132 KV Transmission System Australia

ElectraNet Corporate Headquarters 52-55 East Terrace, Adelaide, South Australia 5000 • PO Box, 7096, Hutt Street Post Office, Adelaide, South Australia 5000

Tel: (08) 8404 7966 • Fax: (08) 8404 7104 • Toll Free: 1800 243 853

Templers Supply Augmentation Regulatory Test Application Notice

October 2009

Version 1.1

TEMPLERS SUPPLY AUGMENTATION October 2009

ElectraNet Pty Ltd

Copyright and Disclaimer

This Application Notice has been prepared for the purposes of clause 5.6.6 of the National Electricity Rules. It may be used by Registered Participants and interested parties only for the purposes of the consultation process under that clause. This Application Notice should not be used or relied on for any other purposes. The contents of this Application Notice may differ from the contents of the preceding application notice.

This Application Notice contains analysis based on estimates prepared by, and assumptions made by, ElectraNet and ETSA Utilities. The document has also been prepared using information, including cost information, provided by a number of third parties. The cost estimates used to evaluate the options described are based on the best information available to ElectraNet and ETSA Utilities at the time of preparing the report and should not be taken as necessarily reflecting the actual costs of later implementing an option.

The Application Notice contains the results of financial modelling and economic analysis undertaken by ElectraNet and ETSA Utilities. It contains assumptions regarding, among other things, economic growth and load forecasts that may or may not prove to be correct.

While care was taken in preparation of the information in this Application Notice, and it is provided in good faith, neither ElectraNet nor ETSA Utilities warrant the accuracy of the contents of this Application Notice, and so far as the law allows accept no responsibility or liability for any loss or damage that may be incurred by any person acting in reliance on this Application Notice or assumptions drawn from it.

.

t.


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Contents

EXECUTIVE SUMMARY .......................................................................................................3

1. INTRODUCTION ........................................................................................................4

2. BACKGROUND: ELECTRICITY SUPPLY SYSTEM ...............................................5

2.1 GEOGRAPHIC AREA .......................................................................................................... 5

2.2 EXISTING SUPPLY ARRANGEMENTS ................................................................................... 5

2.3 COMMITTED NETWORK DEVELOPMENTS ............................................................................ 5

2.4 EXISTING AND COMMITTED GENERATION FACILITIES........................................................... 5

3. BACKGROUND: ELECTRICITY DEMAND..............................................................8

3.1 OVERVIEW........................................................................................................................ 8

3.2 LOAD FORECAST .............................................................................................................. 8

3.3 PATTERN OF USE............................................................................................................11

4. ELECTRANET’S SERVICE OBLIGATIONS ...........................................................13

4.1 NATIONAL ELECTRICITY RULES........................................................................................13

4.2 SOUTH AUSTRALIAN ELECTRICITY TRANSMISSION CODE ..................................................13

5. PROJECTED NETWORK LIMITATIONS ................................................................16

5.1 VOLTAGE LIMITATIONS AT TEMPLERS AND DORRIEN..........................................................16

5.2 THERMAL RATING OF THE 132 KV TRANSMISSION SYSTEM ................................................17

6. ADDRESSING LIMITATIONS: OPTIONS CONSIDERED ......................................19

7. TECHNICAL DETAILS ............................................................................................20

7.1 FUTURE NETWORK DEVELOPMENTS – MID NORTH REGION ..............................................20

7.2 OPTION 1 – TEMPLERS WEST 275/132 KV SUBSTATION...................................................21

7.3 OPTION 2 – CAPACITOR BANKS AT TEMPLERS FOLLOWED BY 132 KV REINFORCEMENT ......28

7.4 OPTION 3 – GENERATION SUPPORT FOLLOWED BY 275/132 KV INJECTION AT TEMPLERS WEST............................................................................................................34

8. SCENARIOS CONSIDERED ...................................................................................43

8.1 CONTEXT FOR EVALUATION OF OPTIONS..........................................................................43

8.2 ASSUMED MARKET DEVELOPMENT SCENARIOS................................................................43


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9. FORMAT AND INPUTS TO ANALYSIS ..................................................................45

9.1 REGULATORY TEST REQUIREMENTS................................................................................45

9.2 INPUTS TO ANALYSIS.......................................................................................................45

9.3 COST OF NETWORK AUGMENTATIONS..............................................................................45

9.4 OTHER INPUTS TO ANALYSIS ...........................................................................................45

10. ECONOMIC ANALYSIS...........................................................................................47

10.1 OTHER INPUTS TO ANALYSIS ...........................................................................................47

10.2 RESULTS OF ANALYSIS....................................................................................................47

10.3 SENSITIVITY ANALYSIS ....................................................................................................48

10.4 INTER-NETWORK IMPACT.................................................................................................49

11. CONSTRUCTION TIMETABLE AND COMMISSIONING DATE.............................50

12. COMPLIANCE WITH SERVICE OBLIGATIONS ....................................................51

13. SUMMARY AND CONCLUSIONS...........................................................................52

14. DRAFT RECOMMENDATION .................................................................................53

15. CONSULTATION .....................................................................................................54

16. GLOSSARY .............................................................................................................55

APPENDIX A NPV ANALYSIS – LOW GROWTH SCENARIO..........................................57

APPENDIX B NPV ANALYSIS – MEDIUM GROWTH SCENARIO....................................60

APPENDIX C NPV ANALYSIS – HIGH GROWTH SCENARIO .........................................63


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Executive Summary

ElectraNet is required to meet the supply reliability standards and quality of supply standards specified in the South Australian Electricity Transmission Code (ETC) and National Electricity Rules (NER) respectively.

ElectraNet has identified emerging limitations within the transmission system that supplies the Templers, Dorrien and Roseworthy connection points, referred to as the Barossa area of the Mid-North region of South Australia within this Application Notice. As a consequence of ongoing load growth within the Barossa area, ElectraNet will be unable to satisfy the NER requirement to maintain adequate voltages under peak load contingency conditions at the Templers, Dorrien and Roseworthy connection points without interrupting load after the summer of 2009/10.

In addition, the 1 July 2008 Electricity Transmission Code upgraded the reliability standard that applies to the Templers and Dorrien connection points. The upgraded standard requires continuous N-1 transmission line and transformer capacity into the Templers and Dorrien connection points by no later than 30 June 2011. Therefore, interruption of supply at either of these connection points as a result of a single contingency will no longer be acceptable.

In order to resolve these limitations, ElectraNet has developed a number of potential solutions and applied the Regulatory Test for reliability augmentations to determine the least cost net present value solution. From this assessment, the recommendation of this Application Notice that a new 275/132 kV substation, to be known as Templers West, be established adjacent to ElectraNet’s existing Templers 132/33 kV substation at an estimated cost of $36.6m. This substation would feed directly into the existing Dorrien 132/33 kV substation by modifying the existing Roseworthy – Dorrien 132 kV transmission line.


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1. Introduction

ElectraNet has identified emerging limitations at the Templers and Dorrien connection points in the Mid-North region of South Australia, including the inability to satisfy the National Electricity Rules (NER) requirement to maintain adequate voltages under peak load contingency conditions at the Templers, Dorrien and Roseworthy connection points after the summer of 2009/10 without interrupting load.

In addition, the supply reliability standard for the Templers and Dorrien connection points was upgraded in the 1 July 2008 Electricity Transmission Code (ETC).

In upgrading the standard, ESCOSA changed the load category of the Templers and Dorrien connection points from Category 3 to Category 4. The result of this change is a requirement to provide continuous N-1 equivalent transmission line and transformer capacity into Templers and Dorrien for at least 100% of the agreed maximum demand of each connection point by no later than 30 June 2011. Therefore, interruption of supply as a result of a single contingency event is no longer acceptable. Consequently, low voltage conditions caused by single transmission line outages can not be managed under the current system configuration. To resolve these limitations, ElectraNet is proposing to establish a new large network asset to meet the reliability standards and maintain security of supply within the area.

The proposed new large network asset is estimated to cost in excess of $20m. Therefore, this ‘Application Notice’ is issued in accordance with clause 5.6.6 of the NER, which requires the following information to be provided:

• the reasons the augmentation is required, including, if relevant, why it is considered a ‘reliability augmentation’, as defined in the NER;

• feasible options available to address the future supply requirements, including non-network alternatives;

• the recommended solution, including the timetable for implementation; and

• why the solution satisfies the Regulatory Test prescribed by the AER.

