Draft Project Assessment Report Dromana Supply Area ...

RIT-D Report This report presents the network limitations at Dromana zone substation and the distribution feeder network within the Dromana / Mornington supply areas, including the preferred option to address those limitations.

Draft Project Assessment Report Dromana Supply Area

Project № UE-DZA-S-15-001

RIT-D Draft Project Assessment Report

Dromana Supply Area Project № UE-DZA-S-15-001 Page 1 of 53

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Table of Contents

1 Approval and Document Control 4

2 Executive summary 5

3 Introduction 13

4 Identified Need 14

4.1 Network overview 14

4.2 Description of the identified need 16

4.2.1 Insufficient zone substation capacity 16

4.2.2 Insufficient load transfer capability 17

4.2.3 High distribution feeder utilisation 18

4.2.4 Poor distribution feeder reliability performance 19

4.3 Closing comments on the need for investment 19

4.4 Quantification of the identified need 20

5 Key assumptions in relation to the identified need 21

5.1 Forecast maximum demand 21

5.1.1 Zone substation 21

5.1.2 Distribution feeders 22

5.2 Expected unserved energy 23

5.3 Characteristic of load profile 23

5.4 Load transfer capacity and supply restoration times 25

5.5 Plant failure rates 26

5.6 Discount rates 26

5.7 Plant ratings 27

5.8 Value of customer reliability 27

6 Summary of submissions 28

7 Credible options included in this RIT-D 29

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

8.2.1 Changes in voluntary load shedding 33

8.2.2 Changes in costs to other parties 33

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 34

8.4 Scenarios and sensitivities 35

8.4.1 Demand forecasts 35

8.4.2 Capital costs 35

8.4.3 Value of customer reliability 36

8.4.4 Discount rates 36

8.4.5 Average Victorian spot price 36

8.4.6 Summary of sensitivity testing 36

9 Results of analysis 37

9.1 Gross market benefits 37

9.1.1 Key categories of market benefits 38

9.2 Net market benefits 39

9.3 Sensitivity and scenario assessment 40

9.4 Economic timing 43

10 Proposed preferred option 45

11 Submission 47

11.1 Request for submission 47

11.2 Next steps 47

12 Checklist of compliance with NER clauses 48

13 Abbreviations and Glossary 49

Appendix A 52



1 Approval and Document Control

Project № UE-DZA-S-15-001 – Dromana Supply Area

VERSION DATE AUTHOR

1 31 July 2014 UE Network Planning

Amendment overview

New document



2 Executive summary

Purpose

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).

The purpose of this report is to provide a basis for consultation on the proposed preferred option to address the network limitations within the Dromana supply area.1 This report has been prepared following the conclusion of consultation on the Non Network Options Report (NNOR), which represents the first stage of the consultation process in relation to the application of the RIT-D.

This report:

Describes the need which UE is seeking to address, together with the assumptions 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, which is the installation of the second DMA transformer plus two new distribution feeders and reconfiguration of the existing DMA distribution network.

The need for investment

Dromana (DMA) zone substation was commissioned in March 2006, as a single transformer zone substation, to provide load relief to neighbouring Mornington (MTN) and Rosebud (RBD) zone substations. From inception, DMA has showed a steady growth in maximum demand, with the actual summer maximum demand in 2011-12 exceeding the nameplate rating of the transformer. Based on the current load forecast, the 10% PoE summer maximum demand at DMA is expected to exceed the station’s ‘N’ cyclic rating in summer 2015-16.

Given DMA is a single transformer zone substation, customers’ supply is normally restored via the distribution feeder network from neighbouring zone substations at MTN and RBD, following the loss of the zone substation transformer or other fault resulting in the total loss of supply to DMA. Due to on-going customer load growth, the spare capacity in the neighbouring network during high

1 NER: clause 5.17.4(k)



demand periods has diminished below the summer maximum demand at DMA. As a consequence, some customers could potentially be without electricity supply until the capacity in the neighbouring network becomes available. Based on the current load forecast, some customers are expected to be without electricity supply from summer 2014-15, following the loss of the transformer during high demand.

The distribution network from DMA zone substation is characterised by relatively long distribution feeders. As a result, a number of distribution feeders within the DMA supply area have shown poor reliability performance compared to the overall UE network. In addition a number of distribution feeders in the DMA and MTN supply areas are forecast to exceed their thermal capability within the next five years.

The forecast impact of the ‘identified need’ discussed above is presented in Figure 1.

Figure 1 – Forecast impact of the identified need

Results of consultation on options

On 28 March 2014, UE published the NNOR providing details on the network limitations within the Dromana 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 Register2 and engaged in joint planning with those proponents to assess the viability of alternative credible options within the

2 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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Dromana supply area. UE received two submissions by 20 June 2014, being the closing date for submissions to the NNOR. Both submissions indicated that there are no identified credible alternative options within the Dromana supply area.

Credible options for addressing the identified need

UE presented seven long term options in the NNOR. Five of these options were regarded as not being credible for reasons set out in that paper. Given there are no identified credible alternative solutions with the Dromana supply area, only two 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

Option 1 This option includes:

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

Extending the 22 kV busbar at Dromana zone substation.

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

The estimated total cost, inclusive of operating costs, is estimated at $8.4 million (in PV terms)

Option 2

This option includes:

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

Developing three new 22 kV distribution feeders at Mornington zone substation to supply the existing loads in and around Dromana area.

Developing one new 22 kV distribution feeder at Rosebud zone substation to supply the existing loads in and around Dromana area.

The estimated total cost, inclusive of operating costs, is estimated at $17.3 million (in PV terms)

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).3 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 option in place.

Scenarios considered

The NER stipulates that the RIT-D must be based on cost-benefit analysis that considers a number of reasonable scenarios of future supply and demand.4 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.

3 AER: “Regulatory Investment Test for Distribution Application Guidelines”, Section 1.1.

Available http://www.aer.gov.au/node/19146 4 NER: clause 5.17.4(c) paragraph 1

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



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

Variable for sensitivity testing

Lower bound Base case Upper bound

Maximum demand Low (Base estimates minus 5% per

annum off the total forecast demand at DMA)

5

Base estimates

N/A

Capital costs Low (Base estimates minus 10%)

Base estimates High (Base estimates plus 10%)

Value of customer reliability

Low (Base estimates minus 15%)


Discount rate 8.5% 9.5% 10.5%

Average Victorian Spot Price



The sensitivity assessment indicated that the net market benefit of each credible option was most sensitive to changes in:

Demand levels;

Value of customer reliability;

Discount rate; and

Cost of investment.

