Draft Project Assessment Report Notting Hill Supply Area Project … · 2017-10-05 · Notting Hill Supply Area Project № UE-DZA-N-17-001 Page 2 of 68 Table of Contents 1 Approval

RIT-D Report This report presents the network limitations at Notting Hill zone substation and the distribution feeder network within the Notting Hill Supply Area, identification and evaluation of credible network and non-network options to alleviate those limitations.

Draft Project Assessment Report Notting Hill Supply Area

Project № UE-DZA-N-17-001

RIT-D Draft Project Assessment Report

Notting Hill Supply Area Project № UE-DZA-N-17-001 Page 1 of 68

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Notting Hill Supply Area Project № UE-DZA-N-17-001

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Table of Contents

1 Approval and Document Control 4

2 Executive summary 5

3 Introduction 3

4 Identified Need 4

4.1 Network overview 4

4.2 Description of the identified need 6

4.2.1 Station Risk 6

4.2.1.1 Insufficient capacity at Notting Hill zone substation 6

4.2.1.2 Incremental energy at risk in neighbouring zone substations 7

4.2.2 Incremental energy at risk in neighbouring distribution network 9

4.2.3 Distribution Feeder Risk 10

4.2.4 Closing comments on the need for investment 11

4.3 Quantification of the identified need 12

5 Key assumptions in relation to the Identified Need 14

5.1 Method for quantifying the identified need 14

5.1.1 Expected unserved energy due to Station Risk 14

5.1.2 Expected Benefits due to new Distribution Feeders 15

5.2 Forecast maximum demand 15

5.3 Characteristic of load profile 16

5.4 Load transfer capacity and supply restoration times 19

5.5 Plant failure rates 19

5.6 Discount rates 20

5.7 Plant ratings 20

5.8 Value of customer reliability 21

6 Summary of submissions 22

6.1 EDL’s Demand Management Proposal 22

6.1.1 Solution highlights 23

7 Credible options included in this RIT-D 27

8 Market modelling methodology 30

8.1 Classes of market benefits considered 30

8.1.1 Changes in involuntary load shedding 31

8.1.2 Changes in load transfer capability 32

8.1.3 Changes in network losses 32

8.2 Classes of market benefits not expected to be material 33



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8.2.1 Changes in voluntary load shedding 33

8.2.2 Changes in costs to other parties 34

8.2.3 Difference in timing of distribution investment 34

8.2.4 Option value 34

8.3 Quantification of costs for each credible option 35

8.4 Scenarios and sensitivities 35

8.4.1 Capital costs 36

8.4.2 Value of customer reliability 36

8.4.3 Discount rates 37

8.4.4 Average Victorian spot price 37

8.4.5 Summary of sensitivity testing 37

9 Results of analysis 38

9.1 Gross market benefits 38

9.2 Net market benefits 39

9.3 Sensitivity assessment on reasonable Scenarios 40

9.4 Economic timing 42

9.5 Reliability assessment on EDL Generation 42

10 Proposed preferred option 43

11 Submission 44

11.1 Request for submission 44

11.2 Next steps 44

12 Checklist of compliance with NER clauses 45

13 Abbreviations and Glossary 46

Appendix A 49



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1 Approval and Document Control

Project № UE-DZA-N-17-001 – Notting Hill Supply Area

VERSION DATE AUTHOR

1 17 October 2016 UE Network Planning

Amendment overview

New document



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2 Executive summary

Summary

Notting Hill (NO) zone substation was commissioned in the late 1960s, as a two-transformer zone substation to provide capacity to the growing Notting Hill, Springvale and Clayton supply areas. This region has developed over time into a flourishing commercial and educational precinct with ongoing development and further growth opportunities. It is a strategically important part of Melbourne with it earmarked as the National Employment Cluster of Monash in the Victorian Government’s Plan - Melbourne Metropolitan Planning Strategy.1 The Notting Hill, Springvale and Clayton area covers approximately 20 square kilometres of UE’s electricity distribution area north of Whiteside Road, Rosebank Avenue and Osborne Avenue, east of Westall Road and Blackburn Road, west of Clayton Road and south of the Monash Freeway.

NO 66/22kV zone substation has connectivity to neighbouring zone substations at Springvale West (SVW), Glen Waverley (GW) and Clarinda (CDA), via the 22kV distribution feeder network. With committed large customer load increases, the spare capacity at NO and the neighbouring networks during high demand periods is diminishing. This limits the load transfer capability away from NO onto neighbouring networks. With NO operating well above its firm rating during periods of high demand, some customers could potentially be without electricity supply in the event of a transformer failure at NO.

UE has identified the following two potential credible network options that are technically comparable to address the identified need:

1. Install a third 20/33MVA 66/22kV transformer, one 66 kV bus tie circuit breaker and a third 22 kV bus at Notting Hill zone substation with two new 22 kV distribution feeders for service by December 2017. The estimated capital cost of this option is $ 5.07 million2 (±10%) in 2016-17 $AUD.

2. Install a fifth 20/33MVA 66/22kV transformer, one 66 kV bus tie circuit breaker and a new 66kV bus at Springvale/Springvale West zone substation with new 22 kV distribution feeders, to offload NO feeders for service by December 2017. The estimated capital cost of this option is $ 8.0 million (±30%) in 2016-17 $AUD.

Alternatively, demand reduction or embedded generation up to 4.5 MW in summer 2017-18 after considering 11.3 MW of available transfer capacity, then a minimum of 2.5 MW per annum (averaged over 5 years) thereafter to manage the diminishing load transfer capability and load growth to maintain reliable supply to the Notting Hill area.

In April 2016, United Energy (UE) commenced the Regulatory Investment Test for Distribution (RIT-D) consultation process to seek alternative options in addressing the need to the proposed network option.

In response to this consultation, UE received one detailed proposal from Energy Developments Pty Ltd (EDL) proposing an alternative way to address the need in the Notting Hill supply area. UE also

1 http://www.planmelbourne.vic.gov.au/

2 This is a reduction on the price published in the Non-Network Options Report (NNOR) as a result of prices received from a competitive

tender process held in parallel with the NNOR consultation for the network option.

http://www.planmelbourne.vic.gov.au/



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received a response from Clean Technology Partners indicating that they will not be submitting a non-network solution proposal for this particular limitation.

After evaluating the submissions, UE identified three credible options that are technically comparable in addressing the identified need – one Network option as published in the Non-Network options Report (NNOR) and two credible hybrid options comprising of a Non-network solution and the deferred Network option. The three credible options identified are:

1. Install a third 20/33MVA 66/22kV transformer, one 66 kV bus tie circuit breaker and a third 22 kV bus at Notting Hill zone substation with two new 22 kV distribution feeders commissioned by December 2017.

2. Contract with EDL to utilise their non-network support services and implement their solution for a one year period starting December 2017, followed by Option 1 ready for service by December 2018 (i.e. 2018-19 summer).

3. Contract with EDL to utilise their non-network support services and implement their solution for a four year period starting December 2017 along with a third 22 kV bus at Notting Hill zone substation with two new 22 kV distribution feeders. This would then be followed by the installation of third 20/33MVA 66/22kV transformer and one 66 kV bus tie circuit breaker (remaining components of Network Option 1) ready for service by December 2021 (i.e. 2021-22 summer).

Based on the economic assessment (detailed later in this report), Option 1 satisfies the requirements of the RIT-D and is therefore identified as the preferred option.

Purpose

This Draft Project Assessment Report has been prepared by UE in accordance with the requirements of clause 5.17.4(j) of the National Electricity Rules (NER).

This report represents the second stage of the consultation process in relation to the application of the RIT-D on potential credible options to address the Zone Substation and Distribution network limitations in the Notting Hill supply area.

The need for investment and the possible options for addressing limitations have been foreshadowed in the NNOR published on 08 April 2016.

This report:

Provides background information on the network limitations in the Notting Hill supply area.

Identifies the need which UE is seeking to address, together with the assumption used in identifying that need.

Summarises and provides commentary on the submission(s) received on the NNOR.

Describes the credible options that are considered in this RIT-D assessment.

Describes the methods used in quantifying each class of market benefit.

Quantifies costs (with a breakdown of operating and capital expenditure) and classes of material market benefits for each of the credible options.



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Provides reasons why differences in changes in voluntary load curtailment, costs to other parties, option value and timing of other distribution investment do not apply to a credible option.

Provides the results of NPV analysis of each credible option and accompanying explanatory statements regarding the results.

Identifies the proposed preferred option.

The need for investment

UE’s NO zone substation supplies approximately 3,800 customer premises in the Notting Hill supply area. By number, 80% of these are residential and 20% are commercial/industrial. By energy volume, 80% is consumed by commercial/industrial customers and 20% by residential.

The area is generally well developed but has prominent signs of ongoing building construction and development. The supply area includes the designated Major Activity Centres of Springvale and Clayton, as well as the Monash University / Health Research Precinct which is designated as a Specialised Activity Centre. The large customers supplied in the area include Monash University, Australian Synchrotron (Supplied from SV) and two major customer data centres. Both the data centres have recently applied to increase their demand, including the requirement for a dedicated supply feeder as well as a backup feeder. Monash Medical Centre is also proceeding with an expansion to establish a new Children’s Hospital due to open in early 2017 and the development of a new retail centre is also planned. Major railway works are also proposed in the area.

NO is a summer-critical zone substation, that is, it experiences high demands during the summer months. The figure below depicts the historical actual maximum demands, summer maximum demand forecasts, together with the zone substation’s summer (N) and (N-1) ratings representing all transformers in service and one transformer out of service respectively.



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Figure 1 – Forecast maximum demand against station ratings for NO zone substation

The figure above shows that the actual maximum demand at NO zone substation has been above its summer (N-1) rating for every summer since 2010-11. Given a forecast high demand growth over the next five years (predominantly driven by committed large customer connections), there could be a significant amount of energy-at-risk should a forced transformer outage occur during periods of high demand.

The forecast impact of the ‘identified need’ discussed above is presented in Figure 2.

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Figure 2 – Forecast impact of the identified need

Presently, there are no 66 kV sub-transmission line circuit breakers at NO zone substation. Therefore, a forced outage of one of the sub-transmission lines into NO zone substation would also lead to an outage of one of the NO zone substation transformers. However, the probability of such an outage is low and the restoration time is expected to be shorter compared to a transformer outage.

Results of consultation on options

On 08 April 2016, UE published the NNOR providing details on the network limitations within the Notting Hill supply area. This report sought information from Registered Participants and Interested Parties regarding alternative potential credible options or variants to the potential credible options presented in that report.

In response to the report, UE received enquiries from several non-network service providers. UE took this opportunity to further populate its Demand Side Engagement Register3 and engaged in joint planning with those proponents to assess the viability of alternative credible options within the Notting Hill supply area. UE received two submissions by 08 July 2016, being the closing date for submissions to the NNOR. One submission indicated that there is a credible alternative non-network option possible within the Notting Hill supply area.

