Transend Networks. Annual Planning Report

Transcription

1 Transend Networks Annual Planning Report

2 CONTACT This document is the responsibility of the Customer & Asset Strategy department, Transend Networks Pty Ltd, ABN COMPANY INFORMATION Transend Networks Pty Ltd Registered office: 1 7 Maria Street, Lenah Valley, Tasmania 7008 Postal address: PO Box 606, Moonah,Tasmania 7009 PUBLICATION DATE 30 June 2012 Document Control Version 1 Telephone: reception@transend.com.au Overseas callers: Internet: Facsimile: This Annual Planning Report is published by Transend Networks Pty Ltd, in compliance with clause 5.6.2A of the National Electricity Rules and Transend s obligation under the terms of Transend transmission licence. It has been prepared in good faith using, inter alia, information and reports provided by other electricity market participants, and load forecasts that may or may not prove to be correct. Although this report is published to help electricity market participants and other interested parties to assess future need for electricity generating capacity, demand management capacity or augmentation of the power system, reliance should not be placed on the information contained in it. Transend Networks Pty Ltd makes no representation or warranty as to the reliability, accuracy, completeness or fitness for any purpose of this report. Except insofar as liability under any statute cannot be excluded, Transend Networks Pty Ltd, its employees, agents and consultants will not in any circumstances be liable to any party for any consequence of the use of this report. Transend Networks Pty Ltd 2012 Page 1

3 Table of contents Executive Summary A changing Tasmanian outlook Electrical energy and demand forecasts New generation connections Transmission system constraints Load reductions Completed and committed projects Feedback Background Responsibilities Purpose of the Annual Planning Report Planning horizon and uncertainty Impact of climate change policy on demand and energy Tasmanian transmission system Transmission system overview Basslink Transmission line ratings Tasmanian supply reliability Introduction Transmission network reliability Transmission plant availability Significant network incidents National flow path developments and existing Tasmanian transmission constraints Introduction National Transmission Network Development Plan National Transmission Flow Paths NEMLink Transmission network developments identified in the NTNDP Transmission network constraints Highlights of existing constraints on major transmission system elements Constraint equations affecting Basslink Tasmanian developments that could impact on Basslink flows Transend Networks Pty Ltd 2012 Page 2

4 2.5.1 Increased wind generation Supply demand outlook Introduction Energy and demand forecasts Carbon Price Mechanism Area load growths Forecast energy generation and sales Maximum demand forecast Comparison of extrapolated and econometric forecasts Back casting Reactive power demand Demand profile Supply demand balance Existing generation capacity Generation developments Capacity balance Energy balance Completed, committed and advanced network augmentations Introduction Completed projects Sheffield Burnie 110 kv transmission line augmentation Paloona Tee to Burnie Substation OPGW Tungatinah Substation 22 kv switchgear replacement and associated works Kingston Substation new 110/33 kv connection point Farrell Substation to John Butters Power Substation OPGW St Leonards Substation development Norwood St Leonards Mowbray 110 kv transmission circuit Committed projects Rosebery Substation 110 kv augmentation George Town Substation 220 kv security upgrade Sheffield Substation to George Town Substation OPGW Palmerston Substation 110 kv redevelopment Arthurs Lake Substation redevelopment Newton Substation redevelopment Burnie Substation 110 kv redevelopment Transend Networks Pty Ltd 2012 Page 3

5 4.3.8 Creek Road Substation 110 kv redevelopment Tungatinah Substation 110 kv redevelopment Advanced projects Proposed network developments Introduction Forecast constraints and proposed developments West coast area development plan North-west area development plan George Town area development plan Northern area development plan Southern area development plan Quantification of constraints Connection point proposals New generation proposals Connection enquiries from Aurora Connection enquiries from other load customers Replacement transmission network assets North Hobart 11 kv switchboard replacement Telecommunications Other relevant Tasmanian issues Power quality Transend objectives Performance criteria Planning levels and strategies Ongoing program of works Performance monitoring Ancillary services Summary Frequency control ancillary services Network support and control ancillary services (NSCAS) System restart ancillary services Reserves capacity Minimum reserve levels Fault levels Operations and maintenance Operational issues Transend Networks Pty Ltd 2012 Page 4

6 6.6.2 Access for maintenance System losses Appendix 1: Load forecast NIEIR Tasmanian forecast Substation forecasts Appendix 2: Power station data Appendix 3: Hydro water storages Definitions of water storages Appendix 4: Criteria for assessment of project commitment Committed projects generation Committed projects transmission Advanced projects Proposed projects Appendix 5: Terminal substations Appendix 6: Fault levels Appendix 7: Tasmanian geographical areas Appendix 8: Network Performance Requirements - Tasmania Appendix 9: Planning process Appendix 10: Abbreviations Transend Networks Pty Ltd 2012 Page 5

7 List of tables Table 1.1 Transmission network loss of supply performance Table 1.2 Transmission plant availability Table 2.1 Tasmanian transmission development 10-year summary Table 2.2 Guiding criteria for categorising transmission network developments occurring in the first 10 years Table 2.3 Comparison of 2010 and 2011 binding constraint equations Table 2.4 Tasmanian network constraint equations affecting Basslink flows Table 3.1 Tasmanian reference temperatures at associated POE (ºC Hobart) Table 3.2 Generator capacity Table 3.3 Generation developments Table 3.4 Modelling details of hydro schemes Table 5.1 Existing and forecast transmission system constraints Table 5.2 Substations that exceeded their transformer short term capacity in Table 5.3 West coast area committed projects Table 5.4 West coast area proposed developments Table 5.5 Table 5.6 Table 5.7 Table 5.8 Table 5.9 Options being considered to address Rosebery Substation supply transformer capacity Options being considered to address Newton and Queenstown substations transmission security Options being considered to address Newton transformer supply capacity Options being considered to address west coast 110 kv transmission security Options being considered to address Farrell Substation 220 kv security upgrade Table 5.10 North-west area committed projects Table 5.11 North-west area proposed developments Table 5.12 Options being considered to address Burnie Substation capacity issue Table 5.13 Options being considered to address Devonport Substation capacity issue Table 5.14 George Town area committed projects Table 5.15 George Town area proposed developments Table 5.16 Table 5.17 Options being considered to address George Town 220 kv Substation security Options being considered to address voltage support for the George Town area Transend Networks Pty Ltd 2012 Page 6

8 Table 5.18 Northern area committed projects Table 5.19 Northern area proposed developments Table 5.20 Table 5.21 Options being considered to address Avoca Substation transformer security Options being considered to address Derby Substation transformer security Table 5.22 Options being considered to address Hadspen Substation security Table 5.23 Options being considered to address Palmerston Avoca St Marys transmission security Table 5.24 Southern area committed projects Table 5.25 Southern area proposed developments Table 5.26 Options being considered to address Kingston area reliability Table 5.27 Table 5.28 Table 5.29 Table 5.30 Table 5.31 Options being considered to address Meadowbank Substation transformer security Options being considered to address Gordon Chapel Street 220 kv transmission security Options being considered to address Waddamana Palmerston 220 kv Transmission Security Options being considered to address voltage support for the greater Hobart area Options being considered to address Bridgewater Substation transformer capacity Table 5.32 Potential constraint deferrals due to load reductions Table 5.33 Planned telecommunications projects Table 6.1 Harmonic planning levels for the Tasmanian network Table 6.2 Voltage fluctuation planning levels Table 6.3 Current power system frequency operating standards Table 6.4 Current power system frequency standards during islanding Table 6.5 Minimum reserve levels Table 6.6 Circuit breaker locations predicted to exceed 80 per cent rated breaking capacity Table 6.7 Transmission lines and transformers with outage issues Transend Networks Pty Ltd 2012 Page 7

9 List of figures Figure 1.1 Tasmania s Electricity Transmission Network Figure 1.2 Bulk transmission network Figure 2.1 National Transmission Zones and National Transmission Flow Paths Figure 2.2 Recorded constraints for the 2011 calendar year Figure 3.1 Transend s demand forecasting methodology Figure 3.2 Load growth and existing generation Figure 3.3 Forecast of total Tasmanian electrical energy sales Figure 3.4 Forecast of total Tasmanian winter maximum demand Figure 3.5 Forecast total Tasmanian summer maximum demand Figure 3.6 Comparison of extrapolated and econometric winter forecasts Figure 3.7 Comparison of extrapolated and econometric summer forecasts Figure 3.8 Back casting of Tasmania maximum winter demand Figure 3.9 Comparison of actual winter maximum demands with 10, 50 and 90 per cent POE Figure 3.10 Samples of related MW and MVAr demand Figure 3.11 Winter and summer maximum demand curves Figure 3.12 Planned generation developments for Tasmania Figure 3.13 Projected excess generator capacity Figure 3.14 Projected excess generator capacity with entry of a major new industry Figure 3.15 Scenario 1 Supply balance to meet the extra energy demand Figure 3.16 Scenario 2 Supply balance to meet the extra energy demand Figure 3.17 Case 1 Monthly storage position with extended outages Figure 3.18 Case 2 Monthly storage position with extended outages Figure 4.1 Proposed 110 kv transmission supply to Rosebery Substation Figure 4.2 Proposed George Town Substation 220 kv arrangement Figure 5.1 Geographical map of west coast area Figure 5.2 West coast area network schematic diagram Figure 5.3 West coast system constraints Figure 5.4 Schematic diagram of existing and proposed west coast 110 kv network Figure 5.5 Farrell Switchyard proposed 220 kv one line diagram Figure 5.6 Geographical map of north-west area Figure 5.7 North-west area network schematic diagram Figure 5.8 North-west system constraints Transend Networks Pty Ltd 2012 Page 8

10 Figure 5.9 Geographical map of the George Town area Figure 5.10 George Town area network schematic diagram Figure 5.11 George Town system constraints Figure 5.12 Geographical map of the northern area Figure 5.13 Northern area network schematic diagram Figure 5.14 Northern system constraints Figure 5.15 Geographical map of the southern area Figure 5.16 Southern area network schematic diagram Figure 5.17 Southern system constraints Figure 5.18 Kingston area 110 kv transmission network Figure 5.19 Proposed Kingston area 110 kv transmission supply network Figure 5.20 Existing and proposed Waddamana Switching Station 220 kv arrangement Figure 6.1 DC and AC component of fault current Transend Networks Pty Ltd 2012 Page 9

11 Executive Summary Transend Networks Pty Ltd (Transend) owns and operates the electricity transmission network in Tasmania. Transend transmits electricity from power stations in Tasmania (and on the mainland via Basslink) to its customers around the State. Transend provides a secure, safe and reliable service to 16 transmission customers, including generators, networks and a number of major industrials. Transend is a registered Transmission Network Service Provider (TNSP). Australia s National Electricity Market (NEM) operates on an interconnected power system that extends from Queensland to South Australia. Tasmania is connected to the NEM via Basslink. Transend owns and operates a telecommunications business that serves customers within the electricity supply industry and in other industries. Our vision is to be a leader in developing and maintaining sustainable networks. Our mission is transmission: safe, reliable and efficient electricity and telecommunications services. The objective of this 2012 Annual Planning Report (APR) is to provide industry participants and other interested parties with an opportunity to: Assess the capability of the transmission system to transfer electrical energy; Understand how the transmission system may affect their operations; Understand locations that would benefit from supply capability or demand-side management initiatives; Identify locations where major industrial loads or new generation could be readily connected; and Provide input to the future development of the system. In addition to meeting the requirements of clause 5.6.2A of the National Electricity Rules (NER), Transend has an obligation under its transmission licence to publish an annual planning statement to provide information required by the Tasmanian Economic Regulator (Regulator). This report also fulfils these obligations. The APR also assists in the preparation of the National Transmission Network Development Plan (NTNDP) by the Australian Energy Market Operator (AEMO). The NTNDP makes available information on the strategic and long term development plans for the national transmission system under a range of market development scenarios. Information contained in the 2012 Annual Planning Report is based in part on the outcomes of the annual planning review held on 19 April 2012 and the outcomes of regular consultation between Transend and the Tasmanian distribution company, Aurora Energy Pty Ltd (Aurora). It also reflects input from other customers and stakeholders. A changing Tasmanian outlook Since the 2011 Annual Planning Report key indicators that can drive investment in the Tasmanian transmission system, namely load and energy forecasts, connection enquiries and major industrial customer demand, have declined. Transend Networks Pty Ltd 2012 Page 10

12 Despite the changing outlook for Tasmania, there remains a number of new generation and new directly connected customer enquiries being progressed. Transend is continuing to work with customers to assess options to supply this potential and committed generation and new and existing load. Given the Tasmanian market outlook, Transend remains focussed on improving services to our customers and maintaining assets using efficient and cost-effective practices. We welcome feedback from interested parties to ensure we invest responsibly in the assets that comprise our transmission system. Electrical energy and demand forecasts Medium forecasts for electrical energy sales and maximum winter demand predict 0.17 per cent average annual growth in electrical energy sales from 2012 to 2026 and 1.19 per cent average increase in winter maximum demand. This forecast rate of growth is lower than that included in the 2011 Annual Planning Report of an average annual growth of 1.08 per cent for energy sales and 1.84 per cent for maximum demand. The lower than forecast increases in energy sales and maximum demand projections are mainly due to closure or downsizing of industries in Tasmania, impact of the high Australian dollar, lower Gross State Product than previously predicted, and the impact of higher retail prices of electricity. This has resulted in changes in timing of emerging network limitations and associated transmission network development plans. The existing available generation capacity indicates that, with Basslink imports, there will be adequate generation capability to meet the forecast Tasmanian maximum demand up to New generation connections A range of wind power, wave power, thermal and geothermal power generation schemes throughout Tasmania are currently being investigated. Changes to Government climate change policy with the introduction of the carbon price and renewable energy target scheme, may lead to further renewable energy generation being established in Tasmania. As a result future generation is likely to be more diversified than currently installed and at new locations. This has the potential to impact significantly on the long-term development plans for the transmission network. Transend has commenced analysis of the impact of increased wind generation on the Tasmanian transmission system. This work aims to identify the maximum wind generation penetration that can occur prior to the need for significant augmentation of the transmission system. The development of the Musselroe wind farm is currently under way, with a potential generation capacity of 168 MW. The proponent plans to commence operation in March Cattle Hill wind farm, with a potential generation capacity of 225 MW, is also being progressed. The proponent plans to commence operation in April Transmission system constraints Transend must meet the requirements of the NER and the Electricity Supply Industry (Network Performance Requirements) Regulations (referred to in this document as ESI Regulations). Transend is required to ensure that the planned power system meets the minimum performance criteria. Transend may also seek an exemption from these criteria, which is done where there is 1 Refer to Appendix 8 for full copy of ESI (Network Performance Requirements) Regulations 2007 Transend Networks Pty Ltd 2012 Page 11

13 agreement from affected customers and/or where the economic, social and environmental costs of satisfying the criteria outweigh the benefits. Emerging limitations and constraints have been identified on the transmission network. These emerging limitations and possible network solutions are as follows: In the west coast area of Tasmania, there are constraints on the security and capacity of some transmission lines, in particular the radial transmission network that supplies Queenstown and Newton substations. Transend is developing a long-term solution to manage the security of supply to these substations. Increasing load in the north west of Tasmania (Burnie and Devonport substations) increases the risk of non-firm supply. Indications are that an augmentation to capacity in this area will be required prior to Security of supply issues to Avoca and St Marys substations is forecast, with the Palmerston Avoca and Avoca St Marys 110 kv transmission lines already failing to meet the performance requirements of the ESI Regulations. A potential solution to address this constraint is being developed, with the construction of a second Palmerston Avoca 110 kv circuit by 2016 a possible outcome. In the southern area, voltage control is becoming increasingly difficult. Capacitor banks are proposed to be installed at the Creek Road 110 kv Substation by 2015, and a dynamic reactive support installation is proposed for the greater Hobart area by In addition, transmission capacity constraints between Palmerston and Waddamana substations are being investigated, along with security of supply constraints at Waddamana 220 kv switchyard. Indications are that a transmission development and substation augmentation may be the most viable solution. Security of supply to the Kingston area is an issue in that a single asset failure affecting the Chapel St to Kingston double circuit 110 kv transmission line would interrupt supply to five terminal substations. A potential solution to address this issue is being developed, with the construction of a Creek Road Kingston Tee 110 kv circuit by 2019 a possible outcome. Load reductions Transend has modelled the impact of demand growth on the transmission system, and identified existing and emerging transmission constraints. Transend has identified where a reduction in load (in the form of demand management or embedded generation) could defer constraints for a period of at least 12 months, with the resulting estimates of load reduction presented in the table below. In accordance with the NER, interested parties have 20 business days from the date of publication of this APR to make written submissions in relation to the potential constraint deferrals included in this APR. However Transend welcomes feedback from interested parties at any time regarding feasible options that may provide cost effective solutions to network issues. Transend Networks Pty Ltd 2012 Page 12

14 Area of constraint Avoca St Marys transmission circuit Year constraint occurs Connection point at which load reduction would be required 2012 St Marys Substation Estimated load reduction required (MW) Request for Proposal (RFP) to be issued 3 MW RIT-T 2 would constitute the RFP Avoca Substation transformer Bridgewater Substation transformers Derby Substation transformer Farrell Que Savage River Hampshire transmission circuit Farrell Rosebery Queenstown transmission circuit Meadowbank Substation transformer Newton Substation transformer Palmerston Avoca transmission circuit Palmerston Waddamana 220 kv security Rosebery Substation transformer Southern voltage stability static reactive support Chapel Street Kingston Knights Road and Chapel Street Kingston Electrona transmission circuits Southern voltage stability dynamic reactive support 2012 Avoca Substation 4 MW This APR constitutes an RFP to address this constraint 2018 Bridgewater Substation 5 MW RIT-T would constitute the RFP 2012 Derby Substation 3.5 MW This APR constitutes an RFP to address this constraint 2012 Savage River 14 MW This APR constitutes an RFP to address this constraint 2012 Queenstown and Newton 2012 Meadowbank Substation 15 MW RIT-T would constitute the RFP 2.1 MW This APR constitutes an RFP to address this constraint 2012 Newton Substation 4 MW This APR constitutes an RFP to address this constraint 2012 Avoca or St Marys substations 7 MW RIT-T would constitute the RFP 2012 Southern Tasmania 42 MW RIT-T would constitute the RFP 2012 Rosebery Substation 1.2 MW This APR constitutes an RFP to address this constraint 2015 Southern Tasmania 16 MW This APR constitutes an RFP to address this constraint 2014 Electrona, Kingston, Knights Road, Kermandie or Huon River substations 1.5 MW RIT-T would constitute the RFP 2018 Southern Tasmania 38 MW RIT-T would constitute the RFP 2 RIT-T Regulatory Investment Test for Transmission Transend Networks Pty Ltd 2012 Page 13