Accordingly, UE has defined twelve scenarios to test the robustness of this RIT-D assessment: the ‘base case’ (or the most likely scenario), and eleven other scenarios which represent plausible combination of upper and lower bound assumptions on the key variables of demand growth, investment cost, value of customer reliability and discount rate.

Table 3 – Reasonable scenarios under consideration

Scenario Demand growth VCR Investment cost Discount rate

Base case Base Base Base Base

Scenario 1 Base Low Base Base

Scenario 2 Base Low High Low

Scenario 3 Base Low High High

Scenario 4 Base High Base Base

Scenario 5 Base High Low Low

Scenario 6 Base High Low High

5 This is equivalent to 2-3 MW per annum lower than the base (expected) forecast at DMA.




Scenario 7 Low Base Base Base

Scenario 8 Low Low Base Base

Scenario 9 Low Low High Low

Scenario 10 Low High Base Base

Scenario 11 Low High Low Low

NPV Results

Table 4 sets out a comparison of the present value of net market benefits of each option under all reasonable scenarios, over a twenty-year period.

The shaded cell in each row indicates the option that maximise the net market benefit for that particular scenario relative to ‘Do nothing’.

Table 4 – Net market benefits of each credible option under various scenarios (PV, $m)

Scenario

Do Nothing Option 1 Option 2

Net Market Benefit

Ranking Net Market Benefit


Ranking

Base case 0 3 37.05 1 19.25 2

Scenario 1 0 3 30.30 1 13.82 2

Scenario 2 0 3 33.82 1 15.74 2

Scenario 3 0 3 25.62 1 8.90 2

Scenario 4 0 3 43.81 1 24.68 2

Scenario 5 0 3 50.58 1 31.41 2

Scenario 6 0 3 39.45 1 22.04 2

Scenario 7 0 3 17.92 1 1.15 2

Scenario 8 0 2 14.03 1 (1.58) 3

Scenario 9 0 2 15.66 1 (1.45) 3

Scenario 10 0 3 21.81 1 3.87 2

Scenario 11 0 3 26.05 1 8.18 2



The results set out in table above show:

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

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

Option 2 is found to have negative market benefit in majority of the scenario analysis, when the demand at DMA is 5% less than forecast. As a consequence, this option is ranked lower than the ‘Do Nothing’ option.

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: Installation of the second DMA transformer plus two new distribution feeders and reconfiguration of the existing DMA distribution network. This option satisfies the requirements of the RIT-D.

Although the choice of the proposed preferred option is clear, the timing of this investment is not, given a number of reasonable scenarios are investigated. 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.

Table 5 below shows the expected timing of the proposed preferred option under each reasonable scenario.

Table 5 – Expected timing of the proposed preferred option

Scenario Timing

Base case 2015-16

Scenario 1 2016-17

Scenario 2 2016-17

Scenario 3 2016-17

Scenario 4 2014-15

Scenario 5 2014-15

Scenario 6 2014-15

Scenario 7 2017-18

Scenario 8 2018-19

Scenario 9 2018-19

Scenario 10 2016-17

Scenario 11 2014-15



The results set out in table above show that:

The timing of the proposed preferred option is 2015-16 under the ‘base case’ reasonable scenario (i.e. under the most likely scenario).

There may be scope for deferring the proposed preferred option by one year if:

o The value of customer reliability is 15% lower than the base estimates.

There may be scope for deferring the proposed preferred option by two years if:

o The maximum demand at DMA is 5% per annum lower than base estimates – that is, the maximum demand at DMA is approximately 2-3 MW per annum lower than the forecast.

The proposed preferred option may be implemented earlier if:

o The VCR is 15% higher than the base estimates.

Recommendation

The recommended action involves:

Installation of a new 20/33 MVA 66/22 kV transformer at Dromana zone substation.

Extension of the 22 kV indoor bus at DMA with:

o One 22 kV transformer circuit breaker

o Four 22 kV feeder circuit breakers

o One 22 kV capacitor circuit breaker

o One 22 kV bus-tie circuit breaker

Upgrade of existing protection and control schemes.

Development of two new 22 kV distribution feeders to supply the existing load in and around the Dromana area, including rearrangement works.

The total project cost, inclusive of operating costs, is estimated at $8.4 million (in present value terms).

While the timing of the base case scenario is indicating a 2015-16 commissioning, it may not be physically possible to complete works by this time. Therefore the expected commissioning date of this option is no later than December 2016 which is consistent with the one-year deferral scenarios identified above.



Next steps

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

All Submissions and enquiries should be directed to the United Energy Manager Network Planning at [email protected].

Submissions are due on or before 26 September 2014.

All submissions will be published on UE website.6

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 in November 2014.

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

mailto:[email protected]



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) for addressing capacity limitations at Dromana (DMA) zone substation and its distribution feeder network.

In March 2014, UE published the first stage of the RIT-D, being the release of the Non Network Options Report (NNOR). 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 two submissions; both indicating that there are no credible alternative options within the Dromana supply area.

This report:

Provides background information on the network limitations at DMA zone substation.

Describes the need which UE is seeking to address, together with the assumptions 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.

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

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

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 preferred option, including detailed characteristics, estimated commissioning date, indicative costs and noting that it satisfies the RIT-D.

The contact detail of UE staff member to send queries on this RIT-D.



4 Identified Need

4.1 Network overview

Dromana (DMA) zone substation is equipped with one 20/33 MVA 66/22 kV transformer and provides electricity supply to approximately 15,000 customers. The areas supplied include Dromana, Mount Martha, Red Hill and Shoreham as illustrated in the map below.

Figure 2 – Geographical areas supplied by DMA zone substation

DMA zone substation was commissioned in March 2006 to:

Off-load Mornington (MTN) and Rosebud (RBD) zone substations;

Off-load distribution feeders; and

Improve supply reliability in the area.



Figure 3 below presents the Single Line Diagram of DMA zone substation depicting the present configuration.