3 UE has established a Demand Side Engagement Register for industry participants, customers, interest groups and non-network service providers who wish to be regularly informed of our planning activities.



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Credible options for addressing the identified need

UE presented five network options in the NNOR. Three of these options were regarded as not being credible for reasons set out in that paper. Furthermore, one of the credible options detailed in the NNOR has been assessed as a higher cost option and not attracting enough market benefits. Therefore only one credible network option presented in the NNOR has been assessed as part of this RIT-D.

Following the NNOR response submissions, one credible non-network solution was identified within the Notting Hill supply area as having a potential to defer but not avoid the proposed network investment. Therefore, one ‘network only’ and two variations of the ‘non-network plus deferred network’ credible options have been considered for further detailed study and application of the RIT-D.

Table 1 – Credible options considered in the RIT-D

Option Description

1

Network Augmentation

Third transformer at Notting Hill zone substation and two new distribution feeders

This option includes:

Installing a new 20/33 MVA 66/22 kV transformer at Notting Hill zone substation.

Installing a new 66kV bus tie circuit breaker

Installing a Neutral Earthing Resistor (NER)

Extending the 22 kV busbar at Notting Hill zone substation.

Developing two new 22 kV distribution feeders to supply the loads in and around Notting Hill area.

This option will:

Eliminate the risk of supply interruption following the loss of one of the two Notting Hill zone substation transformers.

Eliminate the risk of supply interruptions from distribution feeders exceeding their rating under system normal conditions.

Reduce the risk of supply interruptions for loss of a distribution feeder.

The estimated capital cost of this option is $ 5.07 million (± 10%), in 2016-17 $AUD. Annual operating and maintenance costs are anticipated to be around 0.5% of the capital cost.

The estimated commissioning date is December 2017.

The estimated total annual cost of the Preferred Network Option is $ 322,513.

2

EDL + Network Aug

EDL non-network solution followed by deferred Option 1

This option is a hybrid of a non-network solution and network investment project.

Stage 1 - EDL non-network solution

The EDL demand management proposal defers network investment (as described in Option 1 above) by 1-year to address the identified need.


Contracting EDL to provide demand management at NO, SV and SVW supply areas until commissioning of network project (as described in Option 1 above).

Utilising embedded generation and the load transfer capability through the Monash University 22kV bus and providing demand side management by integrating University Building Automation System (BAS).



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Pre-contingent and Post Contingent load relief for NO Zone Substation.

Establishment cost components for a 1-year proposal is 0.33 million in 2016-17 $AUD

Capacity cost ($ 10 per kW - weighted average)

Dispatch cost ($ 1,000 per dispatch day)

The estimated capital cost of Stage 1 of this option is $ 0.37 million in 2016-17 $AUD.

The estimated commissioning date for Stage 1 is December 2017

Stage 2 - Install third transformer at Notting Hill zone substation and two new distribution feeders

Second stage of this option is to implement network project by December 2018 which includes:






The estimated capital cost of Stage 2 is $ 5.07 million (± 10%) in 2016-17 $AUD. Annual operating and maintenance costs are anticipated to be around 0.5% of the capital cost.

The implementation date for this stage is before summer 2018-19 to maximise the net economic benefit.

Total cost

The estimated total cost (Stage 1 + Stage 2) of this option is $ 5.9 million in 2016-17 $AUD.

3

EDL & 2FDR+ Network Aug

Split Option 1 into two parts Option 1a and 1b. Implement EDL non-network solution in conjunction with Option 1a followed by deferred Option 1b


Stage 1 - EDL non-network solution and two new distribution feeders (Option 1a)

The EDL demand management proposal defers network investment (as described in Option 1 above) by 4-years to address the identified need.


Contracting EDL to provide demand management at NO, SV and SVW supply areas until commissioning of complete network project (as described in Option 1 above).



Establishment cost components for a 4-year proposal is $ 0.43 million in 2016-17 $AUD

Capacity cost ($ 10 per kW - weighted average of 4-years)



Developing two new 22 kV distribution feeders to supply the existing loads in and around Notting Hill area.


The estimated commissioning date for Stage 1 is December 2017.

Stage 2 - Install third transformer at Notting Hill zone substation (Option 1b)



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Second stage of this option is to implement Part 1b of the network project by December 2021, which includes:






Total cost


The purpose of the RIT-D is to identify the preferred option that maximises the present value of net market benefit to all those who produce, consume and transport electricity in the National Electricity Market (NEM).4 In order to quantify the net market benefits of each credible option, the expected unserved energy under the base case (where no action is taken by UE) is compared against the expected unserved energy with each of the credible options in place.

Scenarios considered

The NER stipulates that the RIT-D must be based on a cost-benefit analysis that considers a number of reasonable scenarios of future supply and demand.5 In this particular RIT-D, UE notes that different assumptions regarding future supply or transmission development are not expected to impact on the assessment of alternative options.

In order to define reasonable scenarios, UE examined the sensitivity of net market benefits to a change in key input variables or value within the base (expected) estimates that drive market benefits. Table 2 below lists the variables and respective ranges adopted for the purpose of defining reasonable scenarios.

4 AER: “Regulatory Investment Test for Distribution Application Guidelines”, Section 1.1. Available http://www.aer.gov.au/node/19146 5 NER: clause 5.17.4(c) paragraph 1

http://www.aer.gov.au/node/19146



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Table 2 – Variables and ranges adopted for the purpose of defining scenarios

Low Case Base Case High Case

Maximum Demand

Base estimate averaged growth rate per annum at NO minus 0.5%

UE’s 2016 maximum demand forecast for NO zone substation

Base estimate averaged growth rate per annum at NO plus 0.5%

Capital cost6 Base estimate minus 10% $ 5.07m Base estimate plus 10%

Value of customer reliability (VCR)

Base estimate minus 15% $ 43,596 per MWh Base estimate plus 15%

Discount rate

Base estimate minus 1% 6.37% Base estimate plus 1%

As the combination of possible scenarios, with 12 variables, is a very high number, and given that only reasonable scenarios should be considered in the RIT-D assessment, UE has defined different maximum demand levels as three credible scenarios to test the robustness of this RIT-D assessment.

‘Base demand growth scenario’ (or the most likely scenario),

‘Low demand growth scenario’, and

‘High demand growth scenario’.

The above mentioned sensitivities were studied under these three scenarios. 0.5% variation from base estimate averaged growth rate per annum at NO zone substation reflects a 1MW variation in demand in year 2018 and 3 MW variation in demand in year 2025. Given the new major loads to be supplied out by NO zone substation are phased out across multiple years, UE considers 1-3 MW variation in load in any given year serves as a reasonable scenario for further sensitivity studies.

Table 3 shows results of scenario and sensitivity analysis. The shaded cell in each row indicates the option that maximise the net market benefit for that particular scenario relative to ‘Do nothing’.

6 UE has elected to use a range of ±10% on the capital cost sensitivity as we have received at least two competitive tender responses

with pricing well within this range. As UE has used the higher of these only for the purposes of this RIT-D assessment, it is highly unlikely that Network Project cost will increase by 10%.



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Table 3 – Reasonable scenarios under consideration – Base, Low and High Demand Growth


Notting Hill Supply Area Project № UE-DZA-N-17-001 Page 1 of 68

NPV Results

Table 3 sets out a comparison of the present value of net market benefits of each option under all reasonable scenarios, over a twenty-year period 2017-2036.

The results set out in the table above show:

Option 1 maximises net market benefit under the base case set of assumptions;

Option 1 maximises net market benefit under all scenarios involving the variation of assumptions within plausible limits;

Option 2 and 3 have lower net economic benefits under all studied scenarios by a reasonable margin, even when using optimistic performance assumptions.

This RIT-D assessment demonstrates that Option 1 maximises the present value of net market benefits under all reasonable scenarios considered. The preferred option for investment is therefore Option 1: Installing third transformer at Notting Hill zone substation and two new Distribution Feeders by December 2017. This option satisfies the requirements of the RIT-D.

The economic timing of the proposed preferred option is when the annualised cost of power supply interruption exceeds the annualised cost of the proposed preferred option. The timing of the proposed preferred Option 1 is before summer 2017-18 under all reasonable scenario (i.e. under the most likely scenario).

In the absence of forecast reliability performance specified in the EDL proposal, UE has assumed 100% in this RIT-D assessment. This is unlikely to be achieved based on current performance. UE has undertaken an assessments of the EDL Land Fill Gas Generation reliability and availability during the most recent summer periods in its current connection to the UE network at Springvale South zone substation. The generation unavailability was determined for forced-outages triggered by network-related feeder faults. The feeder fault rate was factored into SV17 (where the EDL generation will be connected during post contingent support scenario). Based on recent historical performance, the market benefits captured by Option 2 and Option 3 reduce, therefore increasing the gap from the preferred option even further.

Recommendation

The recommended option is proceed with Option 1 as detailed in Table 1.

Next steps

UE invites written submission on this report from registered participants and interested parties.

All enquiries should be directed to the United Energy Manager Network Planning at [email protected] quoting reference number UE-DZA-N-17-001.

This consultation closes on Friday 25th November 2016.

All submissions must be emailed to [email protected] by the Closing Date on 25th November 2016 by 5pm (Australian Eastern Standard Time) quoting reference number UE-DZA-N-17-001.

mailto:[email protected]




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All submissions will be published on UE’s website.7

Following UE’s consideration of the submissions, the preferred option including the expected commissioning date, and a summary of, and commentary on, the submissions received to this report will be included as part of the Final Project Assessment Report (FPAR). This report represents the third and final stage of the consultation process in relation to the application of the RIT-D.

UE intends to publish the Final Project Assessment Report around January 2017.

7 If you do not want your submission to be publically available, please clearly stipulate this at the time of lodgment.



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3 Introduction

This Draft Project Assessment Report has been prepared by United Energy (UE) in accordance with the requirements of clause 5.17.4(j) of the National Electricity Rules (NER).

This report represents the second stage of the consultation process in relation to the application of the Regulatory Investment Test for Distribution (RIT-D) on potential credible options to address the network limitations in the Notting Hill supply area.

The need for investment and the possible options for addressing limitations have been foreshadowed in the Non Network Options Report (NNOR) published on 08 April 2016.

This report:

Provides background information on the zone substation and distribution network limitations in the Notting Hill supply area.

Identifies the need which UE is seeking to address, together with the assumption used in identifying that need.

Summarises and provides commentary on the submission(s) received on the NNOR.

Describes the credible options that are considered in this RIT-D assessment.

Describes the methods used in quantifying each class of market benefit.

Quantifies costs (with a breakdown of operating and capital expenditure) and classes of material market benefits for each of the credible options.

Provides reasons why differences in changes in voluntary load curtailment, costs to other parties, option value and timing of other distribution investment do not apply to a credible option.

Provides the results of NPV analysis of each credible option and accompanying explanatory statements regarding the results.

Identifies the proposed preferred option as the Network Augmentation.