15 Completed and committed projects During , Transend completed a variety of major projects to improve the reliability and capacity of the transmission network. These include: Sheffield Burnie 110 kv transmission line capacity upgrade. Establishment of a new 33 kv connection point at Kingston Substation, complete with two 110/33 kv 30/60 MVA transformers. Redevelopment of Tungatinah 22 kv Substation, including replacement of outdoor 22 kv switchgear with a new indoor switchboard. Installation of an optical fibre ground wire (OPGW) from Paloona Tee to Burnie Substation, and from Farrell Substation to John Butters Power Substation, to improve lightning protection and communications capability. At the time of writing two complementary projects in the Launceston area were approaching completion, namely: A new 22 kv connection point substation at St Leonards, complete with two 110/22 kv 30/60 MVA transformers. Installation of an underground 110 kv transmission cable between Norwood and Mowbray substations via St Leonards Substation. There are also a number of projects that are underway, or committed, which are summarised in the table below. Transend Networks Pty Ltd 2012 Page 14

16 Project Purpose Expected completion Rosebery Substation 110 kv augmentation George Town Substation 220 kv security upgrade Stage 1 Sheffield Substation to George Town Substation OPGW Palmerston Substation 110 kv redevelopment Newton Substation redevelopment Arthurs Lake Substation redevelopment Creek Road Substation 110 kv redevelopment Burnie Substation 110 kv redevelopment Tungatinah Substation 110 kv redevelopment Improve the security of supply to Rosebery Substation by closing the 110 kv normally open point at Rosebery Substation Improve the security of 220 kv supply to and from George Town Substation Provide OPGW on the Sheffield George Town 220 kv transmission line and to the Badgers Range telecommunication site Improve the security and reliability of supply from Palmerston Substation by replacing assets that are in poor condition Improve the security and reliability of supply from Newton Substation by replacing assets that are in poor condition Improve the security and reliability of supply from Arthurs Lake Substation by replacing assets that are in poor condition Improve the security and reliability of supply from Creek Road Substation by replacing assets that are in poor condition Improve the security and reliability of supply from Burnie Substation by replacing assets that are in poor condition Improve the security and reliability of supply from Tungatinah Substation by replacing assets that are in poor condition and reconnecting transmission lines from Tarraleah Switching Station to Tungatinah Substation October 2012 November 2012 November 2012 March 2013 May 2013 August 2013 December 2013 April 2014 April 2014 Projects which have not yet reached the stage of being committed are classified as advanced projects, although there are no new advanced projects in the 2012 Annual Planning Report. Feedback Transend welcomes feedback on the Transend 2012 Annual Planning Report. We are particularly interested in discussing potential opportunities for interested parties to participate in demand-side management, non-network solutions and/or innovative solutions to manage network constraints. Written submissions regarding the proposed new transmission network assets outlined in this document, or alternative options to address identified constraints, should be received within 20 business days of the publication of this Annual Planning Report. However, as noted above, Transend welcomes feedback from interested parties at any time regarding feasible options that may provide cost effective solutions to network issues. Submissions should be addressed to: Gustavo Bodini General Manager, Customer and Asset Management Transend Networks Pty Ltd P O Box 606 Moonah Tasmania 7009 Transend Networks Pty Ltd 2012 Page 15

17 1 Background 1.1 Responsibilities Transend is the owner and operator of the electricity transmission system in Tasmania and is a registered Transmission Network Service Provider. Transend has been appointed by the Tasmanian Government as the body responsible for transmission system planning in Tasmania. The Australian Energy Market Operator is responsible for carrying out the functions of the National Transmission Planner (NTP). Transend carries out an annual cycle of planning to review system issues and identify possible solutions to meet future Tasmanian and national electricity supply requirements. As part of the transmission system planning process, Transend analyses the performance of the existing transmission system, taking into account the forecast load and generation growth. The performance of the existing transmission system provides a background to determine necessary future system developments. This Annual Planning Report is an output of the planning undertaken over the past year, including the Transend and Aurora annual planning review held on 19 April The APR satisfies an obligation under Clause 5.6.2A of the NER to publish an Annual Planning Report by 30 June each year. This APR also meets a condition of the licence issued to Transend under the Electricity Supply Industry Act 1995 (ESI Act) to publish a Tasmanian Annual Planning Statement (TAPS) that provides information and analysis as specified by the Tasmanian Economic Regulator. 1.2 Purpose of the Annual Planning Report In accordance with clauses 5.6.2A(a) and (b) of the NER (Version 49), the purpose of the annual planning review and this APR is to provide information to registered participants in the NEM and other interested parties about the Tasmanian transmission system and planning for its development. This APR considers: historic and forecast electricity usage and maximum demand (MD) forecasts from the Distribution Network Service Provider, Aurora Energy, and directly connected customers for the next 10 years, and an econometric state-wide forecast of energy usage for the next 10 years prepared by the National Institute of Economic and Industry Research (NIEIR); planning proposals for future connection points; adequacy of the transmission system and available generating units to meet the power transfer and forecast demand, including the connection to the Basslink inter-connector; actual and projected capacity and energy constraints, including national transmission flow path constraints in the Tasmanian region identified by AEMO in the National Transmission Network Development Plan; proposed solutions to identified issues, including transmission system developments and nonnetwork alternatives, including augmentations to the transmission system and how they relate to the most recent NTNDP; and replacement of transmission system assets; other issues that impact on transmission system planning, including performance issues relating to power quality, ancillary services, capacity reserves, fault levels and operation and maintenance. Transend Networks Pty Ltd 2012 Page 16

18 The APR provides cost data that is indicative, unless specifically stated otherwise. All costs are presented in base dollars. 1.3 Planning horizon and uncertainty The APR covers the period 1 July 2012 to 30 June 2022 and includes various market model scenarios, reflecting the significant amount of uncertainty over a ten year planning horizon. Whilst every endeavour is made to ensure the information presented in the APR is accurate, planning of the transmission network is necessarily undertaken in a changing environment. Significant contributors to uncertainty include changes in Transend s load and generation customer base, changes in the regulatory framework for the NEM, and changes to other Federal and State government policies, including the impacts of climate change policy Impact of climate change policy on demand and energy Over the past few years significant Australian policy changes have focussed on controlling greenhouse gas emissions in response to the impact of climate change. Many of these policy changes are focussed on the energy sector, which is a major contributor to Australia s greenhouse gas emissions. The annual planning review process and this APR take into account the expected impact of these policies. Policy support continues for renewable generation, through the large and small scale renewable energy target schemes. The possible significant growth in non-scheduled generation, especially the impact of wind powered generation, has been considered in this APR. The impact of non-scheduled generators on the capacity forecast and their expected contribution to meeting peak electricity demand has also been considered. The projections also assume a carbon levy of $23 per tonne in the form of a Carbon Price Mechanism, which is proposed to be introduced on 1 July This carbon levy is expected to affect indirectly the forecast maximum demand (MD) through its impact on the growth of energy demand. 1.4 Tasmanian transmission system Transmission system overview The Tasmanian transmission system comprises: a 220 kv bulk transmission network which, with supporting 110 kv transmission circuits, provides corridors for transferring power from several major generation centres to major load centres and facilitates transfers between major load centres; a peripheral 110 kv transmission network, and connection assets, which is largely radial and connects load centres and generators to the bulk transmission network; and connection points comprising 44, 33, 22, 11 and 6.6 kv assets. The transmission network of Tasmania covered in the APR is shown in Figure 1.1. This figure provides a geographic representation of the Tasmanian transmission network as at 1 June Transend Networks Pty Ltd 2012 Page 17

19 Figure 1.1 Tasmania s Electricity Transmission Network Figure 1.2 presents a schematic representation of the bulk transmission network as at 1 June Transend Networks Pty Ltd 2012 Page 18

20 Figure 1.2 Bulk transmission network Basslink Basslink is a market network service provider that facilitates the transmission of electricity between Tasmania and the Australian mainland. Basslink has been in full commercial operation since 29 April Basslink is a 400 kv mono-polar high voltage direct current (HVDC) link. It connects to the Victorian transmission network at Loy Yang Power Station and to the Tasmanian transmission network at George Town Substation. Transend Networks Pty Ltd 2012 Page 19

21 Basslink has a continuous sending end capacity of 500 MW and a short term sending end capacity of 630 MW when exporting from Tasmania to Victoria. Power flow from Victoria to Tasmania is limited to 478 MW or calculated from available load trip blocks by the system protection scheme (SPS). The SPS trips contracted load blocks or generation in Tasmania on the loss of Basslink to prevent frequency excursions on the AC transmission network. Basslink also has a non-operational zone between 50 MW export and 50 MW import. Basslink has been constructed with a frequency controller to allow it to transport frequency control ancillary services (FCAS) between the interconnected mainland regions and Tasmania Transmission line ratings Transmission line current ratings are assigned taking into account the heating effects of the electrical current, ambient air temperature, solar radiation, reflected radiation, and the cooling effects of wind and emitted radiation, so that the conductors do not heat to such an extent that they sag below the allowable ground clearance. All of Transend's transmission lines are rated in realtime. This means that wind speed and ambient temperature are regularly measured at representative locations and used to provide inputs to the determination of dynamic conductor current ratings. Other influencing factors such as solar reflected and emitted radiation are modelled in the rating calculations. Real-time transmission line ratings are telemetered at one minute intervals directly to AEMO where they are used in an automated process to determine generator dispatch. Real-time (or dynamic) ratings enable Transend to make more efficient use of the transmission infrastructure by taking advantage of the cooling effects of lower ambient temperatures and higher wind speeds. This enables transmission lines to be loaded, most of the time, at higher throughputs than would be possible if static ratings were used. 1.5 Tasmanian supply reliability Introduction Transend undertakes a range of analysis of the performance of the Tasmanian transmission system. This includes reporting to the Regulator about performance of the existing transmission network, and to the Australian Energy Regulator against measures and targets established in Transend s revenue decision. The following sections provide information on significant network incidents over the financial year, and transmission network reliability and transmission plant availability performance Transmission network reliability Transmission network reliability is monitored and reported to the Regulator in terms of the number of loss of supply (LOS) events occurring during a financial year 4. LOS is measured in system minutes which is calculated by dividing the total energy not supplied to customers during an event (MWh) by the Tasmanian MD (1874 MW in 2011). Targets are set for the number of LOS events greater than 0.1 system minute and for the number of LOS events greater than 1.0 system minutes. Table 1.1 presents the LOS performance of the transmission network over recent financial years. The measures and targets reflect those for the to regulatory period. 4 Reporting to the AER is done by calendar year. Transend Networks Pty Ltd 2012 Page 20

22 % % % % % % % % Table 1.1 Transmission network loss of supply performance Performance measure Target Number of LOS events >0.1 system minute Number of LOS events >1.0 system minutes Measure not in place Number of LOS events >2.0 system minutes 3 Measure not in place Transmission plant availability Transmission plant availability is monitored and reported in terms of the percentage of plant availability, which is defined as the ratio of plant circuit-hours available for transmission plant (plant that is either in service or readily capable of being placed into service) divided by the total possible plant circuit-hours. For transmission circuits it relates to availability of all elements of the circuit, and for transformers it relates to availability of all elements of the transformer circuit. Table 1.2 presents the financial year performance of the transmission network with respect to availability of key components. The measures and targets reflect those for the to regulatory period. Table 1.2 Transmission plant availability Performance measure Target % Transmission circuit availability Measure not in place Transmission circuit availability (critical) Transmission circuit availability (noncritical) Transformer availability Capacitor bank availability Measure not in place Measure not in place Significant network incidents A significant network incident is defined as a loss of supply event exceeding 1.0 system minute. There were four significant network incidents during the financial year. The incidents were: Transend Networks Pty Ltd 2012 Page 21

23 On 22 July 2010, Risdon T1, T2 and T3 110/11 kv transformer circuits tripped due to a protection mal-operation causing a loss of supply of 1.09 system minutes to Nyrstar Ltd; On 7 February 2011, New Norfolk Boyer No kv transmission line circuit tripped due to a protection testing error, causing a loss of supply of 1.26 system minutes to Norske Skog Ltd; On 23 March 2011, Sorell T2 transformer circuit tripped due to vermin incursion during planned work, causing a loss of supply of 1.90 system minutes at Sorell Substation; and On 4 May 2011, Lindisfarne Rokeby No 2-Sorell 110 kv transmission line circuit tripped due to a suspected transformer fault, causing a loss of supply of 2.20 system minutes at Rokeby Substation. Transend Networks Pty Ltd 2012 Page 22

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25 2 National flow path developments and existing Tasmanian transmission constraints 2.1 Introduction This section discusses developments with regard to the: 2011 National Transmission Network Development Plan; National transmission flow paths; Existing transmission constraints in the Tasmanian network; and Tasmanian developments that may affect Basslink flows. 2.2 National Transmission Network Development Plan Preparation of the annual NTNDP is a key part of AEMO s role as the National Transmission Planner. The plan aims to facilitate development of an efficient national electricity network that considers potential transmission and generation investments. The annual NTNDP makes available information on possible strategic and long term development plans for the national transmission system under a range of plausible market development scenarios. The NTNDP provides information to interested parties about transmission capabilities, congestion and investment options across the NEM under these scenarios. To achieve this, AEMO through the NTNDP seeks to advise transmission investment in the following ways: providing a consistent plan that considers the augmentations required under a range of scenarios, and delivering options that enable maintenance of a reliable power system irrespective of which scenario eventuates; providing a national focus on market benefits and transmission augmentations in support of an efficient power system; proposing a range of plausible future scenarios and exploring their impact on the electricity supply industry, with an emphasis on identifying national transmission network needs under those scenarios; identifying network needs early to increase the time available to identify non-network options, including demand-side and generation options; and considering alternative network project timings, including alternatives resulting from the scenarios considered. Studies for the NTNDP include the major transmission network of each region and accordingly the Tasmanian 220 kv and 110 kv network has been included. 2.3 National Transmission Flow Paths National transmission flow paths (NTFPs) are the set of transmission assets connecting zones that represent generation or demand centres and, occasionally, both generation and demand centres. NTFPs connect zones within the same region (intra-regional) and across regional boundaries (interregional). Figure 2.1 illustrates the NTNDP zones and NTFPs. The whole of the Tasmanian Transend Networks Pty Ltd 2012 Page 23

26 network (including all generation and demand centres) is currently represented by one zone, designated TAS. The one NTFP associated with Tasmania is the Basslink interconnector, which links George Town Substation in Tasmania to Loy Yang Power Station in Victoria via a 400 kv High Voltage Direct Current link across Bass Strait. This flow path is designated TAS LV (Tasmania to Latrobe Valley). Basslink has a short term power transfer capability of 630 MW export from Tasmania to Victoria and 478 MW import from Victoria to Tasmania. Figure 2.1 National Transmission Zones and National Transmission Flow Paths NSA ADE SESA NQ CQ SWQ SEQ NNS NCEN SWNSW CAN CVIC NVIC MEL LV Zone abbreviations NTNDP zone Abbreviation North Queensland NQ Central Queensland CQ South West Queensland SWQ South East Queensland SEQ North New South Wales NNS Central New South Wales NCEN Canberra CAN South West New South Wales SWNSW Northern Victoria NVIC Country Victoria CVIC Melbourne MEL Latrobe Valley LV Northern South Australia NSA Adelaide ADE South East South Australia SESA Tasmania TAS TAS NEMLink As part of the 2010 and 2011 NTNDPs, AEMO has provided information on a conceptual project called NEMLink, involving significant transmission investment in a high-capacity backbone that links the regions. The NEMLink conceptual network augmentation is intended to enable largerscale power transfers within and between the regions. The NEMLink project includes the following: a high capacity, 500 kv double-circuit, AC transmission backbone connecting the mainland regions; a further 400 kv HVDC connection between Tasmania and the mainland, similar to the existing Basslink interconnector; and necessary intermediate substations, switching stations, and devices for reactive compensation and power flow control. The NEMLink concept is based on providing an additional 500 MW of power transfer capability between Tasmania and Victoria in both directions. AEMO s Victoria to Tasmania link reflects that Tasmania has excellent existing hydroelectric energy resources, and potential for further renewable generation, in particular wind. The Australian Government s continued support for the large-scale renewable energy target (LRET), together with the Clean Energy Future plan, which includes Transend Networks Pty Ltd 2012 Page 24

27 introduction of a carbon price mechanism in 2012 and closure of 2,000 MW of emissions intensive generation capacity by 2020, is expected to provide an incentive to continue development of renewable energy power generation schemes in Tasmania. AEMO has modelled the location of NEMLink s AC to DC converter station at West Montagu, approximately 120 km west of Burnie. Location of a new inter-connection at this point would necessitate strengthening of the 220 kv transmission link from Sheffield Substation to Burnie Substation and construction of a new 220 kv transmission line from Burnie Substation to a new converter station at West Montagu. AEMO notes that of all the potential inter-connection modelled under NEMLink, the Tasmania to Victorian augmentation has the highest capital cost per unit of capacity and these costs outweigh the market benefits of allowing wind investment in Tasmania, and leveraging the Tasmanian hydroelectric generators to stabilise the intermittency of wind generation in the southern mainland regions 5. AEMO also notes that NEMlink (with or without the Victoria to Tasmania component) may approach economic viability by approximately under high demand growth and high carbon pricing conditions 6. Under conditions that more closely resemble the current NEM policy and economic environment, no modelled NEMLink projects are likely to be viable by 2020, and AEMO considers that future work should consider a longer study period with a view to staged NEMLink completion by 2025 or Transmission network developments identified in the NTNDP The 2010 and 2011 NTNDPs provided a series of network development outlooks for a range of scenarios, noting that the 2011 NTNDP is simply an update on the status of projects identified in Conceptual augmentations relevant to Tasmania that AEMO considers warrant further planning investigations are listed in Table AEMO has now commenced work on the 2012 NTNDP, to be published in December Table 2.1 Tasmanian transmission development 10-year summary Transmission development Rating Summary of AEMO comments T1 Configure Waddamana 220 kv Switching Station, and upgrade the 110 kv Waddamana Palmerston transmission line to 220 kv operation T2 Upgrade the 110 kv Norwood Scottsdale transmission line, or connect new generation to the 220 kv transmission network along the Hadspen George Town corridor T3 Replace the existing 220 kv Sheffield Burnie single-circuit transmission line with a new 220 kv double-circuit transmission line T4 Develop a new 220 kv Palmerston Sheffield double-circuit transmission line T5 Develop a new 220/110 kv transformer in the Hobart area Early attention Early attention Early attention Early attention Monitoring Transend is investigating a preferred option Transend is investigating this option as part of new connection enquiries/applications Transend is investigating this option Transend is investigating this option Not likely to be needed; load growth to be monitored The rating criteria used by AEMO and referred to in Table 2.1 are described in Table Refer 2011 NTNDP page ibid 7 Refer 2011 NTNDP page Refer 2011 NTNDP page 2-26, table Refer NTNDP 2011 page 2-4, Table 2-1. Transend Networks Pty Ltd 2012 Page 25