Figure 3 – Existing configuration of DMA (schematic view)

DMA zone substation is supplied via two 66 kV sub-transmission lines, one from Tyabb Terminal Station (TBTS) and the other from MTN zone substation. There are also two out-going 66 kV sub-transmission lines that supply RBD and then Sorrento (STO) zone substations in the lower Mornington Peninsula.

Ring bus configuration at DMA prevents a single sub-transmission line fault tripping the zone substation transformer. However, a forced outage of the zone substation transformer, the 22 kV bus, the incomer cable or the incomer circuit breaker would result in the loss of the zone substation transformer (i.e. total loss of supply from DMA zone substation). Following such an event, customers’ supply is restored (in part) via the distribution feeder network from neighbouring zone substations at MTN and RBD.

Whilst the probability of a transformer outage or other fault resulting in the total loss of supply to DMA is very low, the energy at risk7 resulting from the total loss of supply of the zone substation is high because customers supplied from DMA zone substation are exposed to such an event all year round, not just during periods of high demand.

7 Energy at risk is the amount of energy that would not be supplied due to a major outage of the DMA zone substation transformer.



4.2 Description of the identified need

4.2.1 Insufficient zone substation capacity

DMA is a summer critical zone substation.

The figure below depicts the historical actual and weather corrected maximum demands, 10% and 50% PoE maximum demand forecasts together with the station’s operational ratings.

Figure 4 – Forecast maximum demand against station ratings for DMA zone substation

As illustrated above:

The historic actual maximum demand at DMA zone substation has been above its nameplate rating since summer 2011-12.

The 10% PoE maximum demand8 at DMA zone substation is expected to exceed the station’s (N) cyclic rating in summer 2015-16, for about 1 hour.

In other words, at the 10% PoE maximum demand at DMA, and in the absence of any mitigation action:

Inadequate capacity at the station would be expected to lead to supply interruption from summer 2015-16, under system normal conditions (i.e. with all plants in service).

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.

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Actual Load 10% PoE Forecast (MW) 50% PoE Forecast (MW) Summer (N-1) Rating

Summer (N) Rating (MVA) Nameplate Rating (MVA) Weather corrected actuals



4.2.2 Insufficient load transfer capability

Following a major outage of the transformer at DMA zone substation, customers’ supply can be restored (in part) via the distribution network from neighbouring zone substations at MTN and RBD. At present, limited load transfer capability exists between DMA and neighbouring network during high demand periods. As a result, some customers could potentially be without electricity supply until the capacity in the neighbouring network becomes available. With increasing demand, the available load transfer capability diminishes, leaving greater numbers of customers exposed to risk of supply interruption as shown in table below.

Table 6 – Forecast load at risk

Year

10% PoE conditions 50% PoE conditions

Demand9

(MW)

Transfer Capability

(MW)

Load at

Risk10

(MW)

Demand9

(MW)

Transfer Capability

(MW)

Load at

Risk10

(MW)

2014-15 42.9 23.8 19.1 39.1 26.3 12.8

2015-16 44.1 23.2 20.9 40.3 25.7 14.6

2016-17 45.3 22.6 22.7 41.5 25.1 16.4

2017-18 46.4 22.1 24.4 42.2 24.5 17.7

2018-19 47.8 21.5 26.3 43.2 23.9 19.4

2019-20 49.3 21.0 28.3 44.5 23.3 21.1

2020-21 50.6 20.4 30.2 45.8 22.8 23.0

2021-22 51.8 19.9 31.9 47.1 22.2 24.9

2022-23 52.9 19.4 33.5 48.5 21.7 26.8

As shown above:

The load transfer capability away from DMA is less than that required to fully restore DMA load following the loss of the zone substation transformer (i.e. N-1) at maximum demand, for about 64 hours (at 10% PoE demand conditions).

In other words, an outage of the DMA zone substation transformer at maximum demand, and in the absence of any mitigation action:

Inadequate load transfer capability between DMA and neighbouring network is expected to lead to supply interruptions from summer 2014-15.

9 The maximum demand forecasts are based on the medium (base) economic growth scenario.

10 Load at risk is the amount of load that would not be supplied due to a major outage of the DMA zone substation transformer. These

numbers reflect the impact of load transfer capability.



4.2.3 High distribution feeder utilisation

Utilisation of critical distribution feeders within the DMA, MTN and RBD supply areas are presented in Figure 5.

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

Figure 5 – Feeder utilisation in summer 2014-15 (10% PoE maximum demand)

As illustrated above:

The loading on DMA 12 is forecast to exceed its cyclic rating in summer 2014-15.

The loading on MTN 35 is forecast to be 99% utilised in summer 2014-15.

The loading on MTN 23 is forecast to be 93% utilised in summer 2014-15.

Emerging capacity limitations in distribution feeders are managed by transferring load away to neighbouring feeders at maximum demand. For instance, some load can be transferred away from DMA 12 to MTN 31. Such actions are adopted usually as the initial mitigation action due to its low upfront cost. However, such an option cannot be sustained in the future, as the spare capacity in the neighbouring feeders have depleted due to on-going customer load growth and load transfers in the past to manage high utilisation in the area.

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4.2.4 Poor distribution feeder reliability performance

The distribution network from DMA zone substation is characterised by relatively long distribution feeders. As a result, they have shown poor reliability performance compared to the overall UE network. More specifically, DMA 13 and DMA 14 are amongst UE’s top ten ‘rogue’ feeders as shown in Table 7.

Table 7 – Ranking of DMA feeders relative to UE network in 2013 (calendar year)

Feeder UE poor reliability ranking for 2013

11

Feeder length

(km)

Customer numbers

DMA 11 >50 16 3,143

DMA 12 30 33 4,045

DMA 13 2 136 2,793

DMA 14 6 18 3,070

DMA 15 >50 50 1,732

With increasing customer numbers, the adverse impact of these feeders on the overall reliability performance of the UE network is expected to increase over time as the rate of customer growth is higher than the UE average.

4.3 Closing comments on the need for investment

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

From summer 2014-15, inadequate load transfer capability between DMA and the neighbouring network is expected to lead to supply interruption, following the loss of the DMA zone substation transformer at maximum demand;

From summer 2015-16, inadequate capacity at DMA zone substation is expected to lead to supply interruption, under system normal conditions (i.e. with all plants in service) for a one-in-ten year summer;

A number of distribution feeders in the DMA and MTN supply areas are forecast to exceed their thermal capability within the next five years; and

A number of distribution feeders within the DMA supply area have shown poor reliability performance.