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4 Identified Need

4.1 Network overview

Notting Hill (NO) zone substation is equipped with two 20/30 MVA 66/22 kV transformers and provides electricity supply to approximately 3,800 customers. The areas supplied include Notting Hill and parts of Clayton. Neighbouring Springvale (SV) and Springvale West (SVW) zone substations supply electricity to approximately 11,700 customers in Clayton and Springvale. It is a strategically important part of Melbourne with it earmarked as the National Employment Cluster of Monash in the Victorian Government’s Plan - Melbourne Metropolitan Planning Strategy. The Notting Hill supply area covers approximately 20 square kilometres of UE’s distribution area north of Whiteside Road, Rosebank Avenue and Osborne Avenue, east of Westall Road and Blackburn Road, west of Clayton Road and south of the Monash Freeway. A total of about 15,500 customers supplied within the area forms about 2.4% of UE’s total customer base. When counted by number, 80% of these are domestic customers and 20% are commercial/industrial, however most of the energy supplied (80%) is consumed by commercial/industrial customers.

Figure 3 – Geographical areas supplied by Notting Hill (and Springvale/Springvale West) zone substations

NO zone substation was established in the late 1960s.

Figure 4 below presents the Single Line Diagram of NO zone substation depicting the present configuration.



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Figure 4 – Existing configuration of NO (schematic view)

NO zone substation is supplied via two 66 kV sub-transmission lines - one from Springvale Terminal Station (SVTS) and the other from Glen Waverley (GW) zone substation. Presently, there are no 66 kV sub-transmission line circuit breakers at NO zone substation. Therefore, a forced outage of one of the sub-transmission line into NO zone substation would also lead to an outage of one of the NO zone substation transformers. However, the probability of such outage is low and the restoration time is expected to be shorter compared to a transformer outage.



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4.2 Description of the identified need

The identified need has been split into two major categories:

1. Station Risk - It includes energy at risk (under N-1 condition) due to:

Insufficient capacity at NO zone substation;

Incremental energy at risk at neighbouring zone substations following load transfers from NO;

Incremental energy at risk at neighbouring distribution feeder network following load transfers from NO; and

Insufficient transfer capability away from NO, leading to excessive load shedding in the NO network.

2. Distribution Feeder Risk – It includes energy at risk due to:

Thermal limitation at Notting Hill and its neighbouring HV distribution network under system normal and switching operation during high demand periods.

4.2.1 Station Risk

4.2.1.1 Insufficient capacity at Notting Hill zone substation

NO is a summer critical zone substation with two 20/30 MVA 66/22kV transformers. The figure below depicts the historical actual maximum demands, 10% and 50% PoE maximum demand forecasts together with the zone substation’s operational ratings.



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Figure 5 – Forecast maximum demand against station ratings for NO zone substation

As illustrated above:

The historic actual maximum demand at NO zone substation has been above its N-1 rating of 36.5 MVA for every summer since 2010-11, but below its N cyclic rating of 74.0 MVA.

Anticipating high demand growth over the next five years primarily driven by committed large customer connections.

The 10% and 50% PoE maximum demand8 at NO zone substation is expected to exceed the zone substation’s (N-1) cyclic rating in summer 2016-17, for about 44 hours9.

In other words, in the absence of any mitigation action, inadequate capacity at the zone substation would be expected to lead to supply interruption from summer 2016-17, under system N-1 conditions (i.e. with any one transformer at NO out of service).

4.2.1.2 Incremental energy at risk in neighbouring zone substations

Springvale (SV), Springvale West (SVW) and Glen Waverley (GW) are neighbouring zone substations to NO with load transfer capabilities at the 22kV distribution network level. Clarinda (CDA) is also a neighbouring zone substation to NO, operating above its N-1 rating during maximum

8 This forecast is also referred to as having a 10% probability of exceedance. It represents a forecast that is expected, on average, to

be exceeded once in ten years.

9 After considering load transfers.

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demand periods. Due to thermal limitations on the CDA distribution feeder with tie to NO, no load can be transferred away from NO onto CDA from summer 2016-17. Therefore no unserved energy at CDA has been accounted for in the energy-at-risk calculations.

SV/SVW is a summer critical combined zone substation with four transformers and a Summer N cyclic rating of 160 MVA. The figure below depicts the historical actual maximum demands, 10% and 50% PoE maximum demand forecasts together with the station’s operational ratings.

Figure 6 – Forecast maximum demand against station ratings for SV / SVW zone substation

As illustrated above the historic actual maximum demand at SV / SVW zone substation has been below its N cyclic rating of 160 MVA. However, the 10% PoE maximum demand forecast is expected to exceed zone substation’s (N-1) cyclic rating of 121.1 MVA from summer 2017-18 and from 2019-20 under the 50% PoE maximum demand forecast.

GW is also a summer critical zone substation with three 66/22 kV transformers with a combined cyclic rating of 103.4 MVA during summer season. The figure below depicts the historical actual maximum demands, 10% and 50% PoE maximum demand forecasts together with the station’s operational ratings.

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Figure 7 – Forecast maximum demand against station ratings for GW zone substation

As illustrated above the historic actual maximum demand at GW zone substation has been below its N-1 cyclic rating of 68.9 MVA. However, the 10% PoE maximum demand forecast is expected to exceed the zone substation’s N-1 cyclic rating from summer 2016-17.

The amount of unserved energy in the SV / SVW and GW supply areas increase after load is transferred away from NO (following the loss of one of the NO transformers). Therefore, the incremental risk due to load being transferred away from NO to neighbouring network has been included in the risk assessment calculation.

4.2.2 Incremental energy at risk in neighbouring distribution network

Following a major outage of any one of the two transformers at NO zone substation, only part of customers’ supply can be restored via the distribution network from neighbouring zone substations at SVW and GW from 2016-17. As a result, some customers could potentially be without electricity supply until the capacity in the neighbouring network becomes available as the demand subsides. With forecast demand growth, the available load transfer capability reduces further, leaving greater numbers of customers exposed to the risk of supply interruption for longer periods of time as shown in table below.

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Summer (N) Cyclic Rating Summer (N-1) Cyclic Rating



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Table 4 – Forecast load at risk at 10% PoE demand conditions

Year Demand Forecast10

(MVA)

Transfer Capability11

(MVA)

Load at Risk12after

transfers

(MVA)

Hours at Risk

(Hours)

2016-17 52.8 11.3 4.9 44

2017-18 56.2 10.9 8.8 54

2018-19 61.0 11.0 13.6 96

2019-20 62.7 10.4 15.7 130

2020-21 64.0 9.9 17.6 159

2021-22 64.9 9.4 19.0 184

2022-23 65.9 8.9 20.5 228

2023-24 67.0 8.5 22.0 260

2024-25 68.8 8.1 24.2 325

As shown above the load transfer capability away from NO is less than that required to fully restore NO load following the loss of one zone substation transformer (i.e. N-1) during periods of high demand for 44 hours (at 10% PoE demand conditions) in 2016-17.

4.2.3 Distribution Feeder Risk

Utilisation of critical distribution feeders within the NO supply area and neighbouring SV / SVW and GW supply areas are presented in Figure 8.

Utilisation describes the ratio of the feeder maximum demand to the summer cyclic rating (N) under normal operating conditions.

10 The maximum demand forecasts are based on the expected (base) economic growth scenario. 11 Load transfer capability away from NO.

12 Load-at-risk is the amount of load that would not be supplied due to a major outage of a NO zone substation transformer. These represent ‘Demand minus Load Transfer Capability minus (N-1) cyclic rating of NO’, reflecting the impact of load transfer capability.



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Figure 8 – Feeder expected utilisation in summer 2017-18 (10% PoE maximum demand)

As illustrated above:

The loading on NO 2 is forecast to be 97% utilised in summer 2017-18.

The loading on SVW 41 and CDA 11 is forecast to be reaching 90% utilised in summer 2017-18.

Emerging capacity limitations in distribution feeders are managed operationally by transferring load away to neighbouring feeders at maximum demand periods. For instance, some load can be transferred away from NO 4 and NO 5 to GW 10. Such actions are adopted usually as a short-term mitigation action but this action merely reduces the load transfer capability further. A forced outage of a highly utilised NO feeder during high demand periods, may lead to supply interruption for some customers until either spare capacity becomes available in neighbouring feeders or the faulty asset is repaired.

4.2.4 Closing comments on the need for investment

The following limitations are to be addressed by this RIT-D:

From summer 2016-17, inadequate load transfer capability between NO and the neighbouring network is expected to lead to supply interruption, following the loss of a transformer at NO zone substation during very high demand periods;

There will be an increase in energy-at-risk in the neighbouring zone substations and distribution network, following load transfers from NO; and

As shown in Figure 8, maximum loading of a number of distribution feeders in the NO, CDA, SVW and GW supply areas are forecast to exceed their thermal capability within the next

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

CDA 11 GW 10 NO 2 SVW 41

Uti

lisati

on

(%

)

Distribution feeder utilisation expected in summer 2017-18



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five years under system normal operation. Losing highly utilised NO feeders during a period of high demand will lead to supply interruption for some customers.

The forecast impact of the total ‘identified need’ discussed above is presented in Figure 9.

Figure 9 – Forecast impact of the identified need

In light of the rapidly growing demand at NO and the increase in load-at-risk, UE has examined a number of options to alleviate the identified need. These options are outlined in Section 6.

4.3 Quantification of the identified need

The forecast impact of the identified need discussed in Section 4.2 is presented in Table 5.

The table shows:

Load-at-risk, which is the MVA load shedding required to avoid network limitation under the 10% PoE maximum demand forecast after taking load transfer capability into consideration.

Hours-at-risk, which is the number of hours the demand at NO zone substation is expected to exceed its N-1 thermal rating after taking load transfer capability into consideration.

Customer value of lost load is the cost of the expected unserved energy, obtained by multiplying the expected unserved energy13 (kWh) by the Value of Customer Reliability (VCR

13 The expected unserved energy is the portion of the energy-at-risk after taking into account the probability of an outage of critical plants,

combined with 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand, as described in Section 5.3



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$/kWh) using a detailed assessment of risk which includes consideration of the load transfer capability. The Station Risk and Distribution Feeder Risk, when combined together reflects the total value of energy-at-risk for the identified need described in Section 4.2.

Table 5 – Forecast network limitation

Year Load at Risk

(MVA)

Hours at Risk

(Hours)

Expected value of unserved energy

($,000)

Station Risk Distribution Feeder Risk

Total Risk

2016-17 4.9 44 169 142 311

2017-1814 8.8 54 263 146 409

2018-19 13.6 96 471 149 620

2019-20 15.7 130 606 153 759

2020-21 17.6 159 755 153 908

2021-22 19.0 184 893 153 1,046

2022-23 20.5 228 1,052 153 1,205

2023-24 22.0 260 1,240 153 1,393

2024-25 24.2 325 1,548 153 1,702

14 Year of preferred network augmentation



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5 Key assumptions in relation to the Identified Need

5.1 Method for quantifying the identified need

The identified need that is to be addressed by this RIT-D, presented in Section 4.3, is comprised of the following components:

Station Risk

o Expected unserved energy due to insufficient N-1 capacity at NO zone substation after considering load transfer to neighbouring zone substations; and

o Expected incremental unserved energy at neighbouring zone substations and distribution feeder network, following load transfers away from NO.