28 Table 2.2 Guiding criteria for categorising transmission network developments occurring in the first 10 years Category Trigger timing Opportunity cost Early attention Preparatory work Monitoring Development is triggered in the first fiveyear period under most scenarios and in the second five-year period in most of the remaining scenarios Development is generally triggered in the second five-year period in most scenarios but possibly later in others Development is triggered in the first or second five-year period in some scenarios High opportunity cost if not done (or has limited or expensive work-arounds) High opportunity cost if a need is established and it requires some long lead-time works (for example, easement acquisition) Likely to have work-arounds if the triggering conditions unfold (in other words, a relatively low opportunity cost if the development is delivered late) It should be noted that any augmentation development over $5 million requires justification in accordance with the Regulatory Investment Test for Transmission (RIT-T) process, as described in Section of the NER. The current status of the developments listed in Table 2.1 is discussed below. T1 Configure Waddamana 220 kv Switching Station, and upgrade the 110 kv Waddamana Palmerston transmission line to 220 kv operation The first part of this development is the augmentation of the Waddamana Substation 220 kv switchyard to circuit-breaker-and-a-half configuration. The second part of this development involves the addition of a second Palmerston Waddamana 220 kv transmission corridor by converting an existing 110 kv single circuit transmission line to 220 kv operation. Transend has highlighted these as proposed network developments in Section 5 of this APR. T2 Upgrade the 110 kv Norwood Scottsdale transmission line, or connect new generation to the 220 kv transmission network along the Hadspen George Town corridor The Norwood Scottsdale 110 kv transmission line has two transmission circuits, each with a capacity of 130 MVA at 20 C ambient air temperature. A single circuit tee-off from one of these transmission circuits supplies Derby Substation. This spur section has a capacity of 171 MVA at 20 C ambient air temperature. The poles in this section are constructed for double circuits. Musselroe wind farm is proposed to generate up to 168 MW, which will be injected into the 110 kv network at Derby Substation via a single transmission circuit. There is potential for further wind generation developments in north-east Tasmania, plus potential hot-rocks geothermal generation developments at Pyengana to the east of Derby Substation. An option is for future generation to be connected to the 110 kv network rather than to the Hadspen George Town 220 kv corridor, with Derby Substation potentially becoming a generation hub. While the 2011 NTNDP notes that Transend is considering the augmentation of the existing Norwood Scottsdale 110 kv transmission line, Transend is processing a connection application for a generation proponent and the expectation is that any augmentation is unlikely to pass the RIT-T and would be funded by the proponent. T3 Replace the existing 220 kv Sheffield Burnie single-circuit transmission line with a new double-circuit transmission line The existing single circuit Sheffield Burnie 220 kv transmission line was constructed in The double circuit Sheffield Burnie 110 kv transmission line was upgraded in 2011 from 110/172 MVA to 208/244 MVA (summer/winter). Loss of a major industrial customer with two sites in the north-west area has deferred the need for a new double circuit Sheffield Burnie 220 kv transmission line. Transend Networks Pty Ltd 2012 Page 26

29 T4 Develop a new 220 kv Palmerston Sheffield double-circuit transmission line The existing single-circuit Palmerston Sheffield 220 kv transmission line was constructed in Replacement of this transmission line may be required around Replacement of the single circuit with a new double circuit Palmerston Sheffield 220 kv transmission line is being investigated. T5 Develop a new 220/110 kv transformer in the Hobart area Two new 220/110 kv 150/200 MVA auto-transformers were installed and commissioned at Lindisfarne Substation in May As noted by AEMO, Transend does not envisage the need for additional 220/110 kv transformers in the greater Hobart area will be triggered until 2020 at the earliest, although load growth in the area will be monitored closely. 2.4 Transmission network constraints Where the power flow through the power system is capable of exceeding a known technical limit, and the flow in that part of the power system is able to be controlled through changes in generation dispatch, the power flow through that portion of the power system is limited by one or more mathematical equations, called constraint equations. These equations are developed by AEMO and are based on advice provided by the relevant TNSP. Network limits are defined by equipment thermal ratings, network equipment protection settings, network stability limits and in the case of Tasmania the special operational requirements of Basslink. Constraint equations are used to manage power flows both within a region and between regions. Some constraints exist under normal conditions when all transmission elements are in service. However, constraints are more likely to occur when some elements of the transmission network are out of service. In the NEM the effect of every constraint is recorded. This means when the flow through a portion of the network is constrained to a particular limit (called binding constraint) or if the limit is exceeded (called violating constraint), it is recorded. Transend undertakes periodic reviews of all binding and violating constraints and provides AEMO with revised limit advice to modify, remove or add new constraints, as required, to ensure power system security is maintained and that the available transmission capacity is maximised. Figure 2.2 illustrates the occurrence of constraints on the major Tasmanian transmission elements (intra-regional constraints) for the 2011 calendar year. The constraints that are presented in Figure 2.2 include both binding and violating constraints. Thermal limit - no outage indicates that the constraint arose with all transmission elements in service. Thermal limit - with outage indicates that an outage somewhere in the network caused the constraint. The constraints are presented in terms of the number of binding or violating dispatch intervals 10 during the 12-month period. 10 Each dispatch interval is 5 minutes. Transend Networks Pty Ltd 2012 Page 27

30 Figure 2.2 Recorded constraints for the 2011 calendar year Highlights of existing constraints on major transmission system elements Table 2.3 compares the number of dispatch intervals constraint equations bound or violated on the 220 kv transmission network during 2010 and Transend Networks Pty Ltd 2012 Page 28

31 The Palmerston Sheffield 220 kv thermal constraint equation bound or violated for 30 dispatch intervals during This was significantly less than 2010 due to changed generation dispatch patterns during 2011 and uprating of terminal equipment. The majority of dispatch intervals for which this equation bound or violated in 2010 occurred prior to the equipment being uprated in April The Liapootah Chapel Street 220 kv thermal and voltage constraints bound or violated less during 2011 than during This is attributed to commissioning of the Waddamana Lindisfarne 220 kv transmission line in April The 31 dispatch intervals when the Liapootah Chapel Street voltage constraint equation bound or violated occurred prior to commissioning of the Waddamana Lindisfarne 220 kv transmission line. Table 2.3 Comparison of 2010 and 2011 binding constraint equations Constraint equation Number of dispatch intervals bound or violated Palmerston Sheffield thermal limit with no outage 2, Liapootah Chapel Street thermal limit with no outage Liapootah Chapel Street voltage stability Sheffield Farrell thermal limit with no outage Constraint equations affecting Basslink The Tasmanian network constraint equations that affected Basslink flows are presented in Table 2.4. The constraint data presented does not give any indication of the amount by which power flow was constrained or any commercial value of that constraint. However, it provides information regarding how often a Basslink related equation bound or violated, and therefore affected the power transfer via Basslink. Table 2.4 Constraint Tasmanian network constraint equations affecting Basslink flows Number of dispatch intervals bound or violated Basslink no-go zone 909 Basslink export limited due to generation unavailability for FCSPS operation Basslink import limited due to load unavailability for FCSPS operation 2,259 Gordon Chapel Street 220 kv transmission line rating constraints with NCSPS operation Sheffield Farrell 220 kv transmission line rating constraints with NCSPS operation Basslink rate-of-change limit Measured from 1 February 2010 to 31 January 2011 and reported in the 2011 APR Transend Networks Pty Ltd 2012 Page 29

32 2.5 Tasmanian developments that could impact on Basslink flows Increased wind generation Asynchronous renewable generators like wind turbine generators typically do not add to the inertia or fault level of the power system. In a small power system such as in Tasmania, the addition of large numbers of asynchronous generators may materially reduce the inertia and fault level of the power system. Asynchronous generators typically do not provide frequency control ancillary services (FCAS). At significant levels of penetration of wind generation, the system behaviour is modified profoundly by these characteristics, which includes the risk of commutation failure of the Basslink converter station under low fault level conditions. If there was to be an increased penetration of wind generation in Tasmania, some of the issues to be considered would include the possible impact that reduced system inertia, fault level and FCAS availability may have on the Tasmanian transmission system, and on Basslink transfers and its ability to change direction in response to market signals. These issues are being investigated by Transend. Transend Networks Pty Ltd 2012 Page 30

33 3 Supply demand outlook 3.1 Introduction This section presents electricity demand forecasts and the anticipated supply demand balance of the Tasmanian electricity system. Section 3.2 presents forecasts of electricity energy and maximum demand for winter and summer peaks in Tasmania. Transend s load forecasting process is based on economic indicators developed by AEMO and customer forecasts. The load forecasting process is described in Section 3.2. Section 3.3 investigates the energy and maximum demand balance between the forecast demand and the supply of generation, including potential generation sources for Tasmania for the next 15- year planning horizon. Energy supply demand balance investigates the future generation energy availability for a 15-year planning horizon including the adequacy of the hydro system in meeting that horizon. This section further includes a brief description about existing and possible future generation expansion in Tasmania. 3.2 Energy and demand forecasts Transend relies on the following information to develop its demand forecast: information provided by AEMO regarding key economic scenarios and macroeconomic and energy market variable factors; the December 2011 distribution connection, 10-year consumption and maximum demand forecast prepared by Aurora; information provided to Transend by its directly connected customers; and the electricity energy sales and MD forecasts for Tasmania for the next 30 years prepared by NIEIR. Transend receives forecast economic indicators for AEMO s National Transmission Network Development Plan scenarios, which describe key energy market policies and economic conditions. These forecast indicators are provided to the National Institute of Economic and Industry Research (NIEIR) for preparation of the regional energy and demand forecasts for Tasmania. The high, medium and low forecasts represent a fast rate of change, a modest rate of change and a slow rate of change in the economy, aligning with the NTNDP 2011 scenarios. The energy forecasts prepared by NIEIR for Tasmania as a whole are for energy sales and energy generation. Energy sales is the total amount of electrical energy sold in Tasmania, and energy generated is the total amount of electrical energy generated (sent out) within Tasmania to meet the forecasted energy sales. The forecasts use a large-scale econometric model that estimates Tasmanian electrical energy consumption based on anticipated: average consumption per dwelling; gross state product; real incomes; electricity prices; weather conditions; and major new industrial, mining and commercial developments. Transend Networks Pty Ltd 2012 Page 31

34 The state economic parameters used in NIEIR s forecasts were sourced from AEMO s scenarios containing key economic factors provided by NIEIR in March In addition, forecasts for connection points are prepared by Tasmania s distribution network service provider (DNSP), Aurora, and directly connected customers who provide their own demand forecasts. The Aurora forecasts include individual demand forecasts for each of its connection points. Once received, the directly connected customer demand forecast is reconciled against NIEIR s forecast and combined with Aurora s demand forecast to produce a consolidated connection point and area demand forecast for Tasmania. Aurora s demand forecast is compared with NIEIR s medium scenario demand forecast to identify and resolve any discrepancies relating to different information or assumptions. Details of state maximum demand and energy forecast and connection point maximum demand forecasts are provided in Appendix 1. Figure 3.1 presents an overview of Transend s demand forecasting methodology. Figure 3.1 Transend s demand forecasting methodology External Inputs Aurora Energy demand forecast (bottom up approach) NIEIR forecast (top down approach) Directly connected customers forecasts Diversity factors Power factors Metering data Transmission losses Verification Transend Forecast (forecast reconciliation) Outputs Tasmania forecast (maximum demand and energy forecast based on generation sent out) Planning System planning Annual Planning Report AEMO Electricity Statement of Opportunities NTNDP Tasmanian area and connection point forecast Carbon Price Mechanism The Carbon Price Mechanism 13 is a market based approach to managing the effects of carbon pollution. The Australian Government will introduce the Carbon Price Mechanism on 1 July 2012, commencing with a fixed price (through the issuance of fixed price units within an emissions trading scheme) before converting to a cap-and-trade emissions trading scheme. 12 National and state economic forecasts to consistent with AEMO scenarios 2012, Prepared by NIEIR, March Transend Networks Pty Ltd 2012 Page 32

35 All three forecasts (ie medium, high and low growth) provided in this APR assume a carbon emissions target of 5 per cent by 2020 (meaning a reduction in emissions of 5 per cent below 2000 levels) Area load growths Figure 3.2 shows the distribution of loads in Tasmania, their relative forecast growth and their location in relation to existing Tasmanian generators. In most cases, the generators are distant from the load centres. In addition, the higher maximum demand growth areas are presented in Figure 3.2. The southern area has the highest average annual demand growth rate of 1.7 per cent. This is closely followed by the northern and north-west areas of 1.6 per cent, west coast area of 1.5 per cent and George Town area of 0.3 per cent. Transend Networks Pty Ltd 2012 Page 33

36 Figure 3.2 Load growth and existing generation Transend Networks Pty Ltd 2012 Page 34

37 Energy (GWh) Forecast energy generation and sales The forecast for total medium energy sales from to implies an average growth of 0.17 per cent per annum. This includes per cent annual growth until and 0.72 per cent annual growth onwards. The overall growth rate is lower than that forecast in the 2011 APR of 1.08 per cent per annum. The overall growth rate given in the 2011 APR includes 3.22 per cent growth in the initial year and 0.93 per cent annual growth after that. The growth for the high scenario is an average of 1.87 per cent per annum from to This is due primarily to assumed more favourable economic conditions. A considerable increase (ie 7.84 per cent) in energy growth is forecast for under this scenario due to the assumed connection of a new directly connected customer to the Tasmanian network. The growth for the low scenario is an average of per cent per annum from to This includes per cent annual growth until and average -0.1 per cent annual growth thereafter. This scenario assumes the loss of a large industrial customer and a lower forecast for industrial customers and also assumes reductions in their future energy consumption. Figure 3.3 presents the 2012 electrical energy sales forecast from to for the medium, high and low growth scenarios and the medium forecast from the 2011 APR. Year indicated in the figure is the financial year ending in June of the year specified. Figure Forecast of total Tasmanian electrical energy sales Year Medium 2012 High 2012 Low 2012 Historic Medium 2011 As per the 2011 actual data, annual energy losses (including distribution losses) were 5.06 per cent of the total generation. This percentage of losses has been used for estimating the expected energy generation required to meet the Tasmanian energy demand. Annual energy generation and sales forecasts are presented in Appendix 1. Transend Networks Pty Ltd 2012 Page 35

38 3.2.4 Maximum demand forecast The winter MD forecast has been prepared by NIEIR and represents the demand on generating equipment in meeting the maximum Tasmanian demand. This includes losses in the transmission and distribution systems. In addition to high, medium, and low scenarios, the MD forecasts are prepared on a probability of exceedance (POE) basis relating to temperature. Three POE conditions have been developed for Tasmania: 10 per cent POE forecast indicates there is a 10 per cent chance of a peak exceeding the forecast occurring in any year; 50 per cent POE forecast indicates there is a 50 per cent chance of a peak exceeding the forecast occurring in any year; and 90 per cent POE forecast indicates that there is a 90 per cent chance of a peak exceeding the forecast occurring in any year. Due to the temperature variability associated with the maximum demand, Transend uses the 10 per cent POE medium growth forecast as a base for its planning studies. The winter maximum demand forecasts have a strong correlation with low average daily temperatures during business winter days. In winter 2011, Tasmanian maximum demand was recorded at 6.00 pm on 5 July. However, out of five peak load days, three peaks were recorded in evenings and the other two were recorded in mornings. It should be noted that the summer maximum demand for Tasmania is associated with cold weather in summer, rather than hot weather. In , peak demands for the highest five summer peak days were recorded in mornings. Table 3.1 shows the lowest average temperature days corresponding to POE maximum demand conditions for winter and summer at the Hobart weather station. The methodology applied by NIEIR is to calculate the probabilities associated with different average daily temperatures. The average temperature has been defined as the weighted average of the overnight minimum and the previous daily maximum. In this calculation the daily minimum was assigned a weight of 80 per cent, while the previous day s maximum had an assigned weight of 20 per cent. Table 3.1 Tasmanian reference temperatures at associated POE (ºC Hobart) POE Winter Summer 10% % % The winter and summer maximum demand forecasts for Tasmania from 2011 to 2026 are presented in Appendix 1. It is important to note that the differences between the high, medium and low growth scenarios reflect both different underlying economic growth and different load assumptions for Tasmanian industrial customers. Figure 3.4 and Figure 3.5 present winter and summer MD respectively for each scenario for a 10 per cent POE. Transend Networks Pty Ltd 2012 Page 36

39 Maximum demand (MW) Figure Forecast of total Tasmanian winter maximum demand Year Medium 2012 High 2012 Low 2012 Historic Medium 2011 The average annual growth rate in winter maximum demand is 1.19 per cent for the medium scenario, compared with 1.84 per cent forecast in the 2011 APR. In 2011, the actual winter maximum demand was significantly lower than that forecast. The lower winter maximum demand was due to a combination of mild winter conditions together with a significant reduction in certain industry loads. In the 2011 forecast, 6.94 per cent growth was expected from 2010 to 2011 and average 1.49 per cent annual growth was expected thereafter. In the 2012 forecast, per cent growth is expected for 2012 and thereafter average annual growth of 1.34 per cent is expected. The predicted growth rate for the winter high scenario is 2.68 per cent, which allows for higher growth in residential, commercial and industrial loads and for a potential new directly connected customer in The predicted growth rate for the winter low scenario is per cent, which includes 6.25 per cent sudden drop of demand in 2012 and average annual 0.43 per cent growth thereafter. The annual summer maximum demand is forecast to grow at an annual average of 1.20 per cent for the medium scenario. The maximum demand forecast provided in the 2011 APR indicated annual growth of 1.84 per cent per annum, which included a per cent growth in summer to summer The main reasons for the actual lower summer maximum demand were a combination of warmer temperatures in summer, together with a reduction in major industrial loads. The average annual growth rate for the summer high scenario is 2.78 per cent, which allows for higher growth in the residential, commercial and industrial loads. In this scenario, sudden growths are expected in (8.34 per cent) and (7.16 per cent) due to economic recovery and connection of a new industrial customer to the network. The annual average summer low growth scenario rate is per cent. This scenario predicts a sudden drop in maximum demand (5.82 per cent) in Transend Networks Pty Ltd 2012 Page 37