In light of the growing demand at DMA and the forecast increase in load at risk, UE has examined a number of options to alleviate the identified need. These options were outlined in the NNOR. The credible options identified for further detailed study and application of the RIT-D are presented in Section 7.

11

From a total UE distribution feeder count of approximately 430 feeders.



4.4 Quantification of the identified need

The forecast impact of the identified need discussed in Section 4.2 is presented in Table 8.

The table shows:

Load at risk, which is the MW load shedding required to avoid the network limitation under the 10% PoE maximum demand forecast. This reflects the reduced impact because of load transfer capability.

Customer value of lost load is the cost of the expected unserved energy, obtained by multiplying the expected unserved energy12 by the Value of Customer Reliability (VCR) using a detailed assessment of the risk which includes consideration of the load transfer capability.

Table 8 – Forecast network limitation

Year Load at Risk13

(MW)

Customer Value of Lost Load

($,000)

2014-15 19.1 696

2015-16 20.9 852

2016-17 22.7 1,182

2017-18 24.4 1,689

2018-19 26.3 1,979

2019-20 28.3 2,381

2020-21 30.2 3,159

2021-22 31.9 4,268

2022-23 33.5 5,682

12

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 a 30% weighting of the 10% PoE demand and 70% weighting of the 50% PoE demand (see Section 5.2). 13

The load at risk includes both pre-contingent and post-contingent load reduction requirements.



5 Key assumptions in relation to the identified need

5.1 Forecast maximum demand

5.1.1 Zone substation

Forecasts of the 10% PoE and 50% PoE summer maximum demand at DMA, MTN and RBD zone substations are presented in Figure 6 and Figure 7 below. These forecasts are based on the base (expected) economic growth scenario.

Figure 6 – 10% PoE summer maximum demand forecasts at DMA, MTN and RBD zone substations

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MTN RBD DMA



Figure 7 – 50% PoE summer maximum demand forecasts at DMA, MTN and RBD zone substations

5.1.2 Distribution feeders

Average annual growth in summer maximum demand of the distribution feeders in the DMA, MTN and RBD supply areas are presented in Table 9.

Table 9 – Annual growth rate of distribution feeders

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

DMA 4.0% 3.9%

MTN 3.1% 3.0%

RBD 2.1% 2.0%

Average UE growth rate (for comparison) 1.7% 1.4%

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MTN RBD DMA



5.2 Expected unserved energy

For the purpose of undertaking the RIT-D, the amount of expected unserved energy was estimated by taking 30% weighting of the unserved energy at 10% PoE maximum demand forecast and 70% weighting of the unserved energy at 50% PoE maximum demand forecast.14

5.3 Characteristic of load profile

DMA zone substation provides electricity supply to approximately 15,000 customers in the areas of Dromana, Mount Martha, Red Hill and Shoreham. The zone substation load is characterised primarily of residential loads with commercial and light industrial loads in the major population centres. The peak demand occurs during summer holiday periods as illustrated in Figure 8.

Figure 8 – Load profile at DMA zone substation (2008-09)

A typical load profile on the day of summer maximum demand is presented in Figure 9.

Normally, the electricity demand at Dromana remains relatively low during the day, with a large increase in demand during the late afternoon to early evening hours.

14

This approach accounts for uncertainty in the demand forecast and is consistent with the approach undertaken by AEMO for estimating the expected unserved energy.

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Figure 9 – Load profile on day of summer maximum demand at DMA zone substation

Figure 10 shows the normalised load duration curves at DMA zone substation for the last five summers.

Figure 10 – Historical load duration curves at DMA zone substation

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The figure above shows that that the load characteristics can vary from year to year. It also shows that around 40-50% of the maximum demand lasts less than ten per-cent of the period. This implies that although the probability of reaching high demand levels is reasonably low, the impact of not having sufficient capacity can result in significant amount of load at risk.

To account for variability in load characteristics, UE has prepared load traces based on historical load traces that characterised:

10% PoE and 50% PoE demand profiles (or close to) for DMA zone substation;

Maximum demand occurring during summer holiday periods; and

Excluded load transfer from / to neighbouring network.

Based on this approach, the expected unserved energy at DMA zone substation was estimated using the expected 2007-0815 and 2008-0916 historical traces.

The above-mentioned approach was adopted to estimate the expected unserved energy at MTN and RBD zone substations. The MTN and RBD load traces were therefore based on the following base years:

Table 10 – Base years used to develop load traces

Zone substation Base year

10% PoE load trace

Base year

50% PoE load trace

DMA 2008-09 2007-08

MTN 2010-11 2006-07

RBD 2008-09 2006-07

5.4 Load transfer capacity and supply restoration times

The load transfer capability between DMA and neighbouring network was calculated for summer 2013-14, as part of UE’s contingency planning studies.

Future load transfer capability between DMA and neighbouring network were estimated by reducing the load transfer capability in 2013-14 by the annual growth rate of MTN and RBD distribution feeders that are used to restore DMA load, following an outage of the DMA zone substation transformer.

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). This figure represents UE’s current reliability performance target for CAIDI.17

15

The 2007-08 historic load trace characterised (or close to) a 50% PoE maximum demand profile at DMA. 16

The 2008-09 historic load trace characterised (or close to) a 10% PoE maximum demand profile at DMA. 17

CAIDI represents the average restoration time for each outage.



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 11 – 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.

Table 12 – 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 13 – 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 9.5 per-cent is adopted in this assessment.



5.7 Plant ratings

The station ratings of DMA, MTN and RBD 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 below.

Table 14 – Summary of transformer cyclic ratings (MVA)

Zone substation

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

N N-1 N N-1

DMA 45.0 0.0 45.8 0.0

MTN 92.9 46.4 97.9 48.9

RBD 91.6 45.8 92.3 46.2

5.8 Value of customer reliability

Location specific Value of Customer Reliability (VCR) is used to calculate expected unserved energy. Where a limitation impacts multiple zone substations, an average VCR of the affected zone substations is used to calculate customer value of lost load.

The location VCR was derived from the sector VCR estimates provided by AEMO, weighted in accordance with the composition of the load, by sector, at the relevant zone substations.