Distribution Feeder Benefit

o Expected benefit due to the elimination of any limitations in the distribution feeders’ capacity within the NO and neighbouring supply areas during high demand periods under system normal and feeder N-1 conditions.

The section below summarises the method adopted to quantify the abovementioned risks and benefits.

5.1.1 Expected unserved energy due to Station Risk

The expected unserved energy due to insufficient capacity at NO and neighbouring zone substations and neighbouring distribution feeder was calculated as follows:

Identify the expected unserved energy at NO zone substation under system normal conditions (i.e. N condition) and following the loss of any one of the two NO zone substation transformers (i.e. N-1 condition) considering load transfer capability.

Identify the incremental expected unserved energy at neighbouring zone substations (SV/SVW and GW) due to transferring load away from NO, following the loss of one of the NO zone substation transformer. This was achieved by comparing the expected unserved energy at neighbouring zone substations before load transfers (by considering the transformer failure rate) with the expected unserved energy at neighbouring zone substations after load transfers (by considering the transformer failure rate).

Identify the incremental expected unserved energy on the neighbouring distribution feeders due (SV/SVW and GW) due to transferring load away from NO, following the loss of one of the NO zone substation transformer. This was achieved by comparing the expected unserved energy on neighbouring distribution feeders before load transfers (by considering the transformer failure rate) with the expected unserved energy on neighbouring zone substations after load transfers (by considering the transformer failure rate).

Identify the expected unserved energy on the NO distribution feeder network due to additional load-shedding following the loss of any one of the two NO zone substation transformers (i.e. N-1 condition) due to the discrete size of the load shedding blocks.



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The combined expected unserved energy from (1) to (4) represents the expected unserved energy that is to be addressed due to insufficient capacity at NO zone substation under the N-1 condition.

5.1.2 Expected Benefits due to new Distribution Feeders

The expected benefits due to two new distribution feeders at NO were calculated as follows:

1. Identify the expected unserved energy in the distribution feeder network at NO and neighbouring feeders under status-quo for each credible option.

2. Identify the expected unserved energy in the distribution feeder network at NO and neighbouring feeders following the implementation of two new distribution feeders at NO (i.e. residual risks).

3. Identify the market benefits realised by comparing (1) with (2).

The market benefits realised under this credible option represents the expected unserved energy that is addressed by installing two new distribution feeders at NO.

5.2 Forecast maximum demand

Zone substation

Forecasts of the 10% PoE and 50% PoE summer maximum demand at NO zone substation is presented in Figure 10 below. This forecast are based on the base (expected) economic growth scenario.

Figure 10 – 10% PoE summer maximum demand forecasts at NO, SV/SVW and GW zone substations

0

20

40

60

80

100

120

140

160

2015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25

Maxim

um

dem

an

d (

MV

A)

Forecast 10 % PoE summer maximum demand

NO SV/SVW GW



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Figure 11 – 50% PoE summer maximum demand forecasts at NO, SV/SVW and GW zone substations

Distribution feeders

Average annual growth in the summer maximum demand of the distribution feeders in the NO, SV/SVW and CDA supply areas are presented in Table 6.

Table 6 – Annual growth rate of distribution feeders

Distribution feeders Annual growth rate at 10% PoE Annual growth rate at 50% PoE

NO 2 1.5% 1.4%

CDA 11 2.4% 2.3%

SVW 41 3.0% 2.8%

GW 3, GW 5 and GW 10 2.7% 2.5%

Average UE growth rate (for comparison) 1.4% 1.2%

The amount of expected unserved energy was estimated by taking 30% weighting of the unserved energy at 10% PoE demand forecast and 70% weighting of the unserved energy at 50% PoE demand forecast.

5.3 Characteristic of load profile

NO zone substation provides electricity supply to approximately 3,800 customers in the areas of Notting Hill and Clayton North. The substation load is characterised primarily of commercial and industrial loads with some residential loads. The very high demand events occur during the summer season i.e. in the month of December, January and February as illustrated in Figure 12.

0

20

40

60

80

100

120

140

2015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 2024-25

Maxim

um

dem

an

d (

MV

A)

Forecast 50 % PoE summer maximum demand

NO SV/SVW GW



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Figure 12 – Load profile at NO zone substation (2013-14)

The load profile on the day of summer maximum demand is illustrated in Figure 13. Typically, the electricity demand at NO remains flat during the day, with a large increase in demand occurring early in the day and a large reduction in demand happening late in the evening hours. In other words high demand at NO zone substation is expected during usual business operating hours i.e. from 10:00am till 5:00pm.

Figure 13 – Load profile on day of summer maximum demand at NO zone substation



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Figure 14 shows the normalised load duration curves at NO zone substation for the last five summers.

Figure 14 – Historical load duration curves at NO zone substation

The figure above shows that the load characteristics can vary from year to year due to the sensitivity of the maximum demand to temperature, however the shape is consistent. It also shows that the actual demand in the previous years remained above 60% of the maximum demand for 20-30% of the year.

To account for variability in load characteristics, UE has prepared load traces based on historical load traces that are characterised by 10% PoE and 50% PoE demand profiles (or close to) at NO zone substation.

Based on this approach, the expected unserved energy at NO zone substation was estimated using the expected 2009-1015 and 2013-1416 historical traces.

The above-mentioned approach was adopted to estimate the expected incremental unserved energy at SV/SVW and GW zone substations and distribution networks. The SV/SVW and GW load traces were therefore based on the following base years:

15 The 2009-10 historic load trace characterised (or close to) a 50% PoE maximum demand profile at NO. 16 The 2013-14 historic load trace characterised (or close to) a 10% PoE maximum demand profile at NO.



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Table 7 – Base years used to develop load traces

Zone substation Base year

10% PoE load trace

Base year

50% PoE load trace

NO 2009-10 2013-14

SV/SVW 2009-10 2013-14

GW 2009-10 2013-14

5.4 Load transfer capacity and supply restoration times

The load transfer capability between NO and neighbouring network is estimated to be 11.3 MVA for summer 2016-17.

Future load transfer capability between NO and neighbouring network were estimated by considering the available spare capacity on neighbouring distribution feeders (by comparing the forecast maximum demand and the feeder rating), and the likely transferability based on network configuration.

For the purpose of this RIT-D, the customers’ supply is restored within 60 minutes following the loss of a major plant (i.e. zone substation transformer / distribution feeders) when the load transfer capability is sufficient to restore supply. This figure represents UE’s current reliability performance target for CAIDI.17

5.5 Plant failure rates

The base (average) reliability data adopted in this assessment are presented in tables below. The data is derived from the Australian CIGRE Transformer Reliability Survey carried out in 1995 and UE’s observed network performance since 1994-95.

Table 8 – Summary of transformer outage rates

Major plant item: zone substation transformer Interpretation

Transformer failure rate (major fault)

0.5% per annum A major failure is expected to occur once per 200 transformer-years.

Duration of outage (major fault) 2190 hours

A total of 3 months is required to repair / replace the transformer, during which time the transformer is not available for service.

Transformer failure rate (minor fault) 1.0% per annum

A minor failure is expected to occur once per 100 transformer-years.

Duration of outage (minor fault) 48 hours

A total of 48 hours is required to repair the transformer, during which time the transformer is not available for service.

17 CAIDI represents the average restoration time for each outage.



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Table 9 – Summary of distribution feeder outage rates

Major plant item: distribution feeder Interpretation

Distribution feeder failure rate per km (major fault)

7 faults per 100 km per annum The average sustained failure rate of UE’s distribution feeder is 7.0 faults per 100 km per year.

Duration of outage (major fault)

4 hours

A total of 4 hours is required to repair / replace the feeder (or sections of feeder), during which time the feeder (or sections of the feeder) is not available.

Table 10 – Summary of other plant outage rates

Equipment Outage rate Outage duration

22 kV bus (major fault)

2% per annum 3 months

22 kV circuit breaker (minor fault)

0.3% per annum 24 hours

5.6 Discount rates

To compare cash flows of options with different time profiles, it is necessary to use a discount rate to express future costs and benefits in present value terms. The choice of discount rate will impact on the estimated present value of net market benefits, and may affect the ranking of alternative options.

A real, pre-tax discount rate of 6.37 per-cent is adopted in this assessment.

5.7 Plant ratings

The zone substation ratings of NO, SV/SVW and GW are limited by the thermal capability of the zone substation transformers. The transformer summer cyclic ratings are calculated based on ambient temperature of 40°C and corresponding load profiles at respective zone substations. The transformer winter cyclic ratings are based on 10°C ambient temperature.

The distribution feeder ratings are calculated based on ambient temperature of 40°C. In addition to temperature, overhead line ratings are based on solar radiation of 1000 W/m2 and a wind speed of 3 m/s at an angle to the conductor of 15° (i.e. an effective transverse wind speed of 0.78 m/s), while the underground cable ratings are based on soil thermal resistivity of 0.9 °Cm/W or 1.2 °Cm/W at specific sites. For underground cables, a typical load profile has been considered to accommodate the variability in demand over time.

Summer and winter ratings of corresponding zone substation transformers are presented in Table 11 below.



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Table 11 – Summary of zone substation cyclic ratings (MVA)

Zone substation

Summer cyclic rating at 40°C Winter cyclic rating at 10°C

N N-1 N N-1

NO 73.0 36.5 85.9 43.0

SV/SVW 163.1 121.1 189.8 141.8

GW 105.0 68.9 121.2 80.5

5.8 Value of customer reliability

Location specific Value of Customer Reliability (VCR) is used to calculated expected unserved energy presented in Section 4.3. The location VCR was derived from the sector VCR estimates provided by AEMO in late 2014, escalated by a factor of 1.013 using the 2015 CPI index, and weighted in accordance with the composition of the load, by sector, at the relevant zone substations.

Table 12 – Summary of location specific VCR

Zone substation VCR

($ per MWh)

NO, SV/ SVW and GW 43,596



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6 Summary of submissions

On 08 April 2016, UE published the Non Network Options Report (NNOR) providing details on the network limitations within the Notting supply area. This report sought information from Registered Participants and Interested Parties regarding alternative potential credible options or variants to the potential credible network options presented by UE.

In response to the NNOR, UE received enquiries from several non-network service providers. UE engaged in joint planning with all of these proponents to assess the viability of credible alternative solutions within the Notting Hill supply area.

UE received one formal proposal by 08 July 2016, being the closing date for submissions to the NNOR, from Energy Developments Ltd submitting a non-network solution which comprised of embedded generation and demand reduction support.

EDL’s solution proposed deferring the timing of the proposed network augmentation and presented a positive net economic benefit by starting their program in 2017-18 for a duration which maximises net market benefits with the flexibility to extend and expand the demand reduction support to further defer network investment.

