Option 1 is the favoured option with
greatest difference occurring in Case 2 with high load growth. Least difference can be found
in Case 1 with low load growth.
4. CONCLUSIONS
Based on the evaluation, the preferred option is Option 1 – The construction of a new
substation in the Glynde area.
The substation will be planned to be constructed in 2014.
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