Table 15 – Summary of location specific VCRs

Zone substation VCR

($ per MWh)

DMA 54,130

MTN 65,220

RBD 68,280



6 Summary of submissions

On 28 March 2014, UE published the Non Network Options Report (NNOR) providing details on the network limitations within the Dromana 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 report, UE received enquiries from several non-network service providers. UE engaged in joint planning with these proponents to assess the viability of credible alternative solutions within the Dromana supply area. UE received two submissions by 20 June 2014, being the closing date for submissions to the NNOR.

The first submission from GreenSync Pty Ltd indicated that they had undertaken detailed assessment of the Dromana area, which included technical analysis of the data supplied in the NNOR and a comprehensive customer survey of the Dromana area. GreenSync identified only a small amount of curtailable load which is insufficient to address the identified need or defer proposed network investment. GreenSync therefore concluded that there are no potential credible non-network solutions within the Dromana supply area. GreenSync’s submission is available on UE’s website.18

The second submission received via email from Cogent Energy also indicated that there are no identified credible non-network solutions within the Dromana supply area.

18

UE: Submissions on Non Network Options Report. Available at: http://uemg.com.au/about-us/regulatory-framework/electricity-regulation/dromana-supply-area-rit-d.aspx

http://uemg.com.au/about-us/regulatory-framework/electricity-regulation/dromana-supply-area-rit-d.aspx




7 Credible options included in this RIT-D

UE presented seven network options in the Non Network Options Report published on 28 March 2014. Five of these options were regarded as not being credible for the reasons set out in that report.19 Given there are no credible non-network solutions, only two credible options have been considered for further detailed assessment and application of the RIT-D.

Details of the credible network options are presented in the table below.

Table 16 – Credible options under consideration

Option Description

Option 1 This option includes:

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

Extending the 22 kV busbar at Dromana zone substation.

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

This option will:

Prevent the risk of supply interruption under system normal conditions.

Prevent the risk of supply interruption following the loss of the Dromana zone substation transformer.

Reduce utilisation of the distribution feeders in the Dromana area.

Improve reliability performance of the distribution feeders in the Dromana area.

The estimated capital cost of this option is $7.6 million (± 10%), in 2013-14 $AUD. Annual operating and maintenance costs are anticipated to be around 1% of the capital cost.

The estimated commissioning date is December 2015.

Option 2

This option includes:

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

Developing three new 22 kV distribution feeders at Mornington zone substation to supply the existing loads in and around Dromana area.

Developing one new 22 kV distribution feeder at Rosebud zone substation to supply the existing loads in and around Dromana area.

This option will:

Prevent the risk of supply interruption under system normal conditions.

Partially reduce the risk of supply interruption following the loss of the Dromana zone substation transformer.

Reduce utilisation of the distribution feeders in the Dromana area.

Improve reliability performance of the distribution feeders in the Dromana area.

The estimated capital cost of this option is $15.6 million (± 10%), in 2013-14 $AUD. Annual operating and maintenance costs are anticipated to be around 1% of the capital cost.

The estimated commissioning date is December 2015.

19

UE: Non Network Options Report. Available at: http://uemg.com.au/about-us/regulatory-framework/electricity-regulation/dromana-supply-area-rit-d.aspx





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.20 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. The modelling discussed in Section 8.1.1 to Section 8.1.2 below has been undertaken across a ten-year study horizon. The market benefits calculated in the final year of the modelling period (i.e. 2023-24) has been applied as the assumed annual market benefit that would continue to arise for a further ten 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.21 UE believes that this approach is a reasonable approach, 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).22

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.23 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.

20

AER: “Regulatory Investment Test for Distribution Application Guidelines – August 2013”, Section 11.1. Available http://www.aer.gov.au/node/19146 21

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 22

AER: “Regulatory Investment Test for Distribution Application Guidelines – August 2013”, Section 1.1. Available http://www.aer.gov.au/node/19146 23

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




8.1.1 Changes in involuntary load shedding

Increasing the supply capability within the Dromana supply area increases the supply available to meet the maximum demand within the Dromana 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 option 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 MWh), after considering the impact of load transfers, and applying the locational VCR (expressed in $/MWh).

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 expected unserved energy due to insufficient capacity at DMA zone substation and multiplying by the locational VCR.

2. Identifying the expected unserved energy due to limitations in the distribution feeders within the Dromana supply area and multiplying by the locational VCR.

The expected unserved energy due to insufficient capacity at DMA zone substation has been quantified as follows:

1. Identify the expected unserved energy at DMA zone substation under system normal conditions (i.e. N condition) and following the loss of the DMA zone substation transformer (i.e. N-1 condition) by considering load transfer capability.

2. Identify the incremental expected unserved energy at MTN zone substation due to transferring load away from DMA to MTN, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy at MTN zone substation before load transfer with the expected unserved energy at MTN zone substation after load transfer.

3. Identify the incremental expected unserved energy on the MTN distribution feeder network due to transferring load away from DMA to MTN, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy on the MTN distribution feeder network before load transfer with the expected unserved energy on the MTN distribution feeder network after load transfer.

4. Identify the incremental expected unserved energy at RBD zone substation due to transferring load away from DMA to RBD, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy at RBD zone substation before load transfer with the expected unserved energy at RBD zone substation after load transfer.



5. Identify the incremental expected unserved energy on the RBD distribution feeder network due to transferring load away from DMA to RBD, following the loss of the DMA zone substation transformer. This was achieved by comparing the expected unserved energy on the RBD distribution feeder network before load transfer with the expected unserved energy on the RBD distribution feeder network after load transfer.

The combined expected unserved energy from (1) to (5) represents the expected unserved energy due to insufficient capacity at DMA 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).

8.1.2 Changes in load transfer capability

Following a major outage of the transformer at DMA zone substation, customers’ supply can be restored (in part) via the distribution network from neighbouring zone substations at MTN and RBD. 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 DMA (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 MTN and RBD.

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 DMA 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 Dromana 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 multiplying the network losses at the time of maximum demand by the loss load factors for 2012-13.24 These MWh figures for losses have then been multiplied by the value of those losses, as measured by the average Victorian spot price for 2013-14, in accordance with the methodology prescribed in the RIT-D Applications Guidelines.25

24

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.) 25

AER: “Regulatory Investment Test for Distribution Application Guidelines”, Example 22. Available http://www.aer.gov.au/node/19146




The average Victorian spot price for 2013-14 has been assumed to be $53.13 per MWh. This value has been derived from the average monthly Victorian spot prices published on AEMO’s website. 26

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 in costs to other parties;

Difference in timing of distribution investment; and

Option value.