6.1 EDL’s Demand Management Proposal

EDL submitted a solution that is capable of providing the required 4.5MW non-network support to UE in summer 2017-18. The proposal submitted by EDL offers a demand reduction network support service of 20,100 to 21,300 kW available within the Notting Hill Supply area during high demand periods from 2017-18 until 2024-25. Table 13 shows maximum demand management support available in any given year as proposed by EDL. UE’s assessment of EDL’s demand reduction is also stated in Table 13 below with the difference between the proposed and assessed limit reflecting UE’s demand reduction needed to defer network augmentation and also what can be practically achievable with limitations within the distribution feeder network.



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Table 13 – EDL’s proposed Non-Network Support

Year Max. available Load

Reduction proposed by EDL (kW)

Max. available Load Reduction assessed by

UE (kW) 18

2017-18 21,300 16,598

2018-19 21,300 16,498

2019-20 20,900 16,048

2020-21 20,100 15,148

2021-22 20,100 14,314

2022-23 20,100 13,464

2023-24 20,100 12,614

2024-25 20,100 11,764

6.1.1 Solution highlights

The solution proposes an EDL-Monash University Clayton Campus (MUCC) Strategic Partnership19 to address the RIT-D requirements through the development of a “Smart Energy Hub” that will deliver a credible and financially viable non-network solution for Notting Hill supply area in the event of a transformer outage at NO zone substation.

EDL proposed that the optimal solution is likely to be achieved by UE undertaking its non-network solution in conjunction with the construction of the two new distribution feeders from NO as in the network preferred option.

EDL’s non-network solution has following three key components:

i. Embedded Generation

EDL proposed to establish a 4.5km underground link between MUCC and the existing 12 MVA EDL Clayton Landfill Gas Generation (LGG) site before the start of December 2017. This will include the rearrangement of the MUCC network supply arrangement. It will result in a pre-contingent load reduction of 4.6MVA at NO zone substation in 2017-18, as well as achieving a further post contingent load transfer capacity.

MUCC also proposed to install 2.5MW of solar panels to reduce demand at MUCC providing further capacity into the network supply area. In addition MUCC already has an existing 1.25MVA natural gas co-generator on site which will be operated across the peak event periods to ensure a reduction in MUCC maximum demand.

ii. Demand Side Management

18 UE assessment indicates reduced numbers due to increase in MUCC load and thermal limitations on NO 02 feeder. This assessment assumes 100% availability of 8.75MW embedded generation at MUCC for the full non-network support period (i.e. from 15 Nov to 15 Mar) as per EDL’s proposal.

19 The EDL proposal is reliant on a technical solution that utilises the private high voltage electrical assets of MUCC. EDL has provided a Letter of Support from MUCC to UE to satisfy the technical viability of their proposal.



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MUCC proposed to implement a Demand Side Management (DSM) system in 2017, enabling MUCC to dynamically manage their demand in response to variable input parameters by linking to MUCC’s Building Automation Systems (BAS). This will enable MUCC to reduce their peak demand by 1MVA from summer 2017-18 onwards.

iii. Load Transfer Capacity

MUCC will utilise its unique supply arrangement to allow a significant increase in the load transfer capacity at NO zone substation, thus significantly reducing the energy-at-risk in the event of a transformer outage at NO zone substation from summer 2017-18 onwards.

Under system normal operation MUCC load will be supplied through SVW51 feeder only. Following an outage of NO zone substation transformer (post contingent scenario), MUCC will offer the spare capacity on its two dedicated underground feeders from Springvale to offload the two overhead shared feeders from the NO zone substation through MUCC’s internal network within 1 hour of contingency.

To allow this arrangement the electrical bus at Monash University will be upgraded to enable load to be transferred from the Notting Hill area to the Springvale area. One of the supply feeders will also be upgraded to improve the transfer capacity available by a further 3MVA.

Table 14 –Evaluation of EDL’s non-network support proposal

Year

Proposed Generation support at

MUCC20

(kW)

Diversified peak load

forecast for MUCC

(kW)

Net peak Demand

forecast for MUCC

(kW)

Two Springvale Distribution

feeder combined rating

(kW)

Achievable Demand

reduction at NO

Zone Sub21

(kW)

Load at Risk after UE load transfers

(kW)

2017-18 8,700 20,300 11,600 28,200 16,598 8,799

2018-19 9,400 21,100 11,700 28,200 16,498 13,558

2019-20 9,750 21,900 12,150 28,200 16,048 15,728

2020-21 9,750 22,800 13,050 28,200 15,148 17,593

2021-22 9,750 23,633 13,883 28,200 14,314 19,028

2022-23 9,750 24,483 14,733 28,200 13,464 20,483

2023-24 9,750 25,333 15,583 28,200 12,614 22,005

2024-25 9,750 26,183 16,433 28,200 11,764 24,162

In summer 2021-22, after implementing EDL’s non-network support, the residual energy-at-risk in the NO supply area is greater than the annualised cost of Network Augmentation and this triggers a need for Network Augmentation in this year. Therefore EDL’s non-network solution cannot be implemented from summer 2020-21 onwards.

20 This assessment assumes 100% availability of embedded generation at MUCC for the full non-network support period (.i.e. from 15

Nov to 15 Mar) as stated in EDL’s proposal.

21 UE assessment indicates reduced numbers are achievable due to increase in MUCC load and thermal limitations at NO 02 feeder.



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Various combinations of duration of EDL’s non-network solution were studied to identify the optimum size and duration of support over the next 8 year period.

For Option 2, the net economic benefits is maximised when a 1-year non-network support is implemented from 2017-18 to defer the Network Augmentation timing by one year to 2018-19.

For Option 3, the net economic benefits is maximised when a 4-year non-network support is implemented from 2017-18 along with the two new distribution feeders which defers the NO 3rd Transformer Augmentation timing by four years to 2021-22.

The Figure 15 shows that among various non-network support combinations, a 4-year EDL non-network support and upfront construction of two new distribution feeders at NO (Option 3) maximises the net economic benefit.

Figure 15 – NPV Comparison of optimum duration of Credible Options starting from 2017-18

EDL proposal pricing is reflected in the table below.



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Table 15 - Proposal ‘Planned’ Solution capacity and pricing summary

Non-network support duration

Establishment Fee

($k)

Annual Fees

($k)

Post Contingent

Dispatch Fees

1-year

(2018) 325 37.5

$1000 per dispatch day

4-year

(2018 till 2021) 425 225

$1000 per dispatch day

EDL confirmed that the identified costs associated with fault level mitigation, generator connection, private underground cable cost, cost of upgrading MUCC bus, and costs of meeting UE’s minimum safety, operational and technical standards will be borne by them and are not included in this RIT-D assessment.



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7 Credible options included in this RIT-D

UE presented two credible network options in the NNOR published on 08 April 2016. UE has considered the lower cost network option in this DPAR as the expected market benefits are similar for both options. UE received one submission for a non-network solution. This credible non-network option has been considered for further detailed assessment and application of the RIT-D. A summary of the credible ‘Network Investment’ option (Option 1) and the two credible ‘Non-Network plus deferred Network Investment’ options (Option 2 and Option 3) are presented in the table below to address the identified need. Table 16 – Credible options under consideration

Option Description

1

Network Augmentation

Third transformer at Notting Hill zone substation and two new distribution feeders







This option will:





The estimated commissioning date is December 2017.

The estimated total annual cost of the Preferred Network Option is $ 322,513.

2

EDL + Network Aug

EDL non-network solution followed by deferred Option 1


Stage 1 - EDL non-network solution

The EDL demand management proposal defers network investment (as described in Option 1 above) by 1-year to address the identified need.


Contracting EDL to provide demand management at NO, SV and SVW supply areas until commissioning of network project (as described in Option 1 above).




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Establishment cost components for a 1-year proposal is $ 0.33 million in 2016-17 $AUD

Capacity cost ($ 10 per kW - weighted average)



The estimated commissioning date for Stage 1 is December 2017

Stage 2 - Install third transformer at Notting Hill zone substation and two new distribution feeders

Second stage of this option is to implement network project by December 2018 which includes:








Total cost


3

EDL & 2FDR+ Network Aug

Split Option 1 into two parts Option 1a and 1b. Implement EDL non-network solution in conjunction with Option 1a followed by deferred Option 1b


Stage 1 - EDL non-network solution and two new distribution feeders (Option 1a)

The EDL demand management proposal defers network investment (as described in Option 1 above) by 4-years to address the identified need.


Contracting EDL to provide demand management at NO, SV and SVW supply areas until commissioning of complete network project (as described in Option 1 above).



Establishment cost components for a 4-year proposal is 0.43 million in 2016-17 AUD

Capacity cost ($ 10 per kW - weighted average of 4-years)



Developing two new 22 kV distribution feeders to supply the existing loads in and around Notting Hill area.


The estimated commissioning date for Stage 1 is December 2017.

Stage 2 - Install third transformer at Notting Hill zone substation (Option 1b)



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Second stage of this option is to implement Part 1b of the network project by December 2021, which includes:






Total cost




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8 Market modelling methodology

The RIT-D requires market benefits to be calculated by comparing the ‘state of the world’ in the base case (where no action is undertaken by UE) with the ‘state of the world’ with each of the credible options in place. The ‘state of the world’ means a reasonable and mutually consistent description of all of the relevant supply and demand characteristics and conditions that may affect the calculation of the market benefits over the period of assessment.22 The uncertainty associated with the future state of the world is addressed by considering a number of reasonable scenarios (Refer to Section 9.3).

In order to calculate the outcomes in the relevant ‘state of the world’, UE has developed the risk assessment model which incorporates the key variables that drive market benefits, as discussed in Section 5.

The RIT-D assessment has been undertaken over a twenty-year period (i.e. 2017 - 2036). The modelling discussed in Section 8.1.1 to Section 8.1.2 below has been undertaken across the same first ten-year study horizon. The market benefits calculated in the final year of the modelling period (i.e. 2025-26) has been applied as the assumed annual market benefit that would continue to arise for a further eleven years. This approach of adopting an extended analysis period, based on continuation of an assumed end value is one which has been adopted in similar assessments.23 This approach is reasonable given the long-lived nature of the investments considered in this RIT-D assessment.

8.1 Classes of market benefits considered

The purpose of the RIT-D is to identify the credible option that maximise the present value of net market benefits to all those who produce, consume and transport electricity in the National Electricity Market (NEM).24

In order to measure the increase in net market benefit, UE has analysed the classes of market benefits required to be considered by the RIT-D.25 The market benefits considered not to be material have been identified in Section 8.2 of this DPAR.

The classes of market benefits that are considered material and have been quantified in this RIT-D assessment are:

Changes in involuntary load shedding;

Changes in load transfer capability; and

Changes in network losses.