This document addresses these NER requirements.


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2. Background: Electricity Supply System

2.1 Geographic Area

The Mid-North region of South Australia is located north of the city of Adelaide, extending east to Robertstown, north to Port Augusta, and includes York Peninsula to the west. This geographic region is shown in Figure 1. The limitations addressed by this Application Notice affect the Templers, Dorrien and Roseworthy connection points within the southern portion of this region between the Para and Waterloo substations, referred to in this report as the Barossa area.

2.2 Existing Supply Arrangements

Loads within the Mid-North region are supplied via a 132 kV transmission network. 275/132 kV substations at Bungama, Brinkworth, Robertstown and Para inject into this network from the main 275 kV transmission system.

Supply to the Templers, Dorrien and Roseworthy connection points is provided via the Para-Roseworthy and the Templers-Waterloo 132 kV transmission lines. Of these two transmission paths, the Para-Roseworthy 132 kV line is the stronger supply due to the 275/132 kV injection at Para Substation. These arrangements are shown in Figure 2.

2.3 Committed Network Developments

ElectraNet is not aware of any committed transmission or sub-transmission network developments planned for the Mid-North region of South Australia that will impact on the emerging limitations in the supply to the Templers, Dorrien and Roseworthy connection points.

2.4 Existing and Committed Generation Facilities

A number of generation facilities, including wind farms, are connected to the Mid-North 132 kV transmission system, including Mintaro Power Station, Wattle Point Wind Farm and Snowtown Wind Farm. In addition to these generation facilities, Hallet Power Station and Brown Hill Wind Farm are connected to the 275 kV network at Canowie, and Angaston Power Station is connected to the ETSA Utilities distribution system at Angaston. Angaston substation is connected to Dorrien substation via two 33 kV lines. Furthermore, approximately 1.5 MW of embedded generation is connected to the transmission system via Roseworthy substation.


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There are currently numerous wind farms under consideration in the Mid-North region. Hallet Hill Wind Farm and Clements Gap Wind Farm are expected to be connected to the transmission system within this region in the near future. There are, however, no other committed sources of thermal generation within the region of which ElectraNet is currently aware.

Figure 1: Mid-North Geographic Region


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Figure 2: Existing transmission system: Mid-North region


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3. Background: Electricity Demand

3.1 Overview

The demand forecasts that underpin the recommendations of this Application Notice are consistent with the ten-year demand and energy forecasts published in ElectraNet’s Annual Planning Review 2009 and the ESIPC’s Annual Planning Report for 2009.

Electricity demand forecasts over a ten-year period are obtained from ETSA Utilities and directly connected customers at each connection point on ElectraNet’s transmission system. Those forecasts take account of demand-side management programmes in-place and foreseen by ETSA Utilities, and embedded generation within ETSA Utilities’ network which may have the effect of reducing the forecast demand to be supplied via each transmission connection point.

3.2 Load Forecast

The growth in electrical load in a region is dependent on many variables, including economic growth, housing and commercial development, industrial growth, spot-load increases that occur in response to local development, and environmental conditions (predominantly weather conditions). The forecasting of electrical load is based on econometric analysis coupled with knowledge of localised developments, historical information and trends. The load forecast provided in this section is based on a 10% probability of exceedance and medium economic growth.

The electrical load in the Mid-North region comprises a diverse mixture of residential, industrial, agricultural, grazing, aquaculture and viticulture loads. Commercial loads contribute a significant portion of the total load at the major centres of Port Pirie, Kadina, Port Wakefield, Clare and in the Barossa Valley. The supply limitations addressed by this Application Notice are entirely located within the Barossa Valley area which is supplied from the Templers and Dorrien connection points

Demand forecasts issued by ETSA Utilities for the Mid-North supply area indicate an overall load growth of approximately 2.7% per annum for the foreseeable future, as indicated in Table 1. Load growth at the Templers and Dorrien connection points is projected to be about 3.0% at each connection point for the foreseeable future. The Templers and Dorrien load forecasts are also shown in Table 1.


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A significant step change in the load at Templers connection point is evident between 2007/08 and 2008/09, as shown in Table 1. During this time, the peak load at Templers increased by 16% in a single year. Furthermore, the forecast rate of load growth for the Templers connection point has also increased. In 2007/08, the forecast load growth at the Templers connection point was 2.5%. As discussed above, this rate of load growth has increased to 3% under the 2009 medium economic growth load forecast.

Dorrien has experienced a slight decrease in the rate of load growth since 2007/08, with load growth at this connection point easing to 1.9% between 2007/08 and 2008/09 from a forecast 3.2%. The ongoing load growth at Dorrien connection point is forecast at 3.0% under the 2009 medium economic load growth forecast, as previously discussed.

A step change in load has also occurred at the Roseworthy connection point. Despite the easing of load growth at Dorrien, the increased load growth at Templers and Roseworthy has brought forward the emerging limitations within the transmission supply to the Barossa area compared to projections based on the 2008 load forecast.


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22/2

3

434.

4

462.

5

44.5

49.6

97.4

108.

8

21/2

2

422.

6

449.

5

43.2

48.1

94.6

105.

5

20/2

1

411.

3

436.

3

42.0

46.6

91.8

102.

3

19/2

0

400.

3

423.

6

40.8

45.2

89.1

99.1

18/1

9

389.

7

411.

5

39.6

43.8

86.5

96.1

17/1

8

379.

5

399.

6

38.4

42.5

84.0

93.1

16/1

7

369.

7

388.

2

37.3

41.2

81.6

90.3

15/1

6

360.

2

377.

2

36.2

39.9

79.2

87.5

14/1

5

351.

0

366.

6

35.2

38.7

76.9

84.8

13/1

4

342.

2

356.

4

34.1

37.5

74.7

82.2

12/1

3

333.

6

347.

8

33.1

36.3

72.5

80.9

11/1

2

325.

4

338.

3

32.2

35.2

70.4

78.5

10/1

1

317.

5

329.

1

31.2

34.1

68.3

76.1

09/1

0

312.

4

323.

5

30.3

33.0

66.3

73.7

08/0

9

301.

9

311.

3

29.4

32.4

64.4

71.5

07/0

8

285.

1

296.

8

25.4

28.2

63.2

68.7

MW

MVA

MW

MVA

MW

MVA

Con

nect

ion

Poin

t

Mid

-Nor

th

Tem

pler

s

Dor

rien

Table 1: Forecast Peak Demand: Templers and Dorrien connection points and Total Mid-North Region (medium economic growth)


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3.3 Pattern of Use

The peak electricity demand in the Mid-North supply area occurs during the summer months of the year, with only a small amount of diversity existing between different areas within the region. This lack of diversity means that the transmission system must be capable of supplying the total peak demand in the Mid-North region simultaneously.

Figure 3 shows the annual load duration curve for the combined Templers, Dorrien and Roseworthy connection points, and Figure 4 provides the recorded daily load curves for both the summer peak load day during 2008/09 and the winter peak load day during 2008 for the Dorrien and Templers connection points.

Templers, Dorrien and Roseworthy Load Duration Curve 2008/09

0

10

20

30

40

50

60

70

80

90

100

0 10 20 30 40 50 60 70 80 90 100

Time (%)

% M

axim

um L

oad

Figure 3: Cumulative Load Duration Curve for the Templers, Dorrien and Roseworthy connection points 2008/09


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Templers and Dorrien Peak Demand Days

0

10

20

30

40

50

60

70

80

0:30

1:30

2:30

3:30

4:30

5:30

6:30

7:30

8:30

9:30

10:3

0

11:3

0

12:3

0

13:3

0

14:3

0

15:3

0

16:3

0

17:3

0

18:3

0

19:3

0

20:3

0

21:3

0

22:3

0

23:3

0

Time

MVA

Dorrien Summer Peak (29/01/2009) Templers Summer Peak (29/01/2009)

Dorrien Winter Peak (29/7/2008) Templers Winter Peak (29/7/2008)

Figure 4: Typical daily load profiles for Templers and Dorrien connection points during summer 2008/09 and winter 2008

The load duration curve for the combined Templers, Dorrien and Roseworthy connection points indicates that high loads occur for relatively short periods of time and that the load only exceeds 70% of the peak value for about 3% of the year. The average load for the combined Templers, Dorrien and Roseworthy connection points is approximately 50% of the peak load, which is typical of a load with a high commercial contribution.