8.2.1 Changes in voluntary load shedding

A credible demand-side reduction option may lead 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 their load to address a network limitation. Customers would usually receive a payment to voluntarily curtail their electricity use under these circumstances.

In the absence of any credible demand-side options, UE has not estimated any market benefits associated with changes in involuntary load curtailment.

8.2.2 Changes in costs to other parties

The lower Mornington Peninsula is supplied by Dromana (DMA), Rosebud (RBD) and Sorrento (STO) 66/22 kV zone substations. These three zone substations together with other zone substations in the region including Frankston South (FSH), Hastings (HGS) and Mornington (MTN) are supplied from the 220/66kV transmission connection point known as Tyabb Terminal Station (TBTS), the sole transmission source of electricity supply to the Mornington Peninsula from the Victorian shared transmission network.

Both credible options considered in this RIT-D address the ‘identified need’ within the UE’s distribution network in the Mornington Peninsula. UE does not propose to transfer load from another transmission connection point to TBTS (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.

26

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



8.2.3 Difference in timing of distribution investment

Both credible options considered in this RIT-D address the ‘identified need’ within the Dromana supply area. No further distribution investments are anticipated within the Dromana area within this planning period. 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.27

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.

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 17.

Table 17 – Summary of project costs

Option Capital cost Operational cost

Do Nothing Zero Customer value of lost load valued at VCR provided in Table 15.

Option 1 $7.6 million Customer value of lost load valued at VCR provided in Table 15.

Asset operating and maintenance expenditure of 1% per annum of the capital cost of the asset.

Option 2 $15.6 million Customer value of lost load valued at VCR provided in Table 15.

Asset operating and maintenance expenditure of 1% per annum of the capital cost of the asset.

The capital costs of network options have been developed by UE, based on in-house estimation by our project estimation team. They are presented in 2013-14 Australian dollars.

27

AER. “Regulatory Investment Test for Distribution Application Guidelines”, Section A6. Available http://www.aer.gov.au/node/19146




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 Dromana supply area.

In order to consider the impact of key factors that drive market benefits, UE has adopted the ‘base case’ reasonable scenario based on the following input assumptions:

Table 18 – Summary of input assumptions of the ‘base case’ reasonable scenario

Variables Values

Maximum demand forecasts Base (expected) economic growth scenario presented in Section 5.1

Capital costs Base estimates provided in Table 17

Operational costs 1% of the capital costs

Value of customer reliability Base estimates provided in Table 15

Discount rate 9.5%

Victorian average spot price Base estimates for 2013-14

The development of additional reasonable scenarios involves a process of applying sensitivity to key input variables within the ‘base case’ reasonable scenario. Where a change to a parameter or value in the ‘base case’ reasonable scenario yields or likely to yield a change in ranking of credible options by net economic benefit, additional reasonable scenarios that reflect variations in that parameter or value would be adopted.

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

8.4.1 Demand forecasts

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

For the purpose of sensitivity testing, a lower bound forecast has been derived by reducing the central estimates for future DMA demand by 5% per annum (that is, the maximum demand at DMA is approximately 2-3 MW per annum lower than the forecast).

8.4.2 Capital costs

Capital cost estimates have been developed based on in-house estimation of detailed scopes of work by our project estimation team. These estimates are subject to a range of ±10%.

Accordingly, for the purpose of sensitivity testing, a range of ±10% around the budget estimate (base) has been assumed to define the upper and lower bounds of the capital costs of all network options.



8.4.3 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 VCR data published by AEMO.

For the purpose of sensitivity testing, the VCR has been varied within limits of ±15%.

8.4.4 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 9.5% has been applied for the purpose of this analysis.

For the purpose of sensitivity testing, a lower bound real discount rate of 8.5% and an upper bound of 10.5% have been applied.

8.4.5 Average Victorian spot price

As already noted, this analysis adopts the average Victorian spot prices for 2013-14 to calculate the expected network losses.

For the purpose of the sensitivity testing, the average Victorian price for 2013-14 has been varied within limits of ±15%.

8.4.6 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 scenarios

Variable for sensitivity testing

Lower bound Base case Upper bound

Maximum demand Low (Base estimates for DMA less

5% per annum off the total forecast demand at DMA

28)

Base estimates

N/A

Capital costs Low (Base estimates minus 10%)


Value of customer reliability



Discount rate 8.5% 9.5% 10.5%

Average Victorian Spot Price



28

This is equivalent 2-3 MW per annum lower than the base (expected) forecast at DMA.



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 results of each of the credible options, under each scenario.

9.1 Gross market benefits

Table 20 below summarises the gross market benefit, in 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 Base case

Option 1

Second transformer at DMA zone substation

Two new distribution feeders at DMA zone substation

45.45

Option 2

Third transformer at MTN zone substation

Three new distribution feeders at MTN zone substation

One new distribution feeder at RBD zone substation

36.52

The results show that, assuming central estimates for key variables, Option 1 delivers the highest gross market benefit.

The gross market benefit of Option 2 is significantly lower compared with Option 1 due to the following reasons:

Although Option 2 addresses the risk of supply interruption under system normal conditions, it does not fully prevent the risk of supply interruption following the loss of the DMA zone substation transformer. As a result, the expected market benefit associated with a reduction expected unserved energy at DMA zone substation is much lower compared to Option 1.

Following a major outage of the transformer at DMA zone substation, customers’ supply can be restored via the distribution network from neighbouring zone substations at MTN and RBD. Given the limited load transfer capability (following implementation of Option 2), the incremental expected unserved energy (as a result of temporary load transfer away from DMA) at RBD zone substation and neighbouring distribution feeders is similar to the expected unserved energy under the ‘Do Nothing’ case (where no action is undertake by UE). As a result, the expected market benefit associated with a reduction in load transfer to neighbouring network is much lower compared to Option 1



Option 2 off-loads highly utilised distribution feeders within the DMA supply area and improves the expected reliability performance. However, the extended lengths of new distribution feeders from MTN and RBD with increased numbers of customers (as a result of permanent load transfer from DMA) offsets the market benefit realised within the DMA distribution feeder network under this option. The new distribution feeders under Option 1 are relatively close to the load centre. As a result, the overall market benefit realised under Option 2 for addressing the distribution feeder limitations is significantly lower when compared to the overall market benefit realised under Option 1.

