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Grid Vision 2040

A vision for Tasmania’s transmission network

Transend’s Grid Vision 2040 July 2011 A vision for Tasmania’s transmission network

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COMPANY INFORMATION

Transend Networks Pty Ltd

Registered office: 1–7 Maria Street, Lenah Valley, Tasmania 7008

Postal address: PO Box 606, Moonah, Tasmania 7009

Telephone: 1300 361 811

Email: [email protected]

Overseas callers: +61 3 6274 3849

Internet: www.transend.com.au

Facsimile: +61 3 6274 3872

CONTACT

This document is the responsibility of the Strategic Grid Planning department, Transend Networks

Pty Ltd, ABN 57 082 586 892

PUBLICATION DATE

July 2011

DOCUMENT CONTROL

Version 1

Version 2: Produced in June 2012 with Figures 24 and 47 changed for consistency to show the new

Waddamana-Lindisfarne 220 kV line commissioned in 2011 and Figures 25 and 60 changed to

show opportunities to maximise decommissioning of old 110 kV lines in the Southern region.

This document has been prepared for the purpose of providing a long-term view of potential

transmission network developments in Tasmania.

This document is not intended to be used as the basis for any investment decisions. Parties should

make their own assessments and enquiries as to the accuracy, reliability and suitability of the

information contained herein for their purpose. In addition to that, Transend recommends that any

party intending to make a decision based on information contained in this document or assumptions

drawn from it contact Transend in advance of making any such decision.

While care has been taken in the preparation of this document Transend, its advisors and

consultants make no warranty as to the accuracy, reliability or completeness of the material

contained herein and accept no liability (including as a result of negligence or negligent

misstatement) for any loss or damage that may be incurred by any person relying on the information

contained in this document or assumptions drawn from it, except to the extent that liability under

any applicable statute cannot be excluded.

© Transend Networks Pty Ltd 2011. No part of this document which is not already in the public

domain may be reproduced or transmitted in any form or by any means without the prior written

consent of Transend.

Transend’s Grid Vision 2040 July 2011 Table of contents

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Table of contents

Message from the Chief Executive Officer ................................................................................... 9

Executive summary ..................................................................................................................... 10

1 Introduction to Grid Vision 2040 ...................................................................................... 15

1.1 Background ............................................................................................................ 15

1.2 The need for change ............................................................................................... 15

1.3 The reasons for Grid Vision 2040 ........................................................................... 16

1.4 Next steps............................................................................................................... 17

2 Sustainability considerations ............................................................................................. 18

3 Strategic environment and scenario planning approach .................................................. 20

4 Creating the smart transmission grid of the future .......................................................... 21

4.1 Impact of electric vehicles ...................................................................................... 22

5 Future generation planning in Tasmania .......................................................................... 24

5.1 Introduction ............................................................................................................ 24

5.2 Existing electricity supply in Tasmania .................................................................. 24

5.3 Hydro generation .................................................................................................... 26

5.4 Gas generation........................................................................................................ 27

5.5 Wind generation ..................................................................................................... 27

5.6 Geothermal energy ................................................................................................. 32

5.6.1 Hydrothermal systems ............................................................................................ 32

5.6.2 Hot rock systems .................................................................................................... 32

5.7 Biomass energy ...................................................................................................... 34

5.7.1 Waste energy .......................................................................................................... 35

5.8 Wave power ........................................................................................................... 35

5.9 Ocean currents........................................................................................................ 36

5.10 Solar power ............................................................................................................ 37

5.11 Future electricity supply in Tasmania ..................................................................... 38

6 Future of main 220 and 110 kV corridors ......................................................................... 41

6.1 Introduction ............................................................................................................ 41

6.2 Utilising the existing 220 kV and 110 kV corridors ................................................ 41

6.3 Asset condition assessment of existing 220 kV and 110 kV lines ............................ 43


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6.4 Alternative conductors............................................................................................ 44

6.5 Market constraints in existing 220 kV corridors ...................................................... 45

6.6 Farrell–Burnie–Sheffield–Farrell 220 kV triangle ................................................... 46

6.7 Palmerston–Sheffield–George Town–Palmerston 220 kV triangle .......................... 47

6.8 Palmerston–Waddamana 220 kV corridor............................................................... 49

6.9 Future supply for the greater Hobart area ................................................................ 50

6.10 Project details ......................................................................................................... 52

6.10.1 Overall budgetary cost ............................................................................................ 52

7 Rationale for a second Bass Strait DC link ....................................................................... 54

7.1 Introduction ............................................................................................................ 54

7.2 The existing Basslink interconnector ...................................................................... 54

7.3 Main drivers for a second DC interconnector .......................................................... 54

7.4 Current source converter vs voltage source converter technologies ......................... 55

7.5 Development options for a second Bass Strait DC link ........................................... 56

7.6 Merchant or regulated link ...................................................................................... 59

8 North-west and west coast region ...................................................................................... 60

8.1 Introduction ............................................................................................................ 60

8.2 Existing transmission system arrangement .............................................................. 60

8.3 Main issues and drivers for development in north-west ........................................... 61

8.3.1 Security of supply and load growth management in Devonport ............................... 61

8.3.2 Security of supply and load growth management in Burnie..................................... 62

8.3.3 Voltage stability and voltage collapse management in the north-west ..................... 64

8.4 Existing transmission system arrangement on the west coast .................................. 64

8.5 Main issues and drivers for development on the west coast ..................................... 65

8.5.1 Security of supply to Rosebery and Queenstown .................................................... 66

8.5.2 Voltage stability and voltage collapse management ................................................ 68

8.6 Project details ......................................................................................................... 69


9 North and north-east region .............................................................................................. 70

9.1 Introduction ............................................................................................................ 70

9.2 The existing transmission system arrangement in the north and north-east .............. 70

9.3 Main issues and drivers for development ................................................................ 71

9.4 Load growth management in Launceston ................................................................ 71

9.5 Security of supply to the greater Launceston area ................................................... 71


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9.5.1 New 220/110 kV injection point into Launceston ................................................... 71

9.6 Security of supply to the north-east......................................................................... 72

9.6.1 Scottsdale–Derby and Avoca–St Marys supply arrangement................................... 72

9.7 Load growth in the Midlands area .......................................................................... 74

9.7.1 Proposed Tunbridge Substation .............................................................................. 74

9.8 Security of supply to George Town ........................................................................ 74

9.8.1 George Town area .................................................................................................. 74

9.9 Voltage stability and voltage collapse management in the north.............................. 76

9.9.1 Steady state and dynamic reactive support required ................................................ 76

9.10 Project details ......................................................................................................... 78


10 South and east coast region ............................................................................................... 80

10.1 Introduction ............................................................................................................ 80

10.2 The existing transmission system arrangement in the south and east coast .............. 80

10.3 Main issues and drivers for development ................................................................ 81

10.4 Voltage stability and voltage collapse management in the greater Hobart

area ........................................................................................................................ 82

10.4.1 Steady state and dynamic reactive support required ................................................ 82

10.5 Security of supply to Hobart ................................................................................... 84

10.5.1 Proposed 220 kV loop Lindisfarne–Risdon–Chapel Street ...................................... 84

10.6 Load growth management in Hobart ....................................................................... 85

10.6.1 Existing Hobart 110/33 kV injection points and 33 kV subtransmission

network .................................................................................................................. 85

10.6.2 Future new 110/33 kV injection points and 33 kV subtransmission

network .................................................................................................................. 86

10.7 Security of supply to the eastern shore and load growth management at

Sorell...................................................................................................................... 87

10.7.1 Proposed 110 kV link between Sorell and Mornington substations ......................... 87

10.7.2 Conversion of Richmond Substation to 110/22 kV or 33/11 kV .............................. 88

10.7.3 Dunalley, Triabunna and east coast supply ............................................................. 89

10.8 Security of supply and load growth management in Kingborough area ................... 89

10.9 Security of supply to the upper Derwent and load growth management at

Bridgewater ............................................................................................................ 91

10.9.1 New Norfolk–Bridgewater 110 kV link .................................................................. 91

10.9.2 Proposed 110/33 kV Bridgewater Substation .......................................................... 92

10.10 Proposed projects ................................................................................................... 92

Transend’s Grid Vision 2040 July 2011 Figures

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11 Future easement and site requirements ............................................................................ 94

12 Conclusion .......................................................................................................................... 95

13 References .......................................................................................................................... 96

Appendix 1: Project timeframes and estimated costs ................................................................ 98

Appendix 2: Future transmission lines and substations .......................................................... 103

Appendix 3: Abbreviations ....................................................................................................... 107

Figures

Figure 1 Transmission grid in 2010 ...................................................................................... 13

Figure 2 Possible future grid in 2040 .................................................................................... 14

Figure 3 Tasmania load forecasts from 2007, 2008 and 2010 ................................................ 16

Figure 4 People, the environment and technology (Woolnorth wind farm in

north-west Tasmania) ............................................................................................. 19

Figure 5 Electricity supply in Tasmania in 2008–09 ............................................................. 25

Figure 6 Electricity supply in Tasmania in 2009–10 ............................................................. 26

Figure 7 Mean wind speed at 80 m above ground level ......................................................... 28

Figure 8 Mean capacity factor at 80 m above the ground level .............................................. 29

Figure 9 Rotary energy storage system ................................................................................. 31

Figure 10 Typical 20 MW geothermal plant ........................................................................... 32

Figure 11 Hot rocks target zones in Tasmania ........................................................................ 34

Figure 12 Tracy Biomass 21.5 MW Plant, California ............................................................. 35

Figure 13 Ocean Power Technology PowerBuoy wave power device ..................................... 36

Figure 14 Tidal generator ....................................................................................................... 37

Figure 15 Supply outlook for Tasmania up to 2040 (for medium load growth

with and without additional wind generation projects) ............................................ 39

Figure 16 Utilisation of Sheffield–George Town No 1 220 kV line ........................................ 42

Figure 17 Swelling of steel reinforced aluminium conductor due to the

development of galvanic corrosion ......................................................................... 44

Figure 18 Alternative conductors for main core grid ............................................................... 45

Figure 19 Farrell–Burnie–Sheffield–Farrell 220 kV existing arrangement .............................. 46

Figure 20 Farrell–Burnie–Sheffield–Farrell 220 kV proposed arrangement ............................ 47

Figure 21 Palmerston–Sheffield–George Town–Palmerston 220 kV existing

arrangement ........................................................................................................... 48

Transend’s Grid Vision 2040 July 2011 Figures

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Figure 22 Existing arrangement between Palmerston–Waddamana–Liapootah ....................... 49

Figure 23 Proposed future arrangement between Palmerston and Waddamana ....................... 50

Figure 24 Supply arrangements for the greater Hobart area in 2011 ........................................ 51

Figure 25 220 kV loop and rationalisation of 110 kV supply in the greater

Hobart area ............................................................................................................. 52

Figure 26 XLPE cables for DC links ...................................................................................... 56

Figure 27 Potential routes for second Bass Strait DC link ....................................................... 57

Figure 28 Potential network upgrades required in Victoria ..................................................... 58

Figure 29 Potential transmission network upgrades required in Tasmania............................... 58

Figure 30 North-west region existing arrangement ................................................................. 60

Figure 31 Devonport current supply arrangement ................................................................... 61

Figure 32 Devonport future supply arrangement ..................................................................... 62

Figure 33 Burnie area existing supply arrangement ................................................................ 63

Figure 34 Burnie area future supply arrangement ................................................................... 64

Figure 35 Existing west coast supply arrangement .................................................................. 65

Figure 36 West coast future supply arrangement – 44 kV option ............................................ 67

Figure 37 West coast future supply arrangement – 66 kV supply option ................................. 68

Figure 38 North and north-east existing supply arrangement .................................................. 70

Figure 39 Proposed arrangement with second 220/110 kV bulk supply points ........................ 72

Figure 40 Existing Scottsdale and Avoca supply arrangement ................................................ 73

Figure 41 Proposed Scottsdale and Avoca supply arrangement ............................................... 74

Figure 42 Options for the future 220 kV arrangement in George Town area ........................... 75

Figure 43 George Town 220 kV voltage following a loss of Farrell–Sheffield

No. 2 circuit ........................................................................................................... 76

Figure 44 George Town 220 kV voltage following a circuit breaker failure at

Sheffield ................................................................................................................. 77

Figure 45 Synchronous condensers......................................................................................... 77

Figure 46 North and north-east proposed supply arrangement ................................................ 78

Figure 47 Southern network existing supply arrangement ....................................................... 81

Figure 48 New generation of synchronous condensers ............................................................ 83

Figure 49 Chapel Street 220 kV voltage following a CB failure at Chapel

Street ...................................................................................................................... 84

Figure 50 Supply arrangement with two 220 kV bulk supply points ....................................... 85

Figure 51 Proposed arrangement with 220 kV loop completed ............................................... 85

Figure 52 Existing Hobart 110/33 kV injection points and 33 kV

subtransmission network ........................................................................................ 86

Transend’s Grid Vision 2040 July 2011 Tables

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Figure 53 Future 110/33 kV supply points and 33 kV subtransmission

network .................................................................................................................. 87

Figure 54 Existing 110 kV supply arrangement from Lindisfarne ........................................... 88

Figure 55 Proposed 110 kV supply arrangement from Lindisfarne ......................................... 88

Figure 56 Existing 110 kV supply arrangement in the Kingborough area ................................ 90

Figure 57 Proposed 110 kV supply arrangement in the Kingborough area .............................. 90

Figure 58 Existing 110 kV supply arrangement to upper Derwent area ................................... 91

Figure 59 Proposed 110 kV supply arrangement to upper Derwent area ................................. 91

Figure 60 South and east coast proposed supply arrangement ................................................. 92

Tables

Table 1 Total cost of proposed projects based on regions and 5 year

revenue reset periods (in $2010, based estimate and plus 30%

contingency and allowances estimate included) ...................................................... 12

Table 2 Estimated wind energy potential ............................................................................. 30

Table 3 Capital cost comparison for different generation technologies ................................ 39

Table 4 220 kV corridor constraints in 2007, 2008 and 2009 ............................................... 45

Table 5 Anticipated future revenue reset expenditure in the north-west and

on the west coast (in $2010, base estimate and 30% contingency

plus allowances estimate included) ......................................................................... 69

Table 6 Anticipated future revenue reset expenditure in the north and north-

east (in 2010 $, base estimate and 30% contingency plus

allowances estimate included) ................................................................................ 79

Table 7 Anticipated future revenue reset expenditure in south and east coast

(in $2010, base estimate and 30% contingency plus allowances

estimate included) .................................................................................................. 93

Table 8 Proposed development projects in 220 and 110 kV core grid .................................. 98

Table 9 Proposed development projects in north-west and west coast .................................. 99

Table 10 Proposed network development projects in south and east coast ........................... 100

Table 11 Proposed network development projects in north and north-east ........................... 101

Table 12 Proposed new transmission lines .......................................................................... 103

Table 13 Proposed new substations ..................................................................................... 105

Transend’s Grid Vision 2040 July 2011 Introduction to Grid Vision 2040

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Message from the Chief Executive Officer

Grid Vision 2040 has been produced by Transend Networks as a road map for the long-term future

development of the transmission network in Tasmania. The need for a long-term vision for the

transmission network is more important now than ever before as we face the challenges of an

uncertain, ambiguous environment in the move towards a stable framework for climate change

management.

To deal with the complexities of this environment, we adopted a scenario-based planning approach.

Climate change and the decisions taken by governments to reduce greenhouse gas emissions are

recognised as key drivers in determining forward investment, in both the generation and demand-

side sectors. Tasmania is well positioned to contribute to the achievement of the nation’s climate

change objectives. As part of the evolution of our 30-year vision for the transmission network, a

wind atlas was developed to assess the wind energy potential in Tasmania. The atlas confirms that

Tasmania has excellent wind energy resources. However, the existing network is not capable to

accommodate significant amount of additional wind generation without considerable upgrade and

additional support in frequency and voltage control ancillary services.

With growing community concern about rising power prices, our plan for the future ensures we

continue to gain maximum benefit from our investment in the existing 220 kV transmission network

backbone. The majority of planning scenarios show that increased capacity of the main 220 kV

backbone can be achieved through the application of new technology and innovations without the

need to increase the core grid voltage. By upgrading sections of the original 220 kV backbone,

installed in 1957, we will remove many existing market constraints and create a more resilient

transmission network backbone.

We also acknowledge the importance of building on the success of more recent developments, such

as Basslink. Since commissioning in 2006, the Basslink interconnector has ensured the security of

supply in Tasmania. However, some operational issues with the interconnector, such as the time

required to change the direction of the power flow, indicate that the benefits of the first

interconnector have not been fully realised and may not be without the addition of a second

interconnector in the future. In preparing Grid Vision 2040, different concepts for a potential second

interconnector were investigated and are detailed in this report.

Grid Vision 2040 also focuses on regional development in Tasmania. The projects proposed for

each region would follow a well-established process of evaluation and justification along with

consultation with our customers.

We hope that Grid Vision 2040 will be an important source of information in guiding the energy

debate in Tasmania. We believe it provides a strong platform for undertaking the future work

needed to ensure that our transmission network continues to deliver essential services to our

customers safely, reliably and efficiently for many decades to come.

Peter Clark

Chief Executive Officer


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Executive summary

The electricity transmission network in Tasmania plays a vital role in linking remote power stations

to population and load centres. This will continue in the future, particularly with the potential

increase in renewable generation connections to the grid.

The development of renewable generation is driven primarily by Australian Government policies

related to climate change and the reduction of greenhouse gas emissions. The expanded renewable

energy target is now in place and it is expected that an emissions trading scheme or carbon tax will

be introduced by 2013. International experience shows that stable government policy is

fundamental to the successful development of renewable generation. Tasmania is rich in renewable

energy resources and the transmission network is vital in realising this energy potential.

Improving demand management

In Australia, the focus is on encouraging demand management through smart grid development

supported by smart or intelligent meters, two-way communication networks, metering data

management systems, energy control and management systems, distribution network automation

and microgrid development. This will enable customers to participate in supply–demand

management. By acquiring knowledge about their own electricity demand patterns and real-time

information about the cost of electricity, customers will be better able to control their energy

consumption and reduce load growth in comparison with load forecasts of just two to three years

ago. Forecast medium energy sales in Tasmania from 2010 to 2024 show an average growth of

0.79 per cent a year, which is well below the 1.46 per cent forecast in 2006. Load forecasts made in

2007 and 2008 for the year 2020 show a drop of 205 MW in maximum demand. This reduced load

forecast was reconfirmed in the latest 2010 forecast report (Transend 2010c). The expectation that

electricity prices will rise further with the introduction of an emissions trading scheme or carbon tax

calls for a cautious approach in considering load growth as the main driver for transmission network

development in Tasmania.