40 Maximum demand (MW) Figure 3.5 Forecast total Tasmanian summer maximum demand Year Medium 2012 High 2012 Low 2012 Historic Medium Comparison of extrapolated and econometric forecasts A comparison between the econometric forecast by NIEIR and the linear trend of the maximum demand growth is presented in Figure 3.6 and Figure 3.7 for winter and summer respectively. The linear trends have been derived from historical data. The figures of actual maximum demands date back to 2006 and show that the NIEIR 50 per cent 14 POE forecast is below the linear trend of the load growth and falls within the 95 per cent confidence interval until 2026 in the winter and summer forecasts per cent POE has been used for consistency with previous forecasts. Transend Networks Pty Ltd 2012 Page 38

41 Summer maximum demand (MW) Winter maximum demand (MW) Figure 3.6 Comparison of extrapolated and econometric winter forecasts Year Actuals Extrapolated Trend Medium 50% POE forecast 95% confidence interval Figure 3.7 Comparison of extrapolated and econometric summer forecasts Year Actuals Extrapolated Trend Medium 50% POE forecast 95% confidence interval Back casting To assess the validity of the econometric model used for the maximum demand forecast, a back cast (a backward looking forecast) of the actual maximum demand has been conducted. The results are presented in Figure 3.8. This 10-year back cast has been conducted by NIEIR, based on daily reference temperature conditions and actual economic conditions. Transend Networks Pty Ltd 2012 Page 39

42 MW In this back cast, the Tasmanian actual maximum demands include directly connected customer loads. Variations in directly connected customer loads could contribute up to 40 MW of the back casting error, although more typically it is around 30 MW. The back casting indicates that, while the forecasting methodology is reasonably conservative (in that it mostly understates demand), it has produced forecasts that are representative of likely maximum demands. Figure 3.8 Back casting of Tasmania maximum winter demand Back casted MD Year Actual Temperature is a key variable that influences the peak demands. Figure 3.9 provides an alternative representation of the forecast equation. Instead of using the actual temperatures at system maximum demand, the POE temperatures for winter are used to generate the 10, 50 and 90 per cent POE backward looking demands. The two extremes, the 10 and 90 per cent POE demand lines, are also adjusted for the average variability in major load demand at system maximum demand. In most instances, the actual winter maximum demand falls within the 10 and 90 per cent POE. Transend Networks Pty Ltd 2012 Page 40

43 MVAr MW Figure 3.9 Comparison of actual winter maximum demands with 10, 50 and 90 per cent POE Year 10 per cent 50 per cent 90 per cent Actual Reactive power demand Figure 3.10 presents the varying relationship between MW and MVAr peak load based on historical data for five separate winter peaks that occurred in each year from 2007 to The real and reactive power data was collected from connected loads, as opposed to generation sent out. Figure 3.10 Samples of related MW and MVAr demand MW Transend Networks Pty Ltd 2012 Page 41

44 System demand (MW) The above samples indicate that reactive power requirement from the connected load has not significantly increased as the winter peak increased Demand profile Figure 3.11 presents the system demand on the maximum demand day in summer and winter The maximum demand curve illustrates the load profiles and the greater demand variability for electrical energy in winter as compared with summer. Figure 3.11 Winter and summer maximum demand curves :00 2:00 4:00 6:00 8:00 10:00 12:00 14:00 16:00 18:00 20:00 22:00 0:00 Time of day 2011 winter summer 3.3 Supply demand balance This section investigates the energy balance between the forecast demand and the supply of generation including potential future generation sources in Tasmania. The provision of electrical energy to Tasmanian users has been, and is expected to be, dominated by hydro generation for the foreseeable future. Hydro power stations have the capacity to provide MW of the total MW Tasmanian generator capacity connected to the transmission network, which is approximately 81 per cent of the generator capacity. Hydro generator availability is affected by maintenance needs and the availability of water. Even with overall water storage at reasonable levels it is possible that some hydro generating plants associated with small and medium storages would not be available. The reliance on hydro generation has been partially mitigated by the commissioning of Aurora Energy s Tamar Valley Power Station (with four open cycle gas turbines producing 163 MW, and a combined cycle plant producing MW), and Basslink with a potential energy import of 478 MW. Wind generation is currently available from Woolnorth Bluff Point and Woolnorth Studland Bay wind farms producing up to MW. Transend Networks Pty Ltd 2012 Page 42

45 This section considers: existing generation capacity and known generation projects; capacity of the existing and future generation assets, compared with the forecast maximum demand imposed by Tasmanian electricity users; and electrical energy generation capacity, compared with forecast electrical energy consumption. The supply-demand balance presented in this section indicates that the Tasmanian electricity demand will be met for at least the next 15 years Existing generation capacity Table 3.2 presents the total existing generation capacity connected to the transmission network in Tasmania as at June This excludes small embedded generators. Table 3.2 Generator capacity Generator type Number of sites Total name-plate capacity (MW) Hydro 27 2,277.6 Thermal (natural gas) Wind Total 30 2, Hydro generation The long-term annual average energy output of Tasmania s hydro power stations is in the order of 8,700 GWh 15. Gas generation Existing gas generation in Tasmania includes: Aurora Energy Tamar Valley (AETV) Power Station, comprising three open cycle gas turbines at 35 MW each, one open cycle gas turbine at 58 MW, and one combined cycle gas turbine (gas turbine at MW and steam turbine at 68.3 MW). Total station capacity is MW. Wind generation Existing wind generation in Tasmania includes: Woolnorth Bluff Point wind farm, comprising 37 wind turbine generators at 1.75 MW each. Total station capacity is MW. Woolnorth Studland Bay wind farm, comprising 25 wind turbine generators at 3.0 MW each. Total station capacity is 75 MW. Embedded generation In addition to the generation sources presented in Table 3.2, there are embedded generators which are not directly connected to the transmission system. These are: Upper Lake Margaret (hydro 8.4 MW); Lower Lake Margaret (hydro 3.2 MW); Cascade (mini-hydro 1.32 MW); 15 Sourced from Hydro Tasmania s Electricity in Tasmania, A Hydro Tasmania Perspective. Transend Networks Pty Ltd 2012 Page 43

46 Jackson Street, Glenorchy (land fill gas 1.6 MW); Remount Road, Launceston (land fill gas 1.1 MW); McRobies Gully (land fill gas 1.0 MW); Meander Dam (mini-hydro 1.9 MW); Nieterana (mini-hydro 2.2 MW); Launceston General Hospital (natural gas co-generation 2.0 MW); Nichols Poultry wind turbine, Sassafras (wind MW); Currie power station, King Island (diesel, wind, solar array 8.55 MW); Fonterra, Wynyard (natural gas 2.0 MW); Whitemark power station, Flinders Island (diesel 2.8 MW); and Parangana (mini-hydro 0.78 MW) Generation developments Known, publicly-announced generation developments are presented in Figure The criterion used to assess the level of commitment of proposed developments is detailed in Appendix 4. The following project descriptions also include an indication of the extent of their commitment. Figure 3.12 Planned generation developments for Tasmania Musselroe Low Head Long Reach Cattle Hill Proposed Advanced Transend Networks Pty Ltd 2012 Page 44

47 Generation developments that would be connected directly to Transend s network are presented in Table 3.3 below. Table 3.3 Generation developments Project Proponent Fuel Level of commitment Capacity (MW) East Coast Hot Rocks KUTh Energy Geothermal Publicly announced up to 1150 Long Reach Pulp Mill Gunns Ltd Wood waste Proposed 60 Musselroe Musselroe Wind Farm Pty Ltd Wind Advanced 168 Cattle Hill NP Power Pty Ltd Wind Proposed 225 Low Head Low Head Wind Farm Pty Ltd Wind Proposed 30 In addition to the above, connection enquiries have been received from Aurora regarding the following embedded generation schemes that would be connected to Aurora s distribution network: Simplot, Ulverstone (natural gas co-generation 8.0 MW); Delta, Devonport (natural gas 2.5 MW); and Tasmanian Irrigation Development Board, Tunbridge (mini-hydro 5.5 MW) Capacity balance Generation capacity is the sum of the name-plate ratings of all available generators. It determines the ability of the generating system to meet the peak load (also referred to as the MD). Apart from some small distribution embedded generators, the total installed capacity of all power stations in Tasmania is MW. Hydro power stations provide MW of this capacity. Figure 3.13 shows the projected excess generator capacity in Tasmania during winter peak for three scenarios: 1 Scenario 1 - all hydro, thermal and wind generators in service operating at their full nameplate rating with no consideration of Basslink; 2 Scenario 2 - all hydro, thermal and wind generators in service operating at their full nameplate rating except for two largest machines out of service (288 MW), and with Basslink in service (478 MW); 3 Scenario 3 - all hydro, thermal and wind generators in service operating at their full nameplate rating, except for Gordon Power Station and one of the largest machines out of service (144 MW), five per cent wind contribution 16, and a 300 MW constraint on Basslink. The methodology makes the following assumptions: excess generator capacity (full name-plate rating) represents the total capacity of all current hydro and thermal generators in Tasmania, wind generation is assumed to be out of service unless otherwise specified, and the excess capacity is determined by deducting the 10 per cent POE medium forecast for winter maximum demand from generator capacity. 16 Historical data shows that during a system peak (90 per cent confidence) only 5 per cent wind is available. With the addition of more new entry wind generators it is expected the contribution would be greater due to their geographical diversity. Transend Networks Pty Ltd 2012 Page 45

48 Excess generation capacity (MW) All three scenarios show that there is sufficient capacity until at least year However, the system required reserve capacity is not included in this analysis. Scenarios 2 and 3 consider Basslink availability. This potential use of Basslink would depend on market conditions and the availability of generation elsewhere in the NEM. Approximately 60 per cent of the total Tasmanian demand is made up of major industrial, directly connected customers. Due to the large proportion of industrial, directly connected loads in Tasmania in comparison with retail demand, Transend carried out a sensitivity analysis on the potential entry of a major new industry of 200 MW connecting to the transmission network in Figure 3.13 Projected excess generator capacity Year Scenario 1 Scenario 2 Scenario 3 Three new scenarios were developed in line with the above three scenarios. 1 Scenario 4 Generation capacities are the same as Scenario 1. Extra 200 MW load is considered beyond 2017; 2 Scenario 5 Generation capacities and availabilities and Basslink availabilities are identical to Scenario 2. Extra 200 MW load is considered beyond 2017; 3 Scenario 6 Generation capacities and availabilities and Basslink availabilities are identical to Scenario 3. Extra 200 MW load is considered beyond The results of these three scenarios are presented in Figure The reserve margins in these three scenarios are 200 MW lower than that of Scenarios 1, 2 and 3 beyond As can be seen, the additional 200 MW load strains the existing generation capacity, bringing forward the requirement for a new entry generator in Tasmania by approximately 7 years. Transend Networks Pty Ltd 2012 Page 46

49 Excess generation capacity (MW) Figure 3.14 Projected excess generator capacity with entry of a major new industry Year Scenario 4 Scenario 5 Scenario Energy balance The energy balance considers the ability of generation sources (including Basslink) to meet future Tasmanian electrical energy needs. It takes into account hydrological variability, which results in varying inflow conditions to hydro storages. Methodology Transend uses an optimisation modelling software tool called Plexos to determine long-term forecasts of energy availability from all energy sources, including Basslink. The tool models the Tasmanian generation system (hydro, wind and thermal) and Basslink. It simulates market behaviour within the Tasmanian region by optimising the dispatch of generation to meet the Tasmanian demand and to trade across Basslink. The function of the Plexos model is to dispatch generators with the lowest cost to meet the Tasmanian demand from all available generation while maintaining a reasonable storage position and trading with Victoria. The approach developed by Transend is to model hydro generation as a limited resource without assigning any price and allow the software to dispatch hydro generation based on Victorian prices and cost of thermal generation. With this approach, the software minimizes the total cost of supplying Tasmanian demand by replacing highest cost imports and thermal generation with hydro generation. Historical inputs include initial volume, daily inflow and half hourly demand. Thermal fuel costs and hourly wind generation data are also entered into the Plexos model. The model uses forecast Victorian energy prices to represent supply in Victoria and it considers periods where there is a shortfall being represented as high prices, and excess supply as low prices. Transend Networks Pty Ltd 2012 Page 47

50 Generator company business imperatives and financial parameters have not been modelled explicitly. However, financial parameters have been included in an indirect manner with assumptions on fuel price and variable operation costs of thermal generators. In addition to the generation system, the Tasmanian transmission network is represented by 28 nodes. Some of the network constraints are also included into the model formulation. All the hydro schemes are represented in the model as presented in Table 3.4. Table 3.4 Modelling details of hydro schemes Hydro scheme Number of storages Number of power stations Great Lake South Esk 3 3 Anthony - Pieman 6 4 King - Yolande 2 3 Derwent 9 9 Mersey - Forth 7 7 Gordon - Pedder 2 1 The following assumptions were made in this year s simulation using Plexos: hydro storage projections were carried out using three inflows: 10 per cent POE (wet) - 10,477 GWh; 50 per cent POE (medium) - 9,225 GWh; 90 per cent POE (dry) - 7,789 GWh; detailed 28 node network model was included with a number of network constraints; the future energy demand in these scenarios was developed based on the historic load profile and 10 per cent POE maximum demand forecast of each substation; consistent with AEMO guidelines in Electricity Statement of Opportunities (ESOO) and NTNDP, only committed generation was assumed to be available for dispatch; the wind profile used for each year s simulation was based on the past five years operation patterns of Bluff Point and Studland Bay wind farms. The energy capacity factor is approximately 40 per cent per annum; variable operation and maintenance cost and fuel prices for AETV combined cycle and open cycle plants were sourced from publicly available information 17. The short run marginal costs (based on marginal operation and maintenance costs) of the combined cycle plant are low and this plant would operate as a base load in Tasmania. The open cycle generators are peaking plants that have relatively high operating costs and usually are operated to pursue higher market prices; the initial reservoir levels used by Plexos for each sequence were the actual reservoir levels as at the beginning of ; system FCAS demand is also included into the model as constant demand; 17 ACIL Tasman report, Fuel resource, new entry and generation costs in the NEM, April Sourced from Hydro Tasmania web site: Transend Networks Pty Ltd 2012 Page 48

51 the energy supply-demand balance for medium and high energy growth scenarios was investigated. This is due to a significant reduction in forecast energy growth in comparison with the 2011 forecast, and uncertainty about how the Carbon Price Mechanism will impact future energy growth in Tasmania; a 10 per cent POE system forecast prepared by NIEIR was used, but only committed, directly connected customer loads were considered. The possibility of a directly connected customer entering in 2018 was considered for the high growth scenario only; and a carbon tax scenario was incorporated in the analysis in two ways: firstly the demand forecasts from NIEIR consider the impact of the Carbon Price Mechanism for Tasmania; and secondly the Victorian pool price forecast uses similar Carbon Price Mechanism assumptions for mainland Australia. Scenarios investigated Two scenarios were investigated in order to estimate future energy balance due to demand forecasts and variation of hydro inflows. The third scenario is to identify the impact of selected outages of the electricity network. The following three scenarios have been investigated using the Plexos modelling tool: Scenario 1 this is the base case, where historical inflow data from (15 years) was used and medium energy growth was incorporated; Scenario 2 historical inflow data from (15 years) was used together with high energy growth, and considers two proposed generation projects and hypothetical timing of availability of the new generation sources; and Scenario 3 extended failure of a major power scheme, local gas supply or Basslink. Scenario 1 In this scenario, no new generation has been considered. The expected energy growth is to be met by the existing sources. Figure 3.15 shows the expected supply share from the available sources to meet the future demand. Transend Networks Pty Ltd 2012 Page 49

52 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE GWh Figure 3.15 Scenario 1 Supply balance to meet the extra energy demand 1,600 1,400 1,200 1, Imports Wind Thermal Hydro There are a few points of note in Figure 3.15: There is no positive growth in energy demand during initial years. In these initial years, variations in the supply sources can be observed. These variations are mainly due to the forecasted Victorian price profile and the availability of hydro energy. The latter part of the planning horizon shows that the major contribution to meet the energy growth is from imports, followed by hydro and thermal generation respectively. No unserved energy was noted during the 15-year horizon. Scenario 2 Scenario 2 uses the same hydro assumptions, but with a higher than expected demand over the next 15 years. It is assumed that the economic factors favouring a high growth in demand would also favour growth in industrial demand. This scenario also assumes that two proposed wind generators connect in 2014 and 2019 respectively. Figure 3.16 shows the expected supply share from the available sources to meet a high growth demand with new generators in Tasmania. Transend Networks Pty Ltd 2012 Page 50

53 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE 50% POE % POE 10% POE GWh Figure 3.16 Scenario 2 Supply balance to meet the extra energy demand 4,400 4,000 3,600 3,200 2,800 2,400 2,000 1,600 1, Imports Wind Thermal Hydro It is noted that the contribution from new generators is significant to meet the future demand. However, imports are more than double with respect to Scenario 1 as the demand growth under this scenario is much higher than that of Scenario 1. The addition of new generators reduces the reliance on hydro generation. Scenario 3 This scenario investigates three extended outages and their impacts on the hydro system in Tasmania. The outages modelled include a major failure of: a power scheme; Transend Networks Pty Ltd 2012 Page 51