9.1.1 Key categories of market benefits

The figure below shows the breakdown of gross market benefits for Option 1 under the base case reasonable scenario.

It is clear from the figure below that the primary category of market benefits is the reduction in involuntary load shedding (unserved energy) resulting from the implementation of the option.29 Losses form only a very minor proportion of the total gross market benefits.

The flat line of market benefits beyond 2023-24 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.

Figure 11 – Option 1: Gross market benefits: Base case reasonable scenario (PV, $m)

29

As discussed earlier, the market benefits associated with a reduction in load transfer from DMA to MTN and RBD are included in the ‘changes in involuntary load shedding’ market benefit category. It should be noted that, given the limited load transfers available, benefits arising from a reduction in load transfer to neighbouring network forms only a small proportion of the total market benefits associated with the changes in involuntary load shedding.

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Figure 12 below shows the breakdown of gross market benefits for Option 2, under the base case reasonable scenario.

Again, the primary category of market benefit for this option is the changes in involuntary load shedding (unserved energy).30

Figure 12 – Option 2: Gross market benefits: 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 cost of each option, all in present value terms.

The table also shows the corresponding ranking of each option under the RIT-D, with options ranked in the order of descending net market benefit.

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

Options Total costs Gross market benefits Net market benefits Ranking under RIT-D

Do Nothing 0 0 0 3

Option 1 8.42 45.45 37.03 1

Option 2 17.28 36.52 19.24 2

30

As discussed earlier, the market benefits associated with a reduction in load transfer from DMA to MTN and RBD are included in the ‘changes in involuntary load shedding’ market benefit category. However, these benefits are immaterial given the incremental expected unserved energy on the neighbouring distribution network is similar to the base case (where no action is undertaken by UE).

0

1

2

3

4

5

6

7

8

20

14-1

5

20

15-1

6

20

16-1

7

20

17-1

8

20

18-1

9

20

19-2

0

20

20-2

1

20

21-2

2

20

22-2

3

20

23-2

4

20

24-2

5

20

25-2

6

20

26-2

7

20

27-2

8

20

28-2

9

20

29-3

0

20

30-3

1

20

31-3

2

20

32-3

3

20

33-3

4

Gro

ss m

arke

t b

en

efi

ts (

PV

, $m

)

Unserved Energy Network Losses



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

This RIT-D assessment demonstrates that Option 1 has the highest net market benefit under the base case reasonable scenario.

9.3 Sensitivity and scenario assessment

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 base case reasonable scenario. Specifically, UE has investigated changes in relation to:

Maximum demand levels;

Discount rate;

Cost of investments;

Value of customer reliability; and

Average Victorian spot price.

Table 22 presents the net market 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.

Table 22 – Net market benefits of each credible option (PV, $m)

Sensitivity Option 1 Option 2

Base case reasonable scenario: Base (expected) estimates 37.03 19.24

Discount rate: 8.5% 42.18 23.56

Discount rate: 10.5% 32.53 15.46

Cost of investment: Base estimate plus 10% 36.19 17.51

Cost of investment: Base estimate minus 10% 37.87 20.96

Value of customer reliability: Base estimate plus 15% 43.79 24.67

Value of customer reliability: Base estimate minus 15% 30.28 13.80

Average Victorian spot price: Base estimate plus 50% 37.10 19.28

Average Victorian spot price: Base estimate minus 50% 36.97 19.19

Demand forecast: Base estimates minus 5% at DMA31

17.92 1.15

31

This is equivalent 2-3 MW per annum lower than the base (expected) forecast at DMA.



The results above show that Option 1 has the highest net market benefit when changes to individual variables are considered.

As discussed earlier, examination of the sensitivity of net market benefits to change in a parameter or value within the base case reasonable scenario is essential to the development of additional reasonable scenarios involving different combination of assumptions. The results above demonstrate that the net market benefit of each option is most sensitive to changes in relation to:

Maximum demand level;

Value of customer reliability;

Discount rate; and

Cost of investments;

Accordingly, UE has defined additional reasonable scenarios to test the robustness of this RIT-D assessment. These scenarios contain plausible and mutually consistent combination of abovementioned key variables as shown in Table 23.

Table 23 – Reasonable scenarios considered in the economic evaluation


Base case Base Base Base Base

Scenario 1 Base Low Base Base

Scenario 2 Base Low High Low

Scenario 3 Base Low High High

Scenario 4 Base High Base Base

Scenario 5 Base High Low Low

Scenario 6 Base High Low High

Scenario 7 Low Base Base Base

Scenario 8 Low Low Base Base

Scenario 9 Low Low High Low

Scenario 10 Low High Base Base

Scenario 11 Low High Low Low



Table 24 presents the net market benefits in NPV terms for each option across all reasonable scenarios considered. The shaded cell in each row indicates the option that maximise the net market benefit under that particular reasonable scenario relative to ‘Do nothing’.

Table 24 – Net market benefits of each credible option under various scenarios (PV, $m)

Scenario

Do Nothing Option 1 Option 2

Net Market Benefit



Ranking

Base case 0 3 37.03 1 19.24 2

Scenario 1 0 3 30.28 1 13.80 2

Scenario 2 0 3 33.80 1 15.72 2

Scenario 3 0 3 25.62 1 8.89 2

Scenario 4 0 3 43.79 1 24.67 2

Scenario 5 0 3 50.56 1 31.40 2

Scenario 6 0 3 39.44 1 22.03 2

Scenario 7 0 3 17.92 1 1.15 2

Scenario 8 0 2 14.03 1 (1.58) 3

Scenario 9 0 2 15.66 1 (1.45) 3

Scenario 10 0 3 21.81 1 3.87 2

Scenario 11 0 3 26.04 1 8.18 2


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

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

Option 2 is found to have negative market benefit in some of the scenario analysis, particularly when the demand at DMA is 5% less than forecast. As a consequence, this option is ranked lower than the ‘Do Nothing’ option.