Maximising use of the existing network

As a result, Transend’s Grid Vision 2040 concentrates on increasing utilisation of the existing

network by installing new 110 and 220 kV ties. In the majority of development scenarios there is no

need for an increase in voltage in the transmission network backbone in Tasmania. Instead,

proposed development projects aim to improve the condition of the original 1957 220 kV line and

to remove market constraints and reliability issues caused by this section of the system. An analysis

of the utilisation of the main 220 kV backbone shows that it is not under stress and that there is

available capacity to accommodate further increases in power transfer. If and when an increase in

capacity of the 220 kV backbone is required it can be achieved in other ways without increasing the

voltage level.

Responding to supply and load changes

An analysis of supply in the north-west and the west coast shows that these regions have

experienced reductions in total load due to the recent closure of some industrial customers. The

need to enhance and protect the security and reliability of supply to the population centres of

Devonport and Burnie will be the main driver for transmission network development in the future.

Projects designed to address these issues are relatively simple and easy to achieve. Mining load is


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dominant on the west coast of Tasmania. As the mining industry is exposed to volatile commodity

prices on the international market, it is hard to predict the future requirements of this load for

transmission network development.

The existing transmission network connecting west coast hydro generation to the rest of the network

is already a bottleneck, preventing unconstrained access to the grid. A special network control and

system protection scheme is in place to enable west coast generation full access to the market. Any

further generation development on the west coast will require the reinforcement of the 220 kV

transmission network. For a potential network reinforcement to proceed, market benefits need to be

demonstrated or project funded by a proponent. The need for the network upgrade or

reconfiguration could also be triggered by the emergence of a potential large industrial customer in

the region.

The transmission network in the north supplies Launceston, the second largest population centre in

Tasmania, and George Town, the largest industrial load centre and also the connection point to the

national transmission network via the Basslink interconnector. Security of supply to Launceston

will be improved by the closure of the 110 kV loop around Launceston after the installation of the

Mowbray–St Leonards–Norwood circuit. The load on the 110/22 kV connection points for

distribution company Aurora Energy can be managed by the transfer of load to new connection

points at Ashley, Launceston CBD, Longford and Exeter. The security of supply to George Town

will be enhanced by the conversion of this substation to a breaker-and-half arrangement, but

preventing voltage collapse in the area remains the biggest challenge. To mitigate this problem, the

installation of dynamic reactive power devices is considered as one potential option to provide the

necessary voltage support as well as the additional inertia and fault contribution required for the

secure operation of the Basslink interconnector. Consideration has also been given to the

construction of a second 220/110 kV injection point into the Launceston area to remove the risk

associated with a potential loss of the 220/110 kV Hadspen Substation.

With the successful commissioning of the Waddamana–Lindisfarne 220 kV line and the Lindisfarne

220 kV Substation the southern region got a second 220 kV injection point, which enhances the

security of supply to the greater Hobart area. Again, voltage collapse in the area remains the main

challenge to be managed. To overcome this problem installation of dynamic reactive power devices

was considered. Dynamic reactive power devices will prevent system from voltage collapse

providing the necessary, fast voltage support in the area.

Aligning with business objectives

The proposed development projects align with Transend’s business objectives and the Tasmanian

Government’s Infrastructure Strategy (Tasmanian Government 2010). Additional factors that have

been taken into consideration in selecting development projects include:

the potential to connect renewable energy resources to the local and national grid;

energy efficiency measures;

smart grid, distributed generation and microgrid development; and

application of new technology.

Table 1 provides indicative costs for projects considered in this Grid Vision report. It reflects

different regions and 5 year revenue reset periods. The table shows that in following 30 years total

required expenditures would be less than $1.5 billion ($2.1 billion with 30% contingency and

allowances). The main amount (one third) would be on the core grid projects and the majority of the

rest is related to strengthening network that supplies major population centres in the north and

south.


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Table 1 Total cost of proposed projects based on regions and 5 year revenue reset periods (in $2010, based estimate and plus 30% contingency and allowances estimate included)

Revenue reset

period

Region

TOTAL Core Grid

South and east coast

North and north–east

North–west and west coast

Base estimate 30%+all. ($M)

Base estimate 30%+all. ($M)

Base estimate 30% + all. ($M)



2014–2019 166.2

236.1

97.4

134.3

91.8

137.0

11.8

16.1

367.2

523.5

2019–2024 77.8

109.3

53.9

72.0

44.3

62.1

8.8

12.7

184.8

256.1

2024–2029 147.1

206.0

75.9

102.5

107.7

152.6

47.5

67.9

378.2

529.0

2029–2034 136.9

191.6

68.3

97.5

154.5

221.5

12.5

16.7

372.2

527.3

2034–2039 57.3

80.2

35.0

47.2

82.6

118.1

16.6

24.7

191.5

270.2

TOTAL 585.3

823.2

330.5

451.7

480.9

691.3

97.2

138.1

1493.9

2104.3

Appendix 1 provides details of individual projects for each region and the revenue reset period.

Figure 1 below shows the existing Tasmanian transmission grid and regions, as considered in

developing the Grid Vision. Figure 2 details the proposed transmission grid in 2040 with new

transmission lines, potential new generation sources and possible options for future interconnectors

with Victoria.


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Figure 1 Transmission grid in 2010

NORTH WEST

WEST COAST

NORTH NORTH EAST

EAST COAST

CENTRAL

SOUTH


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Figure 2 Possible future grid in 2040

Conclusion: striking the right balance

Transend’s Grid Vision 2040 strikes a balance between addressing reliability requirements, costs

and care for the environment. It focuses on maximising use of the existing network, as well as

embracing new technology and the latest innovations. It facilitates the likely increase in renewable

generation, ensures the system is maintained in a secure operating state and satisfies the required

supply reliability standards at an affordable cost.

It is our blueprint for the future.


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1 Introduction to Grid Vision 2040

1.1 Background

In 2006–07, Transend engaged the Nous Consulting Group to produce a high level 30+ year vision

for the transmission network in Tasmania. A scenario–based approach was applied to explore a

range of possible challenges that Transend could face in the long-term development of the network.

The document prepared by the Nous Group recommended: 1 breaking down the 30+ year grid vision into strategic plans; and

2 producing a public version of the 30+ year grid vision document.

Transend has embraced these recommendations and six strategic plans have been developed:

strategic plan for future generation in Tasmania;

strategic plan for the 220 kV transmission network backbone;

strategic plan for a second Bass Strait DC link;

strategic plan for the north-west, including Burnie and Devonport, and the west coast;

strategic plan for the north, including Launceston and George Town, and the north-east; and

strategic plan for the south, including the east coast.

This Grid Vision 2040 document consolidates the information contained in the six strategic plans

and paints a picture of what the transmission system might look like in 2040.

1.2 The need for change

Like all other network service providers in Australia, Transend faces the challenge of developing a

long-term vision for the development of the transmission network to ensure it can continue to

deliver reliable and affordable transmission network services in the following 30+ years.

The energy industry around the world and in Australia is undergoing significant changes. A review

of the national energy market framework was undertaken in light of evolving climate change

policies (AEMC 2009). Also, the Australian Energy Market Commission has undertaken the

Transmission Frameworks Review with the focus on: role of transmission, network charging,

congestion, network planning and connections (Grid Australia 2010).

The renewable energy target has been set by the Australian Government. It is also expected that an

emissions trading scheme will be in place by 2013. These policies should stimulate further

development of renewable energy sources reducing dependence on fossil fuels and carbon-intensive

technology.

The focus is already shifting towards smart grids and the ‘smart customer’ who will be armed with

real-time data and who will have an opportunity to actively participate in maintaining the supply–

demand balance in the future. Encouraging greater energy efficiency is an important part of this

approach. With real-time access to electricity pricing information and demand data, it is expected

that load growth will moderate in comparison with load forecasts of just three to four years ago.


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Figure 3 Tasmania load forecasts from 2007, 2008 and 2010

Figure 3 compares three maximum demand forecasts prepared by the National Institute for

Economic and Industry Research for Transend for 2007, 2008.The comparison shows a significant

decline of 205 MW in maximum demand in the year 2020. This drop in load growth was confirmed

in the 2010 load forecast. Consequently, Grid Vision 2040 focuses on increasing utilisation of the

existing assets by undertaking a balanced approach between meeting future capacity requirements

in the transmission network while minimising any impact on the environment through the

application of new technology and innovations.

Deeper penetration of renewable energy sources will not only push the boundaries of secure system

operation but also open up new business opportunities to all electricity market participants.

1.3 The reasons for Grid Vision 2040

Grid Vision 2040 provides details of how the transmission network should be developed to support

a long-term sustainable and reliable electricity supply in Tasmania. It is also a guide to the network

development needed to support long-term generation development and to meet customer

expectations. Grid Vision 2040 focuses on the synergy of market and reliability drivers to maximise

the economic benefits of a long-term planning approach. A piecemeal, short-term approach of

responding as needs arise could result in an ineffective transmission network and inefficient

investment in the grid. Transmission network developments based on a long-term view are more

economically viable and have less impact on the environment and the community.

Tasmania is rich in renewable energy resources. Making use of these resources for electricity

generation by connecting them to the grid could bring prosperity to Tasmania as well as significant

benefits to the national electricity market by helping to meet renewable energy targets and

greenhouse gas emission targets. Grid Vision 2040 explores and highlights these opportunities and


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examines how these resources can be connected to the local and national grids in the most efficient

way.

This greater penetration of renewable generation, together with the increased role of the end-user in

demand management, and the greater use of distributed generation and microgrid development, will

push the envelope of the secure operation of power system. To manage this issue the Tasmanian

power system might require new forms of ancillary services to keep the system operating in a

secure state. Smart transmission networks can facilitate these changes in the generation sector and

in customer behaviour by the application of new technology and innovations. The objective of Grid

Vision 2040 is to develop a resilient transmission network that is flexible enough to adapt to these

changes.

1.4 Next steps

Grid Vision 2040 proposes a range of infrastructure development projects to be developed on a

regional level, which would strengthen the transmission network in Tasmania as well as increasing

ties with the national grid. Transend will undertake detailed technical and economic studies to more

clearly understand the drivers and triggers for these projects to proceed. Future steps are focused in

three directions. These are:

To undertake market simulation studies to estimate the level of market benefits that proposed

projects will deliver, including the potential development of a second DC link with the

national grid;

To undertake reliability evaluation studies to estimate reliability benefits that the proposed projects will deliver; and

To undertake technical studies to understand system performance and develop technical

solutions to support renewable generation connection to the grid. They should define the

technical envelope inside which Transend would keep the system operating in a secure state.

Collectively, these studies should provide the data to support inclusion of the proposed projects into

Transend’s future revenue cap applications and make a strong case for the projects to proceed. The

process to be followed is well defined on a national level and will include:

publishing project details in Transend’s Annual Planning Reports and the Australian Energy

Market Operator’s (AEMO) National Transmission Network Development Plans (NTNDP);

consulting with and gathering comments from interested parties ; and

applying the Regulatory Investment Test for Transmission for project justification.

Transend’s Grid Vision 2040 July 2011 Sustainability considerations

Page 18

2 Sustainability considerations

A generally accepted meaning of sustainability is: ‘meeting the needs of the present without

compromising the ability of future generations to meet their own needs’ (The University of

Reading).

Sustainability requires the integration of economic, social and environmental considerations.

Transend’s commitment to sustainability is reflected through the company’s vision ‘to be a leader

in developing and maintaining sustainable networks’.

By taking a long-term approach to system development, Transend is playing an active role in

ensuring a sustainable future. Grid Vision 2040 is a response to challenges in the strategic

environment. It is designed to ensure the transmission network is flexible enough to cope with the

speed and impact of these changes on both electricity suppliers and consumers.

The recommendations and outcomes contained in this Grid Vision document and its strategic plans

represent the integration and balancing of the three key pillars of sustainability:

Economic Every effort has been made to try to identify the best economic approach

to satisfy system development for both load and generation customers.

Further detailed economic analysis will be required when system

conditions require the implementation of any of the development options.

Social Meeting the future needs of the community is one of the main drivers of

Grid Vision 2040 and its strategic plans. This will ensure Transend can

continue to provide a secure, reliable and safe electricity supply to all

customers, whether at the generation or load end of the line. This will

contribute to the future prosperity of the state as a whole.

Environmental Careful consideration has been given to minimising the environmental

impacts of our operations, including utilising existing easements with little

or no widening. Consolidation of existing transmission lines has also been

looked at, along with the need for expansion of existing or construction of

new substations. Decisions on the location of any new transmission lines

or substations will take account all environmental issues. Transend will

explore options, such as improving the rating of existing lines to minimise

the need for development of new lines.

New technology will enable Transend to increase use of the existing network and transmission

assets without compromising security and reliability of supply. The integration of new renewable

energy sources, distributed generation and active involvement of customers in achieving a supply–

demand balance will push the boundaries of the secure operation of the system. The approach

proposed in Grid Vision 2040 provides the necessary resilience in the transmission network and

transmission assets to cope with these challenges.

Transend’s Grid Vision 2040 July 2011 Sustainability considerations

Page 19

Figure 4 People, the environment and technology (Woolnorth wind farm in north-west Tasmania)

Transend’s Grid Vision 2040 considers the synergy of main drivers for development and shows the need for:

economic prosperity;

care for the environment; and

the application of new technology and innovations.

Courtesy of Chris Crerar-Photographer

Transend’s Grid Vision 2040 July 2011 Strategic environment and scenario planning approach

Page 20

3 Strategic environment and scenario planning approach

The current environment in which Transend operates is characterised by:

Volatility–a rapid pace of change requiring anticipation and flexibility;

Uncertainty–the impact of change may not always be immediately clear;

Complexity–the inter-relationship between events may not be fully understood; and

Ambiguity–the lack of clarity in input data may impact decision making.

In this VUCA environment, scenario planning is the preferred approach to create a long-term

strategy for the transmission network. The scenario planning approach captures a series of

influential factors that are likely to have an impact on the future of transmission network

development and, consequently, on Transend. Three factors were identified as critical to this

process:

demand growth—high, medium and low;

water inflows in hydro storages—existing and low; and

potential greenhouse gas emissions policy changes—introduction of a modest or high carbon tax.

By combining these factors in different ways 12 development scenarios were created:

Scenario 1 low load growth, existing water inflows and modest carbon tax;

Scenario 2 low load growth, existing water inflows and high carbon tax;

Scenario 3 low load growth, low water inflows and modest carbon tax;

Scenario 4 low load growth, low water inflows and high carbon tax;

Scenario 5 medium load growth, existing water inflows and modest carbon tax;

Scenario 6 medium load growth, existing water inflows and high carbon tax;

Scenario 7 medium load growth, low water inflows and modest carbon tax;

Scenario 8 medium load growth, low water inflows and high carbon tax;

Scenario 9 high load growth, existing water inflows and modest carbon tax;

Scenario 10 high load growth, existing water inflows and high carbon tax;

Scenario 11 high load growth, low water inflows and modest carbon tax; and

Scenario 12 high load growth, low water inflows and high carbon tax.

These scenarios were ranked according to their probability. The ranking shows that the scenario

featuring medium load growth, existing water inflows and a high carbon tax was the most likely

scenario. The Tasmanian transmission network was modelled and analysed against each of these

twelve scenarios for 2010, 2020, 2030 and 2040. Additional sensitivities were incorporated to take

account of Basslink import and export conditions, the availability of the Gordon Power Station and

the impact of a total shut down of this power station, particularly on the security of supply to the

greater Hobart area.

Transend’s Grid Vision 2040 July 2011 Creating the smart transmission grid of the future

Page 21

4 Creating the smart transmission grid of the future

The current electricity grid concept of transferring power from remote, large power stations to

centres of consumption is based on technology that was invented more than 100 years ago.

Although the electricity grid has been continuously updated since that time in response to changes

in the operating environment, it is generally agreed that a new approach is required in the future.

The smart grid concept has evolved from a recognition of the need for more flexible, more

intelligent, more open access to the network and the exchange of energy and information in both

directions, from generators to customers and vice versa. Key technology areas identified as critical

to the development of the grid of the future (Research Reports International 2009) include:

smart meters to enable consumption data to be available to both customers and utilities on a real-time basis;

two-way communication networks using broadband over power lines with smart meters in a meshed network configuration for transferring data;

metering data management systems to support demand response programs by providing consumption data;

energy management and control technology to respond to price signals and automatically control or shift demand during the day; and

distribution network and substation automation technology to reconfigure the distribution

network and provide supply from alternative substations during fault situations, resulting in

improved reliability of supply.

The smart electricity grid of the future will bring forward new capabilities and services that utilities can offer to customers, such us:

dynamic pricing;

real-time feedback about electricity consumption, prices, peak demand and greenhouse gases emitted;

demand response programs;

microgrids with distributed generation and storage devices in parallel operation with the grid; and

electric vehicles, including vehicle to the grid technology.

It is expected that these key technologies and new services will raise awareness of opportunities that

customers might explore to participate in real-time supply and demand management. Consequently,

Grid Vision 2040 is focused on making better use of transmission system assets by increasing levels

of use and strengthening the existing network. This could be achieved efficiently by installing

inter-ties and creating loops in the existing network. This would be reinforced by the creation of a

‘smart transmission grid’ deploying intelligent devices and technology to enhance the existing

transmission network capabilities. These include:

shunt and series compensation devices;

unified power flow controllers;

new generation dynamic reactive power devices;

fly wheel energy storage systems, batteries and active power control devices;

active filters for power conditioning;

new smooth body, high temperature conductors with composite materials;

superconductors and superconducting magnetic energy storages;


Page 22

new direct current technology;

enhanced dynamic line rating system;

synchrophasor measurement technology, wide area measurements and energy management and control systems enhancements; and

new asset monitoring devices and risk assessment tools.

The application of new intelligent devices and the latest technology will increase utilisation of the

existing transmission network and assets, balancing risk and reliability requirements without the

need for a massive investment in the transmission network and assets.

4.1 Impact of electric vehicles

The transport sector is one of the three sectors with the greatest potential for reducing greenhouse

gas emissions to meet Tasmania’s legislated emission reduction target (MMA Consulting 2009).