54 Energy in storage (percentage full) the gas supply network; and Basslink. The methodology applied in modelling the failures was to apply a six-month outage for each failure occurring in 2013 assuming initial volumes for hydro storages as at January According to 2013 energy demand and 50 per cent POE hydro inflow, a net positive export is expected by the end of the year, if the storages levels at the end of 2013 are the same as at the end of Accordingly, two sets of outages were modelled: Case 1: The outages occur from January to June when the system has high exports. Case 2: The outages occur from July to December when the system has fewer exports. The system simulations were carried out for 12 months which includes a six month period post outage to determine if the storage levels will return to the initial levels. Figure 3.17 presents the energy storage position variations under different outages in Case 1. Since the outages occur during high export periods, a Basslink outage would result in high storage levels during the outage period. Similarly, a Gordon Power Station outage would result in high storage levels during the outage period. A major gas failure would result in more generation of hydro energy, which would lead to a reduction in the storage levels during the outage period. However, the highest expected drop of storage level with respect to system normal is 2 per cent. Figure 3.17 Case 1 Monthly storage position with extended outages 70% 60% 50% 40% 30% 20% 10% 0% Month System normal Major Basslink failure Major Gordon outage Major gas failure The storage position variations under these outages in Case 2 are shown in Figure Even though there are few net import months in the outage period, storage variations are similar to Case 1. Transend Networks Pty Ltd 2012 Page 52

55 Energy in storage (percentage full) Figure 3.18 Case 2 Monthly storage position with extended outages 80% 70% 60% 50% 40% 30% 20% 10% 0% Month System normal Major Basslink failure Major Gordon outage Major gas failure Summary of findings The findings regarding the energy supply demand balance are heavily dependent on the assumptions made about the demand, the forecast Victorian pool price and the heuristic controls in Plexos. Any change to these assumptions affects the outcome. The findings suggest that for medium and high energy growth scenarios there are no issues for the next 15-year period. However, high imports would be required to support energy growth in the system. Similarly, there are no issues with the major failures studies. However, a major gas failure may result in a reduction in hydro storage levels of up to 5 per cent. Transend Networks Pty Ltd 2012 Page 53

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57 4 Completed, committed and advanced network augmentations 4.1 Introduction This section provides an overview of the recently completed, committed or advanced transmission network augmentations, connection developments, and asset replacement projects that have an estimated cost of $5 million or more. The criteria for describing projects as completed, committed or advanced are set out in Appendix 4. The identified projects have been, or are being, undertaken to remove existing or emerging transmission constraints, to increase connection site capacity or to improve connection point performance. The objectives of the asset replacement projects are to address safety issues, improve the reliability of electricity supply and to reduce operations and maintenance costs. 4.2 Completed projects This section describes the projects that have been completed between July 2011 and June Sheffield Burnie 110 kv transmission line augmentation The Sheffield Burnie 110 kv transmission line augmentation project consisted of increasing the design operating temperature from 49 C to 75 C by upgrading sections of the transmission line. This has increased the winter/summer rating of the Sheffield Burnie 110 kv transmission line from 172/110 MVA to 244/208 MVA. The project was completed in July Paloona Tee to Burnie Substation OPGW The Paloona Tee to Burnie Substation optical ground wire (OPGW) installation project was the last stage of a strategy to establish a continuous, high capacity telecommunications link that extends from Sheffield Substation to Smithton Substation. The project increased the telecommunications diversity, enabling contemporary transmission line protection schemes to be installed, improving transmission line lightning protection and providing enhanced capacity for remote asset monitoring functions. The project was completed in September Tungatinah Substation 22 kv switchgear replacement and associated works The outdoor 22 kv switchgear at Tungatinah Substation was in poor condition. It presented a safety risk, was unreliable and required frequent maintenance and repair. The project comprised the replacement of the outdoor 22 kv switchgear with indoor switchgear comprising one incomer circuit breaker, four 22 kv feeders and associated protection and control schemes. It also included the installation of a SCADA system and AC and DC supplies. The project was completed in November Transend Networks Pty Ltd 2012 Page 54

58 4.2.4 Kingston Substation new 110/33 kv connection point This project comprised the establishment of a new 33 kv connection point at the existing Kingston Substation, which included the installation of two 110/33 kv 30/60 MVA transformers, 110 kv and 33 kv switchgear and associated protection and control schemes. The new connection point provides additional capacity and improved reliability of supply to Kingston and surrounding areas such as Blackmans Bay, Browns River and Margate. The project was completed in April Farrell Substation to John Butters Power Substation OPGW This project comprised the installation of an OPGW from Farrell Substation to John Butters Power Station, providing communications diversity and facilitating the future upgrade of protection schemes at Queenstown, Newton, Rosebery and Farrell substations. The project was completed in May St Leonards Substation development This project comprised the construction of a new substation at St Leonards in east Launceston, which included the installation of two 110/22 kv 30/60 MVA transformers, 110 kv and 22 kv switchgear and associated protection and control schemes. It is supplied via a new 110 kv underground transmission circuit from Mowbray and Norwood substations (see Section 4.2.7). The combination of the 110 kv transmission circuit between Norwood and Mowbray substations and the new connection point at St Leonards was identified through joint planning between Transend and Aurora as the preferred option to address the current and imminent performance issues in the Launceston area. The project is approaching completion in July Norwood St Leonards Mowbray 110 kv transmission circuit This project comprised the installation of an underground 110 kv transmission cable between Norwood and Mowbray substations via St Leonards Substation. The new transmission circuit provides a 50 MVA firm capacity at Mowbray Substation and an alternate transmission path in the event of a double circuit (tower) failure on either of the Hadspen Norwood or Hadspen Trevallyn 110 kv transmission circuits. The project is approaching completion in July Committed projects This section provides information about projects that satisfy the criteria for committed projects. Each of the committed projects identified in this section were included in the 2011 APR Rosebery Substation 110 kv augmentation Rosebery Substation is supplied via the Farrell Rosebery 110 kv transmission line. The Farrell Rosebery Queenstown 110 kv transmission line also connects to Rosebery Substation, but it is normally operated open at Rosebery Substation because of technical limitations. With Rosebery Substation supplied solely from the Farrell Rosebery 110 kv transmission line, the transmission network that supplies Rosebery Substation does not meet the requirements of clause Transend Networks Pty Ltd 2012 Page 55

59 5(1)(a)(i) of the ESI Regulations as more than 25 MW of load is capable of being interrupted by a credible contingency event. No alternative non-network solutions that would address the reliability issues have been identified through the consultation process. This project comprises the installation of a 110 kv bus coupler circuit breaker at Rosebery Substation and protection scheme replacements at Farrell and Rosebery substations. This will enable the Farrell Rosebery Queenstown transmission line to operate normally closed, providing firm (N-1) transmission security to Rosebery Substation and ensuring the performance requirement of clause 5(1)(a)(i) of the ESI Regulations is met. Figure 4.1 illustrates the proposed transmission network to supply Rosebery Substation. Figure 4.1 Proposed 110 kv transmission supply to Rosebery Substation The project is scheduled to be completed by October George Town Substation 220 kv security upgrade George Town Substation comprises both 220 kv and 110 kv switchyards and is a critical part of the Tasmanian transmission network. The 220 kv substation connects to the remainder of the Tasmanian transmission network via two double circuit 220 kv transmission lines that emanate from Hadspen and Sheffield substations. It also connects to the Victorian transmission network via Basslink. The George Town 220 kv Substation provides connections to Aurora Energy s Tamar Valley Power Station as well as supplying a major industrial customer. The 220 kv and 110 kv switchyards at George Town Substation are interconnected via three auto-transformers. It has been identified that the current configuration of the George Town Substation does not meet the performance requirement of clause 5(1)(a)(ii) of the ESI Regulations in that more than 850 MW of load could be interrupted by a single asset failure. If the bus coupler circuit breaker fails to operate in the event of a fault, it has the potential to cause system instability leading to wide spread loss of load, which could exceed 850 MW. In addition, planned or unplanned outages of the critical Transend Networks Pty Ltd 2012 Page 56

60 220 kv transmission circuits reduce operational flexibility and, in some instances, significantly constrain the transmission network. A number of 220 kv assets including the A busbar, gantry structures, instrument transformers, disconnectors and protection schemes are in poor condition and need to be replaced. No alternative non-network solution that would address the security issue was identified through the consultation process. This project will reconfigure part of George Town Substation and replace assets in poor condition. The reconfiguration includes the transmission circuits that connect to Hadspen and Sheffield substations and the three auto-transformers being reconnected in circuit breaker-and-a-half arrangement. A schematic diagram of the proposed George Town 220 kv Substation is presented in Figure 4.2. A further security issue associated with George Town Substation is discussed in Section Figure 4.2 Proposed George Town Substation 220 kv arrangement To George Town Converter Station From Tamar Valley Power Station From Hadspen From Sheffield George Town 220 kv Bus F George Town 220 kv Bus B To Comalco To George Town 110 kv Substation The project is scheduled to be completed by November Transend Networks Pty Ltd 2012 Page 57

61 4.3.3 Sheffield Substation to George Town Substation OPGW This project consists of the construction of the Sheffield to George Town OPGW which includes installation of OPGW on the Sheffield George Town 220 kv transmission line, with a short tee-off to the Badgers Range telecommunication site and the installation of OPGW on a short section of the Sheffield Railton 110 kv transmission line. The installation will provide lightning protection along the full length of the Sheffield George Town 220 kv transmission line and 40 per cent of the 110 kv transmission line to Railton. The project is scheduled to be completed by November Palmerston Substation 110 kv redevelopment Palmerston 110 kv Substation is critical to ensuring a secure and reliable electricity connection point for customers and generators located in northern Tasmania. Palmerston 110 kv Substation provides an interconnection to Palmerston 220 kv Substation via a 150/200 MVA auto-transformer, 110 kv connections to Arthurs Lake, Avoca, Hadspen, St Marys and Waddamana substations, a 22 kv connection to Aurora, and two 110 kv connections to Hydro Tasmania s Poatina Power Station. The redevelopment of Palmerston 110 kv Substation includes the replacement of circuit breakers, voltage transformers, post insulators and selected protection and control equipment. The substation redevelopment will improve the reliability, security and performance of the electricity supply by replacing assets that are in poor condition and susceptible to failure. The project is scheduled to be completed by March Arthurs Lake Substation redevelopment Arthurs Lake Substation is supplied radially by the Palmerston Arthurs Lake 110 kv transmission line. The transformer at Arthurs Lake provides a 6.6 kv connection to a Hydro Tasmania pumping station and a 6.6 kv connection to Aurora. The planned redevelopment of Arthurs Lake Substation includes the replacement of the transformer, oil containment facilities, 110 kv circuit breaker, 6.6 kv switchgear, station services AC and DC equipment, and protection and control equipment. The substation redevelopment will improve the reliability of electricity supply by replacing assets that are in poor condition and susceptible to failure. The project is scheduled to be completed by August Newton Substation redevelopment Newton Substation is supplied radially by the Queenstown Newton 110 kv transmission circuit. The two transformers at Newton provide an 11 kv connection to a Hydro Tasmania pumping station and a 22 kv connection to Aurora. The planned redevelopment of Newton Substation includes the replacement of the two transformers, oil containment facilities, 110 kv circuit breaker, 22 kv and 11 kv switchgear and protection and control equipment. A new building will be constructed to accommodate the low voltage switchgear, the AC and DC equipment, and protection and control equipment. The substation redevelopment will improve the reliability, security and performance of electricity supply by replacing assets that are in poor condition and susceptible to failure. This project is scheduled to be completed by May Transend Networks Pty Ltd 2012 Page 58

62 4.3.7 Burnie Substation 110 kv redevelopment Burnie 110 kv Substation is critical to ensuring a secure and reliable electricity supply to customers located in north-west Tasmania. It provides an interconnection to Burnie 220 kv Substation via a 150/200 MVA auto-transformer, 110 kv connections to Emu Bay, Hampshire (radial), Port Latta, Sheffield and Smithton substations, and a 22 kv connection to Aurora. The planned redevelopment of Burnie 110 kv Substation includes the replacement of 110 kv circuit breakers, current transformers, protection and control equipment and the installation of voltage transformers. The substation redevelopment will improve the reliability, security and performance of electricity supply by replacing assets that are in poor condition and susceptible to failure. The project is scheduled to be completed by April Creek Road Substation 110 kv redevelopment Creek Road Substation is critical to ensuring a secure and reliable electricity supply to southern Tasmania. It is an integral part of the transmission network in the south with 110 kv connections to Chapel Street, New Norfolk, Risdon and North Hobart substations. Three of Aurora s zone substations in the greater Hobart area are connected to the Creek Road Substation 33 kv switchboard. North Hobart Substation and Aurora s zone substations supply Hobart s central business district, including hospitals and other critical facilities. The load connected to Creek Road and North Hobart substations is approximately 180 MVA. Creek Road Substation was last redeveloped in 1951 to operate at a voltage of 110 kv and at that time it was configured as a ring bus arrangement. This lacks operational flexibility, has complex maintenance issues and has limited capability for expansion for additional circuit connections. The planned redevelopment of Creek Road Substation includes the replacement of all 110 kv primary equipment (including circuit breakers, disconnectors, current and voltage transformers) and replacement of all associated protection and control equipment. The 110 kv outdoor air-insulated switchgear (AIS) ring bus arrangement will be replaced with an indoor gas-insulated switchgear (GIS) double bus arrangement. The indoor GIS substation will be constructed within the existing switchyard area and will include provision for additional bays in the future. The substation redevelopment will remove capacity constraints and improve the reliability of supply to Hobart s central business district and suburbs. The project is scheduled to be completed by December Tungatinah Substation 110 kv redevelopment Tungatinah Substation and Tarraleah Switching Station were commissioned in 1953 and 1938 respectively. The majority of the assets at these sites are in poor condition and susceptible to failure. This project comprises the redevelopment of Tungatinah Substation and the extension of the 110 kv transmission circuits that connect Meadowbank and Tarraleah power stations and New Norfolk Substation to Tungatinah Substation. Three new transmission line bays will be established at Tungatinah Substation. The redevelopment project also provides the opportunity to rationalise the transmission network to remove line crossovers just south of Tarraleah Switching Station, and to bypass the Boyer Tee Structure. As part of the redevelopment, a new 110/22 kv supply transformer will be installed to replace the existing supply transformer at Tungatinah Substation. The project is scheduled to be completed by April Transend Networks Pty Ltd 2012 Page 59

63 4.4 Advanced projects There are no advanced projects in the 2012 APR. Transend Networks Pty Ltd 2012 Page 60

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65 5 Proposed network developments 5.1 Introduction This section describes existing and emerging constraints within the transmission network that have been identified in meeting the performance requirements of the NER and ESI Regulations. A seven year planning horizon has been applied (to include Transend s next Revenue Reset period ). Where new network transmission assets are proposed to relieve constraints, these are presented, as required by the NER. The section also contains proposals for future connection points. As detailed in Section 5.6.5B of the NER, a regulatory investment test for transmission (RIT-T) is required to be undertaken for all capital works projects where the augmentation component is estimated to cost more than $5 million. Not all costs associated with asset replacements or establishing customer connections are subject to the RIT-T. Section of the NER details the procedures and documentation required as part of the RIT-T. System planning studies are conducted to determine the adequacy of the current transmission system to meet the NER and jurisdictional planning criteria, taking into account the forecasted demand growth. A summary of Transend s planning methodology is included in Appendix 9. Section 5.2 describes proposed augmentation projects to be carried out over the next seven years and if the augmentations have any material inter-network impacts. The proposed augmentations outlined in Section 5.2 are for information only and will be subject to further consultation if necessary, as required by the RIT-T. Other issues identified in Section 5.2 include forecast constraints, where consultation with directly connected customers is required or the proposed augmentation to address the constraint is subject to further study. Section 5.3 provides information regarding the estimated reduction in forecast load that could defer an identified constraint for a period of 12 months. New connection point and generation proposals that have been received are presented in Section 5.4. Replacement transmission network assets that have an estimated total capitalised expenditure of more than $5 million and are planned to be implemented over the next seven years are presented in Section Forecast constraints and proposed developments This section presents the constraints in the Tasmanian system forecast to occur over the next seven years and describes the preferred options to relieve these constraints. An explanation of the ranking of reasonable options to address the identified constraints has been provided, in line with the criteria prescribed in the NER. System performance for the planning period is assessed against the following criteria: thermal overloading; voltage performance; security and reliability; ESI Regulations; and electricity industry good practice. The results of system studies are divided into five geographical areas: west coast; Transend Networks Pty Ltd 2012 Page 61

66 north-west; George Town; north; and south. The geographical areas with encompassing power stations and substations are detailed in Appendix 7. The studies have been conducted using Transend s 2012 medium growth, 10 per cent POE 19 demand forecast. This represents a medium economic growth scenario as forecasted by AEMO in its key economic scenarios and macroeconomic and energy variable forecasts. Section 3.2 of this APR discusses the load forecasting methodology whilst Appendix 1 presents the maximum demand and energy forecasts. The results of these studies indicate the location and expected timing of potential constraints. However, the possible duration of the identified constraints and their impact on electricity market operations can vary depending on market and operational conditions hence are not included in the report. Table 5.1 summarises the existing and forecast constraints on the transmission network over the following one, three, five and seven years. The proposed augmentations presented in the remainder of Section 5.2 are the preferred options to meet the criteria. The preferred option that is presented represents the best option at the time of the study. Transend will continue to undertake consultation with the customers impacted by the transmission network changes. Table 5.1 Existing and forecast transmission system constraints Area of constraint Type of constraint Existing and forecast constraints within one year Avoca St Marys transmission circuit Avoca Substation Derby Substation Farrell Que Savage River Hampshire transmission circuit Farrell Rosebery Queenstown transmission circuit Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance prescribed in the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Overload under extreme summer conditions on the Waratah Tee Savage River section Above the 25 MW loss of load performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Forecast year Farrell Substation 220 kv security System stability Now George Town Substation kv busbar arrangement George Town Substation kv dynamic reactive support System stability and above the 850 MW loss of load performance requirement of the ESI Regulations System stability George Town Temco Firm (N-1) capacity exceeded Now Now Now Now Now Now Now Now Now Now per cent chance of a peak exceeding the forecast occurring any year Transend Networks Pty Ltd 2012 Page 62