The daily summer load curve for the Dorrien connection point exhibits a peak between the hours of 11:00 am and 6:00 pm, which is indicative of a high proportion of commercial load during the summer months. The daily summer load curve for the Templers connection point exhibits a similar pattern, with the peak occurring slightly later in the day. This demonstrates a higher residential bias in the Templers load, although the commercial component is still a major constituent.

The winter daily load curves display relatively steady loads during business hours, with a significant peak towards the end of the business day. This is symptomatic of commercial and residential heating loads on a cold winter day, which would commence at the start of the business day (around 8:00 am) and continue to close-of-business at around 5:30 pm. At that stage, domestic electric heating and cooking would become prominent. There is a further peak that is seen on both the summer and winter daily load curves that covers the hours of 11:00 pm to 1:00 am. This is indicative of a high usage of electrical energy to heat water during that ‘J’ tariff, or off peak period.


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4. ElectraNet’s Service Obligations

ElectraNet is required to meet the supply reliability standards and quality of supply standards specified in the South Australian Electricity Transmission Code (ETC) and National Electricity Rules (NER) respectively.

4.1 National Electricity Rules

As discussed previously in this Application Notice, the July 2008 ETC requires continuous N-1 equivalent transmission line transformer capacity at the Templers and Dorrien connection points for at least 100% of agreed maximum demand. That requirement aligns with the intent of Schedule 5.1.2.1 of the NER, ‘Credible contingency events’, that states, in part, that ElectraNet, as a Network Service Provider, must plan, design, maintain, and operate its transmission network to allow the transfer of power from generating units to customers with all facilities or equipment associated with the power system in service, and “may be required by a Registered Participant under a connection agreement to continue to allow the transfer of power with certain facilities or plant associated with the power system out of service”; that is, under N-1 conditions.

The NER also requires in Schedule 5.1.4, that “at all times the supply voltage remains between 90 percent and 110 percent of the normal voltage determined in accordance with clause S5.1a.4 except as a consequence of a contingency event”.

During a contingency, it is accepted that transmission system voltages may be several percent lower than those obtained under normal operating conditions. For planning purposes, a target value of 90% of nominal voltage is typically applied. Voltages below this limit would prevent nominal voltages from being restored at the customer level after transformer tap changing.

4.2 South Australian Electricity Transmission Code

The following relevant service standards are contained in the ETC.

Clause 2.1 Quality of supply and system reliability

2.1.1 Quality of supply

A transmission entity shall use its best endeavours to plan, develop and operate the transmission network to meet the standards imposed by the National Electricity Rules in relation to the quality of transmission services such that there will be no requirements to shed load to achieve these standards under normal and reasonably foreseeable operating conditions.

2.1.2 System reliability

A transmission entity shall use its best endeavours to plan, develop and operate the transmission system so as to meet the standards imposed by the National Electricity Rules in relation to transmission network reliability such that there will be minimal requirements to shed load under normal and reasonably foreseeable operating conditions.


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The ETC also assigns reliability standards for each connection (exit) point or group of connection points within the transmission network and thereby imposes specific requirements on ElectraNet for planning and developing its transmission network. The ETC includes additional obligations with regard to response times, spares holdings, and reporting requirements. The following provides a summary of ElectraNet’s service obligations for the Templers and Dorrien connection points based on the ETC requirements (refer Clause 2.8 of the July 2008 ETC).

Before 1 July 2008, ElectraNet was required to…

• not contract for an amount of agreed maximum demand greater than 100% of installed transmission line or transformer capacity;

• provide N-1 equivalent transmission line capacity and N-1 equivalent transformer capacity for at least 100% of agreed maximum demand by whatever means including distribution capability, generation, load interruptability or any combination thereof. This implies a non-continuous supply is acceptable to meet this requirement.

• in the event of a transmission line or transformer failure, use best endeavours to restore contracted line or transformer capacity within two days of an interruption in the case of a line failure, or four days in the case of a transformer failure.

After 1 July 2008, ElectraNet must…

• not contract for an amount of agreed maximum demand greater than 100% of installed transmission line capacity or installed transformer capacity;

• provide N-1 equivalent transmission line and transformer capacity at the Templers and Dorrien connection points for at least 100% of agreed maximum demand;

• use best endeavours to restore transmission line capacity within 12 hours of an interruption; and

• in the event of a transformer failure, use best endeavours to repair the installed transformer or install a replacement transformer as soon as possible so as to minimise the likelihood of an interruption as a result of the failure of any other transformer also supplying that same connection point.

In addition, after 1 July 2008, ElectraNet must…

• in the event that agreed maximum demand at the Templers or Dorrien connection point exceeds the equivalent line capacity or equivalent transformer capacity standards specified above, use its best endeavours to ensure that the line capacity or transformer capacity into the Mid-North region meets the required standards in 12 months, and in any case, within 3 years.

The 1 July 2008 revised ETC defines N-1 as “the ability of the transmission system to continue to supply the contracted amount of agreed maximum demand connected to the transmission system without interruption should any one element fail (typically an outage of a transmission line or transformer). N-1 capacity may be


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provided by means including by implementation of transmission network capability and / or network support arrangements”.

The 1 July 2008 ETC can be viewed in its entirety at the following website:

http://www.escosa.sa.gov.au/webdata/resources/files/060906-R-ElecTransCodeET05.pdf


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5. Projected Network Limitations

ElectraNet has undertaken analysis of the electricity transmission system that supplies the Templers, Dorrien and Roseworthy connection points and identified a number of emerging network limitations. There are two principal issues that need to be addressed for these connection points: the 132 kV supply voltage in the area under the loss of the Para – Roseworthy 132 kV transmission line at times of peak load, and the thermal rating of the Templers – Waterloo and Para – Roseworthy 132 kV transmission lines and the Para 275/132 kV transformer under peak load N-1 conditions.

5.1 Voltage limitations at Templers and Dorrien

Beyond 2009/10, at times of peak load in the Mid-North region of South Australia, an outage of the 132 kV transmission line from Para substation to Roseworthy substation will result in 132 kV voltages below 90% of nominal at Roseworthy substation. Without augmentation to the transmission system, 132 kV voltages at Dorrien and Templers substations will also fall below 90% of nominal under outage conditions in subsequent years. ElectraNet has under-voltage load-shedding systems in place to ensure system security under these conditions. However, the ETC stipulates that ElectraNet must use best endeavours to ensure that the transmission system maintains voltages within the requirements of the NER under credible contingency conditions without the need for load shedding. Therefore, a reliability augmentation is required to address this emerging limitation.

Voltage excursions under a credible contingency must be in accordance with S5.1a.4 and S5.1.4 of the NER. As discussed earlier, the NER requires that the supply voltage remain between 90% and 110% of the nominal voltage under normal operating conditions.


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5.2 Thermal rating of the 132 kV transmission system

In addition to voltage support issues, the 132 kV network in the Mid-North region that supplies the Templers, Dorrien and Roseworthy connection points is subject to thermal capacity constraints. This adds to the need for the proposed reliability augmentation.

Under contingent conditions, the Templers, Dorrien and Roseworthy connection points may be supplied radially from either Para or Waterloo substation. During such outage conditions, the total load that can be supplied by the transmission system is limited to 141 MVA by the thermal rating of either the Templers – Waterloo or the Para – Roseworthy 132 kV transmission lines. However, other limitations at Waterloo substation limit the possible power transfer via the Templers – Waterloo 132 kV line to 112 MV.A. This means that the effective N-1 capacity of this network is 112 MV.A. Figure 5 shows the N-1 capacity of the 132 kV transmission system that supplies the Barossa area and the forecast load growth at the Templers, Roseworthy and Dorrien connection points. From this graph it is evident that, beyond 2008/09, ETC compliant supply to the Barossa area will no longer be possible with the current system configuration.