One of the most important future transport technologies that can combat greenhouse gas emissions

is the battery-powered electric vehicle, or the plug-in electric vehicle. The range of these vehicles is

increasing, now up to 300 km, and their power rating range has grown from a few tens of kilowatts

for small cars to a few hundred kilowatts for high performance cars.

While electric vehicles can be an additional load on the network during charging, they become

generators when operating in regeneration mode. Concerns have been raised about the potential

impact of an increased number of new, distributed generation, and renewable energy resources as

well as the effect a large fleet of electric vehicles could have on fault levels in the network

associated with reverse power flow, protection system coordination, phase imbalance and power

quality issues.

As a part of the development of Grid Vision 2040, the impact of this technology on the transmission

network has been analysed in detail (Transend 2010h). The impact is expected in three main areas:

load profile and uncontrolled increase in peak demand;

variations in voltage profile; and

possible violations of the rules requirements and potential voltage imbalances caused by single-phase charging points.

This analysis evaluated the potential market and the likely penetration of electric vehicles in

Tasmania in the years 2013 and 2030. Penetration levels of three per cent, 10 per cent, 15 per cent,

20 per cent, 50 per cent and 75 per cent of total motor vehicle sales in the Tasmanian market were

considered. In the absence of a government incentive scheme and the current high price of electric

vehicles, it is likely that the uptake will be at the lower end of estimates in 2013. However, as the

technology advances, uptake should increase in the future.

The analysis showed that if all electric vehicles were put to charge at the same time (the worst case

scenario) the daily demand in Tasmania would vary from 7.7 MW to 193 MW in 2013 and from

9 MW to 229 MW in 2030. Energy requirements for electric vehicles were found to be very low,

ranging from 0.12 per cent to 3.07 per cent in 2013 and from 0.13 per cent to 3.63 per cent in 2030

of total energy consumption. The impact of electric vehicles on daily load profiles of substations or

distribution feeders would vary according to their location and on the electric vehicle charging

points within the network. To avoid creating new peak demand on distribution feeders and

substations, intelligent controls would be in place or incentives would be created to encourage

customers to distribute charging throughout the day. These measures would help to keep voltage

profiles within system standard requirements during maximum load and periods of charging and

discharging by electric vehicles. Interface devices should be designed to minimise, or even


Page 23

eliminate, the effect of these vehicles on the network. When communication with energy control

centres is in place, electric vehicles could be designed to operate as a part of a ‘smart grid’ to

provide network support and frequency and voltage control ancillary services.

Transend’s Grid Vision 2040 July 2011 Future generation planning in Tasmania

Page 24

5 Future generation planning in Tasmania

5.1 Introduction

This section considers the electricity supply contribution in Tasmania for 2008–09 and 2009–10

and examines potential generation sources that could make a greater contribution to the future

energy supply, in particular wind generation. Due to the size of the Tasmanian power system,

additional generation penetration could cause technical challenges in maintaining the secure

operation of the system if this generation is not able to contribute to:

Frequency control ancillary service;

Voltage control ancillary service;

Fault right through capability;

Inertial support.

If new generation is not able to provide these services and demonstrate these capabilities it could be

required that additional equipment is installed or alternatively these services and support could be

contracted from the existing service providers to enable connection to the grid.

5.2 Existing electricity supply in Tasmania

With six major water catchments and 27 hydro power stations, Hydro Tasmania is the largest

generator in Tasmania. The diversity of supply is provided by commissioning of gas fired power

station by Aurora Energy and imports via Basslink interconnector. Hydro generation contribution to

electricity supply in Tasmania is falling down (Marshall 2008) due to declining inflows in water

storages. Hydro Tasmania’s expected annual average yield from its water storages as at 2009

was 8,700 GWh, which was well below the 10,000 GWh target average yield in the past (Hydro

Tasmania 2009). The remaining portion of the required supply came from wind and gas-fired

generation and imports via Basslink.


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Figure 5 Electricity supply in Tasmania in 2008–09

Hydro power stations

Aurora Energy Tamar Valley gas power station

Basslink import

Woolnorth wind farm

The electricity supply–demand balance for 2008–09 (Figure 5) captures only a portion of the

Aurora Energy Tamar Valley gas generation (Transend 2010a).


Page 26

The 2009–10 electricity balance, (Figure 6), shows the increased contribution of gas power

generation following commissioning of Aurora’s combined cycle gas power station in

September 2009. The 2009–10 year also was better from a hydrological point of view, with the

contribution of hydro power stations to the supply–demand balance increasing and imports via

Basslink decreasing (Transend 2010a).

Figure 6 Electricity supply in Tasmania in 2009–10

Hydro power stations

Aurora Energy Tamar Valley gas power station

Basslink import

Woolnorth wind farm

5.3 Hydro generation

Managing declining water storage levels is not the only challenge facing Hydro Tasmania.

Management of its 27 hydro power stations, most of which have passed mid-life, also is demanding.

Maintenance of these hydro power stations is capital intensive and a significant capital investment

is required to keep them running. Hydro Tasmania has put forward a strategic plan to

capture 1,000 GWh of production through refurbishment, efficiency improvements and mini hydro

scheme developments. A capital works program has been put in place to invest $180 million by

2014 to capture the first 425 GWh per year of energy production (Connarty 2009).This timeframe

and the overall 1000 GWh rebuild program, could require a longer period for delivery.

The inherent flexibility in the operation of hydro power stations, their capability for quick starts and

shut downs and further developments in variable renewable generation offers new commercial

opportunities for Hydro Tasmania in the provision of ancillary services, such as frequency control,


Page 27

voltage support, inertia and fault ride through. This could support an increase in renewable

generation in the Tasmanian system in the future.

5.4 Gas generation

Aurora Energy’s Tamar Valley Power Station is the only gas-fired power station in Tasmania. A

plant of a similar size could be required in the south of the State in a high load growth development

scenario (Transend 2010b). However, the small physical size of the gas pipeline from Bell Bay to

Hobart, the drop in load forecast and focus on energy efficiency and demand side management, the

exposure to potential loss of a major point load and the future price of gas in the market create

uncertainties and less favourable market conditions for further large-scale gas generation

development in the south of Tasmania.

The Tasmanian gas network is under-utilised and there are opportunities to increase use of this

network through small-scale distributed generation, co-generation and other forms of energy usage

(Kirkpatrick 2009).

5.5 Wind generation

Wind power modelling and analysis of simulated data for six regions of Tasmania (3Tiers 2010)

focused on the large scale required to calculate bulk wind energy potential rather than on

identifying individual sites suitable for wind farm developments. The six regions—the west coast,

north-west, north-east, east coast, central and south—were sub-divided into 4.5 km x 4.5 km grid

cells. National parks, conservation areas, world heritage areas and protected areas were all excluded

from the analysis.

A Mesoscale Numerical Weather Prediction Model was configured and run over mainland

Tasmania for a 10-year period from January 2000 to December 2009 with 10 minute resolution to

establish long-term wind characteristics. The simulation confirmed that Tasmania has world class

wind resources. Figure 7 presents the plot of the long-term mean wind speed at 80 m above ground

level. The data is averaged over the entire 10-year period, from the start of 2000 to the end of 2009.

The 220 kV transmission network is also shown to illustrate the distance of good wind spots from

the main transmission network backbone. Several areas of the State have an average wind speed

above 8.0 m/s along with a wind capacity factor above 40 per cent.


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Figure 7 Mean wind speed at 80 m above ground level

Figure 8 shows the long-term mean capacity factor at 80 m above the ground level. The data is

averaged over the entire 10-year period, from the start of 2000 to the end of 2009.


Page 29

Figure 8 Mean capacity factor at 80 m above the ground level

Using the assumptions and methodology described on Page 27, the bulk energy potential in

Tasmania was estimated only for grid cells with a capacity factor greater than 40 per cent. The

results are shown in Table 2.


Page 30

Table 2 Estimated wind energy potential

Region Grid points with capacity factor ≥ 40%

Potential installed capacity

[MW]

Potential mean gross energy production

[GWh/year]

West coast 32 1,920 7,143

North-west 79 4,740 17,812

North-east 13 780 2,818

East coast 19 1,140 4,177

Central 167 10,020 39,446

South 101 6,060 25,350

ALL REGIONS 411 24,660 96,746

The figures in Table 2 show that the wind resource is not the limiting factor for wind generation

developments in Tasmania. This calculation assumes that all sites with a capacity factor greater than

40 per cent are available for wind generation development.

But, issues such as:

planning and environmental approvals;

the agreement of land owners;

land availability;

technical issues associated with wind generation integration;

transmission network capacity and access; and

the financial viability of wind farms;

need to be taken into account and could reduce the number of viable sites and consequently the

level of potential wind generation development.

Even when connected to the system, the maximum level of wind generation penetration in real-time

operation would be determent by factors such as: total system load, amount of conventional

generation committed and level of import over Basslink. In addition, due to the small size of the

Tasmanian system and the domination of hydro generation, further wind generation development

will require support, particularly in maintaining system security. Management of system issues such

as rate of change of frequency, fault level, as well as active and reactive power and voltage control,

requires innovation and the possible design of new ancillary services in Tasmania. Hydro power

stations are able to offer these services.

Alternative solutions such as: fly wheels, wind generation technology, DC technology, dynamic

reactive power devices were also considered.

One alternative solution to address some of these issues is shown in Figure 9. A fly wheel system

can suppress frequency fluctuations by realising or absorbing energy from the system by changing

speed of rotation (Akagi 1999). There has also been significant progress in wind turbine generator

development, and new equipment is now available on the market that is capable of providing

system performances similar to conventional synchronous generation (Miller 2010). Further

research and development is required in this field to enable alternative solutions and non-

synchronous generators to achieve the level of performances of conventional synchronous

generators.


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Figure 9 Rotary energy storage system

Courtesy of Toshiba


Page 32

5.6 Geothermal energy

Geothermal energy is the energy stored beneath the surface of the earth. For every 100 metres

below the ground, the temperature of the rock increases about three degrees Celsius. The heat is

extracted using water by natural or artificial means. There are two main types of geothermal

systems that can be used to generate electricity.

Figure 10 illustrates the currently available technology for geothermal energy generation, in this

case a 20 MW system in the United States (Lewis 2009).

Figure 10 Typical 20 MW geothermal plant

5.6.1 Hydrothermal systems

Hydrothermal systems have fluids circulating through rock pores or fractures (as a liquid or vapour)

in areas where high heat flow is present. These systems are often found near active tectonic plate

boundaries where volcanic activity has occurred, such as in Iceland, New Zealand and the

Philippines. Hydrothermal systems can also form above areas of hot basement rocks and it is this

type of system that is found in Australia. High-temperature hydrothermal systems are often

exploited for electricity generation, while low-temperature hydrothermal systems are more suited to

direct-use applications. Countries such as Iceland, which are situated in areas with a high

concentration of volcanoes, are ideal locations for generating geothermal energy. Over 26 per cent

of Iceland’s electrical energy is generated from geothermal sources. In addition, geothermal heating

is used to heat 87 per cent of homes in Iceland. Geothermal energy currently supplies 11 per cent of

New Zealand’s electricity needs (KUTh Energy 2010).

5.6.2 Hot rock systems

Hot rock systems do not have fluids naturally circulating through the rock and in most cases the

rock needs to be fractured to achieve the fluid flow required for heat transfer. Hot rock systems are

normally associated with granites that contain high concentrations of the naturally radioactive

Courtesy of KUTh Energy


Page 33

elements uranium (U), thorium (Th) and potassium (K). Although enriched with these elements

compared to other rocks, element concentrations are still relatively low (commonly ~0.002% U,

~0.01% Th and ~4% K). The radioactive decay of these elements over millions of years generates

heat, which is trapped when the granite is buried by insulating sediments. The thicker the insulating

layer, the hotter the temperatures. For example, granite at a three-km depth overlaid by insulating

sediments can be hotter than 200°C. Currently, a number of companies are exploring Tasmania's

geothermal resources. The geology in Tasmania is very favourable for ‘hot rocks’ geothermal

energy, which is supported by drilling done to date by companies like KUTh Energy and

Geothermal Energy Tasmania. KUTh Energy is undertaking exploration on the east coast as shown

in Figure 11 (Lewis 2009).


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Figure 11 Hot rocks target zones in Tasmania

KUTh Energy heat flow drill hole

Tenement boundary

Other drill hole

At this stage it is not clear what energy potential is in the ‘hot rocks’ that can be used for electricity

generation in Tasmania.

5.7 Biomass energy

Biomass energy is derived from three distinct energy sources: wood, waste and alcohol fuels. Wood

energy is derived both from the direct use of harvested wood as a fuel and from wood waste

SEL 26/2005

SEL 57/2008

SEL 45/2007

Nicholas Fingal inferred resource

Charlton Lemont inferred resource

Courtesy of KUTh Energy


Page 35

streams. The largest source of energy from wood is pulping liquor or ‘black liquor’, a waste product

from processes of the pulp, paper and paperboard industry. The most significant possible

development in Tasmania is the proposed Gunns Bell Bay pulp mill project. The project includes a

steam generator and turbine driven by burning forest biofuel to generate electricity. If it is assumed

that the pulp mill will use 100 per cent plantation eucalypts, the following capacity details of the

generators are (Poyry 2006):

total capacity 169 MW;

power consumption on site 107 MW; and

export power to the grid 62 MW

Figure 12 shows a 21.5 MW biomass plant in California that uses urban and agricultural wood

waste to generate power (US Energy Information Administration, 2009). Forestry Tasmania has

been considering two plants of a similar size, one in the south as a part of the integrated wood

processing yard near Huonville and a second in the north-west near Smithton.

International experience shows that stable and sustainable government policy is fundamental to the

successful development of renewable generation. Sweden has an optimistic renewable energy target

(50 per cent by 2020) in place. Also, its government is determined to make Sweden the world’s first

oil-free economy. With these policies in place, Sweden has been able to generate 32 per cent of its

overall energy from biomass (115,000 GWh) (the renewableenergyworld.com 2010).

Figure 12 Tracy Biomass 21.5 MW Plant, California

5.7.1 Waste energy

Waste energy is the second-largest source of biomass energy. The main contributors of waste

energy are municipal solid waste, manufacturing waste and landfill gas. Opportunities to exploit

waste as an energy source have been taken up by the landfill gas plants operating at Hobart and

Glenorchy council’s landfill sites. These two plants combined have a capacity of about 2.6 MW.

5.8 Wave power

The west coast of Tasmania is potentially a good source of wave power. Wave power devices

extract energy from the flux of the wave. A wave five metres in height has the energy flux of about

Courtesy of U.S Energy Information Administration Courtesy of U.S Energy Information Administration


Page 36

150 kW/m. Waves on the west coast are only above five metres for 10 per cent of the time, during

winter. Most of the time they are between two and four metres with the energy flux between 30-

100 kW/m. Wave devices do not capture all energy potential of waves. If it is assumed that they

capture only 10 per cent of the wave energy potential (4 kW/m), it would be necessary to install

1000 devices in total with a length of 300 km along the west coast to supply 1200 MW of average

load in Tasmania (Griffin 2009).

Recent developments by Ocean Power Technologies of 150 kW (see Figure 13 below) wave

generator and plans to increase the size to 500 kW suitable for wave power station parks and

already contracts signed for installations in the US, Spain, Ireland, England, Japan and Australia

making wave power more and more competitive against other renewable technologies. The

advantages of wave power are (Ocean Power Technology, 2011):

Wave energy is the most concentrated form of renewable energy, predictable;

Capacity factor of 30-45% ;

Environmentally benign & non-polluting;

No exhaust gases, no noise, minimal visibility from shore, safe for sea life;

Scalable to high capacity power stations (100 MW+).

Recently the Federal Government of Australia awarded to partnership of Ocean Power

Technologies Australasia (OPTA) and Leighton Contractors Pty Ltd a contract in values of

$66.5 million to build in three phases a 19.0 MW wave power project at Portland in Victoria. This

project is an opportunity to closely monitor wave power performances and efficiency.

Figure 13 Ocean Power Technology PowerBuoy wave power device

5.9 Ocean currents

Ocean currents have been identified as another potential energy source for electricity generation. At

this stage, ocean current potential is well behind wave power as an alternative source of renewable

energy.

Banks Strait, between the north-east tip of Tasmania and Clarke Island, has been identified as a

potentially suitable location for tidal power generation. This form of renewable generation is still in

the early stages of development. While it is not financially competitive with wind generation,

Courtesy of Ocean Power Technologies Courtesy of Ocean Power Technologies


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significant potential is available. At some stage in the future, when this technology becomes

financially viable and the issues of corrosion and maintenance are addressed, a sizable tidal

generating plant could be constructed in this area.

Figure 14 shows the first commercial tidal generator (1.2 MW) installed in Northern Ireland that

would be suitable for installation in Banks Strait (Griffin 2009). The possible hazard to shipping

and marine life from these structures will require careful management, but it is still a technology in

development and worthy of future consideration.

Figure 14 Tidal generator

5.10 Solar power

Some Australian Government initiatives, such as the Solar Homes and Community Plan, provide

cash rebates for the installation of solar panels on residential or community properties. Another

government initiative is a feed-in tariff that offers a premium rate to producers of renewable energy

via their solar power systems. At present there is no national feed-in tariff scheme and the rate paid

varies in each state and territory.

Energy Australia pays 60 ¢/kWh via a credit on its electricity bills to customers in New South

Wales, with the excess credit paid out on request after 12 months or upon termination of the

contract. In October 2010, the New South Wales Government announced that the 60 ¢/kWh feed-in

tariff would be reduced to just 20 ¢/kWh. A cap of 300 MW for solar generators connected under

the scheme was imposed as well (ESAA 2010).

Courtesy of Marine Current Turbines Limited


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Similar happened in Western Australia where the government in less than 12 months after unveiling

the initiative, revealed in the budget that it was halving the feed-in tariff for households with

photovoltaic cells (from current ¢40/kwh to ¢20/kWh). It was acknowledged by the West Australia

government energy minister that the scheme was unaffordable and very expensive exercise blowing

the budget 500 per cent in the cost (The West Australian, 2011).

In Tasmania, Aurora Energy currently offers a voluntary ‘net metering buy-back’ scheme for

installations up to 3 kW, at a rate equivalent to the relevant retail tariff. This means that if the

power and light Tariff 31 is offset by solar panel generation, customers will be paid 22.648 ¢/kWh

(this is 01 December 2010-30 June 2011 Aurora’s Tariff 31 energy value) for power provided back

to the grid.

Large-scale solar generation development is not currently competitive financially with other forms

of renewables, particularly wind. The potential good sites are very remote from the existing

transmission network and connection cost could be very high. Large-scale solar generation

development would be hard to justify in Tasmania due to less favourable weather conditions and

consequently a low solar generation capacity factor.