67 Area of constraint transmission line George Town Comalco transmission lines Hadspen Substation 220 kv security Type of constraint Firm (N-1) capacity exceeded System stability Forecast year Now Now Meadowbank Substation Newton Substation Palmerston Avoca transmission circuit Palmerston Waddamana Liapootah 220 kv transmission line Queenstown Newton transmission circuit Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 3000 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations St Marys Substation Firm (N-1) capacity exceeded Now Upper Derwent generation Loss of line capacity restrictions in summer Now Waddamana Substation 220 kv security Forecast constraints within three years Chapel Street Kingston Knights Road and Chapel Street Kingston Electrona transmission circuits System stability Above the 3000 MWh unserved energy performance requirement of the ESI Regulations Now Now Now Now Now Now 2014 Rosebery Substation Firm (N-1) capacity exceeded 2014 Rosebery Substation Southern area - voltage stability Forecast constraints within five to seven years Devonport 110/22 kv transformer capacity constraint Southern area - voltage stability requiring dynamic reactive support Above the 300 MWh unserved energy performance requirement of the ESI Regulations Non-compliance with the NER criteria to maintain 1% reactive margin as per Clause S5.1.8 Above the 300 MWh unserved energy performance requirement of the ESI Regulations Non-compliance with the NER criteria to maintain 1% reactive margin as per Clause S There are substations where the MD is currently above the four-hour short term firm (N-1) rating of the supply transformers. Table 5.2 lists these substations and the number of hours the transformer four-hour short term firm rating was exceeded during Appendix 5 provides data on the 2011 actual and 2022 forecast MD at each of Transend s substations as a percentage of substation firm (N-1) capacity, with the substation rated at its four-hour short term rating. Transend Networks Pty Ltd 2012 Page 63

68 Table 5.2 Substations that exceeded their transformer short term capacity in 2011 Substation Hours exceeding short term capacity St Marys 17.0 Lindisfarne West coast area development plan Existing network overview The west coast 220/110 kv transmission system consists of a network that supplies the area that stretches from south of Hampshire Substation to John Butters Power Station, and includes the generation centres at Bastyan, John Butters, Mackintosh, Reece, Tribute, Lake Margaret (note Lake Margaret is connected at 11 kv at Queenstown not 110 kv or 220 kv) and transmission substations at Queenstown, Rosebery, Newton, Farrell, Que, Waratah Tee and Savage River. The west coast area is a large net exporter of energy to the system. The installed generation capacity is around MW and the coincidental maximum demand in 2011 was about 72 MW. The west coast 110 kv transmission system is operated radially. Farrell Substation is the major substation in the west coast area. It is the connection point for all generation in the area. There is one 220 kv transmission line that connects the generation supply from Farrell Substation to the rest of the transmission network. There are two radial 110 kv networks in the west coast area: Farrell Que Waratah Tee Savage River Hampshire and Farrell Rosebery Queenstown Newton. The Farrell Que Waratah Tee Savage River Hampshire 110 kv circuit supplies load at Que and Savage River substations with the circuit operated normally open at Hampshire Substation. The Farrell Rosebery 110 kv and Farrell Rosebery Queenstown 110 kv transmission circuits supply loads at Rosebery, Queenstown and Newton substations. Figure 5.1 presents a geographical map of the west coast area, with Figure 5.2 presenting the 220/110 kv transmission network. Figure 5.1 Geographical map of west coast area Legend: 220 kv 110 kv Transend Networks Pty Ltd 2012 Page 64

69 Figure 5.2 West coast area network schematic diagram Existing and committed generation The west coast area s existing generation is entirely hydro. The hydro generators are located at Reece (231.2 MW), John Butters (144 MW), Tribute (82.8 MW), Bastyan (79.9 MW), Mackintosh (79.9 MW) and Lake Margaret (8.4 MW) power stations. There is potential for new renewable generation to be installed within the planning period, as there are a number of wind farm opportunities in the west coast area Load forecast The load in the west coast area is mostly mining and minerals processing. The connection points for the distribution network (Aurora) are located at Savage River, Rosebery, Queenstown and Newton. The current maximum distribution load is approximately 7 MW at the Queenstown Substation 22 kv connection point, 21 MW collectively at the Rosebery Substation (44 kv and 22 kv) connection point, 4 MW at Newton Substation and 2 MW at Savage River Substation. The remaining connection points provide supply to Que Substation (Bass Metals), Queenstown Substation 11 kv (Copper Mines of Tasmania), Rosebery Substation (Mining & Manufacturing Group) and Savage River Substation (Grange Resources). The west coast area has many mineral and ore deposits. Due to the load being predominantly mining load and subject to commodity prices and economic conditions at the time, it is critical that Transend continues to consult with the customers to ensure that the appropriate network security and reliability levels are provided. There are a number of proposals to establish new mines and preliminary connection enquiries have been received during The maximum retail demand forecast for the west coast area substations is presented in Appendix 1. Transend Networks Pty Ltd 2012 Page 65

70 Fault Levels The fault levels for the west coast area have been analysed to ensure that they remain within the equipment and design limits (refer Section 6.5). A table listing the current maximum and minimum fault levels for the substations in the west coast area is provided in Appendix Committed Projects Currently the west coast area has two committed network projects. These projects have been included in all planning scenarios for the west coast area. The details of these projects are presented in Section 4.3. Table 5.3 outlines the status of committed projects. Table 5.3 West coast area committed projects Project (Committed) Expected completion Rosebery Substation 110 kv augmentation October 2012 Newton Substation redevelopment May Constraints, options and preferred solutions The forecast network constraints for this area are impacted significantly by the load demands for the area. All connection points have been analysed collectively and individually during the development of the west coast area plan. The following section presents details of the network system constraints, including the forecast year of impact, options that are currently being considered, preferred option and the estimated cost. The cost data is high level and indicative of the proposed costs and is presented in 2012 base dollars. Constraints that exist or are forecast to occur within seven years in the west coast area are presented in Figure 5.3 and outlined in Table 5.4. The proposed network developments to address the identified issues are described in this section. There are no proposed asset renewal projects that have an estimated cost of more than $5 million and are planned to be commissioned over the next seven years. Transend Networks Pty Ltd 2012 Page 66

71 Figure 5.3 West coast system constraints Table 5.4 West coast area proposed developments Constraint Driver(s) Proposed development Estimated Year of Completion Estimated cost Rosebery Substation supply transformer capacity Firm (N-1) capacity exceeded Above the 300 MWh unserved energy requirement of the ESI Regulations Replace the existing supply transformers with larger units 2015 $5.6 million Newton and Queenstown substations transmission security Above the 25 MW requirement of the ESI Regulations Above the 300 MWh unserved energy requirement of the ESI Regulations Tee-off Farrell John Butters 220 kv transmission circuit and install a 220/110 kv network transformer at Queenstown Substation 2017 $12.0 million Newton transformer supply capacity Above the 300 MWh requirement of the ESI Regulations Maintain existing service level security. n/a n/a West Coast 110 kv transmission security Above the 25 MW requirement of the ESI Regulations Above the 300 MWh unserved energy Maintain existing service level security n/a n/a Transend Networks Pty Ltd 2012 Page 67

72 Constraint Driver(s) Proposed development Farrell Substation 220 kv security upgrade requirement of the ESI Regulations System stability Install one new circuit breaker in the bus coupler bay to create a double breaker arrangement Estimated Year of Completion Estimated cost 2017 $1.3 million Rosebery Substation supply transformer capacity Rosebery Substation has two 110/44-22 kv 20/30 MVA supply transformers. The maximum demand at Rosebery Substation in 2011 was 26.5 MW and is forecast to exceed the continuous firm rating of the transformers by A transformer contingency by winter 2015 could result in unserved energy in excess of 300 MWh. This does not meet the performance requirements of clause 5(1)(a)(iv) of the ESI Regulations. The options outlined in Table 5.5 have been considered to address the identified capacity issue. Table 5.5 Options being considered to address Rosebery Substation supply transformer capacity Option Type of option Detail 1 Network Install a third 110/44 kv 20/30 MVA supply transformer at Rosebery Substation, increasing the firm capacity to 60 MVA 2 Network Replace the existing two 110/44-22 kv 20/30 MVA supply transformers at Rosebery Substation with two 110/66-44 kv 30/60 MVA units, increasing the firm capacity to 60 MVA. This option would allow the future establishment of a 66 kv sub-transmission network in the area and enable the 44 kv load to be progressively transferred to 66 kv 3 Network Establish a 220/66 kv connection point at Farrell Substation. This option would allow the future establishment of a 66 kv sub-transmission network in the area and enable the 44 kv load to be progressively transferred to 66 kv, reducing the load on the existing 44 kv network to within the (N-1) continuous rating of the transformers 4 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 5 Generation At this stage Transend is not aware of any prospective embedded generation in the area The preferred option to address the identified constraint at Rosebery Substation is Option 2. The estimated cost of the replacement of the two transformers is $5.6 million and it is proposed to be completed by June The proposed augmentation will not have any significant inter-network impact Newton and Queenstown substations transmission security The Farrell Rosebery Queenstown 110 kv transmission circuit supplies Queenstown and Newton substations. Currently, this line is normally operated open at Rosebery Substation but from October 2012 it will normally be closed. The coincidental maximum demand of loads at Queenstown and Newton substations in winter 2011 was 23.9 MW and is expected to exceed 25 MW by A contingency on the Farrell Rosebery Queenstown transmission circuit results in loss of supply to both substations and could interrupt more than 25 MW of load by winter In addition, by winter 2012, a transmission contingency on the Farrell Rosebery Queenstown transmission circuit Transend Networks Pty Ltd 2012 Page 68

73 could result in more than 300 MWh of unserved energy. This does not meet the performance requirements of clauses 5(1)(a)(i) and 5(1)(a)(iv) of the ESI Regulations. The options outlined in Table 5.6 are currently being considered to address the identified security issue. Table 5.6 Options being considered to address Newton and Queenstown substations transmission security Option Type of option Detail 1 Network Tee-off Farrell John Butters 220 kv transmission circuit and install a 220/110 kv network transformer at Newton Substation 2 Network Tee-off Farrell John Butters 220 kv transmission circuit and install a 220/110 kv network transformer at Queenstown Substation, connect Farrell Rosebery Queenstown 110 kv circuit in and out of Newton Substation, and dismantle Queenstown Newton circuit 3 Network Construct a new 110 kv Rosebery Newton transmission circuit 4 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 5 Generation At this stage Transend is not aware of any prospective embedded generation in the area The preferred option to address the identified transmission security to Newton and Queenstown substations is Option 2. This project will require extension of the Queenstown Substation switchyard to accommodate a 220/110 kv 90/150 MVA transformer and associated switchgear. A short 220 kv tee-off line of approximately 250 m will be constructed from the Farrell John Butters 220 kv transmission circuit to Queenstown Substation. In order to establish firm supply to Newton Substation, the 110 kv Farrell Rosebery Queenstown transmission circuit will be converted to a loop-in-loop-out connection at Newton Substation. This will allow the existing Queenstown Newton 110 kv transmission line to be decommissioned and dismantled. This line was constructed in 1936 and is in poor condition. The estimated cost of the preferred option is $12.0 million and it is proposed to be completed by June The proposed augmentation will not have any significant inter-network impact Newton transformer supply capacity Newton Substation supplies an Aurora Energy connection via a single 110/22 kv supply transformer. Currently, a contingency on this supply transformer could result in excess of 300 MWh of unserved energy. This does not meet the performance requirement of clause 5(1)(a)(iv) of the ESI Regulations. The planned redevelopment of Newton Substation is expected to be completed by May This includes replacement of the supply transformer, oil containment facilities, 110 kv circuit breaker, secondary switchgear, AC and DC equipment and protection and control equipment. However this replacement will not address the firm security issue. The options in Table 5.7 are currently being considered to address the identified issue. Transend Networks Pty Ltd 2012 Page 69

74 Table 5.7 Options being considered to address Newton transformer supply capacity Option Type of option Detail 1 Network Install a second 110/22 kv 17/25 MVA supply transformer at Newton Substation 2 Network Install a suitable cold spare transformer at Newton Substation. This would be compatible with the existing transformer, and would be stored in readiness for operation (filled with oil) but would not be connected until required by a contingency 3 Exemption after consultation 4 Demand management Maintain existing service level security At this stage there has been no indication from connected customers on the willingness to offer demand management 5 Generation At this stage Transend is not aware of any prospective embedded generation in the area Due to the size of the load at Newton Substation Transend s preferred option is Option West Coast 110 kv transmission security Que and Savage River substations are supplied via the Farrell Que Waratah Tee Savage River Hampshire 110 kv transmission circuit. In 2011, the maximum demand at Que and Savage River substations was 7.5 MW 20 and 21.7 MW respectively. The coincidental maximum demand was 28.7 MW. There are a number of issues relating to the security of supply at Que and Savage River substations. Overloading of the Waratah Tee Savage River section of the Farrell Que Waratah Tee Savage River Hampshire 110 kv transmission circuit occurs during extreme summer conditions (very high ambient temperature and low wind). This section of the circuit has a design operating temperature of 49 C. This constraint is being managed by the application of dynamic transmission line ratings. Currently, a contingency on the Farrell Que Waratah Tee Savage River 110 kv transmission circuit would interrupt load, resulting in more than 300 MWh of unserved energy. This does not meet the performance requirements of clauses 5(1)(a)(i) and 5(1)(a)(iv) of the ESI Regulations. Que Substation load is supplied via a single 110/22 kv 30/50 MVA transformer. A contingency on the transformer would result in unserved energy of more than 300 MWh. This does not meet the performance requirements of clause 5(1)(a)(iv) of the ESI Regulations. Transend is investigating the staged augmentation of the Farrell Que Waratah Tee Savage River Hampshire 110 kv transmission line to improve the security of supply at Que and Savage River substations. Figure 5.4 presents a schematic diagram of the existing and the proposed arrangement following the redevelopment. At present, the Farrell Que Waratah Tee section is designed to operate at 75 o C, however the Burnie Hampshire Waratah Tee Savage River section is designed to operate at 49 o C. 20 Since May 2012, Bass Metals at Que are on care and maintenance with load demand around 1 MW Transend Networks Pty Ltd 2012 Page 70

75 Figure 5.4 Schematic diagram of existing and proposed west coast 110 kv network LEGEND Burnie Substation Burnie Substation N/O N/C 110 kv 22 kv Normally open Normally closed Savage River Substation 22 kv IBIS Waratah Tee N/O Hampshire substation Que Substation Proposed 110 kv redevelopment Savage River Substation Nitrogen N/C Hampshire Substation Que Substation Farrell Substation Farrell Substation The options in Table 5.8 are currently being considered to address the identified issues. Table 5.8 Options being considered to address west coast 110 kv transmission security Option Type of option Detail 1 Network Staged 110 kv development to Hampshire and Savage River 2 Exemption after consultation 3 Demand management Maintain existing service level security At this stage there has been no indication from connected customers on the willingness to offer demand management 4 Generation At this stage Transend is not aware of any prospective embedded generation in the area Option 1 consists of two stages. In the first stage, Burnie Hampshire Waratah Tee transmission section would be upgraded to 75 o C design operation. In order to operate Burnie Hampshire Waratah Tee section normally closed, new protection systems would be installed at Hampshire Substation. In the second stage, a 22 kv feeder would be removed from the southern side of the Waratah Tee Savage River line section and this section of line augmented to operate at 110 kv at 75 o C. Waratah Tee would be bypassed and decommissioned. A bus coupler and a line bay would be installed at Savage River Substation. The above strategy is driven by load growth in the area. With the current load reduction at Que Substation, Transend s preferred option is Option 2. Another driver is to increase the 110 kv transmission capacity from Farrell to Burnie to enable increased dispatch of west coast generation especially during outages of the Farrell Sheffield double circuit 220 kv transmission line Farrell Substation 220 kv security upgrade Farrell Substation is a major substation in the west coast area. It provides the connection point for MW of hydro generation via 110 kv and 220 kv transmission systems. The Farrell Transend Networks Pty Ltd 2012 Page 71

76 Substation 220 kv switchyard is designed as a double busbar with single bus coupler arrangement. A potential risk has been identified that failure of the bus coupler circuit breaker during high west coast generation, could lead to a total loss of supply to the area and a significant loss of generation. Under certain conditions, this could cause instability leading to a partial system blackout. The schematic one line diagram of Farrell 220 kv switchyard is presented in Figure 5.5, showing the proposed second bus coupler circuit breaker. Figure 5.5 Farrell Switchyard proposed 220 kv one line diagram The options outlined in Table 5.9 are currently being considered to address the identified issue. Table 5.9 Options being considered to address Farrell Substation 220 kv security upgrade Option Type of option Detail 1 Network Installation of one new circuit breaker in the bus coupler bay to create a double breaker arrangement 2 Network Relocation of Farrell Sheffield circuits to create double breaker diameters 3 Network Fully selectable circuit-breaker-and-a-half arrangement for one transmission circuits 4 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 5 Generation At this stage Transend is not aware of any prospective embedded generation in the area A fully selectable circuit-breaker-and-a-half arrangement for all 220 kv transmission circuits at Farrell would mean a redesign of the substation with significant costs. Hence the preferred development option to improve the security of supply at Farrell Substation 220 kv is Option 1. The Transend Networks Pty Ltd 2012 Page 72

77 estimated cost is $ 1.3 million and it is proposed to be completed by June The proposed augmentation will not have any significant inter-network impact North-west area development plan Existing network overview The north-west 220/110 kv transmission system consists of a network that stretches from Woolnorth Bluff Point wind farm in the north to Rowallan Power station in the south. The northwest area load is supplied from the core 220 kv transmission system via two 220/110 kv autotransformers at Sheffield Substation, a 220 kv transmission circuit Sheffield Burnie and one 220/110 kv auto-transformer at Burnie Substation. The installed generation capacity is around 450 MW and the coincidental maximum demand in 2011 was about 230 MW. In October 2010 approximately 30 MW load was lost due to the closure of Australian Paper plants at Emu Bay and Wesley Vale. There are two hydro power stations connected to the 110 kv system comprising Devils Gate and Paloona, plus the Woolnorth wind farms comprising Studland Bay and Bluff Point. There are also five hydro power stations connected on radial circuits to the 220 kv bus at Sheffield Substation comprising Fisher, Rowallan, Wilmot, Cethana, and Lemonthyme. There are two 28.9 MVAr capacitor banks with one connected to the 110 kv Sheffield Substation bus and the other to 110 kv Burnie Substation bus to provide voltage support. Aurora (through joint planning with Transend) has expressed interest in two new connection points at Emu Bay and Wesley Vale substations. Aurora has submitted connection enquiries for embedded generation connections to their 22 kv feeders at Ulverstone Substation (8.0 MVA) and Devonport Substation (2.5 MVA). Figure 5.6 presents a geographical map of the north-west area whilst Appendix 7 presents details of the power stations and substations located in the north-west area. Figure 5.6 Geographical map of north-west area Legend: 220 kv 110kV Transend Networks Pty Ltd 2012 Page 73