The Para 275/132 kV transformer feeds both the Mid-North and the Eastern Hills transmission regions of South Australia. If, during times of peak load under the existing system configuration, an outage of the Templers - Waterloo 132 kV line occurs, pumping loads in the Eastern Hills region will need to be constrained to prevent the overloading of this transformer. Similarly, the two Robertstown 275/132 kV transformers feed both the Mid-North and the Riverland regions of South Australia. At times of peak load, an outage of one of the Robertstown 275/132 kV transformers will require Murraylink transfer (import or export) to be constrained to prevent the overloading of the remaining transformer.

In order to avoid these constraints, and satisfy the ETC reliability standards at the Templers, Dorrien and Roseworthy connection points, augmentation of the transmission system is necessary.


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Load at Templers, Dorrien and Roseworthy vs N-1 Capacity (loss of the Para - Roseworthy 132kV line)

0

20

40

60

80

100

120

140

160

180

200

07/08 08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25

Year

MV.

A

Total load at Templers, Dorrien and Roseworthy N-1 Capacity

Figure 5: Total load in the Barossa area vs. N-1 Capacity of the 132kV transmission system


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6. Addressing Limitations: Options Considered

ElectraNet considers both network and non-network options for addressing emerging network limitations.

In this particular case demand side management, generator network support and transmission network options were investigated.

The negotiation of demand side management agreements with high demand customers within the Barossa area would delay the need for reinforcement to the transmission system. The extent of this delay would be dependant upon the amount of load that is available for shedding under contingency conditions. Any demand side management initiative would only act as an interim measure and reinforcement of the transmission system would ultimately still be required due to ongoing load growth within the region.

In order to assess potential demand side management opportunities within the Barossa area, ElectraNet requested that ETSA Utilities contact its customers on ElectraNet’s behalf in order to determine whether there were any interested parties. ElectraNet also discussed demand side management strategies with a direct connect customer within the area. None of the parties contacted expressed an interest in participating in a demand side management scheme.

The option of establishing a generator network support agreement with an existing generator within the Barossa area was examined by ElectraNet.

Several transmission network options were also developed for augmentation of the electricity supply to the Barossa area.

Finally the following three options were subjected to the Regulatory Test for reliability augmentations:

1. 275 /132 kV injection at a greenfields site adjacent to the existing Templers 132 /66 kV substation feeding directly into the existing Dorrien 132/33 kV substation;

2. the installation of capacitor banks at Templers 132/ 66 kV substation followed by 132 kV network reinforcement; and

3. the establishment of a transmission network support contract utilising the existing Angaston Power Station and applying augmentations to the 132 kV network in the Mid-North region as required.

These options are considered in more detail in sections 7.2, 7.3 and 7.4 of this Application Notice.


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Option 1 – Templers West 275/132 kV substation

Date required Proposed Augmentation Total capital cost (in $2009)

2011-12

Establish Templers West 275/132 kV substation with a single 160 MV.A 275/132 kV transformer feeding directly into Dorrien 132/33 kV substation.

$36.6m

2020-21 Install a 12 Mvar capacitor bank at Roseworthy 132kV substation.

$5.1m

2024-25 Install a second 160 MV.A 275/132 kV transformer at Templers West 275/132 kV substation feeding directly into Dorrien 132/33 kV substation. Replace aged disconnectors, secondary systems, telecommunication systems and bus at the existing Templers 132/33 kV substation.

$23.6m

Table 3: Proposed augmentations associated with Option 1.


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Figure 6: Option 1, Stage 1 - 275 kV injection at Templers West


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Figure 7: Option 1, Stage 2 - 275kV injection at Templers West


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7.2.1 Transformer Capacity

The ultimate network configuration proposed by this option would result in the entire load at Dorrien substation being supplied via two 275/132 kV transformers at Templers West substation. Under this configuration, the 160 MV.A transformers at Templers West would be adequate to supply the load at Dorrien under N-1 conditions until 2041/42. The existing 132 kV transmission lines that supply Dorrien, however, will only be adequate until 2032/33, at which time additional transmission line capacity will be required into the area. Furthermore, since Dorrien substation has significant space constraints, this transmission capacity must be sourced from a new substation. For this reason, the selection of 160 MV.A transformers at Templers West 275/132 kV substation is considered prudent given the existing network infrastructure.

7.2.2 Scope of Works

The initial stage of works would require the installation of the following primary plant at Templers West 275/132 kV substation, as shown in Figure 8:

• One 160 MV.A 275/132 kV transformer;

• Three 275 kV circuit breakers; and

• One 132 kV circuit breaker.

Minor works would also be required at the existing Templers 132/33 kV substation during the initial stage of Option 1, as shown in Figure 9. One circuit breaker at Templers 132/33 kV substation requires replacing in order to re-establish the previously abandoned Roseworthy exit using part of the Roseworthy-Dorrien 132 kV transmission line. The remainder of this line would then be used to establish a connection from the 275/132 kV transformer via a 132 kV circuit breaker at Templers West substation to Dorrien substation.

The second stage of Option 1 involves the addition of a 12 Mvar capacitor bank at Roseworthy 132/11 kV substation. This stage would require the following primary plant:

• Three 132 kV circuit breakers at Roseworthy substation; and

• 12 Mvar 132 kV capacitor bank at Roseworthy substation.

The third stage of Option 1 involves the installation of the following primary plant at Templers West 275/132 kV substation, as shown in Figure 8:

• A second 160 MV.A 275/132 kV transformer;




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The existing Templers-Dorrien 132 kV transmission line would then be used to connect the second 275/132 kV transformer via a 132 kV circuit breaker at Templers West substation to Dorrien substation. This arrangement is shown in Figure 6.


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Figure 8: Option 1: Templers West substation layout

Figure 9: Option 1: Required works at the existing Templers 132/33 kV substation


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7.3 Option 2 – Capacitor banks at Templers followed by 132 kV reinforcement

This option proposes delaying major works in the Barossa area by installing capacitor banks at the existing Templers 132/33 kV substation for voltage support. The addition of capacitor banks to the existing Templers substation would require a complete rebuild of that substation to accommodate the new plant and equipment. Since Templers substation requires rebuilding, the opportunity would be taken to turn the existing Roseworthy-Dorrien 132 kV line in and out of Templers substation, thus saving on network losses. These works would then be followed by augmentation of the 132 kV network once the reactive support of the installed capacitor banks is exhausted.

Table 4 provides the required timing for each of the stages for this option and the estimated capital cost of each stage over the 20 year planning period. Schematic representations of the three stages of Option 2 are shown in Figure 10, Figure 11 and Figure 12.

Option 2 – Capacitor banks at Templers followed by 132 kV reinforcement

Date required Proposed Augmentation Total capital cost (in $2009)

2011/12 Rebuild Templers 132 kV yard at Templers West with 2x15 Mvar 132 kV capacitor banks. Turn Roseworthy – Dorrien 132 kV line in and out of Templers.

$25.2m

2012/13 Install a 2nd 275/132 kV transformer with a 200 MV.A rating at Para substation and construct a new 132 kV line from Para to Templers.

$34.4m

2026/27 Rebuild the Templers – Waterloo 132 kV line as double circuit with the second circuit bypassing Waterloo and connecting to Robertstown substation

$31.9m

Table 4: Proposed augmentations associated with Option 2


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Figure 10: Option 2, Stage 1 - 132 kV reinforcement


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The 275/132 kV 160 MV.A transformer specified for Option 2 would be installed parallel to the existing 275/132 kV 160 MV.A transformer at Para substation. Because the N-1 transformer capacity at a given two transformer substation is equal to the lowest rated transformer installed, and the existing 275/132 kV transformer at Para has a significant service life remaining, it is difficult to justify installing a transformer with higher rating than 160 MV.A. Furthermore, ElectraNet has system spares available for this size transformer. Thus a replacement would be readily available if a transformer at Para failed. For these reasons, the selection of a 160 MV.A 275/132 kV transformer was considered prudent for this option.


The first stage of works required for Option 2 involves the construction of Templers West 132/66 kV substation including 2x15 Mvar capacitor banks adjacent to the existing Templers substation. The existing transformers at Templers substation would be left in place and connected into the new Templers West substation and the remainder of the old Templers yard would be removed. Templers West substation would initially be built as a three diameter 1½ breaker substation with two capacitor bank bays. The substation layout will be designed to allow for a further 1½ breaker diameter during later stages of development. This arrangement, as shown in Figure 13, would require the following primary plant at Templers West substation:

• Eleven 132 kV circuit breakers; and

• Two 15 Mvar 132 kV capacitor banks.