5.11 Future electricity supply in Tasmania

The electricity supply outlook for Tasmania up to 2040 was analysed for all 12 development

scenarios described in the Section 3. The supply outlook for Scenario 5 (medium load growth,

business as usual for water inflows in Hydro water storages and the introduction of a modest carbon

tax) is shown in Figure 15 (Transend 2010a). As shown on pie charts in Section 5.2, Tasmania

imported 26% in 2008-09 and 15% in 2009-10 of the overall electricity supply needs.

This situation could change if further wind generation development happened in Tasmania. This

development could be driven by the expanded renewable energy target and a carbon tax imposed on

high polluters. In this case, Tasmania would be able to meet the local supply needs and be an

electricity exporter (Figure 15, teal line). If additional wind generation development does not go

ahead, Tasmania will become more and more dependent on the continuous import of electricity

from the mainland. The import will gradually increase and reach value of around 3000 GWh per

year in this particular Scenario (Figure 15, cherry line). It is equivalent to 300 MW Basslink

capacity continuously required for import purpose (Figure 15, blue line, secondary axis).


Page 39

Figure 15 Supply outlook for Tasmania up to 2040 (for medium load growth with and without additional wind generation projects)

Renewable generation will become more and more competitive with technological progress. Still

financial viability of renewable generation is dependent on subsidies due to low capacity factor of

this technology. It is expected that introduction of the carbon tax and its possible slow rise in the

future will disadvantage high polluting technology in comparison with renewable technology. The

table below shows capital costs comparison for different generation technologies.

Table 3 Capital cost comparison for different generation technologies

Generation Capital costs in $ million/MW

Source

Supercritical Pulverized Black coal 2.676 ACIL Tasman report

Supercritical Pulverized Brown coal 3.571 ACIL Tasman report

OCGT without carbon capture and storage 0.985 ACIL Tasman report

CCGT without carbon capture and storage 1.368 ACIL Tasman report

CCGT with carbon capture and storage 2.359 ACIL Tasman report

Wind large scale (500 MW) 2.744 ACIL Tasman report

Wind medium scale (200 MW) 2.886 ACIL Tasman report

Wind small scale (50 MW) 3.178 ACIL Tasman report

Photovoltaic PV single axis tracking 5.100 ACIL Tasman report


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Generation Capital costs in $ million/MW

Source

Solar Thermal - Parabolic Trough without Storage 5.109 ACIL Tasman report

Geothermal - Hot Sedimentary Aquifers 6.600 ACIL Tasman report

Biomass small plant 1.5-4.0 Green World Investor

Biomass large plant 2.0-3.0 Green World Investor

Biomass cogeneration or combined heat and power 0.250 Green World Investor

Wave power 3.9 Ocean Power Technologies

Ocean current 11.0 Marine Current Turbines

Nuclear power 5.283 ACIL Tasman report

The costs of biomass generation fall in a very wide range because of the wide variety of fuel it uses.

The costs of biomass energy also depend on the distance of the fuel, how it is procured, managed

and used up by a biomass plant. Urban waste and waste wood are some of the cheapest forms of

biomass available. Co-generation plants or combined heat and power biomass plants located close

to sawmills or paper plants virtually have free fuel while standalone biomass plants which can use a

variety of fuel are quite expensive in nature (Green World Investor).

The latest market modelling (IES, June 2011) recognised that wind generation was the only existing

mature large scale renewable energy technology that would be able to meet a large scale renewable

energy target. The federal government has established a Solar Flagships Program ($1.5 billion

committed to establish up to 1000 MW of solar power generation capacity) to assist the

development of large scale solar power. However, there is no such equivalent scheme for

geothermal or other forms of renewable generation. Other forms of renewable generation such us

geothermal, wave, ocean current and hot rocks are still in an early stage of development. Some pilot

projects are in place and testing is under way. However, these projects cannot be financially

justified for large-scale development at present. Therefore, wind generation is the most likely

energy source that would be further developed in Tasmania in near future.

Transend’s Grid Vision 2040 July 2011 Future of main 220 and 110 kV corridors

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6 Future of main 220 and 110 kV corridors

6.1 Introduction

The core grid of the transmission network in Tasmania was designed for, and operates at, 220 kV as

shown in Figure 1. The 220 kV network started operation in 1957 when the first 220 kV line was

built between Waddamana power station and Burnie. Since then, the 220 kV network has expanded

to accommodate the development of new hydro power schemes in the 1960s, 1970s and 1980s.

As a part of the Grid Vision 2040 project the utilisation of the existing 220 kV core grid was

analysed. It was found that the condition of some assets such as steel reinforced aluminium

conductor (ACSR), particularly one installed on 220 kV sections in 1957, required attention. New

conductors now available on the market offer potential for transmission line upgrades as part of

long-term plans for the 220 kV core grid.

Commissioning of the new Waddamana–Lindisfarne 220 kV line, scheduled for mid 2011, offers

opportunities to reduce a number of 110 kV lines from the upper Derwent power stations. Some of

the 110 kV transmission lines connecting these power stations were built in the 1930s and 1940s

and rationalisation is required.

6.2 Utilising the existing 220 kV and 110 kV corridors

An analysis of all 220 kV corridors was performed to understand how much the lines were utilised

during the year. This analysis also provided information on stress levels in the transmission

corridors to determine the need, if any, to upgrade to a higher voltage, such as 275 kV or even to

330 kV (Transend 2010b).

Loading of the main 220 kV corridors was analysed for one year before the commissioning of

Basslink in 2006 and for four years following Basslink commissioning. Figure 16 shows the loading

of Sheffield–George Town No 1 220 kV line before and after the commissioning of Basslink.


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Figure 16 Utilisation of Sheffield–George Town No 1 220 kV line

In the four years following the Basslink commissioning, the average load of 220 kV lines in the

north of the state has been slightly reduced. This could be due to lower rainfall and the predominant

import of power from the mainland during 2007 and 2008. There was a visible increase, of short

duration, in trend of loading of these lines above the firm capacity (N–1 capacity). This could be

attributed to short-term opportunities for the export of power from Tasmania to the mainland during

favourable dispatching intervals for Hydro Tasmania. The years 2009 and 2010 showed increased

utilisation (indicated by the arrow in the Figure 16) due to improved rainfall levels. It is expected

that this trend will continue in the future until a significant amount of renewable generation is built

in Tasmania, which could then turn Basslink flow around.

The southern region of Tasmania currently has a close balance between available generation and

maximum demand. The power flow from north to south will slowly increase. This is due to the

increasing gap between available hydro generation and load growth in the region.

The analysis of utilisation of all 220 kV transmission lines indicates that there is spare capacity in

220 kV transmission lines to accommodate future load growth in Tasmania in a majority of the

scenarios. To use this capacity efficiently and load more and more 220 kV lines but manage risk

exposure, the enhancement of the existing tools and application of new technology is required. This

will be achieved by the:

further use of shunt reactive power compensation;

introduction of series compensation;

introduction of dynamic reactive power devices;

potential use of unified power flow controllers;

increased use of the dynamic line rating system;


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increased use of special protection schemes; and

use of synchrophasor measurements, wide area measurement and enhancement of energy

control and management systems with real-time application software.

Other options to be explored to increase capacity of the existing 220 kV lines include the use of:

new high temperature conductors with composite core or composite reinforced core; and

bundled conductors.

The introduction of higher voltage, 275 kV or 330 kV, would be hard to justify without a significant

increase in load or generation. The 330 kV system would require a completely different

transmission line design with a minimum of two conductors per phase. Consequently, new

transmission towers, foundations and new easements would also be required (Transend 2010b).

6.3 Asset condition assessment of existing 220 kV and 110 kV lines

A comprehensive assessment of the condition of all transmission line assets is a part of Transend’s

rolling five-year Transmission System Management Plans (Transend 2009). Some sections of the

transmission system are among the oldest in Australia. A total of 60 per cent of the transmission

support structures were constructed more than 40 years ago and approximately 20 per cent were

built more than 60 years ago. Since 1999, no new transmission assets at the 110 or 220 kV voltage

level have been built as part of the main transmission network backbone. The main concern is the

condition of the steel reinforced aluminium conductor, which makes up 63 per cent of all conductor

length in Tasmania. This was the conductor of choice in the past because of its good mechanical

and electrical properties. However, corrosion is affecting the durability and life expectancy of this

conductor. Figure 17 shows swelling detected on the Wesley Vale–Devonport 110 kV line, which

was installed in 1970.


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Figure 17 Swelling of steel reinforced aluminium conductor due to the development of galvanic corrosion

Some lines in the main 220 kV transmission backbone were installed in 1957 and there is concern

that conductors will reach the end of their useful lives by 2020. Options for their replacement with

new higher temperature, low sag and smooth body composite conductors now available on the

market are being considered.

6.4 Alternative conductors

Since 1999 Transend has been using all aluminium alloy conductors (AAAC) as default conductors,

when economically justified, for new transmission lines as well as for upgrade work and to improve

line ratings.

Future overhead augmentation work to address age and thermal limitations may require the

retention of existing towers with little or no reinforcement work. This would require the use of the

new conductor technology now available on the market.

Some typical types of new technology conductors are featured in Figure 18, including:

aluminium conductors with composite core and trapezoidal wire shape (ACCC/TW);

aluminium conductors with aluminium fibre composite reinforced core (ACCR); and

super heat-resistant aluminium alloy conductors with galvanized INVAR core (ZTACIR).

These conductors have low drag, low sag high operating temperatures and lower weight

characteristics than comparable ACSR or AAAC conductors.


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Figure 18 Alternative conductors for main core grid

General cable

Aluminium conductor with composite core

3M Aluminium

conductor composite

reinforced

Thermal resistant

aluminium INVAR

reinforced

6.5 Market constraints in existing 220 kV corridors

Transend’s Annual Planning Report (Transend 2010c) provides details about transmission network

performance, including data on market constraints. Constraints are reported as binding or violating

constraints. The table below summarises the constraints for 220 kV corridors over three years.

Table 4 220 kV corridor constraints in 2007, 2008 and 2009

Constraint Number of 5 min dispatching intervals

bound in 2007

Number of 5 min dispatching intervals

bound in 2008

Number of 5 min dispatching intervals

bound in 2009

Palmerston–Sheffield thermal constraint, no outage

30 988 5,790

Liapootah–Chapel Street thermal constraint, no outage

39 218 178

Liapootah–Chapel Street voltage stability constraint

121 201 156

Sheffield–Farrell thermal constraint, no outage

126 463 288

With the commissioning of the new Waddamana–Lindisfarne 220 kV transmission line in 2011, it

is expected that constraints on the Liapootah–Chapel Street 220 kV corridors will be resolved well

into the future. The Sheffield–Farrell 220 kV corridor limitation is related to the high west coast

generation scenario and is not a limiting factor during export when network control and the system

protection scheme is armed to allow higher then N–1 loading of the corridor. The main concern is

the limitation on the Palmerston–Sheffield 220 kV corridor.


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6.6 Farrell–Burnie–Sheffield–Farrell 220 kV triangle

The Farrell Substation on the west coast of Tasmania is a connection point to more than 620 MW of

hydro generation with only 80 MW of load connected. Therefore 220 kV corridor between Farrell

and Sheffield substations mainly export power to the rest of the system. This corridor in 2010 was

constraint for (Transend 2010c):

288 dispatching intervals in normal system configuration;

326 dispatching intervals during an outage; and

17 dispatching intervals due to transient stability conditions.

The existing arrangement is shown in Figure 19. It is proposed to establish a 220 kV Farrell–

Burnie–Sheffield–Farrell triangle as shown in Figure 20. The advantages of this development are:

enhanced security of supply to the Burnie area with an alternative 220 kV supply;

concerns regarding the old ACSR conductor are addressed;

concerns regarding voltage and transient stability on the west coast are addressed;

removal of market constraints on Sheffield–Farrell 220 kV corridor, opening opportunities for

the connection of additional renewable generation on the west coast to the grid;

increased capacity in the 220 kV network for large-scale load development and connection to the grid;

increased opportunities provided for the connection of renewable generation to the grid in the north-west; and

increased opportunities provided for a second Bass Strait DC link connection in the north-west.

Figure 19 Farrell–Burnie–Sheffield–Farrell 220 kV existing arrangement


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Figure 20 Farrell–Burnie–Sheffield–Farrell 220 kV proposed arrangement

6.7 Palmerston–Sheffield–George Town–Palmerston 220 kV triangle

The existing arrangement is shown in Figure 21. The Palmerston–Sheffield 220 kV transmission

line is a section of the first 220 kV line installed in Tasmania in 1957. It is a single circuit, flat

design structures 220 kV line with ACSR Goat conductor originally designed for 49 deg operation

but upgraded to 65 deg operation in 2002/03. This line loading is controlled by thermal and

transient stability constrained equations. In 2009 this line rating was bounding 988 dispatching

intervals and in 2010, 5,790 dispatching intervals as shown in the Table 3 above. Replacement of

this line with a new double circuit 220 kV line is proposed, as shown in Figure 22. The advantages

of this development are:

it addresses concerns regarding old ACSR conductor installed in 1957;

it provides an opportunity to convert the existing line to 110 kV operation which will

strengthen 110 kV network and enable establishment of a new connection point at Ashley, as requested by Aurora Energy;

concerns regarding system transient stability are addressed ;

the removal of market constraints on the Palmerston–Sheffield 220 kV corridor;

increased capacity in the 220 kV network for potential large-scale renewable generation development and connection to the grid;

it provides opportunities for a second Bass Strait DC link connection in the north-west;

enhanced security of supply to the greater Launceston area with the second 220/110 kV injection; and

space limitations and concerns for security of supply for the George Town Substation will be addressed with the establishment of George Town No 2 switchyard.


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Figure 21 Palmerston–Sheffield–George Town–Palmerston 220 kV existing arrangement

Figure 21 Proposed development options for Palmerston–Sheffield–George Town–Palmerston 220 kV triangle


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6.8 Palmerston–Waddamana 220 kV corridor

This corridor links the northern and southern 220 kV supply parts of the transmission network

backbone. The security of this corridor is of paramount importance to keep the Tasmanian

transmission network intact. A single asset failure in this corridor can split Tasmanian 220 kV

transmission network into two islands.

There are a number of old assets in this corridor that need decommissioning. The establishment of a

220 kV substation at Waddamana and a Waddamana–Lindisfarne 220 kV transmission corridor

provide an opportunity to ensure the layout at substations and this corridor arrangement meet our

long-term vision. Figure 22 shows when different assets were built in this area. Dotted lines show

assets that are not in service. Additional sections of 110 kV transmission lines 409 and 410, built in

1937 and 1939 respectively, are no longer in service and require decommissioning. This will create

the space required for a new double circuit 220 kV line in this corridor. The 1957 transmission line,

which operates partly as the 220 kV Liapootah to Waddamana section (TL 502) and partly as the

110 kV Waddamana to Palmerston line (TL 410), could then be used for potential renewable

generation connection.

Figure 22 Existing arrangement between Palmerston–Waddamana–Liapootah

The preferred configuration for this corridor is shown in Figure 23. The proposed new double

circuit 220 kV line should be the same design and capacity as the existing Liapootah–Palmerston

220 kV TL 527. This will strengthen the corridor and address issues of single asset failure and the

potential break-up of the Tasmanian system into north and south islands.


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Figure 23 Proposed future arrangement between Palmerston and Waddamana

6.9 Future supply for the greater Hobart area

The greater Hobart area is a major population and load centre in Tasmania. The maximum winter

load approaching 800 MW which is currently equally balanced by Gordon and lower and upper

Derwent river hydro power stations. Chapel Street Substation used to be the only 220 kV injection

in the area and Liapootah–Chapel Street 220 kV corridor used to be the only 220 kV supply

corridor to the area. Commissioning of the Waddamana–Lindisfarne 220 kV double circuit line and

the Waddamana and Lindisfarne 220 kV substations is scheduled for mid 2011. This will provide a

second 220 kV source and second 220 kV supply corridor to the greater Hobart area and address

security of supply issues to the capital city, as shown in Figure 24.


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Figure 24 Supply arrangements for the greater Hobart area in 2011

The 110 kV transmission lines connecting the upper Derwent River power station at Tarraleah, with

Tungatinah, Lake Echo and Derwent Bridge were built in the 1930s and 1950s. They have played a

vital role in ensuring security of supply to the area.

However, with the commissioning of the Waddamana–Lindisfarne 220 kV transmission line there

are opportunities to rationalise the 110 kV supply to the greater Hobart area and decommission

some or all of these old 110 kV lines.

One option could be to keep a mix of 110 kV and 220 kV supply. This mixed arrangement which

can be realised with establishment of 220/110 kV yard at Tarraleah is suitable to provide long-term

security of supply to the greater Hobart area. Another option is to maximise decommissioning of

old 110 kV lines by installation of one auto transformer 220/110 kV at Waddamana and

establishment of 220 kV yard and installation of one autotransformer at Tarraleah. This option will

increase utilisation of the new 220 kV asset installed at Waddamana and Lindisfarne. In the high

growth development scenario, additional 220 kV lines would be required with an option to build a

new Waddamana to Lindisfarne double circuit 220 kV line. These options must be assessed against

a potential gas-fired power station in the greater Hobart area, possibly located at Bridgewater or

Brighton. The proposed arrangement is shown in Figure 25.


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Figure 25 220 kV loop and rationalisation of 110 kV supply in the greater Hobart area

In addition to voltage stability management in the area, conditions of Liapootah–Chapel Street 220

kV lines ACSR Goat conductor installed in 1961 will stay main concern for secure supply in the

future. Potential extension of the 220 kV network from Lindisfarne to Risdon and closing a 220 kV

loop with Chapel Street will easy access to these assets for maintenance or replacement purpose.

6.10 Project details

The proposed projects to address issues in the main 220 kV transmission network backbone are

listed in Appendix 1. A more detailed analysis would be required to assess the scale and need for

each project.

6.10.1 Overall budgetary cost

A total capital expenditure of $585.3 million (in 2010 dollars) is needed to strengthen the main 220

kV and 110 kV transmission networks over a period of 25 years. This would be invested over the

following revenue reset periods:


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Table 4 Anticipated future revenue reset expenditure in 2010 dollars

Revenue reset

period

Anticipated capital expenditure: Base ($M)

Anticipated capital expenditure: With 30% contingency + allowances

($M)

2014–2019 166.2 236.1

2019–2024 77.8 109.3

2024–2029 147.1 206.0

2029–2034 136.9 191.6

2034–2039 57.3 80.2

TOTAL 585.3 823.2

Appendix 1 details the individual projects proposed for each revenue reset period.