22 AER: “AER – Final RIT-D Application Guidelines – August 2013”, Section 11.1.

Available http://www.aer.gov.au/node/19146 23 AEMO: Regional Victorian Thermal Upgrade RIT-T – Project Assessment Draft Report, March 2013. Available: http://www.aemo.com.au/Electricity/Planning/Regulatory-Investment-Tests-for-Transmission/Regional-Victorian-Thermal-

Capacity-Upgrade Powerlink and TransGrid: Development of the Queensland – NSW interconnector, March 2014. Available: http://www.transgrid.com.au/network/consultations/Pages/CurrentConsultations.aspx 24 AER: “AER – Final RIT-D Application Guidelines – August 2013”, Section 1.1. Available http://www.aer.gov.au/node/19146 25 NER: clause 5.17.1(c) paragraph 4.


http://www.aemo.com.au/Electricity/Planning/Regulatory-Investment-Tests-for-Transmission/Regional-Victorian-Thermal-Capacity-Upgrade

http://www.aemo.com.au/Electricity/Planning/Regulatory-Investment-Tests-for-Transmission/Regional-Victorian-Thermal-Capacity-Upgrade

http://www.transgrid.com.au/network/consultations/Pages/CurrentConsultations.aspx




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8.1.1 Changes in involuntary load shedding

Increasing the supply capability within the Notting Hill supply area increases the supply available to meet the maximum demand within the area. This will provide a greater reliability for this region by reducing potential supply interruptions and the consequent risk of involuntary load shedding.

UE has used the risk assessment model to calculate the impact of changes in involuntary load shedding by comparing the expected unserved energy under the base case (where no action is undertaken by UE) with each of the credible options in place. Specifically, the model estimates the customer value of lost load by estimating the magnitude of unserved energy in each hour over the modelling period (expressed in kWh), after considering the impact of load transfers, and applying the locational VCR (expressed in $/kWh).

An increase in the customer value of lost load (compared to the base case) makes a negative contribution to the market benefit of a credible option while a reduction in the customer value of lost load (compared to the base case) makes a positive contribution to the market benefit of a credible option.

The customer value of lost load was calculated by:

1. Identifying the Station Risk and multiplying by the locational VCR.

2. Identifying the Distribution Feeder Risk within the Notting Hill supply area and multiplying by the locational VCR.

The expected unserved energy due to insufficient capacity at NO zone substation has been quantified as follows:

1. Identify the expected unserved energy at NO zone substation under system normal conditions (i.e. N condition) and following the loss of one NO zone substation transformer (i.e. N-1 condition) by considering load transfer capability.

2. Identify the incremental expected unserved energy at GW zone substation due to transferring load away from NO to GW, following the loss of the NO zone substation transformer. This was achieved by comparing the expected unserved energy at GW zone substation before load transfer with the expected unserved energy at GW zone substation after load transfer.

3. Identify the incremental expected unserved energy on the GW distribution feeder network due to transferring load away from NO to GW, following the loss of the NO zone substation transformer. This was achieved by comparing the expected unserved energy on the GW distribution feeder network before load transfer with the expected unserved energy on the GW distribution feeder network after load transfer.

4. Identify the incremental expected unserved energy at SV/SVW zone substation due to transferring load away from NO to SV/SVW, following the loss of the NO zone substation transformer. This was achieved by comparing the expected unserved energy at SV/SVW zone substation before load transfer with the expected unserved energy at SV/SVW zone substation after load transfer.

5. Identify the incremental expected unserved energy on the SV/SVW distribution feeder network due to transferring load away from NO to SV/SVW, following the loss of the NO zone substation transformer. This was achieved by comparing the expected unserved energy on



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the SV/SVW distribution feeder network before load transfer with the expected unserved energy on the SV/SVW distribution feeder network after load transfer.

The combined expected unserved energy from (1) to (5) represents the Station Risk at NO zone substation.

The expected unserved energy due to distribution feeder limitations was calculated as follows:

1. Identify the expected unserved energy in the distribution feeder network under status-quo for each credible option.

2. Identify the expected unserved energy in the distribution feeder network following the implementation of each credible option (i.e. residual risks).

The customer value of energy at risk was calculated by identifying the total expected unserved energy due to limitations within Notting Hill supply area and multiplying it by the average locational VCR $43,596 per MWh.

The identified customer value of energy at risk was treated as a market benefit to justify all credible options discussed in Table 16. Market benefits were calculated depending upon the amount of reduction in involuntary load shedding achieved by implementing each credible option. In each credible option, full market benefits are achieved from the commissioning year of the network augmentation until 2036.

8.1.2 Changes in load transfer capability

Following a major outage of the transformer at NO zone substation, customers’ supply can be restored (in part) via the distribution network from neighbouring zone substations at GW and SV/SVW. Where there is adequate load transfer capability, the numbers of customers exposed to the risk of supply interruption can be significantly reduced. Although this reduces the expected unserved energy at NO (compared to the level of expected unserved energy in the absence of any load transfers to neighbouring network), it may increase the level of expected unserved energy at GW and SV/SVW.

The modelling undertaken in Section 8.1.1 considers any changes in load transfer that may be expected to occur with each of the credible options in place.

A reduction in load transfer from NO to neighbouring network (compared to the base case) results in reduced expected unserved energy (net), which makes a positive contribution to market benefit of a credible option.

8.1.3 Changes in network losses

Increasing the supply capability within the Notting Hill supply area can lead to a reduction in network losses compared with the level of network losses which would occur in the base case.

The market benefits associated with the change in network losses have been quantified by a direct calculation of the likely MWh impact on the losses for each year of the modelling horizon. Specifically, losses on the distribution feeders and zone substations have been estimated by



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multiplying the network losses at the time of maximum demand by the loss load factors of 2%26. The average Victorian spot price of $50 per MWh has been used in this RIT-D assessment, in accordance with the methodology prescribed in the RIT-D Applications Guidelines27. This value has been derived from the average monthly Victorian spot prices published on AEMO’s website28.

Table 17: Expected value of reduction in network losses per year after network investment

Network Investment year

MWh Savings Value of expected savings on

Network Losses

2017-18 70.6 $ 3,532

2018-19 81.3 $ 4,066

2019-20 85.6 $ 4,278

2020-21 90.0 $ 4,501

2021-22 95.0 $ 4,748

2022-23 97.6 $ 4,881

2023-24 99.3 $ 4,967

2024-25 104.7 $ 5,235

8.2 Classes of market benefits not expected to be material

UE considers that the following classes of market benefit are not likely to be material for this RIT-D assessment:

Changes in voluntary load shedding;

Changes to NEM generation dispatch;

Changes in costs to other parties;

Difference in timing of network investment; and

Option value

8.2.1 Changes in voluntary load shedding

A credible demand-side reduction leads to an increase in the amount of voluntary load curtailment, in place of involuntary load shedding. Voluntary load curtailment is when customers agree to reduce

26 The load loss factors of distribution feeders were estimated by considering the network topology following the implementation of each credible option. This was achieved by considering backbone length of the reconfigured feeder, geometry of the reconfigured feeder (i.e.

location of the load, backbone conductor – UG vs. Cable etc.) 27 AER: “AER – Final RIT-D Application Guidelines – August 2013”, Example 22. Available http://www.aer.gov.au/node/19146

28 AEMO: Average Victorian spot prices. Available at: http://www.aemo.com.au/Electricity/Data/Price-and-Demand/Average-Price-Tables


http://www.aemo.com.au/Electricity/Data/Price-and-Demand/Average-Price-Tables



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their load to address a network limitation. Customers would usually receive a payment to voluntarily curtail their electricity use under these circumstances.

UE has captured associated changes in voluntary load curtailment as a cost of demand-side option i.e. it is implicitly included in the full contract cost that would be paid by UE to the non-network service providers.

8.2.2 Changes in costs to other parties

The Notting Hill area is supplied by two Notting Hill (NO) 66/22 kV zone substation transformers. This zone substation together with other zone substations in the region including Glen Waverley (GW), Springvale (SV) and Springvale West (SVW) are supplied from the 220/66kV transmission connection point known as Springvale Terminal Station (SVTS).

All credible options considered in this RIT-D assessment address the ‘identified need’ within UE’s distribution network in the Notting Hill region. UE does not propose to transfer load from another transmission connection point to SVTS (or vice versa) under each of the credible option. UE therefore does not consider any transmission investments would be affected by the credible options.

As a result, UE has not estimated any market benefit associated with changes in costs to other parties.

8.2.3 Difference in timing of distribution investment

All credible options considered in this RIT-D assessment address the ‘identified need’ within the Notting Hill supply area. At this stage no further distribution investments are anticipated within this region within the next 10 year planning horizon. Implementation of these options may affect the timing of other distribution investments for unrelated identified needs. However, these credible options are not expected to materially change the timing of future investments being considered by UE.

UE therefore has not estimated any additional distribution investment market benefit.

8.2.4 Option value

UE notes the AER’s view that option value is likely to arise where there is uncertainty regarding future outcomes, the information that is available in the future is likely to change and the credible options considered by the RIT-D proponent are sufficiently flexible to respond to that change.29

UE also notes the AER’s view that appropriate identification of credible option (and reasonable scenarios) captures any option value as a class of market benefit under the RIT-D.

UE considers that the estimation of any option value benefits captured via the scenario analysis and comparison of the credible option under those scenarios would be adequate to meet the NER requirements to consider option value as a class of market benefit. UE therefore does not propose to estimate any additional option value market benefit for this RIT-D assessment.

29 AER: “AER – Final RIT-D Application Guidelines – August 2013”, Section A6. Available http://www.aer.gov.au/node/19146




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8.3 Quantification of costs for each credible option

The capital and operating cost assumptions for each credible option considered in this RIT-D assessment are summarised in Table 18.

Table 18 – Summary of project costs

Option Capital cost Operational cost

Do Nothing Zero Expected value of unserved energy valued at VCR provided in Table 12.

Option 1 $ 5.07 million Expected value of unserved energy valued at VCR provided in Table 12.

Asset operating and maintenance expenditure of 0.5% per annum of the capital cost of the asset.


Cost of voluntary load shedding presented in Table 15.



Cost of voluntary load shedding presented in Table 15.


The capital cost of the network investment option has been sourced from a competitive tender, based on a detailed scope of works for the network option, and is presented in 2016-17 Australian dollars. The cost of non-network investment option has been calculated based on the non-network service provider’s proposal.

8.4 Scenarios and sensitivities

Clause 5.17.1(c) paragraph 1 of the NER requires the RIT-D to be based on a cost-benefit analysis that considers a number of reasonable scenarios of future supply and demand. In this RIT-D assessment, different assumptions regarding future supply and other transmission developments are not expected to have any impact on the assessment of alternative options to address the limitations within the Notting Hill supply area.

In order to consider the impact of key factors that drive market benefits, UE has adopted three reasonable scenarios:

‘Base demand growth’ scenario;

‘Low demand growth’ scenario; and

High demand growth scenario.

The 2016 maximum demand forecasts based on base (expected) economic growth scenario were adopted as the base case estimates of future demand.