The second stage of works required for Option 2, three years after the initial stage, involves the addition of a second 275/132 kV transformer at Para substation, as shown in Figure 15, and the addition of a new 132 kV transmission line from Para substation to Templers substation, as shown in Figure 11. The construction of the new line would be partially achieved by rebuilding the existing Para to Roseworthy 132 kV transmission line as a double circuit 132 kV line.

The second stage of works would require the following primary plant, as shown in Figure 13, Figure 14 and Figure 15:

• Two 132 kV circuit breakers at Templers West substation;

• Five 132 kV circuit breakers at Para substation;

• Two 275 kV circuit breakers at Para substation; and

• A single 275/132 kV 200 MV.A transformer at Para substation.

Further reinforcement would then be required in 2026/27 to prevent the overloading of the remaining Para 275/132 kV transformer after the loss of the first 275/132 kV transformer and also to prevent the overloading of the Para-Roseworthy 132 kV line after the loss of the new Para-Templers 132 kV line. The option includes rebuilding of the Templers-Waterloo 132 kV line as a double circuit line at this stage as it resolves both of these issues. This arrangement is shown in Figure 12 while the works required at Templers West substation is shown in Figure 14.


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Figure 13: Option 2 Stage 1 - works at Templers West substation

Figure 14: Option 2 Stage 2 - works at Templers West substation


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Figure 15: Option 2 Stage 2 - works at Para substation

7.4 Option 3 – Generation support followed by 275/132 kV injection at Templers West

This option proposes the use of Angaston Power Station, an existing generator connected to ETSA Utilities’ Angaston substation, for network support to defer the requirement for major expenditure on new transmission assets. Once adequate reactive margins are no longer available within the Barossa area with generation network support running, a transmission 275/132 kV injection solution would then be required at Templers West as described in Option 1. 275/132 kV injection at Templers West was selected for this option over further reinforcement of the 132 kV system within the area due to the clear cost advantages presented by this solution during early stages of development.

When Angaston Power Station is dispatched for network support purposes, the generators would be required to stay on-line for planned and unplanned N-1 outages. However, current operating practice requires that the power station shuts down and does not allow any machine starts once supply to the Barossa is radialised.


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The existing 132 kV transmission network between Para substation and Waterloo substation utilises three-pole circuit breakers. Under single phase fault conditions, three-pole circuit breakers trip the entire line and then lock open. Patrolling of the faulted line is then necessary before the line may be restored. If these three-pole circuit breakers are replaced by single-pole circuit breakers, only the faulted phase will be tripped and then restored once the fault is cleared. This reduces the impact of clearing the fault on Angaston Power Station, restores the line immediately for most single phase fault conditions and removes the need for patrolling the line. Furthermore, the risk of islanding the power station is greatly reduced due to the shorter amount of time a line would remain out of service. This risk would be further mitigated through the upgrading of ETSA Utilities’ protection systems at Angaston and Dorrien substations.

ETSA Utilities has advised that it will need to augment its distribution system between Angaston and Dorrien in order for this solution to be practical and meet the requirements of the NER with respect to system security. The required augmentations involve the addition of duplicate high speed telecommunications links from Dorrien to Angaston and duplicate 33 kV line protection at Dorrien and Angaston substations.

To ensure that adequate reactive margins are maintained in the Mid-North region, 20 Mvar of capacitor banks must be installed on the existing Templers 132 kV bus and 12 Mvar of capacitor banks must be installed on the Roseworthy 132 kV bus. These augmentations would ensure that a generator network support arrangement would meet NER requirements until 2016/17. At this time it would be necessary to establish Templers West 275/132 kV substation to ensure that adequate voltages are maintained within the Barossa area. Schematic representations of the three stages of Option 3 are shown in Figure 16 and Figure 17.

Table 5 provides the required timing for each of the stages for this option and the estimated capital cost of each stage over the 20 year planning period. These capital costs exclude operating costs associated with generation network support. As part of the detailed financial analysis undertaken by ElectraNet on each option considered, these operating costs were included. Further discussion of this analysis is provided in Sections 9 and 10 of this Application Notice.


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Option 3 – Generation support followed by 275/132 kV injection at Templers West

Date required

Proposed Augmentation Total capital cost1 (in $2009)

2011/12

A 20 Mvar 132 kV capacitor bank to be installed at Templers substation and a 12 Mvar 132 kV capacitor bank to be installed at Roseworthy substation. Line exit 132 kV circuit breakers from Para substation to Waterloo substation converted to single pole operation. Communications systems and ETSA Utilities network augmentations as required for transmission support. Transmission network support contract to commence by summer 2011/12.

$25.6m

2016/17 Establish Templers West 275/132 kV substation with a single 160 MV.A 275/132 kV transformer feeding directly into Dorrien 132/33 kV substation.

$36.0m

2025/26 Install a second 160 MV.A 275/132 kV transformer at Templers West 275/132 kV substation feeding directly into Dorrien 132/33 kV substation. Replace aged disconnectors, secondary systems, telecommunications systems and bus bar at the existing Templers 132/33 kV substation.

$23.6m

Table 5: Proposed augmentations associated with Option 3

1 Capital cost excludes operational costs associated with running generation support.


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Figure 16: Option 3 Stage 1 - Generation support followed by 275/132 kV injection at Templers West


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Figure 17: Option 3 Stage 2 - Generation support followed by 275/132 kV injection at Templers West


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The first stage of works required for Option 3 involves the installation of capacitor banks at Templers and Roseworthy substations (as shown in Figure 18 and Figure 19), and the replacement of circuit breakers in the Mid-North region (as shown in Figure 20, for the case of Dorrien substation, to allow for single pole reclosing). The third 132/33 kV transformer shown at Dorrien substation in Figure 20 will not be installed as part of the Templers augmentation, but will form part of a separate project. These arrangements would require the following primary plant:

• Three 132 kV circuit breakers at Roseworthy substation;

• 12 Mvar 132 kV capacitor bank at Roseworthy substation;

• Three 132 kV circuit breakers at Templers substation;

• 20 Mvar 132 kV capacitor bank at Templers substation;

• Three 132 kV circuit breakers at Dorrien substation; and

• Two 132 kV circuit breakers at Waterloo substation.

The second stage of works required for Option 3 is identical to the initial stage of works previously described for Option 1. Templers West substation would be established at this time with a single 275/132 kV 160 MV.A transformer, as shown in Figure 16 and Figure 17. The anticipated ultimate layout for Templers West substation, as shown in Figure 21, comprises two 1½ breaker diameters and two 160 MV.A 275/132 kV transformers. The initial stage of works will require the installation of the following primary plant at Templers West 275/132 kV substation:

• One 160 MV.A 275/132 kV transformer;



Minor works would also be required at the existing Templers 132/33 kV substation during the second stage of Option 3. One circuit breaker at Templers 132/33 kV substation requires replacing in order to re-establish the previously abandoned Roseworthy exit using part of the Roseworthy-Dorrien 132 kV transmission line. This is shown in Figure 19. The remainder of this line would then be used to establish a connection from the 275/132 kV transformer via a 132 kV circuit breaker at Templers West substation to Dorrien substation.


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The third stage of Option 3 involves the installation of the following primary plant at Templers West 275/132 kV substation:

• A second 160 MV.A 275/132 kV transformer;



The existing Templers-Dorrien 132 kV transmission line would then be used to connect the second 275/132 kV transformer via a 132 kV circuit breaker at Templers West substation to Dorrien substation.

Figure 18: Option 3 Stage 1 required works at Roseworthy


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Figure 19: Option 3 Stage 1 required works at Templers

Figure 20: Option 3 Stage 1 required works at Dorrien Substation


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Figure 21: Option 3 Stage 1 required works at Templers West substation


Option 3 is effectively a delayed version of Option 1 and so the 275/132 kV transformer specified for this option is the same as that specified for Option 1. As with Option 1, the ultimate network configuration proposed by this option would result in the entire load at Dorrien substation being supplied via two 275/132 kV transformers at Templers West substation. Under this configuration, the 160 MV.A transformers at Templers West would be adequate to supply the load at Dorrien under N-1 conditions until 2041/42. The existing 132 kV transmission lines that supply Dorrien, however, would only be adequate until 2032/33, at which time additional transmission line capacity would be required into the area. For this reason, the selection of 160 MV.A transformers at Templers West 275/132 kV substation is considered prudent for this option given the existing network infrastructure.