Transend’s Grid Vision 2040 July 2011 Rationale for a second Bass Strait DC link

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7 Rationale for a second Bass Strait DC link

7.1 Introduction

This section examines the potential for the establishment of a second direct current (DC) link across

Bass Strait between Tasmania and Victoria. The performance of the existing DC interconnector

with Victoria is examined, followed by an explanation of the main drivers for a second

interconnector. A comparison between current and voltage source converter technologies is also

given.

Seven different options for a potential route across Bass Strait with a 220 kV or 500 kV connection

in Victoria were analysed. Some network upgrades in both Victoria and Tasmania would be

required to accommodate this link. This section finishes with a discussion about the best way to

develop the link, as a regulated or non-regulated (merchant) link. Market uncertainty, lack of stable

and sustainable policy and the risks facing a potential developer are not going to encourage private

sector to invest in a merchant link.

7.2 The existing Basslink interconnector

The existing Basslink interconnector between Tasmania and Victoria started commercial operation

on 29 April 2006. Since commissioning, the Basslink interconnector has been invaluable in

ensuring the security of supply in Tasmania. In the 2008–09 financial year, the import of electricity

through the Basslink interconnector contributed 26 per cent to the overall supply–demand balance

in Tasmania (Transend 2010d). The Basslink interconnector control scheme includes a frequency

control algorithm which, in addition to energy, enables the transfer of frequency control ancillary

services (FCAS) via Basslink. The energy and FCAS transfers are co–optimised as a part of the

AEMO dispatching engine algorithm. Due to a shortage of supply and particularly fast FCAS

services in Tasmania, Basslink’s operation can be constrained and occasionally Basslink can be

trapped on counter price flow. This does have an impact on the most effective use of this

interconnector, as the number of 5 minutes dispatching intervals on counter price flow is becoming

significant (2334 in 2008–09, Transend 2010d, 3587 in 2009–10, OTTER 2011).

7.3 Main drivers for a second DC interconnector

The main drivers for establishment of a second DC interconnector include the expanded renewable

energy target and introduction of an emissions trading scheme or carbon tax. It is expected that both

should encourage investments in renewable and gas fired generation. Tasmania with a reach wind

resources is a potential location for further wind generation development. This is confirmed by the

least-coast generation expansion planning done by AEMO as a part of the National Transmission

Network Development Plan 2010 (AEMO 2010). AEMO’s least-coast expansion tool models at

least 500 MW of wind generation in Tasmania under all scenarios, and a high of 2,050 MW under

the uncertain world scenario with low carbon price.

A second Bass Strait DC link would create opportunities for new entrants in generation and retail

sectors to trade across the link, addressing the current lack of competition in generation and retail sectors in Tasmania, and would enable additional transfer of FCAS services in the State.


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The need for construction of a new gas power station in Victoria could be delayed or removed

entirely and potential future carbon credit payments in Tasmania would be reduced. Fuel diversity

in the NEM would be increased and further interconnection in the NEM would be achieved.

7.4 Current source converter vs voltage source converter technologies

The Basslink interconnector was designed and built using current source converter technology. Due

to the characteristics of this technology, Basslink has a ‘no-go’ zone from –50 MW to +50 MW

inside which all FCAS services must be sourced internally from Tasmania. This can cause

occasional spikes in FCAS prices in Tasmania due to a shortage of supply of these services in the

State. Extraordinarily high FCAS costs occurred in Tasmania during the first three weeks of April

2009 (Transend 2010d).

Other disadvantages of this technology include commutation failure due to a disturbance in the

main grid supply and minimum fault level requirements because the technology depends on an

adequate short circuit ratio (SCR) between the network’s short circuit level and its own MVA rating

for stable operation.

Current source converter technology also requires reactive power and harmonic filtering. Each

converter station is equipped with several capacitor banks, which are located in large outdoor

switchyards. Other issues include temporary over voltage (TOV), particularly when connected to

weak AC systems as can occur in Tasmania, and voltage polarity reversal to change power flow

direction, which is a particular issue for long DC cable applications. In order for the Basslink cable to execute a power reversal sequence, a two minute de-energisation timeframe is required.

There is now a viable alternative to the current source converter technology, especially for long DC

cable applications. This new technology is based on voltage source converter technology, which has

already been applied in Australia for the Murraylink and Directlink interconnectors. Voltage

sourced converter technology has a number of advantages when compared with the current source

converter technology used in Basslink (Transend 2010d).

The new technology provides full control, with no additional reactive support required, and only

minimal filters, if any, are needed. Consequently, there is no temporary over voltage issue to

manage as this technology can operate at any power factor. Power reversal with this technology can

be achieved by reversing the DC current direction and it has bi-directional linear DC current,

eliminating dead zones.

It allows for the use of lower cost XLPE cables (ABB and Prysmian submarine and land cables, as

shown in Figure 26) and there is good harmonic performance when properly controlled. Improved

AC fault performance with no commutation failures means there is no need for minimum fault level requirements.

The new technology also provides more stability with weak AC systems and easier implementation

of multi-terminal and black-start capabilities. Power can be transmitted even with severely

imbalanced AC supply voltages and a smaller footprint is required because there is no need for

capacitor banks or filters.


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Figure 26 XLPE cables for DC links

Voltage source converter technology is applied in a multi-level design to achieve higher voltages

and higher power transfers. It is expected that the ratings for voltage source converter technology

for high voltage DC links will increase and the cost per MW of capacity will decrease.

7.5 Development options for a second Bass Strait DC link

Different development options to increase the transfer capacity between Tasmania and Victoria

were analysed. These included:

converting the existing Basslink interconnector to a bi-polar link; or

introducing alternative routes using new voltage source converter technology.

The existing Basslink interconnector was not designed to be a bi-polar interconnector. While it is

possible to convert the existing link to a bi-polar interconnector, this option does have some

disadvantages and risks (High Electrical Power Consulting 2010).

Seven alternative routes were considered from the north-west corner of Tasmania to western

Victoria. The main drivers for selection of these options were an attempt to reduce the total length

of the link and the potential for high load or generation connection points in Victoria. A multi-

terminal DC link with one additional connection at King Island also was considered. Figure 27

shows two of the seven potential routes analysed.


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Figure 27 Potential routes for second Bass Strait DC link

Main connections in Victoria are to the existing 500 kV Moorabool–Haywood corridor, potentially

at the Mortlake gas-fired power station or Shaw River gas-fired power station yards. Additional

generation projects are proposed in this part of Victoria, such as at Mortlake, Macarthur, Ryans

Corner and Hawkesdale, and the Mt Gellibrand wind farm and Tarrone gas-fired power station.

These could potentially lead to the establishment of new 220 and 500 kV connection points in this

area. The potential upgrade of this 500 kV corridor and the 220 kV triangle Terang–Ballarat–

Moorabool could be required, see Figure 28.

Shaw River Mortlake

230 km

Apollo Bay

West Montagu Cape Grim

Warrnambool

Point Henry aluminium smelter

Portland aluminium smelter Existing Basslink

Interconnector 290 km


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Figure 28 Potential network upgrades required in Victoria

A transmission network extension and deeper transmission network upgrades in Tasmania would be

required to realise full potential of this interconnector, as shown in Figure 29.

Figure 29 Potential transmission network upgrades required in Tasmania


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These deeper transmission network upgrades could be done in stages and can follow the level of

renewable generation development. There are currently a lot of interconnectors in size of 500 MW

in development stages around the world and this size was just used as an example in the Grid Vision

2040 development and National Transmission Network Development Plan 2010.

AEMO, as a part of the National Transmission Network Development Plan 2010, designed a

conceptual project called NEMLink which is envisaged for large-scale power transfers between all

NEM regions. The second Bass Strait DC link was included as a part of the NEMLink concept. The

level of the benefits observed and uncertainties related to carbon tax do warrant further

investigation and modelling and different scenarios creation for potential staged development of the

NEMLink concept (AEMO 2010).

Therefore, more detailed market simulation studies for calculation of market benefits with the

second DC link plus required deeper network upgrades in Victoria and Tasmania would need to be

performed against alternative options to demonstrate financial viability of this link. Steady state and

dynamic system studies also would need to be performed to understand the impact of this link on

the performance of both the Tasmanian and Victorian systems and any potential impact on the

existing Basslink operation. Also, preliminary planning issues, such as land availability, impact on

flora, fauna and marine reserves, and heritage issues, would need to be analysed to assess the actual

viability of this project.

7.6 Merchant or regulated link

The existing Basslink interconnector is a market service provider and non-regulated or merchant

interconnector. Even though the Basslink interconnector is not a regulated interconnector, revenue

from the facility is guaranteed through the Basslink Service Agreement between Basslink Pty Ltd

and Hydro Tasmania. This financial arrangement which underpinned Basslink’s development,

transfer all market-based inter regional revenue payments to Hydro Tasmania in return for the

payment of monthly facility fees. The financial arrangement, physical, trading and other

implications of the commercial arrangement between Basslink Pty Ltd and Hydro Tasmania are

central matters for a Tasmanian Electricity Supply Industry Expert Panel review which is now

underway (Electricity Supply Industry Expert Panel, 2011). The Basslink role in delivering

competition outcomes in the wholesale sector in Tasmania would be closely examined.

There is a safe harbouring section in the rules (Clause 2.5.2 (c)) providing for the later conversion

of a non-regulated interconnector to a regulated interconnector, which distinguishes Australia from

the rest of the world. However, lessons learned from the conversion of the Murraylink and

Directlink interconnectors to regulated interconnectors (Transend 2010d) indicate that the

Regulatory Investment Test for Transmission would be applied up front to test the financial

viability of potential future interconnectors. Other mechanisms could be put in place to protect

developers from the financial risk associated with the volatility of the market. Greater uncertainty,

unstable and non sustainable government policies and risk exposure would not encourage private

investments in a non-regulated or merchant interconnector.

Transend’s Grid Vision 2040 July 2011 North-west and west coast region

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8 North-west and west coast region

8.1 Introduction

This section describes the existing transmission system arrangement in the north-west and west

coast region, the main issues and drivers for transmission system development and proposed options

to address these issues. It also includes a list of envisaged projects for the next 30 years.

Both areas recently experienced a drop in electricity demand due to the closure of some major

industries, such us paper production and vegetable processing (Transend 2010e). The low price of

commodities on the international market, particularly zinc, copper, tin, nickel and silica, also has

had an impact on existing mining operations on the west coast, with some mines discontinuing

operations and put on care and maintenance. In addition, some proposed mining ventures have not

progressed far enough in the development stages to be considered as committed projects. However,

both areas offer opportunities for load development due to the extent of their natural resources and

access to port facilities. They also have the potential for the development of renewable generation

due to very good wind resources.

8.2 Existing transmission system arrangement

The north-west region includes Devonport and Burnie, the third and fourth largest population

centres in Tasmania. In addition to residential and small commercial loads, the region has a well-

developed agricultural sector. It is supplied from a single 220 kV switchyard at Sheffield

Substation. There is no alternative 220 kV supply to the region. The 110 kV transmission link

between Burnie, Hampshire and Farrell is weak and is kept open at Hampshire in normal system

operation as shown in Figure 30.

Figure 30 North-west region existing arrangement


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8.3 Main issues and drivers for development in north-west

Issues to be addressed to provide a more reliable and secure supply to the north-west include:

security of supply and load growth management in Devonport;

security of supply and load growth management in Burnie; and

voltage stability and voltage collapse management in the north-west.

In assessing the system, attention was also given to the requirements of the local Electricity Supply

Industry Regulation 2007, and in particular addressing a single asset failure event (resulting in

3000 MWh of unserved energy) which could affect several circuits in this area in the future.

Long-term forecasts for the north-west region indicate no significant load growth is likely in the

region in the next 30 years. The recent closure of Australian Paper factories at Wesley Vale (25

MVA load) and Emu Bay (15 MVA load) and the closure of the McCain vegetable processing plant

in Smithton were factored into the load forecast. However, these and other well-developed

industrial sites, including Port Latta, offer opportunities for alternative industrial load development.

8.3.1 Security of supply and load growth management in Devonport

Figure 31 shows current supply arrangements in the Devonport area. There is only one 110/22kV

injection point that supplies not only Devonport but a broad area around the city including the

Cradle Mountain tourist area to the south and Port Sorell to the east.

Figure 31 Devonport current supply arrangement

The load forecast shows no significant increase in winter load in Devonport in future years (0.6%

per year). Transend has recently upgraded all three transformers in Devonport (3x30 MVA), all

110 kV yards and switchgear and all 22 kV equipment, including a new switch house, and

protection and control gear. The main concern for the future is security of supply due to reliance on

a single injection point and only one 110 kV transmission line from Sheffield to Devonport. This

16.2 km double circuit line with Tern ACSR was built in 1969. To address these limitations, the

following options were considered:

the conversion of Wesley Vale Substation to 110/22 kV supply;

strengthening the 22 kV feeder ties between Devonport, Ulverstone and Railton substations; and


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establishing a 110 kV network tie with Palmerston, Hadspen or George Town.

The future proposed supply arrangement for Devonport is shown in Figure 32. Transend is working

with Aurora Energy to establish the best timeframe for the different stages of the development. The

reinforcement of 22 kV ties between Devonport and adjacent substations will increase utilisation of

the distribution network, which will require changes in the design of the main 22 kV feeder trunks.

With full automation in place, the transfer of load to adjacent substations through the distribution

network in the case of catastrophic failure of transmission assets will lead to more intelligent use of

the existing distribution and transmission assets without the need for a massive investment in the

transmission network.

Figure 32 Devonport future supply arrangement

Establishment of the Ashley 110/22 kV connection point for Aurora Energy, planned for 2017, will

enable preparation and planning for an alternative 110 kV supply to be provided from Palmerston

Substation. This alternative 110 kV supply could also include Railton Substation and would

increase security of supply to Railton, Devonport and Wesley Vale substations.

8.3.2 Security of supply and load growth management in Burnie

The current electricity supply arrangement in the Burnie area is shown in Figure 33. The Burnie

CBD is supplied by 11 kV feeders from Emu Bay Substation. This substation also was used to

supply the nearby Australian Paper factory, which closed in 2010. The rest of the Burnie area is

supplied by 22 kV feeders from Burnie 110/22 kV substation. This extensive area includes small

townships such as Penguin and Wynyard. Forecasts for the Burnie Substation show that the load at

Burnie already exceeds the firm 60 MVA supply and is envisaged to grow further to 86 MVA by

2040.


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Figure 33 Burnie area existing supply arrangement

Possible options to address this risk at the Burnie Substation include:

gradually phasing out the 11 kV network and converting Emu Bay Substation to 22 kV supply;

establishing a 110/22 kV connection point at Wynyard; and

establishing a 110/22 kV connection point at Penguin.

These three projects would meet load growth at Burnie Substation and keep the load below the firm

capacity, and reduce 22 kV feeder exposure by decreasing the number of customers connected to a

feeder, inherently improving reliability of supply.

The projects also would address the long-term future and security of supply to the Burnie CBD,

which would be converted to 22 kV and supplied from Emu Bay Substation with back-up available

from Burnie 22 kV feeders. Management of the capacity issue would be improved by sharing the

load between Port Latta, Burnie and Ulverstone areas, with new 22 kV injection points at Wynyard,

Emu Bay and Penguin.

Timing for these proposed developments will be coordinated with Aurora Energy.

Like Devonport, Burnie is supplied from the Sheffield 220 kV source. This means security of

supply from Sheffield will continue to be the main challenge in the future. Supply is available from

the Woolnorth wind farm in the north-west via the 110 kV network but it is not possible to operate

the Burnie area in an ‘island’ situation using this source. Alternative options for strengthening the

110 kV or 220 kV ties with other part of the network have been investigated, including reinforcing

the 110 kV supply from Farrell and creating a 220 kV triangle (Farrell–Burnie–Sheffield–Farrell).

The establishment of a 220 kV triangle with Farrell and Sheffield substations will remove current

market constraints on the Sheffield–Farrell 220 kV corridor and open opportunities for further


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development of renewable generation on the west coast. The proposed future supply arrangement at

Burnie is illustrated in Figure 34.

Figure 34 Burnie area future supply arrangement

8.3.3 Voltage stability and voltage collapse management in the north-west

With a radial, single 220 kV supply from Sheffield, the north-west region can be exposed to voltage

stability and voltage collapse issues in the case of loss of the Sheffield–Burnie 220 kV line. A

110 kV capacitor bank has been installed at Burnie and 22 kV capacitor banks at Port Latta and

Ulverstone to provide steady state reactive support. If renewable generation increases in the region,

particularly with the development of wind farms at Robins Island and Jims Plain and on the west

coast, a dynamic reactive power device will need to be installed in the region.

In developing Grid Vision 2040, market simulation and system studies have been undertaken

including wind generation penetration and a second direct current interconnector with Victoria. The

analysis shows that the considered dynamic reactive support in Burnie will provide invaluable

inertia and fault level contributions in addition to the fast voltage control and support in the area.

8.4 Existing transmission system arrangement on the west coast

The west coast of Tasmania is well known for its rich mineral and ore deposits, stretching from

Queenstown to Rosebery and Savage River. The mining industry started in the early 1890s and over

the years has experienced frequent ups and downs, depending on the fortunes of the commodities

market. With a pattern of mines closing and then re-opening, there is a lot of uncertainty in demand

forecasting. That makes long-term load forecasting for the mining industry, and the region as a

whole, a particularly daunting task.


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Exploration and investigations for new mineral deposits are continuing and it is likely that some

new supply points could be required while some existing ones could be closed.

Figure 35 shows the existing supply arrangement on the west coast. The region is supplied from the

Farrell 220/110 kV Substation. Farrell Substation is also a main connection point for more than 620

MW of Hydro Tasmania generation. The 110 kV network developed from this substation is a radial

network mainly supplying the mining industry at Queenstown, Rosebery, Que and Savage River.

There is only limited 110 kV supply from Burnie and this is not available in normal system

operation. There is an open point at Hampshire.

Figure 35 Existing west coast supply arrangement

8.5 Main issues and drivers for development on the west coast

To ensure the continuation of a reliable and secure supply to the west coast in the future, some

issues need to be addressed, including:

security of supply and potential load growth management in Rosebery;

security of supply and potential load growth management in Queenstown; and

voltage stability and voltage collapse management in the region.