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For the purpose of sensitivity testing, the upper and lower bound forecast has been derived by varying the central (base) estimates for future Notting Hill (NO) demand growth rate average by 0.5% per annum. The 0.5% variation from base estimate averaged growth rate per annum at NO zone substation reflects a 1MW variation in demand in year 2018 and 3 MW variation in demand in year 2025. Given the new major loads to be supplied out by NO zone substation are phased out across multiple years, UE considers 1-3 MW variation in load in any given year serves as a reasonable scenario for further sensitivity studies.

Figure 16 – Notting Hill 10% POE maximum demand growth reasonable scenario study

The section below provides details of the sensitivity testing undertaken with respect to key input variables within the reasonable scenario study.

8.4.1 Capital costs

Capital cost have been received by UE in a parallel competitive tendering process for the network option based on detailed scopes of work. To test the robustness of RIT-D and for the purpose of sensitivity testing, a range of ±10% around the Base Cost has been assumed to define the upper and lower bounds of the capital costs of Network Option 1.

8.4.2 Value of customer reliability

As already noted, this analysis adopts the location specific Value of Customer Reliability (VCR) to calculate the expected unserved energy, based on the average Victorian VCR published by AEMO in 2014 which shows a reduction of approximately 40% from the value published in 2013. For the purpose of sensitivity testing, the VCR has been varied within the limits of +15% and -15%.

52

54

56

58

60

62

64

66

68

70

72

2017 2018 2019 2020 2021 2022 2023 2024 2025

MVA

Year

Low Growth Base Case High Growth



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8.4.3 Discount rates

Under the RIT-D, any present value calculations must be carried out using a commercial discount rate appropriate for the analysis of a private enterprise investment in the electricity sector. A real pre-tax discount rate of 6.37% has been applied for the purpose of this analysis. For the purpose of sensitivity testing, a lower bound real discount rate of 5.37% and an upper bound of 7.37% have been applied.

8.4.4 Average Victorian spot price

As already noted, this analysis adopts the average Victorian spot prices for 2015-16 to calculate the expected savings from network losses. As the market benefits associated with savings in Network Losses are negligibly low, this sensitivity has not been applied.

8.4.5 Summary of sensitivity testing

The table below lists the variables and ranges of variables adopted for the purpose of defining scenarios.

Table 19 – Variables and ranges adopted for the purpose of defining scenario and sensitivity study

10 year Averaged demand

growth rate

VCR Investment

cost Discount rate

Low -0.5% -15% -10% -1%

Base

2016 MD forecast

averaged growth rate for

NO is 4.6%

$ 43.6/kWh $ 5.07m 6.37%

High +0.5% +15% +10% +1%



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9 Results of analysis

This section summarises the results of the Net Present Value (NPV) analysis for each of the credible options considered in this RIT-D assessment.

Appendix A sets out the full NPV Market benefits of each of the credible options, under each scenario.

9.1 Gross market benefits

Table 20 below summarises the gross market benefit, in present value (PV) terms, for each of the credible options considered in this RIT-D assessment under the base case reasonable scenario. The gross market benefit is the sum of each of the individual categories of material market benefit (both positive and negative), as quantified on the basis of the approach set out in Section 8.1.

Table 20 – Gross market benefits of each credible option under ‘base case’ reasonable scenario (PV, $m)

Options Non-Network Network Total

Option 1

Network Augmentation - $ 13.90 $ 13.90

Option 2

EDL’s 1-year non-network support

+

Deferred Network Augmentation

$ 0.19 $ 13.52 $ 13.71

Option 3

EDL’s 4-year non-network support and two new NO distribution feeders

+

Deferred Network Augmentation

$ 1.50 $ 12.14 $ 13.64

The results show that, assuming central estimates for key variables, Option 1 delivers the highest gross market benefit followed closely by Option 3 and Option 2.

The gross market benefit of Option 2 is lower compared with Option 1 because Option 2 (non-network support) only addresses partial need until the commissioning of the network investment. This reduces the gross market benefit for this option.

Figure 17 below shows the breakdown of gross market benefits for the option with the highest gross market benefit, Option 1, under the base case reasonable scenario.

By far the largest category of market benefit for this option is the changes in involuntary load shedding (unserved energy).

The flat line of market benefits beyond 2024-25 represents the modelling of residual benefits at the end of the ten-year forecasting horizon, which have been assumed to be the market benefit calculated in the final year of simulation modelling timeframe.



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Figure 17 – Option 2: Gross involuntary load shed and Network Losses market benefits under base case reasonable scenario (PV, $m)

9.2 Net market benefits

The table below summarise the net market benefit in NPV terms for each credible option. The net market benefit is the gross market benefit, under the base case reasonable scenario (as set out in Table 20), minus the total capital, operating and maintenance cost of each option, all in present value terms.

The table also shows the corresponding ranking of each option under the RIT-D.

Table 21 – Net market benefits of each credible option, under base case reasonable scenario (PV, $m)

Options Cost

Market Benefits

Net Economic

Benefit

Ranking under RIT-D

Network Non-

Network Total

Do Nothing 0 0 0 4

Option 1 4.99 - 4.99 13.90 8.91 1

Option 2 4.69 0.35 5.04 13.71 8.67 3

Option 3 4.36 0.47 4.83 13.64 8.81 2

The table above shows that all credible options considered have a positive net market benefit, in the form of large reductions in involuntary load shedding (unserved energy). As a consequence, all three options are ranked higher than the ‘Do Nothing’ option, and could be expected to result in an overall net economic benefit to the market.



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This RIT-D assessment demonstrates that Option 1 - Network Augmentation has the highest net economic benefit under the base case reasonable scenario and is reflected in Figure 18 below.

Figure 18 – NPV Analysis of credible options

9.3 Sensitivity assessment on reasonable Scenarios

As discussed earlier, UE has tested the robustness of the RIT-D assessment to the inclusion of a number of sensitivity tests around the input assumptions adopted in the three reasonable scenarios. Specifically, UE has investigated changes in relation to:

Discount rate;

Cost of network investments; and

Value of customer reliability.

Table 22 presents the net economic benefits in NPV terms for each option relative to ‘Do nothing’, reflecting changes to one variable adopted in the base case reasonable scenario. The shaded cell in each row indicates the option that maximise the net market benefit under that particular set of assumptions.



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Table 22 – Net economic benefit of each credible option under Sensitivity analysis (PV, $,000)

The results set out in table above show that:

Option 1 maximises net market benefit under the base case set of assumptions

Option 1 maximises net market benefit under all scenarios involving the variation of assumptions within plausible limits

Option 2 and 3 have a lower market benefit under all studied cases by a material margin

Under the RIT-D, the preferred option should maximise the present value of the net economic benefit to all those who produce, consume and transport electricity in the National Electricity Market (NEM).30 This RIT-D assessment clearly demonstrates that Option 1 maximises net economic

30 AER: “AER – Final RIT-D Application Guidelines – August 2013”, Section 1.1.

Base Demand Growth Case

Sensitivity on Base Demand

Growth CaseOption 1 Timing Option 2 Timing Option 3 Timing

No Change (Base Case) $8,912 2018 $8,672 2018 $8,806 2018

Discount Rate 5.37% $10,226 2018 $9,942 2018 $10,013 2018

Discount Rate 7.37% $7,757 2018 $7,561 2018 $7,752 2018

Network Investment cost -10% $9,411 2018 $9,141 2018 $9,226 2018

Network Investment cost +10% $8,413 2018 $8,204 2018 $8,386 2018

VCR -15% $6,834 2018 $6,624 2018 $6,766 2018

VCR +15% $10,989 2018 $10,721 2018 $10,846 2018

Low Demand Growth Case

Sensitivity on Low Demand


No Change (Low Case) $5,912 2018 $5,674 2018 $5,819 2018

Discount Rate 5.37% $6,908 2018 $6,625 2018 $6,709 2018

Discount Rate 7.37% $5,037 2018 $4,843 2018 $5,036 2018



VCR -15% $4,284 2018 $4,075 2018 $4,228 2018

VCR +15% $7,539 2018 $7,272 2018 $7,410 2018

High Demand Growth Case

Sensitivity on High Demand


No Change (High Case) $13,215 2018 $12,981 2018 $13,107 2018

Discount Rate 5.37% $14,999 2018 $14,720 2018 $14,784 2018

Discount Rate 7.37% $11,648 2018 $11,457 2018 $11,640 2018



VCR -15% $10,492 2018 $10,287 2018 $10,421 2018

VCR +15% $15,938 2018 $15,675 2018 $15,793 2018

Net Economic Benefit ($,000)





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benefit under all reasonable scenarios considered. Therefore Option 1 is considered the proposed preferred option to address the ‘identified need’.

The results above also demonstrate that applying weightings for each reasonable scenario (and undertaking sensitivity assessment on the weightings adopted) would not alter the outcome of this RIT-D. Although applying different weightings may result in a change in the overall magnitude of net market benefit of each option, Option 1 is still expected to be ranked first.

As a result, UE does not consider any detailed assessment required to identify probability to each reasonable scenario is warranted in this instance.

9.4 Economic timing

Table 22 above shows the expected timing of the proposed preferred option under each reasonable scenario. The table above show that the timing of proposed preferred option (Option 1) is 2017-18 under all reasonable scenario (i.e. under the most likely scenario). Therefore expected implementation timing of the preferred option is no later than December 2017.

9.5 Reliability assessment on EDL Generation

In the absence of forecast reliability performance specified in the EDL proposal, UE has assumed 100% in this RIT-D assessment. This is unlikely to be achieved based on current performance. UE has undertaken an assessments of the EDL Land Fill Gas Generation reliability and availability during the most recent summer periods in its current connection to the UE network at Springvale South zone substation. The generation unavailability was determined for forced-outages triggered by network-related feeder faults. The feeder fault rate was factored into SV17 (where the EDL generation will be connected during post contingent support scenario). Based on recent historical performance, the market benefits captured by Option 2 and Option 3 reduce, therefore increasing the gap from the preferred option even further. The net Economic Benefit for each credible option, after factoring in EDL generation unavailability during summer support period is shown in Table 23 below.

Table 23 - Net market benefits of each credible option, after factoring in EDL generator availability (PV, $m)

Options Cost

Market Benefits

Net Economic

Benefit

Ranking under RIT-D

Network Non-

Network Total

Do Nothing 0 0 0 4

Option 1 4.99 - 4.99 13.90 8.91 1

Option 2 4.69 0.35 4.50 13.67 8.64 3

Option 3 4.36 0.47 4.83 13.51 8.68 2

Available http://www.aer.gov.au/node/19146




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10 Proposed preferred option

The previous section has presented the results of the NPV analysis conducted for this RIT-D assessment. The NER requires the DPAR to include the identification of the preferred option under the RIT-D. This should be the option with the greatest net economic benefit and which is therefore expected to maximise the present value of the net market benefits to all those who produce, consume and transport electricity in the market.

This RIT-D assessment clearly demonstrates that Option 1 maximise the present value of net market benefits under the majority of reasonable scenarios considered. The preferred option for investment is therefore Option 1: Installing third transformer at Notting Hill zone substation and two new Distribution Feeders by December 2017. This option satisfies the requirements of the RIT-D.