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8. Scenarios Considered

8.1 Context for Evaluation of Options

All feasible options to the identified supply requirements must be viewed in the context of wider developments in the NEM. ElectraNet is not aware of any inter-state or intra-state transmission network augmentations that would impact the reliability or quality of electricity supply to the Barossa area, as discussed in this Application Notice.

8.2 Assumed Market Development Scenarios

The Regulatory Test for reliability augmentations requires that options to address network requirements be assessed against a number of reasonable scenarios. Those scenarios need to consider:

• The existing network;

• Future network developments;

• Variations in load growth;

• Committed generation and demand side developments; and

• Potential generation and demand side developments.

The purpose of this approach is to test the PV costs of the options being evaluated under a range of plausible scenarios.

8.2.1 Existing Network and Future Transmission Developments

As discussed in Section 7.1 of this report, existing and future network developments that have the potential to impact supply arrangements to the Mid-North region have been included as anticipated projects in the underlying analysis.

8.2.2 Variations in Demand Growth

The forecast demand growth used in this assessment was based on medium economic conditions and hot weather forecasts (10% Probability of Exceedance, or PoE) for electricity usage. Use of 10% PoE demand forecasts is standard ElectraNet practice when planning the transmission system.

The forecasts include all known information about existing and planned demand-side management initiatives, and include independent forecasts of existing and planned local embedded generation.


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For the purposes of the Mid-North augmentation studies, scenarios assuming both high (3.5%) and low (2.2%) demand growth were also considered to test the robustness of the analysis which is based on medium load growth (2.7% per annum).

8.2.3 Existing and Committed Generators and Demand Side Developments

The use of demand side management within the Barossa area was considered as part of the option development process. Major customers on both the Transmission Network and the ETSA Utilities owned Distribution Network were contacted to identify demand side management candidates. No demand side management solutions were identified as a result of these enquiries.

The utilisation of existing or committed generation within the Barossa area for transmission support was examined and forms the basis for Option 3 of this Application Notice. ElectraNet is not aware of any other existing or committed generators within the area that could provide a viable transmission network support option.

8.2.4 Potential New Generation

ElectraNet is not aware of any committed generation projects that will directly impact the supply to the Barossa area.

As electricity demand continues to grow, it is forecast that additional generation will be required within the South Australian region. It has been assumed for the purposes of planning studies examining future supply requirements to the Barossa area that, although entry of new generation into South Australia will occur in the foreseeable future to meet the increasing electricity demand, that new generation plant will be located such that its direct impact on the reliability of supply to the Barossa area will be immaterial.


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9. Format and Inputs to Analysis

9.1 Regulatory Test Requirements

The Regulatory Test requires that, for reliability augmentations, the recommended option be the option that “minimises the present value of costs, compared with a number of alternative options in a majority of reasonable scenarios”.

The Regulatory Test contains guidelines for the methodology to be used to identify the lowest cost option. Information to be considered includes construction costs, operating and maintenance costs, and the cost of complying with existing and anticipated laws and regulations. However, the Regulatory Test specifically excludes indirect costs and costs that cannot be measured as a cost in terms of financial transactions in the electricity market.

9.2 Inputs to Analysis

The Regulatory Test has been carried out using a discounted cash flow model and a pre-tax real Weighted Average Cost of Capital (WACC) of 8.50% as the discount rate, which equates to a nominal WACC of 11.36%.

Cost inputs to the economic analysis are described below.

9.3 Cost of Network Augmentations

The economic analysis considers all foreseeable cost impacts of the proposed network augmentations on market participants.

The capital cost2 to implement each of the feasible options outlined in Section 6 has been estimated by ElectraNet based on a conceptual scope of works. Sensitivity studies have been carried out using variations in the capital cost estimates of plus and minus 20%.

9.4 Other Inputs to Analysis

The economic analysis includes the costs of anticipated future projects that will be needed to maintain the required reliability standards for the Barossa area during the twenty-year analysis period.

The timings for anticipated projects are based on meeting future electricity supply requirements for the Barossa area using load forecasts prepared by ETSA Utilities in April 2009 and published in ElectraNet’s 2009 Annual Planning Review. Actual timings of the anticipated projects may change as a result of developments in the Mid-North region and other market developments during the twenty-year planning horizon.

2 In 2009 dollars.


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The sensitivity of the timing of the anticipated projects to a range of market development scenarios, and therefore the incidence of the capital expenditure, has been included as part of the economic analysis to ensure that the findings are robust.


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10.4 Inter-network Impact

ElectraNet is required under the NER to assess whether a new large network asset is reasonably likely to have a material inter-network impact. ElectraNet has determined that the proposed new large network asset will have minimal impact on inter-regional transfer capacity. The proposed new large network asset improves inter-network transfer capability under most conditions except for the case where light load, maximum export conditions coincide with maximum generation at Waterloo Windfarm. Under this scenario, transfer capability is reduced by less than 2%. This is not considered to be a material change to the transfer capability as specified by the NER.


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11. Construction Timetable and Commissioning Date

The proposed construction and commissioning program for the remainder of the work associated with the establishment of the recommended solution being the new Templers West 275/132 kV substation and associated infrastructure is as follows:

• Lodgement of development application – February 2010

• Civil works for Substation to commence – December 2010

• Delivery of plant – December 2010 (to storage or potentially delayed)

• Civil works for Transmission line to commence – January 2011

• Delivery of transformers – April 2011

• Transformer pre-commissioned – May 2011

• Substation commissioning – June 2011

• Substation commercially available – June 2011


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12. Compliance with Service Obligations

Section 4 of this Application Notice sets out the service obligations that ElectraNet is required to meet for the transmission system within the Barossa area. The following discussion demonstrates the compliance of the preferred option by identifying the worst case credible contingencies that trigger each stage of development for this option.

At no time does Option 1 result in forecast agreed maximum demand exceeding the level of transformer or line capacity.

Once Templers West substation is established in Stage 1 of Option 1, no single credible contingency will result in lost load or the need for under voltage load shedding or excursions in voltage outside the accepted tolerance range under the NER. Under the worst case credible contingency, the loss of either the Templers West 275/132 kV 160 MV.A transformer or the Templers West – Dorrien132 kV transmission line (refer to Figure 6) under peak load conditions, NER compliant supply to the Templers, Dorrien and Roseworthy connection points will be maintained. The implementation of this solution also meets the applicable deadline of 30 June 2011 under the ETC.

Immediately prior to the proposed 2021 implementation of Stage 2 of Option 1, under single credible contingency conditions, voltage control within the Barossa area will once again become a limitation of the transmission system. The establishment of Stage 2 of this option will mitigate these limitations.

In 2024, immediately prior to the implementation of Stage 3, under peak load single credible contingency conditions the reactive margin at Dorrien connection point will not meet NER requirements. Stage 3 of Option 1 resolves this limitation.

Prior to the completion of Stage 3, the worst case N-2 credible contingency within the area is the loss of both the Templers West 275/132 kV transformer and the Para – Roseworthy 132 kV line at peak load periods. This contingency, and several other N-2 configurations, will require under-voltage load shedding to be in place to ensure system security. Such protection devices will ensure compliance with both the NER and the ETC.

Once Stage 3 is complete, under-voltage load shedding will still be required for some N-2 system configurations, such as the loss of both the Para-Roseworthy 132 kV transmission line and the Robertstown-Waterloo 132 kV transmission line under peak load conditions; this is within ElectraNet’s obligations under the ETC, which requires only N-1 supply to these connection points, and the NER which requires system security be maintained at all times.


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13. Summary and Conclusions

The following summary and conclusions have been drawn from the analysis presented in this report:

• The augmentation proposed in this document is defined as a ‘reliability augmentation’ under the NER as it will prevent interruptions to supply during peak load periods under critical single-contingency events in the transmission network supplying the Templers, Roseworthy and Dorrien connection points.

• There is no acceptable ‘do-nothing’ option. ElectraNet is required to meet the new ETC reliability standard for the Templers and Dorrien connection points and maintain NER compliant transmission system voltages within the area. This is not possible given recent load growth and the existing network configuration.