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In assessing the system, attention was given to the Electricity Supply Industry (Network

Performance Requirements) Regulations 2007, in particular to single asset failure event

requirements (resulting in a 3000 MWh unserved energy loss), which could affect several circuits in

this area in the future.

Long-term forecasts provide no evidence of significant load growth in the region in the next 30

years. But price volatility of commodities on the international market requires consideration of a

broad spectrum of development options, from a ‘do-minimum’ approach to the potential

development of a 66 kV ring along the west coast.

8.5.1 Security of supply to Rosebery and Queenstown

To provide a secure supply to Rosebery and Queenstown in the future, the following options were

considered:

8.5.1.1 Maintain the existing 44 kV supply arrangement

This option envisages minor changes at the Rosebery and Queenstown substations to increase

security of supply and keep 44 kV voltage for the mining industry and Aurora Energy’s distribution

network. The potential development of a 220 kV triangle between Farrell, Burnie and Sheffield

substations could be triggered by the further development of renewable generation on the west

coast. This proposed arrangement, which is shown in Figure 36, also:

enables decommissioning of the old Queenstown–Newton 110 kV transmission line 406 built in 1936; and

provides for the establishment of a supply ring Farrell–Rosebery–Queenstown–Farrell with the installation of one 220/110 kV autotransformer at Queenstown.

This proposed arrangement keeps the existing 44 kV distribution network for Aurora Energy and

the mining industry. However, any new potential development will require extensions to the 44 kV

or 22 kV distribution network. There would also be an opportunity to close a loop between Zeehan

and Strahan on the west coast, but with a limited 22 kV network capacity.


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Figure 36 West coast future supply arrangement – 44 kV option

8.5.1.2 Introduce 66 kV voltage on the west coast

If the environment for mining developments on the west coast improves, more connection points

with load sizes not capable of being supplied by the 22 kV or 44 kV networks could be required. In

this case, one option would be to develop a 66 kV ring around the west coast with Aurora Energy

developing 66/22 kV zone substations to connect customers.

Upgrading supply voltage from 44 to 66 kV and establishing a 66 kV loop would require:

the establishment of 220/66 kV connection points at Farrell and Queenstown substations for Aurora Energy; and

the establishment of a 66 kV ring, with Aurora building 66/22 kV zone substations in Zeehan, Strahan, Renison, Rosebery and Mt Lindsay.

This option is shown in Figure 37.


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Figure 37 West coast future supply arrangement – 66 kV supply option

This option has the advantage of increasing the capacity of the network and providing for the

connection of bigger load points or renewable generation to the 66 kV network. Reliability of

supply to Strahan has been an issue for Aurora for some time and the closure of the 66 kV loop

would assist by providing firm supply. The biggest disadvantage of this option is cost and the

uncertainty of future load growth in the area driven by volatility of commodity prices in the

international market.

8.5.2 Voltage stability and voltage collapse management

Farrell Substation is a main connection point for more than 620 MW of power produced by Hydro

Tasmania power stations on the west coast. Voltage issues management previously has not been a

problem in this area due to the availability of generation. But since joining the electricity market it

has been observed that on some occasions all west coast generation could be out of service and not

scheduled. In addition, on some occasions the adjacent Mersey–Forth hydro generators also were

not scheduled. These market events left the west coast exposed without one synchronous generator

providing reactive power for voltage support. To date, Transend has not installed any steady state or

dynamic reactive power devices in this region. However, as part of the Grid Vision 2040

development, installation of a 110 kV capacitor bank at Farrell Substation for steady state reactive


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support was considered to cater for these events and at the same time reduce reliance on Hydro

Tasmania generators for the provision of this service.

8.6 Project details

The proposed projects to address issues in the north-west and on the west coast are listed in

Appendix 1. Further more detailed analysis would need to be performed to determine the exact

requirements and need for each project.


A total capital expenditure of $97.2 M is expected for proposed projects in the north-west and on

the west coast over a period of 25 years. This investment would be required over the following

revenue reset periods:

Table 5 Anticipated future revenue reset expenditure in the north-west and on the west coast (in $2010, base estimate and 30% contingency plus allowances estimate included)

Revenue reset period Anticipated capital expenditure:

Base ($M)

Anticipated capital expenditure:

With 30% contingency + allowances ($M)

2014–2019 11.8 16.1

2019–2024 8.8 12.7

2024–2029 47.5 67.9

2029–2034 12.5 16.7

2034–2039 16.6 24.7

TOTAL 97.2 138.1

Appendix 1 details the individual projects applicable to each revenue reset period.

Transend’s Grid Vision 2040 July 2011 North and north-east region

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9 North and north-east region

9.1 Introduction

The north and north-east region encompasses the greater Launceston, George Town and upper

Tamar area as well as the central Midlands and Scottsdale and Derby.

This section looks at the existing transmission system arrangement in the north and north-east

region, including the main issues and drivers for transmission system development, proposed

options and envisaged projects to be developed over the next 30 years.

9.2 The existing transmission system arrangement in the north and north-east

The existing transmission system in the north and north-east regions can be seen in Figure 38. The

region is supplied from Hadspen and Palmerston 220/110 kV injection points. The existing 110 kV

network that supplies 110/22 kV connection points for Aurora Energy at Hadspen, Trevallyn,

Mowbray, Norwood, Scottsdale, Derby, Palmerston, Avoca and St Marys substations is a radial

transmission network with only limited back up supply available through the 22 kV distribution

network. Access to these 110 kV transmission lines for maintenance and asset replacement is

difficult to achieve. There are opportunities for connecting renewable generation, particularly wind

generation in the north-east and potentially geothermal (hot rocks) on the east coast. But the limited

capacity of the 110 kV network will constrain renewable generation potential in this area.

Figure 38 North and north-east existing supply arrangement


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9.3 Main issues and drivers for development

A number of issues require attention in order to provide a reliable and secure supply in the north

and north-east, including:

meeting load growth in Launceston;

ensuring security of supply to the greater Launceston area;

ensuring security of supply to the north-east and accommodating connections for potential renewable generation;

meeting irrigation load growth in the Midlands area;

securing supply to George Town and providing for potential renewable generation connection; and

addressing voltage stability and voltage collapse management issues in the north.

During system studies, attention was given also to the requirements of the local Electricity Supply

Industry Regulation 2007 and in particular to single asset failure event requirements (resulting in a

3000 MWh unserved energy loss) which could affect several circuits in this area in the future.

9.4 Load growth management in Launceston

Forecast load growth in the Launceston CBD has been reduced in comparison with previous years,

but will still exceed the firm rating of some existing substations, particularly at Trevallyn,

Mowbray, Norwood and Hadspen. Transend and Aurora Energy have been managing the loading of

substations by balancing the load between them and using available transfer capabilities in the

22 kV distribution network. Transend and Aurora are developing one additional 110/22 kV

injection point at St Leonards and the creation of a 110 kV loop around the Launceston CBD. This

is scheduled for commissioning before the winter of 2012.

Additional connection points will be required to address load growth over the next 30 years.

Proposed new substations (Transend 2010f) include:

Ashley (Westbury) 110/22 kV;

Launceston CBD 110/22 kV;

Longford 110/22 kV; and

Exeter 110/22 kV.

These substations are shown in Figure 46 on page 76.

The proposed Ashley Substation will also facilitate the provision of an alternative 110 kV supply to

Wesley Vale and Devonport substations, which are at risk of losing supply due to a single asset

failure. The Ashley Substation could address the loading issue at Railton Substation as well

providing capacity for any potential new industrial developments. This strategy was discussed in

detail in the ‘Security of supply and load growth management in Devonport’ section on page 59.

9.5 Security of supply to the greater Launceston area

9.5.1 New 220/110 kV injection point into Launceston

Hadspen Substation is a main 220/110 kV bulk supply point into Launceston and to other parts of

the north-east. Supply from Palmerston 220/110 kV Substation is limited by the capacity of the


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single autotransformer and the 110 kV transmission lines connecting Palmerston to Launceston. In

the case of loss of supply from Hadspen Substation, the limited capacity of the 110 kV network

from Palmerston, together with generation from the Trevallyn Power Station, would not be

sufficient to pick up total load in the area and some load shedding would be unavoidable. To

overcome this problem and to ensure a reliable and secure supply to the greater Launceston area, in

the future, three options for the provision of a second 220/110 kV bulk supply point were analysed.

These included:

construction of a new 220/110 kV substation at Riverside close to the Trevallyn Substation;

construction of a new 220/110 kV substation at Longford where a new 110/22 kV substation is already proposed; and

upgrade of the Palmerston 220/110 kV substation and reinforcement of the 110 kV network to meet total load requirements for the area.

Figure 39 illustrates how either the Riverside or Longford substations would provide the second

220/110 kV bulk supply point.

Figure 39 Proposed arrangement with second 220/110 kV bulk supply points

9.6 Security of supply to the north-east

9.6.1 Scottsdale–Derby and Avoca–St Marys supply arrangement

Both the Scottsdale and Derby substations are supplied off a radial transmission line from Norwood

Substation. Avoca and St Marys substations are supplied off a radial transmission line from

Palmerston Substation. The loss of these transmission lines, or the need for scheduled planned

outages, would result in power interruptions to these areas due to the very limited supply available

through the 22 kV distribution network. The existing arrangement also limits opportunities for

Transend to access assets for maintenance purposes.

There are opportunities for connecting renewable generation in this area. The proposed Musselroe

wind farm will be connected to the Derby Substation. In addition, the area around St Helens has


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been identified as the site for potential wind farm and geothermal developments. However, the lack

of electricity infrastructure limits opportunities to realise renewable generation potential in the area.

There is also a concern about the condition of the Palmerston–Avoca–St Marys 110 kV

transmission line. The Palmerston–Avoca section was built in 1956 using copper conductor

(19/.083) with a very limited capacity, which is now approaching the end of its useful life.

Construction of a 110 kV loop in this region, together with a new substation at St Helens, is

proposed to resolve these issues. This would provide several important benefits such as:

enhanced security of supply by a 110 kV loop arrangement;

a new connection point to support future renewable generation;

a new connection point for Aurora Energy at St Helens Substation; and

improved access to assets for the replacement/augmentation of the Palmerston–Avoca–St Marys 110 kV single circuit radial line.

Figure 40 and Figure 41 show the existing and proposed transmission line arrangements in this area.

Figure 40 Existing Scottsdale and Avoca supply arrangement


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Figure 41 Proposed Scottsdale and Avoca supply arrangement

9.7 Load growth in the Midlands area

9.7.1 Proposed Tunbridge Substation

The Midlands area, which extends from Campbell Town to Ross and Oatlands, has been identified

for reinforcement. This will:

improve reliability of the 22 kV distribution feeders in the area; and

meet requirements to supply new irrigation load.

The Tasmanian Government is promoting Tasmania as the food bowl of Australia (Tasmanian

Government 2010). Therefore, the Tasmanian Irrigation Development Board was established by the

Tasmanian Government in September 2008 to progress a number of regionally significant irrigation

schemes in many parts of Tasmania. One potential water development scheme is the Midlands

Water Scheme, where water pumps and other electrical load will require a secure and reliable

supply (Tasmanian Irrigation Development Board, 2010). There are also plans for the development

of mini hydro generation schemes in the area.

There is no 110/22 kV injection point in the Midlands area and load there is supplied via long

22 kV feeders from Avoca, Palmerston, Sorell and Meadowbank substations. It is proposed to

construct a new substation near Tunbridge to be supplied from the Palmerston– Avoca 110 kV

transmission line to address above requirements. Figure 41 provides details of this proposal.

9.8 Security of supply to George Town

9.8.1 George Town area

The existing George Town Substation is a connection point for:

the Basslink interconnector with Victoria;

http://www.tidb.com.au/Projects.aspx?page=B536FD54-1B08-45F8-A739-6E0A54DDB1AA

http://www.tidb.com.au/Projects.aspx?page=B536FD54-1B08-45F8-A739-6E0A54DDB1AA


Page 75

Aurora Energy’s Tamar Valley open and combined cycle gas power stations;

major industrial loads including Rio Tinto’s aluminium smelter and Temco’s manganese

ferro-alloy plant; and

Aurora Energy’s retail load.

It is vital that security of supply to the George Town Substation is preserved at all times. The

substation has limited space for further expansion. The area is also very attractive as a site for major

industrial development (mining and wood processing) due to its port access.

This area also has good quality wind resources, low marginal costs and is close to electricity

infrastructure, making it suitable for the development of wind generation. In addition, Transend is

planning to install a dynamic reactive support device in the area.

Two options were considered for the establishment of a new 220 kV connection point in the George

Town area:

development of a new 220 kV switchyard at Long Reach; or

development of a 220 kV switchyard in Sidmouth.

Both locations are close to the existing Sheffield–George Town and Hadspen–George Town 220 kV

lines. The final decision regarding the preferred location will depend on the synergy of drivers for

development.

A new 110/22 kV substation is proposed at Exeter, which could help to manage retail load at the

George Town Substation by transferring and balancing load between these two injection points for

Aurora Energy. This new substation is shown in Figure 39 and Figure 46.

Figure 42 shows the proposed 220 kV arrangement including the potential Sidmouth and George

Town substations.

Figure 42 Options for the future 220 kV arrangement in George Town area


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9.9 Voltage stability and voltage collapse management in the north

9.9.1 Steady state and dynamic reactive support required

Due to the combination of high load, power generation and Basslink connection at George Town

Substation, maintaining voltage levels in the narrow band specified by customer requirements is a

major challenge. The proposed installation of a dynamic reactive power device at the George Town

Substation would have a range of benefits, including:

removal of the constraint on temporary over voltage when Basslink is on high export;

reduced risk resulting from a Basslink commutation failure, and removal of the constraint

based on providing a minimum fault level at the George Town 220 kV bus;

increased export capability from the west coast by providing additional reactive support at the

receiving end, particularly when either Basslink or generation in the George Town area is not available;

reduced risk caused by double circuit failure or circuit breaker failure; and

reduced risk of over voltage caused by the frequency control special protection scheme or under frequency load shedding scheme.

In its existing state, the system would struggle to survive a credible contingency if both west coast

generation and Basslink import were at a high level. The situation could become even worse if a

circuit breaker failure occurred. This is shown in Figure 43 and Figure 44 respectively, where

voltage instability and the time taken for voltage recovery are worse without the proposed dynamic

reactive power support at George Town.

Figure 43 George Town 220 kV voltage following a loss of Farrell–Sheffield No. 2 circuit

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0

Vo

lta

ge

(p

u)

Time (Seconds)

2pG @FASH cleared in 95 ms withoutSVC2pG @FASH cleared in 95 ms with SVC

2PG fault on FA-SH cleared in 95 ms without

dynamic reactive support

2PG fault on FA-SH cleared in 95 ms with dynamic

reactive support


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Figure 44 George Town 220 kV voltage following a circuit breaker failure at Sheffield

One potential option to address these issues is the installation of a new generation of synchronous

condensers as shown in Figure 45 (Marken 2009). The additional benefits that they can offer, such

as inertia, fault contribution, no harmonics generation, overloading capabilities and no impact on

Basslink operation, should be considered in the selection of the future dynamic reactive device to be

installed at the George Town Substation.

Figure 45 Synchronous condensers

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0

Vo

lta

ge

(p

u)

Time (Seconds)

1pG @FA-SH + CB fail without SVC

1pG @FA-SH + CB fail with SVC

Courtesy of General Electric

1PG fault on FA-SH + circuit breaker failure

without dynamic reactive support

1PG fault on FA-SH + circuit breaker failure with

dynamic reactive support


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9.10 Project details

Appendix 1 contains details of proposed future projects in the north and north-east along with

indicative timings and project costs.

Figure 46 shows the proposed north and north-east arrangement to be in place by 2040.

Figure 46 North and north-east proposed supply arrangement


A total capital expenditure of $480.9 M is expected in the north and north-east areas over a period

of 25 years. This will be invested over the following revenue reset periods:


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Table 6 Anticipated future revenue reset expenditure in the north and north-east (in 2010 $, base estimate and 30% contingency plus allowances estimate included)

Revenue reset period Anticipated capital expenditure: Base ($M)


with 30% contingency+ allowances ($M)

2014–2019 91.8 137.0

2019–2024 44.3 62.1

2024–2029 107.7 152.6

2029–2034 154.5 221.5

2034–2039 82.6 118.1

TOTAL 480.9 691.3


Transend’s Grid Vision 2040 July 2011 South and east coast region

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10 South and east coast region

10.1 Introduction

The southern part of Tasmania encompasses greater Hobart, Kingborough, New Norfolk, the

Tasman Peninsula and the east coast. This section considers the existing transmission system

arrangement in the area, the main issues and drivers for transmission system development, and

proposed options to address these issues. A list of envisaged projects in the area over the next 30

years also is provided.

10.2 The existing transmission system arrangement in the south and east coast

The existing transmission system in the southern area is shown in Figure 47. This area is supplied

from only one 220/110 kV injection point at the Chapel Street Substation. A second 220/110 kV

injection point at Lindisfarne Substation is under construction and will be commissioned in early

2011 together with a new 220 kV double circuit from Waddamana to Lindisfarne as shown in

Figure 24 ‘Supply arrangements for the greater Hobart area in 2011’ in Section 6 on page 49.

Aurora Energy takes supply from 33 kV subtransmission voltage at Creek Road, Risdon and

Lindisfarne 110/33 kV substations. The new 110/33 kV Mornington Substation is in the

construction stage and is scheduled for completion in mid 2011(Transend 2010g).


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Figure 47 Southern network existing supply arrangement

10.3 Main issues and drivers for development

To provide reliable and secure supply in the south and east coast region, a number of issues will

need attention in the future, including:

voltage stability and voltage collapse;

security of supply to Hobart;

load growth management in Hobart;

security of supply to Hobart’s eastern shore and load growth management at Sorell;

security of supply and load growth management in the Kingborough area; and

security of supply to the upper Derwent and load growth management at Bridgewater.

Although predicted load growth in the greater Hobart area is now reduced in comparison with

previous years, demand will still exceed the firm rating of some existing substations, particularly at

Creek Road, North Hobart and Kingston. Transend and Aurora Energy have been managing the

issue of loading of substations by balancing the load between them and using available transfer

capabilities in both the subtransmission and distribution networks. The 110/11 kV substations,


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including those at North Hobart, Chapel Street, Kingston, Bridgewater and Rokeby were built in the

1970s and 1980s and over the next 30 years will reach the end of their useful lives. The preferred

approach of both Transend and Aurora Energy is to continue to build up the 33 kV subtransmission

network in the area, reducing exposure of the 11 kV network.