The economic timing of the proposed preferred option is when the annualised cost of power supply interruption exceeds the annualised cost of the proposed preferred option. The timing of the proposed preferred Option 1 is before summer 2017-18 under all reasonable scenario (i.e. under the most likely scenario).

Option 1 - Install third transformer at Notting Hill zone substation and two new distribution feeders

The Preferred Option includes:






The Preferred Option will:




Total Cost




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11 Submission

11.1 Request for submission

UE invites written submissions on this report from registered participants and interested parties.

All enquiries should be directed to the United Energy Manager Network Planning at [email protected] quoting reference number UE-DZA-N-17-001.

This consultation closes on Friday 25th November 2016.

All submissions must be emailed to [email protected] by the Closing Date on 25th November 2016 by 5pm (Australian Eastern Standard Time) quoting reference number UE-DZA-N-17-001.

All submissions will be published on UE’s website.31

11.2 Next steps

Following UE’s consideration of the submissions, the preferred option including the expected commissioning date, and a summary of, and commentary on, the submissions received to this report will be included as part of the Final Project Assessment Report (FPAR). This report represents the third and final stage of the consultation process in relation to the application of the RIT-D.

UE intends to publish the Final Project Assessment Report by January 2017.

31 If you do not want your submission to be publically available, please clearly stipulate this at the time of lodgment.





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12 Checklist of compliance with NER clauses

This section sets out a compliance checklist which demonstrates the compliance of this DPAR with the requirements of clause 5.17.4(j) of the NER.

NER Clause

Summary of requirements Relevant section in

DPAR

5.17.4(j)(1) A description of the identified need for investment Section 4

5.17.4(j)(2) The assumptions used in identifying the need (including, in the case of proposed reliability corrective action, why the RIT-D proponent considers reliability corrective action is necessary).

Section 5

5.17.4(j)(3) Summary of, and commentary on, the submissions on the non-network options report

Section 6

5.17.4(j)(4) A description of each credible option Section 7

5.17.4(j)(5) A quantification of each applicable market benefit for each credible option Section 9.1

5.17.4(j)(6) A quantification of each applicable cost for each credible option, including breakdown of operating and capital expenditure

Section 8.3

5.17.4(j)(7) A detailed description of methodologies used in quantifying each class of market benefit

Section 8.1

5.17.4(j)(8) Where relevant, the reasons why UE has determined that a class or classes of market benefits do not apply to a credible option

Section 8.2

5.17.4(j)(9) The results of a net present value analysis for each option and accompanying explanatory statements regarding the results

Section 9

5.17.4(j)(10) The identification of the proposed preferred option Section 10

5.17.4(j)(11) Details of the proposed preferred option Section 10

5.17.4(j)(12) Contact details of suitable staff at UE Section 11



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13 Abbreviations and Glossary

Abbreviations

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

CDA Clarinda zone substation

DAPR Distribution Annual Planning Report

DPAR Draft Project Assessment Report

DSED Demand Side Engagement Document

FPAR Final Project Assessment Report

GW Glen Waverley zone substation

MUCC Monash University Clayton Campus

NEM National Electricity Market

NER National Electricity Rules

NO Notting Hill zone substation

NNOR Non Network Options Report

PoE Probability of Exceedance

PSSE Power System Simulator for Engineers

RIT-D Regulatory Investment Test for Distribution

SV Springvale zone substation

SVW Springvale West zone substation

SVTS Springvale Terminal Station

UE United Energy Distribution Pty Ltd

VCR Value of Customer Reliability



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Glossary

Term Definition

1-in-2 peak day The 1-in-2 peak day demand projection has a 50%

probability of exceedance (PoE). This projected level of

demand is expected, on average, to be exceeded once

in two years.

1-in-10 peak day The 1-in-10 peak day demand projection has a 10%

probability of exceedance (PoE). This projected level of

demand is expected, on average, to be exceeded once

in ten years.

Credible option An option that:

Addresses the identified ‘need’;

Is commercially and technically feasible; and

Can be implemented in sufficient time to meet

the identified ‘need’.

Expected Energy at Risk The expected amount of energy that cannot be supplied

each year because there is insufficient capacity to meet

demand, taking into account equipment unavailability

and load-at-risk.

Identified ‘need’ Any capacity or voltage limitation on the distribution

system that will give rise to Expected Energy at Risk.

Limitation Any limitations on the operation of the distribution

system that will give rise to expected energy at risk.

Network option A means by which an identified ‘need’ can be fully or

partly addressed by expenditure on the distribution

asset.

Non-network option A means by which an identified ‘need’ can be fully or

partially addressed other than by a network option.

Non-network service provider A party who provides a non-network option

Potential credible option An option has the potential to be a credible option based

on an initial assessment of the identified ‘need’.

Preferred option A credible option that maximise the present value of net

economic benefit to all those who produce, consume and

transport electricity in the market. The preferred option

can be a network option, non-network option, or do

nothing (i.e. status quo).



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Term Definition

Probability of exceedance Refers to the probability that a forecast temperature

condition will occur one or more times in any given year

and the maximum demand that is expected to

materialise under these temperature conditions. For

example, a forecast 10% probability of exceedance

maximum demand will, on average, be exceeded only 1

year in every 10.

System-normal condition All system components are in-service and configured in

the optimum network configuration.

System-normal limitation A limitation that arises even when all electrical plant is

available for service.

Value of customer reliability The value customer places on having a reliable supply

of energy, which is equivalent to the cost to the customer

of having that supply interrupted expressed in $/MWh.



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Appendix A

Base (expected) maximum demand forecast

Option 1

Year

Market benefit (in 2016-17 AUD)

Changes in involuntary load shedding

Changes in network losses

Total

2016-17 - - -

2017-18 $408,694 $3,532 $412,226

2018-19 $620,088 $4,066 $624,154

2019-20 $759,172 $4,278 $763,450

2020-21 $908,187 $4,501 $912,688

2021-22 $1,046,215 $4,748 $1,050,963

2022-23 $1,205,398 $4,881 $1,210,279

2023-24 $1,393,005 $4,967 $1,397,972

2024-25 $1,701,583 $5,235 $1,706,818

2025-2035 (even) $1,701,583 $5,235 $1,706,818

Option 2

Year



Changes in network losses

Total

2016-17 - - -

2017-18 $200,673 - $200,673

2018-19 $620,088 $4,066 $624,154

2019-20 $759,172 $4,278 $763,450

2020-21 $908,187 $4,501 $912,688

2021-22 $1,046,215 $4,748 $1,050,963

2022-23 $1,205,398 $4,881 $1,210,279

2023-24 $1,393,005 $4,967 $1,397,972

2024-25 $1,701,583 $5,235 $1,706,818

2025-2035 (even) $1,701,583 $5,235 $1,706,818



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Option 3

Year


Changes in involuntary

load shedding Changes in network

losses Total

2016-17 - - -

2017-18 $346,299 - $346,299

2018-19 $552,111 - $552,111

2019-20 $681,036 - $681,036

2020-21 $816,661 - $816,661

2021-22 $1,046,215 $4,748 $1,050,963

2022-23 $1,205,398 $4,881 $1,210,279

2023-24 $1,393,005 $4,967 $1,397,972

2024-25 $1,701,583 $5,235 $1,706,818

2025-2035 (even) $1,701,583 $5,235 $1,706,818



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Low maximum demand forecast

Option 1

Year



Changes in network

losses Total

2016-17 - - -

2017-18 $308,941 $3,532 $308,941

2018-19 $385,339 $4,066 $388,871

2019-20 $537,656 $4,278 $541,723

2020-21 $639,100 $4,501 $643,378

2021-22 $744,013 $4,748 $748,514

2022-23 $843,318 $4,881 $848,066

2023-24 $955,886 $4,967 $960,767

2024-25 $1,087,714 $5,235 $1,092,681

2025-2035 (even) $1,296,905 $5,235 $1,302,140

Option 2

Year




losses Total

2016-17 - - -

2017-18 $164,335 - $164,335

2018-19 $385,339 $4,066 $388,871

2019-20 $537,656 $4,278 $541,723

2020-21 $639,100 $4,501 $643,378

2021-22 $744,013 $4,748 $748,514

2022-23 $843,318 $4,881 $848,066

2023-24 $955,886 $4,967 $960,767

2024-25 $1,087,714 $5,235 $1,092,681

2025-2035 (even) $1,296,905 $5,235 $1,302,140



Page 52 of 68

Option 3

Year




losses Total

2016-17 - - -

2017-18 $309,961 - $309,961

2018-19 $461,884 - $461,884

2019-20 $552,552 - $552,552

2020-21 $650,964 - $650,964

2021-22 $744,013 $4,748 $748,514

2022-23 $843,318 $4,881 $848,066

2023-24 $955,886 $4,967 $960,767

2024-25 $1,087,714 $5,235 $1,092,681

2025-2035 (even) $1,296,905 $5,235 $1,302,140



Page 53 of 68

High maximum demand forecast

Option 1

Year



Changes in network

losses Total

2016-17 - - -

2017-18 $436,054 $3,532 $439,586

2018-19 $717,787 $4,066 $721,853

2019-20 $908,213 $4,278 $912,491

2020-21 $1,111,860 $4,501 $1,116,361

2021-22 $1,299,169 $4,748 $1,303,917

2022-23 $1,515,558 $4,881 $1,520,440

2023-24 $1,778,006 $4,967 $1,782,973

2024-25 $2,312,629 $5,235 $2,317,864

2025-2035 (even) $2,312,629 $5,235 $2,317,864

Option 2

Year




losses Total

2016-17 - - -

2017-18 $213,683 - $213,683

2018-19 $717,787 $4,066 $721,853

2019-20 $908,213 $4,278 $912,491

2020-21 $1,111,860 $4,501 $1,116,361

2021-22 $1,299,169 $4,748 $1,303,917

2022-23 $1,515,558 $4,881 $1,520,440

2023-24 $1,778,006 $4,967 $1,782,973

2024-25 $2,312,629 $5,235 $2,317,864

2025-2035 (even) $2,312,629 $5,235 $2,317,864



Page 54 of 68

Option 3

Year




losses Total

2016-17 - - -

2017-18 $371,152 - $371,152

2018-19 $644,880 - $644,880

2019-20 $824,103 - $824,103

2020-21 $1,018,426 - $1,018,426

2021-22 $1,299,169 $4,748 $1,303,917

2022-23 $1,515,558 $4,881 $1,520,440

2023-24 $1,778,006 $4,967 $1,782,973

2024-25 $2,312,629 $5,235 $2,317,864

2025-2035 (even) $2,312,629 $5,235 $2,317,864

Documents

Draft Project Assessment Report Notting Hill Supply Area Project … · 2017-10-05 · Notting Hill Supply Area Project № UE-DZA-N-17-001 Page 2 of 68 Table of Contents 1 Approval