78 Figure 5.7 North-west area network schematic diagram Existing and committed generation The north-west area s existing generation consists of hydro and wind generation. The hydro generators are located at Cethana (85 MW), Devils Gate (60 MW), Fisher (43.2 MW), Lemonthyme (51 MW), Paloona (28 MW), Wilmot (30.6 MW) and Rowallan (10.45 MW) and wind generation is located at Bluff Point (64.75 MW) and Studland Bay (75 MW). There is potential for further renewable generation to be developed in the planning period, as there are a number of wind farm opportunities in the north-west area Load forecast The load in the north-west area consists mainly of retail load. The connection points for Aurora are located at Burnie, Devonport, Emu Bay, Port Latta, Railton, Smithton, Ulverstone and Wesley Vale substations. The current maximum distribution load is approximately 65 MW at Burnie Substation, 67 MW at Devonport Substation, 11 MW at Emu Bay Substation, 5 MW at Port Latta Substation, 49 MW at Railton Substation, 21 MW at Smithton Substation, 36 MW at Ulverstone Substation and 2 MW at Wesley Vale Substation. The remaining connection points provide supply to directly connected customers at Hampshire (Gunns Limited) and Port Latta (Grange Resources). The maximum retail demand forecast for the north-west area substations is presented in Appendix Fault Levels The fault levels for the north-west area have been analysed to ensure that they remain within the equipment and design limits (refer Section 6.5). A table listing the current maximum and minimum fault levels for the substations in the north-west area is provided in Appendix 6. The fault level at the Wesley Vale Substation 11 kv connection point bus exceeds 13.1 ka which is the limit specified in the connection agreement between Transend and Aurora. This does not meet the criteria stated in the NER 5.2.3(e1)(2). This fault level is currently being handled operationally by opening Transend Networks Pty Ltd 2012 Page 74

79 the bus coupler circuit breaker as required. Options for a long term solution are currently being discussed between Transend and Aurora Committed Projects Currently the north-west area has two committed network projects. These projects have been included in all planning scenarios for the north-west area. The details of these projects are presented in Section 4.3. Table 5.10 outlines the status of committed projects. Table 5.10 North-west area committed projects Project (Committed) Expected completion Sheffield Substation to George Town Substation OPGW November 2012 Burnie Substation 110 kv redevelopment April Constraints, options and preferred solutions The forecast network constraints for this area are impacted significantly by the load demands for the area. All connection points have been analysed collaboratively and individually during the development of the north-west area plan. The following section presents details of the network system constraints, including the forecast year of impact, options that are currently being considered, preferred option and the estimated cost. The cost data is high level and is indicative of the proposed costs and is presented in 2012 base dollars. Constraints that exist or are forecast to occur within seven years in the north-west area are presented in Figure 5.8 and outlined in Table The proposed network developments to address the identified issues are described in this section. Figure 5.8 North-west system constraints Transend Networks Pty Ltd 2012 Page 75

80 Table 5.11 North-west area proposed developments Constraint Driver(s) Proposed development Estimated Commissioning Year Burnie Substation supply transformer capacity Devonport Substation supply transformer capacity Firm (N-1) capacity exceeded Firm (N-1) capacity exceeded Above the 300 MWh unserved energy criteria prescribed in the ESI Regulations Conversion of one of the transformers at Emu Bay Substation to 110/22 kv and load transfer Conversion of one of the transformers at Wesley Vale Substation to 110/22 kv and load transfer Burnie Substation 110/22 kv transformers capacity To be determined Estimated cost $3.7 million 2018 $1.6 million Burnie Substation comprises two 110/22 kv 30/60 MVA transformers that each have a short- term rating of 72 MVA. The peak load recorded at Burnie Substation during winter 2011 was 62 MW, which exceeded the 60 MVA firm continuous rating of the substation. Maximum demand at Burnie Substation is forecast to increase steadily at around 1.1 % per annum. By 2021 it is forecast that the loss of a transformer would result in more than 300 MWh of unserved energy, which would not meet the performance requirement of clause 5(1)(a)(iv) of the ESI Regulations. The transformers at Burnie Substation are both 42 years old and are scheduled for replacement based on condition in Transend does not have any supply transformers rated higher than 60 MVA so the replacement transformers proposed for Burnie Substation will be the standard 30/60 MVA rating. The options presented in Table 5.12 are currently being considered to address the identified issue. Table 5.12 Options being considered to address Burnie Substation capacity issue Option Type of option Detail 1 Network Conversion of one of the transformers at Emu Bay Substation to 110/22 kv and load transfer 2 Network Installation of a third 110/22 kv 60 MVA transformer at Burnie Substation 3 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 4 Generation Aurora has submitted connection enquiries for embedded generation connections to their 22 kv feeders at Ulverstone Substation (8.0 MW) and Devonport Substation (2.5 MW). However this will be insufficient to offset the load growth at Burnie. The preferred option to address the identified issue at Burnie Substation is Option 1. Burnie is supplied from Emu Bay Substation via four 11 kv distribution feeders. Emu Bay Substation comprises two 110/22-11 kv 20/40 MVA transformers each with a short term rating of 48 MVA. Australian Paper which was directly connected to Emu Bay Substation 11 kv ceased its operation in 2010, reducing the connected load to approximately 10.6 MW. A joint planning study is being conducted with Aurora and a detailed cost-benefit analysis for the following augmentation at Emu Bay Substation: reconnection of the secondary windings of one of the two existing transformers to 22 kv (the other transformer will continue to operate at 11 kv); installation of a new 22 kv switchboard; and Transend Networks Pty Ltd 2012 Page 76

81 installation of one new 22/0.415 kv station services transformer. Two new 22 kv feeders from Emu Bay Substation would off-load Burnie Substation. Aurora would install two 22/11 kv 5 MVA transformers to provide an alternate 11 kv supply to Burnie. The estimated cost of this augmentation is $3.7 million. Timing has yet to be determined but will be contingent on load growth in the area. This augmentation would have no material inter-network impact Devonport Substation 110/22 kv transformers capacity Devonport Substation comprises three 110/22 kv 20/30 MVA transformers that each have a short term rating of 36 MVA. The peak load recorded at Devonport Substation during winter 2011 was 63 MW which exceeded the 60 MVA firm continuous rating of the substation. Maximum demand at Devonport Substation is forecast to increase steadily at around 3.5 % per annum. In addition, two 22 kv distribution feeders from Devonport Substation are operating close to their maximum ratings during periods of peak loading. A contingency on a Devonport supply transformer would result in unserved energy of more than 300 MWh in This does not meet the performance requirements of clause 5(1)(a)(iv) of the ESI Regulations The options in Table 5.13 are currently being considered to address the identified issue. Table 5.13 Options being considered to address Devonport Substation capacity issue Option Type of option Detail 1 Network Conversion of one of the transformers at Wesley Vale Substation to 22 kv and load transfer 2 Network Replace Devonport Substation transformers with two 90 MVA transformers. 3 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 4 Generation Aurora has submitted connection enquiries for embedded generation connections to their 22 kv feeders at Ulverstone Substation (8.0 MW) and Devonport Substation (2.5 MW). However this will be insufficient to offset the load growth at Devonport. The preferred option is Option 1. Wesley Vale Substation comprises two 110/22-11 kv 15/25 MVA transformers that each have a short term rating of 28 MVA. In 2010 Australian Paper which was directly connected to Wesley Vale Substation 11 kv ceased operation, reducing the connected load to approximately 2.0 MW. Railton Substation has two 110/22 kv 30/50 MVA transformers each with a short term rating of 60 MVA. The peak load recorded at Railton Substation during winter 2011 was 46.5 MW. Two 22 kv distribution feeders from Railton Substation are operating at close to their maximum ratings during periods of peak loading. The establishment of a 22 kv connection point at Wesley Vale Substation would off-load Devonport and Railton 22 kv distribution feeders and the substation supply transformers, thereby deferring the capacity augmentation issues at Devonport and Railton. The period of deferral of transformer capacity augmentation will depend on the transfer capability which is to be determined with Aurora. The estimated cost of this augmentation is $1.6 million and it is proposed to be completed by December This augmentation would have no inter-network material impact. Transend Networks Pty Ltd 2012 Page 77

82 5.2.3 George Town area development plan Existing network overview George Town Substation is a key node in the Tasmanian power system, forming part of the 220 kv core grid, connecting to Sheffield and Hadspen 220 kv substations, both via double circuit lines. Three 220/110 kv auto-transformers provide the connection to the 110 kv bus. The installed generation capacity is around MW and the coincidental maximum demand in 2011 was about 450 MW. The majority of the load is supplied to two major industrial customers at Pacific Aluminium (Comalco Substation) and Temco (Temco Substation), supplied from the George Town 220 kv and 110 kv buses respectively, each via double circuit lines. A small industrial load is supplied at Starwood Substation via a single 110 kv circuit from George Town Substation and the Aurora retail load is supplied at 22 kv via two 110/22 kv transformers. The 630/478 MW (Export/Import) Basslink HVDC scheme is connected to the 220 kv bus at George Town Substation, via a single 220 kv circuit. Reactive support for George Town Substation is provided by a 220 kv 60 MVAr capacitor bank and a 110 kv 30 MVAr capacitor bank. Figure 5.9 presents the geographical map of the George Town area, with Figure 5.10 presenting a simplified representation of the 220/110 kv transmission network. Figure 5.9 Geographical map of the George Town area Legend: 220 kv 110 kv Transend Networks Pty Ltd 2012 Page 78

83 Figure 5.10 George Town area network schematic diagram TEMCO STARWOOD BASSLINK CONVERTER COMALCO GEORGE TOWN TAMAR VALLEY (TVOCPS) LEGEND: 220kV 110kV To Sheffield To Hadspen TAMAR VALLEY (TVCCPS) Existing and committed generation The George Town area s existing generation is entirely gas powered. There are two power stations, Tamar Valley Open Cycle Power Station (163 MW), connected to the George Town Substation 110 kv bus by a double circuit line, and Tamar Valley Combined Cycle Power Station (208.9 MW), connected to the George Town Substation 220 kv bus by a single circuit line Load forecast The load in the George Town area is mostly large industrial customers. The only connection point for Aurora is located at George Town Substation 22 kv with the current maximum demand approximately 29 MW. The remaining connection points provide supply to Comalco Substation (Pacific Aluminium), Temco Substation (Temco) and Starwood (Gunns Limited). The maximum retail demand forecast for George Town Substation is presented in Appendix Fault Levels The fault levels for the George Town area have been analysed to ensure that they remain within the equipment and design limits (refer Section 6.5). A table listing the current maximum and minimum fault levels for the substations in the George Town area is provided in Appendix Committed Projects Currently the George Town area has one committed network project. This project has been included in all planning scenarios for the George Town area. The detail of the project is presented in Section 4.3. Table 5.14 outlines the status of this committed project. Table 5.14 George Town area committed projects Project (Committed) Expected completion George Town Substation 220 kv security upgrade (Stage 1) November 2012 Transend Networks Pty Ltd 2012 Page 79

84 Constraints, options and preferred solutions The forecast network constraints for this area are impacted significantly by the load demands. All connections points have been analysed collaboratively and individually during the development of the George Town area plan. The following section presents details of the network system constraints, including the forecast year of impact, options that are currently being considered, preferred option and the estimated cost. The cost data is high level and is indicative of the proposed costs and are presented in 2012 base dollars. Constraints that exist or are forecast to occur within seven years in the George Town area are presented in Figure 5.11 and outlined in Table The proposed network developments to address the identified issues are described in this section. There are no proposed asset renewal projects that have an estimated cost of more than $5 million and are planned to be commissioned over the next seven years. Figure 5.11 George Town system constraints STARWOOD BASSLINK Circuits nonfirm (existing) TEMCO CONVERTER COMALCO N Security (existing) GEORGE TOWN TAMAR VALLEY (TVOCPS) 220 kv Security (existing) LEGEND: 220kV 110kV To Sheffield To Hadspen TAMAR VALLEY (TVCCPS) Table 5.15 George Town area proposed developments Constraint Proposed development Driver(s) Estimated cost George Town 220 kv Substation security Voltage support for the George Town area Comalco Substation security Temco Substation security George Town 220 kv Substation security upgrade (stage 2) Installation of -100/+100 MVAR STATCOM at George Town Substation Maintain current operating practice until the directly connected customer requests an upgrade in security or capacity Maintain current operating practice until the directly connected customer requests an upgrade in security System stability System stability Supplied radially with N security Firm (N-1) capacity exceeded $6.5 million $30 million $0 $0 Transend Networks Pty Ltd 2012 Page 80

85 George Town 220 kv Substation security upgrade (stage 2) As described in Section 4.3.2, part of the George Town 220 kv Substation is being developed to a circuit-breaker-and-a-half arrangement. This includes conversion of four diameters of the switchyard to a circuit-breaker-and-a-half arrangement and the replacement of the A busbar. A failure of circuit breaker Z152 at George Town 220 kv Substation could lead to a significant loss of supply to the to the area and a significant loss of generation. Under certain conditions, this could cause instability. The options in Table 5.16 are currently being considered to address the identified issue. Table 5.16 Options being considered to address George Town 220 kv Substation security Option Type of option Detail 1 Network Convert the remaining two diameters (still on single breaker and double disconnector arrangement), one to circuit-breaker-and-a-half and the other to double breaker arrangement (for future circuit breaker-and-a-half) 2 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 3 Generation Network support agreement with a generator for dynamic reactive support on an ongoing basis The preferred option is Option 1. The estimated cost of this augmentation is $6.5 million and it is proposed to be completed by June The proposed augmentation will have no material internetwork impact Voltage support for the George Town area Although the load at this substation is fairly constant, the output of generation and Basslink can be volatile due to market behaviour. As a result, voltage control at George Town Substation is an issue. Sheffield George Town and Hadspen George Town 220 kv double circuit transmission lines are of single tower double circuit construction. A single asset failure of a tower could result in a double circuit failure. Under some operating scenarios, such failure could result in significant interruption to supply or, in the worst case, a system black out. A significant event could result in the loss of over 850 MW load and/or 3000 MWh of unserved energy, which would not meet the performance criteria prescribed in the ESI Regulations. System studies have shown that installing a dynamic reactive support device at George Town Substation would significantly reduce the potential risk of system collapse due to either circuit breaker failure or double circuit failure. While further detail studies are being conducted to ascertain the risk. In addition a failure of Basslink under some system configurations could result in over-voltages at George Town Substation as well as some substations in the north-west area. It is important to note that most of these over-voltages appear within 100 milliseconds after the fault. Therefore, dynamic reactive support is required to prevent such events. The options in Table 5.17 are currently being considered to address the identified issues. Transend Networks Pty Ltd 2012 Page 81

86 Table 5.17 Options being considered to address voltage support for the George Town area Option Type of option Detail 1 Network Install -100/+100 MVAr STATCOM at George Town Substation; 2 Network Install -100/+100 MVAr SVC at George Town Substation 3 Network Install 2 x 50 MVAr synchronous condensers at George Town Substation 4 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 5 Generation Network support agreement with a generator for dynamic reactive support on an ongoing basis All dynamic voltage support devices are considered as connected to the 220 kv bus at George Town Substation. Due to the recent technological development including short term overload capabilities, Option 1 is the preferred option. The cost of the project is estimated at $30 million. Further studies will be undertaken to confirm the type of device to be installed and required timing of installation George Town Comalco 220 kv transmission circuits Comalco Substation is currently supplied radially with N security. During maintenance, when the total load is supplied by a single circuit, and during summer conditions, the transmission circuits can experience thermal overload. This is managed operationally by using dynamic ratings and by controlling access to those sections of the easement where conductor sag violates standard ground clearances. The current operating practice will be maintained until the directly connected customer requests an upgrade in security, at which time options will be evaluated George Town Temco 110 kv transmission circuits The two George Town Temco 110 kv transmission circuits can exceed their firm ratings during normal operating conditions. This is currently managed operationally by the use of dynamic ratings and radialising the load at Temco Substation. The current operating practice will be maintained until the directly connected customer requests an upgrade in capacity, at which time augmentation options will be evaluated Northern area development plan Existing network overview The northern 220/110 kv transmission system consists of a network that supplies the area south of Derby to Arthurs Lake, and includes the generation and load centres at Arthurs Lake, Avoca, Derby, Norwood, Trevallyn, Mowbray, Hadspen, Palmerston, Scottsdale and St Marys. The installed generation capacity is around MW and the coincidental maximum demand in 2011 was about 245 MW. The northern area network is divided into two sub-areas, north-east and central, which are supplied from the 220 kv transmission network at Hadspen and Palmerston substations respectively. Hadspen and Palmerston substations are connected by 220 kv and 110 kv double circuit transmission lines, with two 220/110 kv auto-transformers at Hadspen Substation and one 220/110 kv auto-transformer at Palmerston Substation. There is also a 110 kv single circuit Palmerston Waddamana transmission line linking the northern and southern 110 kv networks. Transend Networks Pty Ltd 2012 Page 82

87 The north-east sub-area is supplied from the Hadspen Substation 110 kv bus. Two double circuit transmission lines supply Trevallyn and Norwood substations. Trevallyn Power Station connects to the Trevallyn Substation 110 kv bus. The proposed commissioning of St Leonards Substation in July 2012, will result in a 110 kv ring being formed between Norwood and Mowbray substations. Scottsdale Substation is supplied from Norwood Substation via a double circuit 110 kv transmission line, with Derby Substation connected to Scottsdale Tee via a single circuit. The central sub-area is supplied from the Palmerston Substation 110 kv bus, with single circuit transmission lines supplying Avoca and St Marys substations and Arthurs Lake Substation. Figure 5.12 presents a geographical map of the northern area, with Figure 5.13 presenting a simplified representation of the 220/110 kv transmission network. Figure 5.12 Geographical map of the northern area Legend: 220 kv 110 kv Transend Networks Pty Ltd 2012 Page 83