Planning also takes account of the requirements of the local Electricity Supply Industry Regulation

2007, particularly in relation to single asset failure event requirements (resulting with 3000 MWh

unserved energy loss) which could affect several circuits in this area in the future.

10.4 Voltage stability and voltage collapse management in the greater Hobart area

10.4.1 Steady state and dynamic reactive support required

A comprehensive voltage stability study of the southern Tasmanian power system was undertaken

as a part of Transend’s 30+ year grid vision development (Hydro Tasmania Consulting 2009).

Without additional generation in the south and with the predicted ongoing load growth, voltage

stability management is a major challenge. Transend has been installing capacitor banks to ensure

the provision of steady state voltage support in the region for many years. The system relies heavily

on Hydro Tasmania generators for dynamic reactive support in the absence of any stand-alone

dynamic reactive support devices. The variability of generator dispatch in the Tasmanian power

system due to market behaviour, planned maintenance and water storage levels, suggests that the

reactive support expected in some areas may not always be available when it would be required in

emergencies to ensure voltage stability and avoid voltage collapse.

Gordon Power Station is the largest power station in the south. It also provides invaluable steady

state and dynamic reactive power support. However, recent prolonged planned outages and

unplanned shut downs of this power station exposed the region to the lack of valuable dynamic

voltage support.

The study recommended installing a first dynamic reactive support device for load levels during the

period between 2015 and 2020. The pros and cons of different types of dynamic reactive power

devices such as synchronous condensers, static VAR compensators (SVC) and static condensers

(STATCOM) were analysed.

One of the possible solutions is to install a new generation of synchronous condensers, as shown in

Figure 48 (Markel 2009). Synchronous condensers are characterised by the speed of their response

and their capacity to provide dynamic reactive power support and, consequently, voltage control to

reduce voltage fluctuations and prevent voltage collapse in the system. In addition, this unit

provides other valuable benefits such as fault contribution and contributes to the system inertia,

which are not provided by alternative power electronic devices such as SVCs or STATCOMs.


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Figure 48 New generation of synchronous condensers

The installation of synchronous condensers could significantly improve voltage control in the area,

providing a range of benefits such as:

additional reactive power support for winter maximum load > 960 MW;

reduced reliance on southern generation, particularly the Gordon, when the area load is high;

support for future renewable generator connections due to inherent inertia support;

contributing to minimum fault levels, keeping voltage step changes due to reactive power device switching within standards;

reduced risk from double circuit failure or circuit breaker failure events;

reduced risk of over voltage around the area caused by load shedding, due to either frequency control (FCSPS) or under frequency load shedding (UFLSS) actions; and

increased stability transfer limits from north to south to realise possible market benefits that

would not otherwise be possible.

Courtesy of General Electric


Page 84

Figure 49 shows voltage instability and the time for voltage recovery, with and without the

proposed dynamic reactive power support device at the Chapel Street Substation.

Figure 49 Chapel Street 220 kV voltage following a CB failure at Chapel Street

A single-phase-to-ground fault was simulated on the Liapootah–Cluny Tee–Chapel Street 220 kV

transmission line and a primary circuit breaker failure to open. The failure of the circuit breaker to

open resulted in a longer fault clearance time. Note that in this study the voltage did not return to

system minimum of 0.9 pu voltage without dynamic reactive support. With the use of a dynamic

reactive support device the voltage recovers to 0.8 pu within 800 msec.

Transend would continue to install capacitor banks for steady state reactive support depending on

the load growth in the area. Further engineering work is underway to gather more complete

information on design, location, costs and the benefits of implementing the first dynamic reactive

support device.

10.5 Security of supply to Hobart

10.5.1 Proposed 220 kV loop Lindisfarne–Risdon–Chapel Street

There is an opportunity in the future to close a 220 kV loop between Chapel Street and the

Lindisfarne Substation to further increase the security of supply to the Hobart CBD. Due to limited

space at Lindisfarne Substation, 220/110 kV transformers could be installed at Risdon Substation if

required in the future. The existing 110 kV crossing of the River Derwent between Risdon and

Lindisfarne substations was designed for 220 kV operation. The 220 kV section between Risdon

and Chapel Street substations could be entirely underground, or a combination of underground and

overhead line sections. The closure of this 220 kV loop would provide Transend with access to

Liapootah–Chapel Street 220 kV line for maintenance or conductor replacement work in the future.

The existing arrangement is shown on Figure 50 and the proposed arrangement in Figure 51.

1PG fault on LI-CLtee-CS + circuit breaker fail

without dynamic reactive support

1PG fault on LI-CLtee-CS + circuit breaker fail

with dynamic reactive support


Page 85

Figure 50 Supply arrangement with two 220 kV bulk supply points

Figure 51 Proposed arrangement with 220 kV loop completed

10.6 Load growth management in Hobart

The Hobart CBD is supplied from Creek Road and Risdon 110/33 kV injection points and from the

110/11 kV North Hobart Substation. The eastern shore is supplied from the Lindisfarne 110/33 kV

injection point and the 110/11 kV Rokeby Substation.

10.6.1 Existing Hobart 110/33 kV injection points and 33 kV subtransmission network

The 33 kV subtransmission network was established on the eastern shore in 1964 with the 110/33

kV Lindisfarne Substation as the only supply point. From 2000–2005, the 22 kV subtransmission

network on Hobart’s western shore was converted to 33 kV supply, with new 110/33 kV supply

points at Risdon and Creek Road substations.The existing arrangement is shown in Figure 52.


Page 86

Figure 52 Existing Hobart 110/33 kV injection points and 33 kV subtransmission network

10.6.2 Future new 110/33 kV injection points and 33 kV subtransmission network

Load forecasts indicate that new 110/33 kV supply points would be required at Bridgewater and

Cascades to ensure effective management of load growth, particularly at the 110/33 kV Creek Road

Substation and downstream on the West Hobart and Sandy Bay zone substations. The 110/11 kV

North Hobart Substation, which was commissioned in 1976, will also require attention in the next

15–20 years. There are options to convert it to 110/33 kV or to maintain it as a 110/11 kV injection

point by balancing the load with adjacent zone substations operated by Aurora Energy. Continuing

load growth in the Kingston area will require the eventual establishment of a Kingston 110/33 kV

supply point. The 33 kV subtransmission network will provide mutual support between these

substations and the necessary back-up supply in the case of the failure of the 110 kV network.

Transend has already committed resources to establish a 110/33 kV substation at Mornington as a

second 33 kV supply source for the eastern shore. This substation will reduce the load on the

Lindisfarne 110/33 kV and Rokeby 110/11 kV substations and enable Aurora Energy to further

expand the 33 kV subtransmission network in the area. The proposed future supply arrangement is

shown in Figure 53.


Page 87

Figure 53 Future 110/33 kV supply points and 33 kV subtransmission network

10.7 Security of supply to the eastern shore and load growth management at Sorell

10.7.1 Proposed 110 kV link between Sorell and Mornington substations

Both the new Mornington and Sorell substations are supplied off radial transmission lines

originating from the Lindisfarne Substation. With future load growth projections, the loss of these

transmission lines would result in no supply to these areas, which could exceed the local electricity

supply industry regulation requirements.


Page 88

In order to provide a secure and reliable supply to these areas, it is proposed to construct a new

transmission line to connect the Sorell and Mornington substations, which would result in a 110 kV

loop supply arrangement.

Figure 54 and Figure 55 show the existing and proposed transmission line arrangements in this

south-east.

Figure 54 Existing 110 kV supply arrangement from Lindisfarne

Figure 55 Proposed 110 kV supply arrangement from Lindisfarne

10.7.2 Conversion of Richmond Substation to 110/22 kV or 33/11 kV

It is proposed to establish a new terminal substation at Richmond around 2025 to align with the

need for a third circuit to Sorell from Lindisfarne. The combined Sorell and Triabunna loads would

exceed the 3000 MWh limit for unserved energy due to a single asset failure. This new substation

will be supplied from Lindisfarne. The Triabunna Substation could also be supplied from this new

110 kV switchyard. The establishment of this substation will provide several benefits including:

improving security and reliability of supply to the local distribution network;


Page 89

provision of a new connection point for the Triabunna transmission line, removing the risk of a fault on the existing Triabunna spur line affecting Sorell;

eliminating the need for a 22 kV sub-transmission line from Sorell to the Richmond zone substation;

removing the need to run a third 110 kV circuit to Sorell from Lindisfarne and the augmentation of the 110 kV bus at Sorell;

enabling the change from the existing 11 kV supply to the Colebrook area to 22 kV; and

supporting irrigation activities in the Coal River area, assisting the Tasmanian Government’s promotion of Tasmania as the food bowl of Australia.

An alternative option is to convert the existing Richmond 22/11 kV substation to a 33/11 kV

substation and to supply it from Lindisfarne Substation, with a potential 33 kV link to the

Cambridge 33/11 kV substation as shown in Figure 53.

10.7.3 Dunalley, Triabunna and east coast supply

The establishment of a substation at Dunalley will reduce load at the Sorell Substation as shown in

Figure 55. This will remove the need to augment Sorell Substation in 2032. Under this scenario, the

Dunalley Substation would be the supply point to the peninsula and southern beaches area and

would complement the existing Sorell Substation.

A substation at Dunalley, to be constructed around 2032, would also provide a connection point for

potential renewable generation on the Tasman Peninsula.

The load at Triabunna is less than 25 MW and so does not require a second transmission line to

satisfy firm rating requirements. However, there is a requirement to satisfy local electricity supply

industry regulation requirements for a potential of 300 MWh of unserved energy in the event of loss

of the existing radial Lindisfarne–Sorell–Triabunna single circuit. There are also asset issues with

the old ‘K’ towers on this circuit, which are approaching 100 years of age. Some of the ‘K’ towers

are second hand from the old Waddamana–Shannon transmission line, which was originally

constructed around 1916.

The establishment of a new substation at Swansea would provide a more reliable and secure supply

to the residents of the east coast. The proposed substation would be connected to both the Triabunna

and Avoca substations, providing a 110 kV loop supply up the east coast. This would provide an

alternative supply point for the Avoca Substation to be utilised when the Palmerston to Avoca line

is augmented to replace the ageing copper conductor and associated towers.

A substation at Swansea would also provide a connection point for any potential renewable

generation in the area.

10.8 Security of supply and load growth management in Kingborough area

There is concern that a single asset failure on the existing Chapel Street–Kingston transmission line

could exceed 3000 MWh of unserved energy. Work is under way to investigate the most cost-

effective method to remove this limitation. To provide a diverse transmission path to Kingston and

to overcome current problems in satisfying the 3000 MWh of unserved energy requirement due to a

single asset failure, it is planned to develop a new double circuit 110 kV transmission line between

Creek Road and Kingston using the old Creek Road–Electrona 88 kV easement path.


Page 90

This transmission line will also provide supply to the proposed 110/33 kV Cascades Substation to

be located in South Hobart. The Cascades Substation is required by Aurora to satisfy the growing

demand for power in the Hobart area and to overcome the potential overloading of existing

110/33 kV bulk supply points at Creek Road and Risdon substations.

A second 110 kV Knights Road–Kermandie transmission line may be required by 2040. This

proposal would potentially provide for connection to new bio-mass generation and also replace

ageing assets. Figure 56 and Figure 57 show the existing and proposed supply arrangements in the

area.

Figure 56 Existing 110 kV supply arrangement in the Kingborough area

Figure 57 Proposed 110 kV supply arrangement in the Kingborough area


Page 91

10.9 Security of supply to the upper Derwent and load growth management at Bridgewater

10.9.1 New Norfolk–Bridgewater 110 kV link

A new 110 kV transmission line between the New Norfolk and Bridgewater substations will be

required if transmission lines from Tarraleah–New Norfolk and /or Waddamana–Bridgewater are

decommissioned. This link between Bridgewater and New Norfolk substations will provide security

of supply in the event of the loss of a single asset and as a consequence exceeding 3000 MWh of

unserved energy at both New Norfolk and Bridgewater substations.

Installation of this 110 kV link from New Norfolk to Bridgewater would create a 110 kV ring

around the Greater Hobart area and provide increased security of supply.

Once the proposed New Norfolk–Bridgewater 110 kV transmission line is constructed the

Waddamana–Bridgewater circuit can be decommissioned. This will then allow for the re-

configuration of the Bridgewater to Lindisfarne line to provide a double circuit connection between

the two substations. Figure 58 and Figure 59 show the existing and proposed supply arrangements

in the area.

Figure 58 Existing 110 kV supply arrangement to upper Derwent area

Figure 59 Proposed 110 kV supply arrangement to upper Derwent area


Page 92

10.9.2 Proposed 110/33 kV Bridgewater Substation

Load growth in Hobart’s northern suburbs and in the Bridgewater and Brighton areas will increase

loading of Aurora’s 11 kV feeders and the 110/11 kV Bridgewater Substation. One option to

address this issue and improve asset condition at the substation over the next 30 years is to convert

it to 110/33 kV. This would require an extension of the 33 kV subtransmission network to Hobart’s

northern suburbs. At the same time, this will help to address loading at the Creek Road Substation

by transferring the Claremont Substation from Creek Road to this potential new 110/33 kV

substation at Brighton. Figure 53 provides more details.

10.10 Proposed projects

Details of the proposed projects in the south and on the east coast are provided in Appendix 1.

Figure 60 shows the proposed supply arrangement for the south and east coast in 2040. Further

more detailed analysis will be needed to determine the exact requirements and timing for each

project.

Figure 60 South and east coast proposed supply arrangement


Page 93


The estimated capital expenditure required to provide the south and east coast region with a more

secure and reliable supply is around $330.5 M ($451.7 M with a 30% contingency + estimation

allowance) for a period of 25 years.

This is expected to be invested over the following revenue reset periods:

Table 7 Anticipated future revenue reset expenditure in south and east coast (in $2010, base estimate and 30% contingency plus allowances estimate included)

Revenue reset period Anticipated capital expenditure:

Base ($M)


With 30% contingency + allowances ($M)

2014–2019 97.4 134.3

2019–2024 53.9 72.0

2024–2029 75.9 102.5

2029–2034 68.3 95.7

2034–2039 35.0 47.2

TOTAL 330.5 451.7


Transend’s Grid Vision 2040 July 2011 Future easement and site requirements

Page 94

11 Future easement and site requirements

Based on an analysis of potential future development options, it is necessary also to consider what

additional transmission line easement and substation sites may be required. Obtaining extensions to

existing easement or substation site footprints or to new easements or sites in the future could be

both time consuming and expensive.

Several transmission line easements and substation site land procurements may be required to

accommodate future grid arrangements. These are listed in individual area strategic plans. They

include:

Transmission lines:

Sheffield to Palmerston 220 kV

Sheffield to Burnie 220 kV

Farrell to Burnie 220 kV

Longford to Norwood 110 kV

Derby to St Helens to St Marys 110 kV

Bridgewater to New Norfolk 110 kV

Triabunna to Swansea to Avoca 110 kV

Tunbridge 110 kV supplied off the existing Palmerston–Avoca line

Substation sites:

Longford 220/110/22 kV terminal substation

George Town 2 220 kV switching station

Exeter 110/22 kV terminal substation

Riverside 220/110 kV terminal substation

Ashley 110/22 kV terminal substation

St Helens 110/22 kV terminal substation

Launceston CBD 110/22 kV terminal substation

Richmond 110/22 kV terminal substation

Cascades 110/33 kV terminal substation

Additional land at George Town for proposed dynamic reactive power devices

Once circuit routes and substation locations are identified work can begin to formally record

easement details to avoid delays in the future.

Transend’s Grid Vision 2040 July 2011 Conclusion

Page 95

12 Conclusion

Transend’s Grid Vision 2040 consolidates the findings from all the detailed strategic plans

developed for the future, including generation mapping, the future of core transmission grid,

rationale for a second Bass Strait DC link, and the future of supply to the north-west and west coast,

north and north-east and southern regions.

Wind atlas and wind energy potential calculated for Tasmania confirmed that the State has

significant wind energy resources. Depending on sustainability and design details of national

government renewable energy policies, wind energy could play a significant role in meeting the

supply–demand balance in Tasmania in the future as well as contributing to the achievement of

State and national renewable energy targets. Deeper penetration of wind generation, encouraged by

national renewable energy policies, will make Tasmania an energy exporter and could open

opportunities for an additional DC interconnector between Tasmania and Victoria. Progress in DC

technology has reduced the cost of new interconnectors significantly in comparison to just a couple

of years ago.

Our work indicates that in a majority of scenarios there is no need for an increase in transmission

network voltage to provide for higher capacity in transmission network backbone. This increase, if

required, can be achieved through the application of modern conductors and new technology and

innovations. This planned approach is supported by current reductions in load growth and concerns

that, with the inevitable increase in electricity prices, load growth will continue to moderate in the

future. Our vision, which includes the further development of the smart grid concept, encourages

customers to participate more directly in demand side management and contribute to the supply–

demand balance.

Transend’s Grid Vision 2040 focuses on better utilisation of existing assets and further application

of new technology and innovation. The proposed projects will increase ties in the existing network

and make it more resilient and flexible enough to respond to customer needs and requirements.

The Grid Vision document will be reviewed and updated on a regular basis to take account of

potential changes in customer behaviour in response to State, national and international climate

change policies, as well as global events that will shape the electricity supply industry in the future.

Transend’s Grid Vision 2040 July 2011 References

Page 96

13 References

3Tier 2010, Wind Power Modelling and Analysis of Simulated Output for Regions in Tasmania,

report for Transend D10/34713.

ACIL Tasman, 2010, Preparation of energy market modelling data for the Energy White Paper.

AEMO 2009, National Transmission Statement for the National Electricity Market,

http://www.aemo.com.au.

AEMO 2010, National Transmission Network Development Plan 2010, http://www.aemo.com.au.

Akagi, H, Hikaru, S 1999, Power Compensation Effect of an Adjustable–Speed Rotary Condenser

with a flywheel for a Large Capacity Magnet Power Supply, Proceedings of the 1999 Particle

Accelerator Conference, New York.

AEMC 2009, Review of Energy Market Frameworks in light of Climate Change Policies, 2nd

Interim Report by, 30 June 2009.

Connarty, M 2009, Future Energy Options for Hydro Tasmania, Royal Society of Tasmania Winter

Series Lectures.

Electricity Supply Industry (Network Performance Requirements) Regulations 2007.

Electricity Supply Industry Expert Panel, 2011, The Evolution of Tasmania’s Energy Sector-

discussion paper, April 2011.