Under the RIT-D, the preferred option should maximise the present value of the net market benefits to all those who produce, consume and transport electricity in the National Electricity Market (NEM).32 This RIT-D assessment clearly demonstrates that Option 1 maximises net market benefit under all scenarios considered, therefore is considered the proposed preferred option to address the ‘identified need’.

32

AER. “Regulatory Investment Test for Distribution Application Guidelines”, Section 1.1. Available http://www.aer.gov.au/node/19146




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.

9.4 Economic timing

The previous section demonstrates Option 1 to be the proposed preferred option to address the ‘identified need’. Although the choice of the proposed preferred option is clear, the timing of this investment is not, given a number of reasonable scenarios are investigated. The economic timing of the proposed preferred option is when the annualised cost of lost load exceeds the annualised cost of the proposed preferred option.

Table 25 below shows the expected timing of the proposed preferred option under each reasonable scenario.

Table 25 – Expected timing of the proposed preferred option

Scenario Demand growth VCR Investment cost Discount rate Timing

Base case Base Base Base Base 2015-16

Scenario 1 Base Low Base Base 2016-17

Scenario 2 Base Low High Low 2016-17

Scenario 3 Base Low High High 2016-17

Scenario 4 Base High Base Base 2014-15

Scenario 5 Base High Low Low 2014-15

Scenario 6 Base High Low High 2014-15

Scenario 7 Low Base Base Base 2017-18

Scenario 8 Low Low Base Base 2018-19

Scenario 9 Low Low High Low 2018-19

Scenario 10 Low High Base Base 2016-17

Scenario 11 Low High Low Low 2014-15


The timing of the proposed preferred option is 2015-16 under the ‘base case’ reasonable scenario (i.e. under the most likely scenario).

There may be scope for deferring the proposed preferred option by one year if:



o The value of customer reliability is 15% lower than the base estimates.

There may be scope for deferring the proposed preferred option by two years if:

o The maximum demand at DMA is 5% per annum lower than base estimates – that is, the maximum demand at DMA is approximately 2-3 MW per annum lower than the forecast.

The proposed preferred option may be implemented earlier if:

o The VCR is 15% higher than the base estimates.

While the timing of the base case scenario is indicating a 2015-16 commissioning, it may not be physically possible to complete works by this time. Therefore the expected commissioning date of this option is no later than December 2016 which is consistent with the one-year deferral scenarios identified above.



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 market 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 has clearly demonstrates that Option 1 maximise the present value of net market benefits under all reasonable scenario considered. The preferred option for investment is therefore Option 1: Installation of the second DMA transformer plus two new distribution feeders and reconfiguration of the existing DMA distribution network. This option satisfies the RIT-D.

The total project cost, inclusive of operating costs, is estimated at $8.4 million (in present value terms).

While the economic timing is by December 2015, the expected commissioning date for this option is no later than December 2016.

The technical characteristics of the preferred option are presented below:

Install a new 20/33 MVA 66/22 kV transformer at Dromana zone substation.

Extension of the DMA 22 kV indoor bus with:

o One 22 kV transformer circuit breaker

o Four 22 kV feeder circuit breakers

o One 22 kV capacitor circuit breaker

o One 22 kV bus-tie circuit breaker

Upgrading of existing protection and control schemes.

Developing two new 22 kV distribution feeders to supply the existing load in and around the Dromana area, including rearrangement works.

The proposed single line arrangement for the preferred option is shown in Figure 13.



Figure 13 – Proposed single line arrangement



11 Submission

11.1 Request for submission

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

All Submissions and enquiries should be directed to the United Energy Manager Network Planning at [email protected].

Submissions are due on or before 26 September 2014.

All submissions will be published on UE website.33

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 in November 2014.

33

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

mailto:[email protected]



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 4.2

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



13 Abbreviations and Glossary

Abbreviations

AEMO Australian Energy Market Operator

DAPR Distribution Annual Planning Report

DPAR Draft Project Assessment Report

DSED Demand Side Engagement Document

FPAR Final Project Assessment Report

NEM National Electricity Market

NER National Electricity Rules

NNOR Non Network Options Report

PoE Probability of Exceedance

RIT-D Regulatory Investment Test for Distribution

UE United Energy Distribution Pty Ltd

VCR Value of Customer Reliability



Glossary

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).

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.



Appendix A

Base (expected) maximum demand forecast

Option 1

Year Market benefit (PV)

Changes in involuntary load shedding

Changes in network losses Total

2014-15 695,792 32,480 728,272

2015-16 851,781 35,036 886,818

2016-17 1,180,839 37,703 1,218,542

2017-18 1,685,900 40,481 1,726,380

2018-19 1,973,419 40,910 2,014,330

2019-20 2,372,789 41,407 2,414,195

2020-21 3,143,053 41,853 3,184,906

2021-22 4,240,500 42,264 4,282,764

2022-23 5,640,217 42,661 5,682,878

2023-24 7,286,094 43,164 7,329,258

Option 2




2014-15 (31,326) 19,739 (11,586)

2015-16 103,934 21,472 125,406

2016-17 412,433 23,286 435,719

2017-18 902,581 25,153 927,734

2018-19 1,184,688 27,212 1,211,901

2019-20 1,571,903 27,917 1,599,820

2020-21 2,329,055 28,509 2,357,564

2021-22 3,413,730 29,045 3,442,775

2022-23 4,797,058 29,554 4,826,611

2023-24 6,416,712 30,194 6,446,906



Low maximum demand forecast

Option 1




2014-15 608,929 28,889 637,817

2015-16 670,870 31,155 702,024

2016-17 768,436 33,518 801,955

2017-18 903,362 35,980 939,342

2018-19 1,065,439 36,358 1,101,797

2019-20 1,335,726 36,794 1,372,520

2020-21 1,684,155 37,186 1,721,341

2021-22 2,151,017 37,546 2,188,563

2022-23 3,023,736 37,894 3,061,631

2023-24 4,217,051 38,344 4,255,395

Option 2




2014-15 (122,769) 16,878 (105,890)

2015-16 (78,548) 18,436 (60,111)

2016-17 33,630 20,041 53,671

2017-18 228,562 21,690 250,252

2018-19 382,484 22,251 404,736

2019-20 645,025 22,947 667,972

2020-21 983,943 23,528 1,007,471

2021-22 1,439,005 24,054 1,463,059

2022-23 2,301,492 24,554 2,326,045

2023-24 3,483,647 25,157 3,508,804

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