• Planning studies were undertaken to evaluate potential network options that would address emerging network limitations in the electricity supply to the Templers, Roseworthy and Dorrien connection points, from which three viable options were identified.

• Economic analysis carried out in accordance with the Regulatory Test has identified the preferred option, Option 1 (establishing a new 275/132 kV substation adjacent to the existing Templers 132/33 kV substation feeding directly into Dorrien 132/33 kV substation, that will be known as Templers West 275/132 kV substation) as the least-cost solution over the 20-year period of the analysis in all of the credible scenarios considered. Sensitivity studies demonstrate that the results of that analysis are robust to variations in capital cost and other key input variables. Option 1 is therefore considered to satisfy the Regulatory Test.


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14. Draft Recommendation

Based on the conclusions drawn from the preceding analysis, it is recommended that the following be progressed:

• Establish on an ElectraNet owned site adjacent to the existing Templers 132/33 kV substation, a new 275/132 kV substation comprising one 160 MV.A 275/132 kV transformer feeding directly into Dorrien 132/33 kV substation;

• Restore to service the Roseworthy exit at the existing Templers 132/33 kV substation to allow for the use of part of the existing Roseworthy – Dorrien 132 kV line to feed Dorrien directly from Templers West; and

• Provide 275 kV supply to Templers West 275/132 kV substation from the existing Para – Brinkworth 275 kV transmission line which will be turned in and out of the new substation.

at a total estimated cost of $36.6m ($2009).


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15. Consultation

In accordance with NER requirements, ElectraNet invites submissions from Registered Participants and interested parties on this Application Notice.

Submissions are due by the close of business on 4 December 2009.

Please address submissions to:

Simon Appleby Senior Manager NEM Development and Regulation, ElectraNet, PO Box 7096, Hutt Street Post Office, Adelaide, South Australia, 5000 Tel: (08) 8404 7324 Fax: (08) 8297 0162

Following consideration of submissions, ElectraNet expects to publish a Final Report in February 2009.


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16. Glossary

AER Australian Energy Regulator

AEMO Australian Energy Market Operator

AMD Agreed Maximum Demand – for a connection point or a group of connection points, it is the demand specified as such in the connection agreement between ElectraNet and the relevant transmission customers or ETSA Utilities.

Application Notice A notice made available to Registered Participants and Interested Parties pursuant to clause 5.6.6 of the Rules

Distribution Code – EDC

South Australian Electricity Distribution Code – as issued by ESCOSA

DNSP Distribution Network Service Provider

ElectraNet ElectraNet is the principle transmission network service provider in South Australia. It is a privately owned company that has a long term lease for the operation, maintenance, and development of the South Australian transmission system which comprises plant and equipment mainly operating at voltages of 132 kV and above. ElectraNet is registered with AEMO as a Transmission Network Service Provider (TNSP)

Equivalent Transformer Capacity

Capacity to transform energy to meet demand using means including, but not limited to:

• transmission system capability;

• network support arrangements.

As defined in the ESCOSA Electricity Transmission Code

ESCOSA Essential Services Commission of South Australia established under the Essential Services Commission Act 2002

ETC South Australian Electricity Transmission Code issued by ESCOSA

ETSA Utilities ETSA Utilities is South Australia’s principal Distribution Network Service Provider (DNSP), and is responsible for the distribution of electricity to all distribution grid connected customers within the State under a regulatory framework. ETSA Utilities is a partnership of Cheung Kong Infrastructure Holdings Ltd (CKI), Hong Kong Electric International Ltd (HEI), and Spark Infrastructure

Market Participant

A person who has registered with AEMO as a Market Generator, Market Customer or Market Network Service Provider under Chapter 2

NEM National Electricity Market

NPV Net Present Value


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PoE Probability of Exceedance

Registered Participant

A person who is registered with AEMO as a Network Service Provider, a System Operator, a Network Operator, a Special Participant, a Generator, a Customer or a Market Participant

Regulatory Test The test promulgated by the AER, which all major regulated network augmentation investments must comply with

RFI Request for Information

RFP Request for Proposals

Rules National Electricity Rules (Rules) formerly the National Electricity Code (NEC)

TNSP Transmission Network Service Provider

WACC Weighted Average Cost of Capital



Appendix A NPV Analysis – Low Growth Scenario

Scenario A Low load Growth0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29Option 1 Establish Templers West 275/132kV substationEstablish Templers West 275/132kV substation 36 6

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.3 4.2 4.2 4.1 4.0 3.9 3.9 3.8 3.7==> NPV of TUOS $34.80

Install 12MVAr cap bank at Roseworthy 5.19/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.7 0.7 0.7 0.6 0.6==> NPV of TUOS $0.95

Install 2nd TF at Templers West 23 69/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 1.8==> NPV of TUOS $0.00

Total TUOS per year 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.3 4.2 4.2 4.5 4.7 4.6 4.5 4.4 6.2

NPV of total TUOS $35.62

Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0.0 2 800 1 300 1.500 1.600 1.700 1 900 2 200 2.400 2 600 2.700 2 800 3.000 3.200 3.600 5.400 2.100 3.745 3.886 4.026Loss Saving $ 0.0 0 212 0 098 0.114 0.121 0.129 0.144 0.167 0.182 0.197 0 204 0 212 0.227 0.242 0.272 0.409 0.159 0.283 0.294 0.305=> NPV of Cost of Losses (Saving) $1.65

Reliability Costs9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0 3 0.3 0.4 0.4=> NPV of Reliability Costs $2.72

Total for Option 1 $36.69

Option 1 – Low growth scenario




9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29Option 2 Rebuild Templers 132kV yard with 2x15MVAr caps.Rebuild Templers 132kV yard with 2x15MVAr caps. 25.2

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 2.0 3.3 3.3 3.2 3.2 3 2 3.1 3.1 3 0 3.0 2.9 2.9 2.8 2.8 2.7 2.7 2.6 2.6==> NPV of TUOS $23.93

Install 2nd TF at Para, line works 34.49/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 2.7 4.6 4.5 4.4 4.4 4.3 4.2 4 2 4.1 4.0 4.0 3.9 3.8 3 8 3.7 3.6 3.6==> NPV of TUOS $29.34

Rebuild Templers-Waterloo 132kV as d/c 31.99/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0==> NPV of TUOS $0.00

Total TUOS per year 0.0 2.0 6.0 7.9 7.7 7.6 7 5 7.4 7.3 7 2 7.1 6.9 6.8 6.7 6.6 6.5 6.4 6.3 6.1


Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0.0 4.100 3.200 3.700 1.200 1 200 1.400 1.800 1 800 2.000 2.000 2.100 2.300 2.400 1.700 2 600 4.200 2 288 2 279 2.271Loss Saving $ 0.0 0.3 0.2 0.3 0.1 0.1 0.1 0.1 0.1 0.2 0 2 0.2 0.2 0.2 0.1 0.2 0 3 0.2 0.2 0.2=> NPV of Cost of Losses (Saving) $1.65


0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0=> NPV of Reliability Costs $0.00






9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29Option 4 Gen support setup costsGen support setup costs 25.6

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 2.0 3.4 3.3 3.3 3.2 3.2 3.1 3.1 3.0 3.0 2.9 2.9 2 9 2 8 2.8 2.7 2.7 2.6==> NPV of TUOS $24.31

Establish Templers West 275/132kV substation 36.0

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2 8 4.8 4.7 4.6 4.6 4 5 4.4 4.4 4 3 4.2 4.2==> NPV of TUOS $14.66

Total TUOS per year 0.0 2.0 3.4 3.3 3.3 3.2 3.2 3.1 5 9 7.8 7.7 7.6 7.5 7 3 7 2 7.1 7 0 6.9 6.8


Generation support cost9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Estimated MW.hours 0 6 6 42 93 163 251 333 496 0 0 0 0.000 0.000 0.000 0.000 0.000 0.000 0 000Corrected MW/hrs required 0 31 31 82 150 243 356 462 658 0 0 0 000 0.000 0.000 0.000 0.000 0.000 0.000 0 000$ (millions) 0.0 0.000 0.441 0.441 0.441 0.443 0.444 0.446 0.448 0.452 0.000 0.000 0 000 0.000 0.000 0.000 0.000 0.000 0.000 0 000=> NPV of Generation Support $2.31

Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0.000 0.000 0.000 0.000 0.000 0 000 0.000 0.000 0.000 0.000 0.000 0 000 2.800 3.000 3.200 3.600 5.400 2.100 3.745Loss Saving $ 0.0 0.000 0.000 0.000 0.000 0.000 0 000 0.000 0.000 0.000 0.000 0.000 0 000 0.212 0.227 0.242 0.272 0.409 0.159 0 283=> NPV of Cost of Losses (Saving) $0.43


0.3 0.3 0.3 0.3 0.3 0.3 0.3 0 3 0 3 0.3 0.3 0.3 0.3 0 3 0.3 0.3 0 3 0.4 0.4=> NPV of Reliability Costs $2.60





Appendix B NPV Analysis – Medium Growth Scenario

Scenario B Medium load Growth0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19


9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.3 4.2 4.2 4.1 4.0 3 9 3 9 3 8 3.7==> NPV of TUOS $34.80

0.0 0.0Install 12MVAr cap bank at Roseworthy 5.1

9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.7 0.7 0.7 0.6 0 6 0 6 0 6 0 6==> NPV of TUOS $1.64


=> TUOS 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.8 3.1 3.1 3 0 3 0==> NPV of TUOS $2.86

Total TUOS per year 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.7 4.9 4.8 4.7 6.5 7.7 7 6 7 5 7 3


Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0 2.800 1.300 1.500 1.600 1.700 1.900 2.200 2.400 2.600 2.700 2.800 3.000 3.200 3.600 6 200 3.700 4.325 4.516 4.707Loss Saving $ 0 0.212 0.098 0.114 0.121 0.129 0.144 0.167 0.182 0.197 0.204 0.212 0.227 0.242 0.272 0.469 0.280 0.327 0.342 0.356=> NPV of Cost of Losses (Saving) $1.72


0 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0 3 0 3 0.4 0.4=> NPV of Reliability Costs $2.51


Option 1 – Medium growth scenario





9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 0.0 2.0 3.3 3.3 3.2 3.2 3 2 3.1 3.1 3 0 3.0 2.9 2.9 2.8 2.8 2.7 2.7 2.6 2.6==> NPV of TUOS $23.93


=> TUOS 0.0 0.0 0.0 2.7 4.6 4.5 4.4 4.4 4.3 4.2 4 2 4.1 4.0 4.0 3.9 3.8 3 8 3.7 3.6 3.6==> NPV of TUOS $29.34


=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 4.2 4.2==> NPV of TUOS $1.59



Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29










9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 2.0 3.4 3.3 3.3 3.2 3.2 3.1 3.1 3.0 3.0 2.9 2.9 2 9 2 8 2.8 2.7 2.7 2.6==> NPV of TUOS $24.31

0.0 0.0

Establish Templers West 275/132kV substation 36.09/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 2.8 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.3 4.2 4 2 4.1 4.0==> NPV of TUOS $19.23

Install 2nd TF at Templers West 23.609/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0 0 0.0 0.0 0.0 0.0 0 0 0.0 1.8 3.1 3.1 3.0==> NPV of TUOS $1.99

Total TUOS per year 0.0 2.0 3.4 3.3 3.3 3.2 6.0 7.9 7 8 7.7 7.6 7.4 7.3 7 2 7.1 8 8 10.0 9.8 9.7

NPV of total TUOS 45.53


Estimated MW.hours 6.0 42 0 93.0 162 5 250.5 332 5 496.0 0.0 0 0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0Corrected MW/hrs required 30 6 70 2 126 3 214 8 323.6 429 8 625.6 0.0 0 0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0$ (millions) 0.0 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.0 0 0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0=> NPV of Generation Support $2.27

Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 2.8 3.0 3.2 3 6 6 2 3.7 4.325 4.516176 4.707353Loss Saving $ 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.2 0.2 0.2 0 3 0 5 0 28004 0.327344 0.341813 0 356283=> NPV of Cost of Losses (Saving) $0.72


0 0.271 0.272 0.272 0.270 0.270 0.271 0.271 0.275 0.278 0.281 0.307 0.312 0.316 0.320 0.326 0.330 0.334 0.367 0.431=> NPV of Reliability Costs 2.39

Total for Option 4 49.48




Appendix C NPV Analysis – High Growth Scenario

Scenario C High load Growth0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19


9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.5 4.4 4.4 4.3 4.2 4.2 4.1 4.0 3.9 3.9 3.8 3.7==> NPV of TUOS $34.80

Install 12MVAr cap bank at Roseworthy 5.19/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.7 0.7 0.7 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6==> NPV of TUOS $2.50


=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.8 3.1 3.1 3.0 3.0 2 9 2.9 2.9 2.8==> NPV of TUOS $7.03

Total TUOS per year 0.0 2.9 4.9 4.8 4.7 4.6 4.6 4.9 5.1 5.0 6.8 8.0 7.9 7.7 7.6 7.5 7.4 7.2 7.1


Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0 2 800 1 300 1.500 1.600 1.700 1 900 2 200 2.400 2 600 2.700 2 800 3.000 3.800 3.500 5.400 2.100 3.830 3.977 4.124Loss Saving $ 0 0 212 0 098 0.114 0.121 0.129 0.144 0.167 0.182 0.197 0 204 0 212 0.227 0.288 0.265 0.409 0.159 0.290 0.301 0.312=> NPV of Cost of Losses (Saving) $1.66


0 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0 3 0.3 0.4 0.4=> NPV of Reliability Costs $2.51


Option 1 – High growth scenario





9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 0.0 2.0 3.3 3.3 3.2 3.2 3 2 3.1 3.1 3 0 3.0 2.9 2.9 2.8 2.8 2.7 2.7 2.6 2.6==> NPV of TUOS $23.93


=> TUOS 0.0 0.0 0.0 2.7 4.6 4.5 4.4 4.4 4.3 4.2 4 2 4.1 4.0 4.0 3.9 3.8 3 8 3.7 3.6 3.6==> NPV of TUOS $29.34


=> TUOS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0 0.0 0.0 0 0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 4.2 4.2==> NPV of TUOS $1.59



Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29








Scenario C High load Growth0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19


9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29=> TUOS 0.0 2.0 3.4 3.3 3.3 3.2 3.2 3.1 3.1 3.0 3.0 2.9 2.9 2 9 2 8 2.8 2.7 2.7 2.6==> NPV of TUOS $24.31

Establish Templers West 275/132kV substation 36.09/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

=> TUOS 0.0 0.0 0.0 0.0 2.8 4.8 4.7 4 6 4 6 4.5 4.4 4.4 4.3 4 2 4.2 4.1 4 0 3.9 3.9==> NPV of TUOS $24.55

Total TUOS per year 0.0 2.0 3.4 3.3 6.1 8.0 7.9 7 8 7.7 7.5 7.4 9.1 10 3 10.2 10 0 9.8 9.7 9.5 9.3



Estimated MW.hours 163 251 333 496 0 0 0 0 0 0 0 0 0.000 0.000 0.000 0.000 0.000 0.000 0 000Corrected MW/hrs required 0 203 300 390 582 0 0 0 0 0 0 0 0 000 0.000 0.000 0.000 0.000 0.000 0.000 0 000$ (millions) 0.0 0.444 0.445 0.447 0.451 0.000 0 000 0.000 0.000 0.000 0.000 0.000 0 000 0.000 0.000 0.000 0.000 0.000 0.000 0 000=> NPV of Generation Support $1.46

Cost of Losses9/10 10/11 11/12 12/13 13/14 14/15 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25 25/26 26/27 27/28 28/29

Losses Saving after implementation (MW) 0.000 0.000 0.000 0.000 0.000 0 000 0.000 2.600 2.600 2.700 2.800 3 000 3.800 3.500 5.400 2.100 3.830 3.977 4.124Loss Saving $ 0.0 0.000 0.000 0.000 0.000 0.000 0 000 0.000 0.197 0.197 0.204 0.212 0 227 0.288 0.265 0.409 0.159 0.290 0.301 0 312=> NPV of Cost of Losses (Saving) $0.95


0.3 0.3 0.3 0.3 0.3 0.3 0.3 0 3 0 3 0.3 0.3 0.3 0.3 0 3 0.3 0.3 0 3 0.4 0.4=> NPV of Reliability Costs $2.60



132 KV Transmission System Australia

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