ESAA 2010, ESAA welcomes decision to reduce feed–in tariff, media statement, 27 October 2010.

Grid Australia 2010, Grid Australia Submission to Transmission Frameworks Review:

AEMC Directions Paper – 26 May 2011.

Griffin, D 2009, Ocean Power–Waves and Tides, Royal Society of Tasmania Winter Series

Lectures.

Green World Investor, 2011, Costs of Biomass Energy and Biomass Plant Invesment – Wide Range.

High Electrical Power Consulting 2010, The role of HVDC in Tasmania’s Future Electrical Power

Grid, report for Transend, May 2010.

Hydro Tasmania 2009, Electricity in Tasmania ‘A Hydro Tasmania Perspective’.

http://www.hydro.com.au.

Hydro Tasmania Consulting 2009, Southern Region Dynamic Voltage Collapse Analysis, December

2009.

IES, June 2011, Insider, Issue 012.

KUTh Energy 2010, What is geothermal energy? http://www.kuthenergy.com/geothermal_energy/

Lewis, R 2009 Geothermal Potential in Tasmania, Royal Society of Tasmania Winter Series

Lectures.

Marken, P et al 2009, Dynamic Performance of Next Generation Synchronous Condensers at

VELCO, IEEE 2009.

http://www.aemo.com.au/

http://www.hydro.com.au/

http://www.kuthenergy.com/geothermal_energy/

Transend’s Grid Vision 2040 July 2011 References

Page 97

Marshall, D 2008, Storage Management and Drought, Royal Society of Tasmania Winter Series

Lectures.

Miller, N, Markel, P 2010, Facts on Grid Friendly Wind Plant, presented at IEEE PES General

Meeting, Minneapolis.

MMA Consulting 2009, The Tasmanian Wedges project, November 2009.

Ocean Power Technology, 2011, Company presentation in New York, March 2011.

OTTER, 2011, Tasmanian Energy Supply Industry Performance Report 2009–10, January 2011.

Poyry, 2006, Gunns Bell Bay pulp mill - overview of pulp mill operation.

Research Reports International 2009, Creating the Electric Grid of the Future, July 2009.

Therenewableenergyworld.com 2010, Biomass Generates 32% of All Energy in Sweden, June 2010.

The West Australian, May 21, 2011, Feed-in tariff for solar power slashed.

Transend 2010a, 30+ year grid vision–Strategic Plan for Generation Mapping, D10/28345.

Transend 2010b, 30+ year grid vision–Strategic Plan for 220 and 110 kV corridors, D10/12524.

Transend 2010c, 2010 Annual Planning Report, http://www.transend.com.au.

Transend 2010d, 30+ year grid vision–Strategic Plan for the 2nd

Bass Strait DC link, D10/89410.

Transend 2010e, 30+ year grid vision–Strategic Plan for North-West and West Coast, D10/83287.

Transend 2010f, 30+ year grid vision–Strategic Plan for North and North-East, D10/87047.

Transend 2010g, 30+ year grid vision–Strategic Plan for South and East Coast, D10/39451.

Transend 2010h, Future Impact of Electrical Vehicles on Transmission Grid, D10/57949.

Transend 2009, Transmission System Management Plans 2009–2014, December 2009.

Tasmanian Government 2010, Tasmania’s Innovation Strategy, www.development.tas.gov.au ,

2010.

Tasmanian Irrigation Development Board, 2010, www.tidb.com.au

The University of Reading, Definitions of Sustainability, www.ecifm.rdg.ac.uk.

US Energy Information Administration, 2009

http://www.eia.doe.gov/cneaf/solar.renewables/page/biomass/biomass.html

http://www.transend.com.au/

http://www.eia.doe.gov/cneaf/solar.renewables/page/biomass/biomass.html

Transend’s Grid Vision 2040 June 2011 Appendix 1: Project timeframes and estimated costs

Page 98

Appendix 1: Project timeframes and estimated costs

The following tables provide a summary of the most likely projects and the expected revenue reset

period in which they may be considered, together with estimated costs (in nominal $2010) for

individual projects. Not all potential projects are listed here. Alternative projects are listed and

discussed in more detail in individual strategic plans.

Table 8 Proposed development projects in 220 and 110 kV core grid

Strategic Project

No. Project title

Indicative timing (RCA)

Estimate level 1 ($M)

Base

+30% contingency plus allowances

6 Palmerston–Sheffield new DC 220 kV transmission line

2014–2019 88.3

124.0

7 Existing Palmerston–Sheffield TL 503 converted to 110 kV

2014–2019 3.5

5.1

9 Develop Waddamana 220 kV switchyard

2014–2019 5.8

8.3

10 Waddamana–Palmerston new DC 220 kV transmission line

2014–2019 68.6

98.7

1 Sheffield–Burnie new DC 220 kV transmission line

2019–2024 63.8

90.0

3 Farrell Substation double bus coupler arrangement

2019–2024 0.7

1.0

11 Restring second circuit on Liapootah–Waddamana TL 527

2019–2024 8.0

10.6

12 Decommission old TL 502 from Liapootah–Waddamana

2019–2024 5.3

7.7

2 Convert Palmerston 220 kV yard to triple busbar arrangement

2024–2029 4.6

6.5

13 Replace conductor on Liapootah–Chapel Street TL 500 with ACCC

2024–2029 43.5

60.9

14 Convert Chapel Street 220 kV yard to triple busbar arrangement

2024–2029 4.5

6.5

15 Convert Liapootah 220 kV yard to breaker and half

2024–2029 4.6

6.4

27 Farrell–Burnie new 220 kV DC transmission line

2024–2029 89.8

125.7

70 Establish 220/110kV yard at Tarraleah

2029–2034 43.4

60.9

71 Decommission 110 kV Tarraleah–New Norfolk TL 417

2029–2034 3.9

5.5


Page 99

Strategic Project

No. Project title



Base


75 Decommission 110 kV Waddamana–Bridgewater TL 400

2029–2034 7.1

9.9

16 Replace conductor on Hadspen–George Town TL 509 with ACCC

2029–2034 25.3

35.4

17 Replace conductor on Palmerston–Hadspen TL 509 with ACCC

2029–2034 16.0

22.2

18 Replace conductor on Sheffield–George Town TL 510 with ACCC

2029–2034 41.2

57.7

74 Decommission 110 kV Lake Echo–Waddamana, both sections

2034–2039 1.8

2.5

19 Replace conductor on Sheffield–Farrell TL 518 with ACCC

2034–2039 52.5

73.5

20 Convert Hadspen 220 kV yard to breaker and half

2034–2039 3.0

4.2

Table 9 Proposed development projects in north-west and west coast

Strategic Project

No. Project title



Base


109 Convert Wesley Vale Substation to 22kV supply for Aurora Energy

2014–2019 1.2

1.6

110 Convert Emu Bay Substation to 22kV supply for Aurora Energy

2014–2019 2.6

3.4

117 Redesign Newton 110 kV yard to H arrangement

2014–2019 6.1

8.5

119 110 kV capacitor Bank at Rosebery or at Farrell

2014–2019 1.9

2.6

116 Establish one 220/110 kV auto-transformer at Queenstown

2019–2024 6.8

10.2

118 Decommission old 110 kV TL 406 Queenstown–Newton

2019–2024 2.0

2.5

111 Wynyard 110/22 kV connection point for Aurora Energy

2024–2029 20.5

30.4


Page 100

Strategic Project

No. Project title



Base


113 Install synchronous condensers at Burnie

2024–2029 27.0

37.5

114 Establish 220/66 kV yard at Farrell for Aurora Energy

2029–2034 8.0

11.1

115 Establish 110/66 kV yard at Queenstown for Aurora Energy

2029–2034 4.5

5.6

112 Penguin 110/22 kV connection point for Aurora Energy

2034–2039 16.6

24.7

Table 10 Proposed network development projects in south and east coast

Strategic Project

No. Project title



Base


90 Creek Road to Kingston 110 kV DC TL

2014–2019 18.5

24.4

88 Sorell–Triabunna transline 110 kV

2014–2019 27.8

37.5

5 Synchronous condenser installation in the greater Hobart area

2014–2019, or

2019–2024

27.0

37.5

120 Restring second 110 kV circuit on Knights Rd–Kermandie TL No 436

2019–2024 13.9

18.1

83 Mornington–Sorell transline110 kV includes substation work

2019–2024 18.8

25.3

53 North Hobart 110/33 kV Substation

2024–2029 7.3

9.8

77 New Norfolk–Bridgewater transline110 kV includes substation work

2024–2029 21.2

28.6

40 Swansea Substation

110/22kV

2024–2029 19.6

26.5

39 Triabunna–Swansea transline110 kV includes substation work at Triabunna

2024–2029 29.4

39.7

93 Richmond Substation

110/22kv or 33/11 kV zone sub

2024–2029 19.6

26.5


Page 101

Strategic Project

No. Project title



Base


79 Establish 220 kV underground link between Chapel Street and Risdon

2029–2034 47.1

66.0

72 Establish 220/110 kV yard at Risdon and convert existing Risdon–Lindisfarne 110 kV lines to 220 kV operation

2029–2034 21.2

29.7

89 Cascades Substation 110/33 kV includes transline cost

2029–2034 24.1

34.9

48 Dunalley Substation

110/22kv

2034–2039 16.4

22.1

47 Sorell–Dunalley transline110 kV includes substation work at Sorell

2034–2039 18.6

25.1

Table 11 Proposed network development projects in north and north-east

Strategic Project

No. Project title

Indicative timing(RCA)


Base


8 New Ashley 110/22 kV Substation

2014–2019 17.0

30.0

96 New Tunbridge 110/22 kV Substation

2014–2019 17.4

25.3

97 Tunbridge transline off Palmerston–Avoca 110 kV DC

2014–2019 28.2

40.9

101 Avoca–St Marys new DC 110 kV line strung SC initially

2014–2019 26.0

36.5

69 Synchronous Condenser at George Town

2014–2019

or

2019–2024

29.2

40.8

94 New Longford sub 110/22 kV 2019–2024 18.2

25.5

31 George Town 2 new substation (220 kV Gunn’s Substation)

2019–2024 26.1

36.6

32 Derby–St Helens new 110 kV DC

2024–2029 34.8

50.4

33 St Helens–St Marys new 110 kV SC

2024–2029 25.2

36.5


Page 102

Strategic Project

No. Project title

Indicative timing(RCA)


Base


34 St Helens new substation (110/22 kV)

2024–2029 15.3

21.4

95 Hadspen–Trevallyn string second side of 471

2024–2029 2.2

3.0

104 Derby 110 kV Substation expansion for DC to St Helens

2024–2029 9.4

13.2

106 St Marys Substation 110/22 kV to accommodate SC from St Helens

2024–2029 3.7

5.2

107 Avoca Substation 110/22 kV 2024–2029 17.1

22.9

38 Avoca–Swansea new 110kV SC 2029–2034 38.5

55.8

41 Palmerston–Avoca new 110 kV DC strung SC (for wind and replace old SC copper conductor)

2029–2034 Strung single cct.

37.9

53.1

98 Launceston CBD new 110/22 kV sub

2029–2034 15.9

22.2

100 Mowbray–Launceston CBD–St Leonards new 110 kV U/G SC

2029–2034 13.2

19.2

102 Ashley–Wesley Vale new 110 kV DC strung SC

2029–2034 31.6

45.9

103 Scottsdale Tee–Derby 110 kV. String second side of poles

2029–2034 3.4

4.9

44 Riverside–Trevallyn new 110 kV DC

2034–2039 5.5

8.0

52 Riverside new 220/110 kV sub 2034–2039 44.3

64.3

45 Riverside–Exeter new 110 kV DC

2034–2039 15.5

21.6

46 Exeter new sub (110/22 kV) 2034–2039 17.3

24.2

Transend’s Grid Vision 2040 June 2011 Appendix 2: Future transmission lines and substations

Page 103

Appendix 2: Future transmission lines and substations

The following tables detail proposed new transmission lines and substations required by the year

2040 to ensure Tasmania continues to have a secure and reliable transmission network. The

timeframe for each project differs and costs will be spread over the relevant revenue reset periods.

Table 12 Proposed new transmission lines

Voltage kV

Proposed Transmission lines Area

220 Burnie–West Montague–new double circuit (SENE–Scale Efficient Network Extension) (alt. path Hampshire 2 to West Montague)

north-west

220 Farrell–Burnie via Hampshire 2–new double circuit north-west

220 Hampshire 2–Sheffield– new double circuit (as an option to Sheffield to Burnie line)

north-west

220 Sheffield–Palmerston–new double circuit (alt. path Sheffield to Waddamana) north-west

220 Sheffield–Burnie–new double circuit, replace existing 220 kV line (TL No 504)

north-west

220/110 Sheffield–Palmerston 220 kV line (line No 503) convert the existing one to 110 kV operation; alternatively leave at 220 kV as third circuit

north-west

110 Ashley–Wesley Vale–new circuit (option to connect via Railton) north-west

220 Reece–Pieman–new double circuit (SENE–Scale Efficient Network Extension) west

220 George Town 2–Bridport–Musselroe–new double circuit ( SENE–Scale Efficient Network Extension )

north

220 Waddamana–Palmerston–new double circuit lines 3 & 4 north

220 Waddamana–Palmerston–decommission old T/L 502 north

110 Exeter–Hadspen–new double circuit utilising existing Trevallyn–Hadspen 413 (or new connection Exeter to Riverside)

north

110 St Leonards–Launceston CBD radial underground. (alt. break into 110 kV ring Mowbray–St Leonards or radial from Trevallyn)

north

220/110 Chapel St–Kingston–(initially run as third circuit link 110 kV) or Creek Rd– Kingston @ 110 kV third and fourth circuits.

south

220/110 Gordon–Chapel Street Tee–Kingston 220 kV or New Norfolk–Kingston 110 kV (SENE–Scale Efficient Network Extension)

south

220 Liapootah–Waddamana–restring No 1 on No 2 line towers from Liapootah up to Waddamana

south

220 Tarraleah–in and out of Liapootah–Waddamana T/L 502 south

220 Chapel St–Risdon–Lindisfarne Link (convert existing Risdon–Lindisfarne 110 kV lines to 220 kV operation) (option into Creek Rd)

south

110 Palmerston–Tunbridge–Avoca, (new connection at Tunbridge) south

110 Lake Echo–Waddamana–decommission portion of TL 425 and 426, No 1 and No 2

south

110 Tarraleah–Meadowbank–New Norfolk–decommission old TL No 418, and construct new DC 110 kV line

south


Page 104

Voltage kV

Proposed Transmission lines Area

110 Tarraleah–New Norfolk–decommission No 417 TL south

110 Waddamana–Bridgewater–decommission old 110 kV TL No 400. south

110 New Norfolk–Bridgewater–new 110 kV circuit south

110 Mornington–Sorell–new circuit south

110 Sorell–Dunalley–new circuit south

110 Triabunna–Swansea–new circuit east

110 Avoca–Swansea–new circuit east

110 Derby–St Helens– new circuit (include Pyengana (SENE–Scale Efficient Network Extension )

east

110 St Marys–St Helens–new circuit east


Page 105

Table 13 Proposed new substations

Voltage kV Proposed substations Area

220 West Montague (SENE–Scale Efficient Network Extension )–establish 220 kV switching station

north-west

220/22 Hampshire 2 Substation–establish 220/22 kV substation (SENE–Scale Efficient Network Extension)

north-west

110/22 Penguin Substation–establish 110/22 kV substation north-west

110/22 Wynyard Substation–establish 110/22 kV substation north-west

220 Pieman (SENE–Scale Efficient Network Extension)–establish 220 kV switching station

west

220 George Town 2 substation–establish 220 kV switching station (alternatively Sidmouth)

north

220 George Town 2 Substation–install Dynamic Reactive Power Support north

220 Bridport (SENE–Scale Efficient Network Extension)–establish 220 kV switching station

north

220/110 Musselroe–establish 220/110 kV substation north

220/110 Riverside Substation– establish 220/110 kV substation (alternative to Longford)

north

220/110/22 Longford Substation–establish 220/110/22 kV substation (In/Out HA–PM T/L) (alternatively only 110/22 kV if Riverside goes ahead)

north

220/66 Sidmouth–establish 220/66 kV (alternative to Exeter and requires establishment of 66 kV sub–transmission by Aurora)

north

110/22 Exeter Substation–establish 110/22 kV substation north

110/22 Launceston CBD–establish 110/22 kV substation north

110/22 Ashley (Westbury)–establish 110/22 kV substation (alternatively 220/22 kV) north

220 Waddamana– establish 220 kV switching station south

220 Hermitage (SENE–Scale Efficient Network Extension) establish 220 kV switching station

south

220 Maydena Tee establish 220 kV switching station south

220/110 Tarraleah–establish 220/110 kV substation south

220/110 Risdon–establish 220/110 kV substation south

220/110 Kingston–establish 220/110 kV substation south

110/33 McRobies Gully off CS–KI or Cascades off CR–KI–establish 110/33 kV substation

south

110/22 Tunbridge– establish 110/22 kV substation south

110/22 Dunalley–establish 110/22 kV substation south

110/11 Richmond–establish 110/22 kV (could be also 33/11 kV for Aurora) substation

south

110 Chapel St–install dynamic reactive power device (alternative location could be at Risdon or Creek Road)

south

110/22 Swansea–establish 110/22 kV substation east

110/22 St Helens–establish 110/22 kV substation east


Page 106

Voltage kV Proposed substations Area

110 Pyengana (SENE) establish 110 kV switching station east

Transend’s Grid Vision 2040 June 2011 Appendix 3: Abbreviations

Page 107

Appendix 3: Abbreviations

AEMO Australian Energy Market Operator

DC Direct Current

NTNDP National Transmission Network Development Plans

RITT Regulatory Investment Test for Transmission

VUCA Volatility, Uncertainty, Complexity, Ambiguity

NEM National Electricity Market

ACSR Aluminium Conductor Steel Reinforced

AAAC All Aluminium Alloy Conductors

ACCC/TW Aluminium conductors with composite core and trapezoidal wire shape

ACCR Aluminium conductors with aluminium fibre composite reinforced core

ZTACIR Super heat resistant aluminium alloy conductors with galvanized invar core

FCAS Frequency Control Ancillary Services

XLPE Cross-linked polyethylene

SVC Static VAr Compensator

STATCOM Static Synchronous Compensator

FCSPS Frequency Control Special Protection Scheme

UFLSS Under Frequency Load Shedding Scheme

CBD Central Business District

PU Per Unit

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