88 Figure 5.13 Northern area network schematic diagram To George Town Trevallyn Mowbray Hadspen 220 kv St Leonards (proposed) Palmerston 220 kv To Sheffield Hadspen 110 kv Norwood Scottsdale To Waddamana Palmerston 110 kv Avoca Derby St Marys Arthurs Lake To Waddamana Legend: 220kV 110kV 110 kv proposed Existing and committed generation The northern area s existing generation is entirely hydro. The hydro generators are located at Trevallyn (93 MW), Poatina (300 MW), and Tods Corner (1.6 MW). The proposed wind farm project at Musselroe is expected to have a capacity of 168 MW with connection to Derby Substation 110 kv. Musselroe wind farm is currently under construction and is expected to commence operation in March In addition, there has been a publicly announced East Coast Hot Rocks geothermal power project in the east coast of Tasmania near Pyengana Load forecast The load in the northern area consists of retail load. The connection points for Aurora are located at Avoca, Derby, Norwood, Trevallyn, Mowbray, Hadspen, Palmerston, Scottsdale and St Marys substations. The current maximum load is approximately 7 MW at Avoca Substation, 3 MW at Derby Substation, 62 MW at Norwood Substation, 81 MW at Trevallyn Substation, 36 MW at Mowbray Substation, 61 MW at Hadspen Substation, 6 MW at Palmerston Substation, 13 MW at Scottsdale Substation and 15 MW at St Marys Substation. There are a number of proposals to establish new mines and preliminary connection enquiries have been received during The maximum retail demand forecast for the northern area substations is presented in Appendix 1. Transend Networks Pty Ltd 2012 Page 84

89 Fault Levels The fault levels for the northern area have been analysed to ensure that they remain within the equipment and design limits (refer Section 6.5). A table listing the current maximum and minimum fault levels for the substations in the northern area is provided in Appendix 6. The fault level at the Trevallyn and Mowbray substations 22 kv connection point buses exceed 13.1 ka which is the limit specified in the connection agreement between Transend and Aurora. This does not meet the criteria stated in the NER 5.2.3(e1)(2). These fault levels are currently being handled operationally by opening the bus coupler circuit breakers as required. Options for long term solutions are currently being discussed between Transend and Aurora Committed Projects Currently the northern area has two committed network projects. These projects have been included in all planning scenarios for the northern area. The details of these projects are presented in Section 4.3. Table 5.18 outlines the status of these committed projects. Table 5.18 Northern area committed projects Project (Committed) Expected completion Arthurs Lake Substation redevelopment August 2013 Palmerston Substation 110 kv redevelopment March Constraints, options and preferred solutions The forecast network constraints for this area are impacted significantly by the load demands. All connection points have been analysed collaboratively and individually during the development of the northern area plan. The following section presents details of the network system constraints, including the forecast year of impact, options that are currently being considered, preferred option and the estimated cost. The cost data is high level and is indicative of the proposed costs and are presented in 2012 base dollars. Constraints that exist or are forecast to occur within seven years in the northern area are presented in Figure 5.14 and outlined in Table The proposed network developments to address the identified issues are described in this section. The Arthurs Lake and Palmerston substations redevelopment projects are asset renewal projects that each has an estimated cost of more than $5 million. Transend Networks Pty Ltd 2012 Page 85

90 Figure 5.14 Northern system constraints To George Town Trevallyn Mowbray Hadspen 220 kv 110 kv security St Leonards (proposed) Palmerston 220 kv To Sheffield Hadspen 110 kv Norwood Scottsdale To Waddamana Derby Palmerston 110 kv Avoca 110/22 kv transformer capacity Arthurs Lake To Waddamana 110 kv transline security Legend: 220kV 110kV 110 kv proposed St Marys Table 5.19 Northern area proposed developments Constraint Proposed development Driver(s) Estimated Completion Year Avoca Substation transformer capacity Derby Substation transformer capacity Hadspen Substation security Install a suitable cold spare transformer at Avoca Substation. Install a suitable cold spare transformer at Derby Substation. Install second 110 kv circuit breaker for transformer T2 Above the 300 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations System security and good industry practice n/a n/a Estimated cost $0.1 million $0.1 million 2017 $1.0 million Transend Networks Pty Ltd 2012 Page 86

91 Constraint Proposed development Driver(s) Estimated Completion Year Palmerston Avoca St Marys transmission security St Marys Substation transformers capacity Install a second 110 kv transmission line Palmerston Avoca strung one circuit initially Maintain existing service level security Above the 300 MWh unserved energy performance requirement of the ESI Regulations Firm (N-1) capacity exceeded Avoca Substation transformer T2 installation Estimated cost 2016 $30.0 million n/a $0 The load connected to Avoca Substation is supplied radially via a single 110/22 kv 10 MVA transformer that has a short term rating of 12 MVA. In the event of transformer contingency, supply to all connected load is interrupted. Currently during peak loads, the loss of the transformer could result in more than 300 MWh of unserved energy, which does not meet the performance requirement of clause 5(1)(a)(iv) of the ESI Regulations. The options outlined in Table 5.20 are currently being considered to address the identified issue: Table 5.20 Options being considered to address Avoca Substation transformer security Option Type of option Detail 1 Network Purchase a mobile transformer to service Derby, Avoca and Meadowbank substations, all of which supply load via a single supply transformer 2 Network Install a suitable cold spare transformer at Avoca Substation. This would be compatible with the existing T1 transformer, and would be stored in readiness for operation (filled with oil) but would not be connected until required by a contingency of T1 3 Network Install a second 110/22 kv transformer at Avoca Substation 4 Demand management Augment Aurora s distribution network to enable increased transfer capacity with other substations, allowing the expected unserved energy to be reduced to meet the performance requirements of the ESI Regulations 5 Generation Aurora has submitted a connection enquiry for an embedded generation connection to one of their 22 kv feeders at Avoca Substation (5.5 MW) as part of a proposed irrigation scheme. However this would not operate continuously so could not be relied upon to meet the performance requirements of the ESI Regulations at all times. Transend s preferred option is Option 2 as this is the least cost option. Transend will consult further with Aurora regarding the demand management option followed by an economic analysis. The proposed project will have no material inter-network impact Derby Substation transformer T2 installation The load connected to Derby Substation is supplied radially via a single 110/22 kv 10 MVA transformer that has a short term rating of 12 MVA. In the event of transformer contingency, supply to all connected load is interrupted. Currently, the loss of the transformer during peak loads could result in more than 300 MWh of unserved energy, which does not meet the performance requirement of clause 5(1)(a)(iv) of the ESI Regulations. The options outlined in Table 5.21 are currently being considered to address the identified issue. Transend Networks Pty Ltd 2012 Page 87

92 Table 5.21 Options being considered to address Derby Substation transformer security Option Type of option Detail 1 Network Purchase a mobile transformer to service Derby, Avoca and Meadowbank substations, all of which supply load via a single supply transformer 2 Network Install a suitable cold spare transformer at Derby Substation. This would be compatible with the existing T1 transformer, and would be stored in readiness for operation (filled with oil) but would not be connected until required by a contingency of T1 3 Network Construct a 110 kv bus at Derby Substation and install a second 110/22 kv transformer 4 Demand management Discussion with Aurora has indicated a possible 5 MW of load backed up through the 22 kv distribution network, which would meet the performance requirements of clause 5(1)(a)(iv) of the ESI Regulations until Aurora is undertaking further studies to assess the back-up capability of the distribution network in the Derby area 5 Generation At this stage Transend is not aware of any prospective embedded generation in the area Transend s preferred option is Option 4 as this is the least cost option. Transend will consult further with Aurora with regards to back-feeding capability during peak periods. The alternative preferred option is Option Hadspen Substation security upgrade Hadspen Substation is the 110 kv supply point to 6 terminal substations in the northern area. The only other 110 kv injection to this area is from Trevallyn Power Station, so if this power station is out of service, supply to the entire area load emanates from Hadspen Substation. This makes this substation very important for maintaining security of supply to Launceston city and the surrounding area. Additionally both Trevallyn Power Station and the proposed Musselroe wind farm generators must export their energy to the wider Tasmanian system via Hadspen Substation. Hadspen Substation has a unique layout. Instead of the traditional single bus coupler arrangement employed at most substations it has a double breaker arrangement on one of its two 220/110 kv autotransformers on each side. With the current arrangement at Hadspen substation, a breaker failure of either of the two 110 kv circuit breakers connected to autotransformer T1 would trip both the autotransformer and one of the 110 kv buses. This could lead to overloading of the remaining 110 kv transmission circuits supplying the northern area. Transend Networks Pty Ltd 2012 Page 88

93 The options outlined in Table 5.22 are currently being considered to address the identified issue: Table 5.22 Options being considered to address Hadspen Substation security Option Type of option Detail 1 Network Install double breaker configuration on 110 kv side of Hadspen autotransformer T2 2 Network Install double breaker configuration on 110 kv side of Hadspen autotransformer T2 and breaker and-a-half configuration on 220 kv side of Hadspen autotransformer T1 and transmission circuit Palmerston-Hadspen No 1 3 Network Create a second 110 kv injection point to the Launceston area via a new 220/110 kv singe transformer substation at Riverside, connected to Trevallyn substation via a single 110 kv circuit 4 Network Construct a new single circuit 110 kv transmission line between George Town and Trevallyn substations Transend s preferred option is Option 2. The estimated cost of this augmentation is $4.0 million and it is proposed to be completed by June The proposed augmentation will have no material inter-network impact Palmerston Avoca St Marys transmission security Avoca and St Marys substations are supplied radially from Palmerston Substation via the Palmerston Avoca and Avoca St Marys 110 kv transmission circuits. The loss of the Palmerston Avoca 110 kv transmission circuit will interrupt supply to Avoca and St Marys substations and the loss of the Avoca St Marys circuit also will interrupt supply to St Marys Substation. Currently, the loss of either of these circuits could result in more than 300 MWh of unserved energy, exceeding the criteria prescribed in clause 5(1)(a)(iv) of the ESI Regulations. The Palmerston Avoca section was constructed in 1956 and is strung in copper conductor with a limited capacity (approximately 39/60 MVA summer/winter). The options outlined in Table 5.23 are currently being considered to address the identified issue. Table 5.23 Options being considered to address Palmerston Avoca St Marys transmission security Option Type of option Detail 1 Network Construct a second Palmerston Avoca 110 kv transmission line (double circuit construction strung one circuit) 2 Network Construct a new 110 kv transmission line between St Marys and Derby substations 3 Demand management At this stage there has been no indication from connected customers on the willingness to offer demand management 4 Generation A proposed embedded 5.5 MW generator to be installed near Tunbridge will supply new load associated with a proposed irrigation scheme only The preferred option is Option 1. It is proposed to construct a new double circuit 110 kv transmission line Palmerston Avoca, strung one side initially with phosphorous conductor rated at 157 MVA (Stage 1). The second side will be strung when required by the condition of the existing Palmerston Avoca line (Stage 2). The Stage 1 works is estimated to cost $30.0 million and it is proposed to be completed by June The Stage 2 works (stringing the second side of the new transmission line and dismantling the old transmission line) is proposed to be carried out around Transend Networks Pty Ltd 2012 Page 89

94 The proposed augmentation will have no material inter-network impact St Marys Substation transformers As detailed in Table 5.2, the load connected to St Marys Substation exceeded the short term rating of the transformers for a total of 17 hours during The performance requirement of clause 5.(1)(a)(iv) of the ESI Regulations, where a contingency of one of these transformers could result in more than 300 MWh of unserved energy, is not forecast to occur until 2023, at which time the upgrade of these transformers would be considered Southern area development plan Existing network overview The southern area is the largest in the Tasmanian transmission network, in terms of both area and number of substations. The southern 220/110 kv transmission system consists of a network that supplies the area that stretches from south of Waddamana to Kermandie, and includes the generation and load centres at Boyer, Bridgewater, Butlers Gorge, Catagunya, Chapel Street, Cluny, Creek Road, Derwent Bridge, Electrona, Gordon, Huon River, Kermandie, Kingston, Knights Road, Lake Echo, Liapootah, Lindisfarne, Meadowbank, New Norfolk, North Hobart, Repulse, Risdon, Rokeby, Sorell, Tarraleah, Triabunna, Tungatinah, Waddamana, and Wayatinah. The installed generation capacity is MW and the coincidental maximum demand in the southern area in 2011 was 715 MW; coincidental maximum demand of retail load was about 570 MW. The southern area is connected to the rest of the network via the two 220 kv double-circuit Liapootah Waddamana Palmerston and Waddamana Lindisfarne transmission lines and the single-circuit 110 kv Waddamana Palmerston transmission line. There are three directly connected customers in the southern area, Forestry Tasmania (connected to Huon River Substation), Norske Skog (connected to Boyer Substation) and Nyrstar (connected to Risdon Substation). The southern area load is supplied from the 110 kv transmission system. The 110 kv system is connected to the core grid 220 kv transmission system via 220/110 kv auto-transformers at Chapel Street Substation (four) and Lindisfarne Substation (two). The 110 kv system is also supplied by the Upper Derwent generation scheme and by the Waddamana Palmerston 110 kv transmission line. Figure 5.15 presents a geographical map of the southern area, with Figure 5.16 presenting a simplified representation of the 220/110 kv transmission network. Transend Networks Pty Ltd 2012 Page 90

95 Figure 5.15 Geographical map of the southern area Legend: 220 kv 110 kv Transend Networks Pty Ltd 2012 Page 91

96 Figure 5.16 Southern area network schematic diagram Existing and committed generation The southern area s existing generation is entirely hydro power. The hydro generators are located at Butlers Gorge (12.2 MW), Lake Echo (32.4 MW), Meadowbank (40 MW), Tarraleah (90 MW), Tungatinah (125 MW), Catagunya (50 MW), Cluny (17 MW), Repulse (28 MW), Gordon (432 MW), Liapootah (83.7 MW) and Wayatinah (38.25 MW). Transend currently has a new generation connection application for a 225 MW wind farm at Cattle Hill, just south of Waddamana. In addition, there is potential for more renewable generation to occur within the planning period of this report, as there are a number of wind farm opportunities within the southern area Load forecast The load in the southern area is a mix of retail and industrial. The current maximum distribution load is approximately 35 MW at Bridgewater Substation, 42 MW at Chapel Street Substation, 111 MW at Creek Road Substation, 0.2 MW at Derwent Bridge Substation, 21 MW at Electrona Substation, 0.3 MW at Gordon Power Station, 7 MW at Kermandie Substation, 38 MW at Kingston Substation, 19 MW at Knights Road Substation, 68 MW at Lindisfarne Substation, 5 MW at Meadowbank Substation, 19 MW at New Norfolk Substation, 60 MW at North Hobart Substation, Transend Networks Pty Ltd 2012 Page 92

97 75 MW at Risdon Substation, 22 MW at Rokeby Substation, 35 MW at Sorell Substation, 8 MW at Triabunna Substation, 1 MW at Tungatinah Substation, 0.8 MW at Waddamana Substation and 0.4 MW at Wayatinah Substation. Directly connected customers are supplied form Huon River Substation (Forestry Tasmania), Boyer Substation (Norske Skog) and Risdon Substation (Nyrstar). The maximum retail demand forecast for the southern area substations is presented in Appendix Fault Levels The fault levels for the southern area have been analysed to ensure that they remain within the equipment and design limits (refer Section 6.5). A table listing the current maximum and minimum fault levels for the substations in the southern area is provided in Appendix 6. The fault level at Bridgewater, Chapel Street, Electrona, Kingston, and Rokeby substations 11 kv connection point buses, and at Creek Road Substation 33 kv connection point bus, exceed 13.1 ka which is the limit specified in the connection agreement between Transend and Aurora. This does not meet the criteria stated in the NER 5.2.3(e1)(2). These fault levels are currently being handled operationally by opening the bus coupler circuit breakers as required. Options for long term solutions are currently being discussed between Transend and Aurora Committed Projects Currently the southern area has two committed network projects. These projects have been included in all planning scenarios for the southern area. The details of these projects are presented in Section 4.3. Table 5.24 outlines the status of committed projects. Table 5.24 Southern area committed projects Project (Committed) Expected completion Creek Road Substation 110 kv redevelopment December 2013 Tungatinah Substation 110 kv redevelopment April Constraints, options and preferred solutions The forecast network constraints for this area are impacted significantly by the load demands. All connection points have been analysed collaboratively and individually during the development of the southern area plan. The following section presents details of the network system constraints, including the forecast year of impact, options that are currently being considered, preferred option and the estimated cost. The cost data is high level and is indicative of the proposed costs and are presented in 2012 base dollars. Constraints that exist or are forecast to occur within seven years in the southern area are presented in Figure 5.17 and outlined in Table The proposed network developments to address the identified issues are described in this section. There is one proposed asset renewal project that has an estimated cost of more than $5 million in the southern area; North Hobart 11 kv switchboard replacement (refer Section 5.5.1). The proposed commissioning date for this project is June Transend Networks Pty Ltd 2012 Page 93

98 Figure 5.17 Southern system constraints Table 5.25 Southern area proposed developments Constraint Proposed development Driver(s) Estimated Commissioning Year Kingston Huon area transmission security Meadowbank Substation supply transformer security Demand management and a new 110 kv transmission circuit between Creek Road Substation and the Kingston Tee (at tower T41) Install a suitable cold spare transformer at Meadowbank Substation. Above the 3000 MWh unserved energy performance requirement of the ESI Regulations Above the 300 MWh unserved energy performance requirement of the ESI Regulations Estimated cost 2017 $19.0 million n/a $0.1 million Transend Networks Pty Ltd 2012 Page 94

99 Constraint Proposed development Driver(s) Estimated Commissioning Year Gordon Chapel Street 220 kv transmission security Waddamana Palmerston 220 kv transmission security Voltage support for the greater Hobart area Voltage support for the greater Hobart area Tarraleah New Norfolk Nos. 1 and 2 transmission line capacity Tungatinah Lake Echo Waddamana Nos. 1 and 2 transmission line capacity Tungatinah Butlers Gorge Derwent Bridge transmission line capacity Upgrade the cross arms on 63 towers of the Gordon Chapel Street transmission line Convert the existing single circuit Waddamana Palmerston 110 kv transmission line to 220 kv and reconfigure Waddamana 220 kv substation to circuit breaker-and-a-half Installation of two 110 kv 40 MVAr capacitor banks at Creek Road Substation Installation of dynamic reactive support in the southern area Maintain existing service level security Maintain existing service level security Maintain existing service level security Estimated cost System stability n/a To be estimated System stability 2019 $20.0 million System stability 2015 $4.75 million System stability 2018 $30.0 million Increase capacity n/a $0 Increase capacity n/a $0 Increase capacity n/a $ Kingston area augmentation The Kingston and Huon areas of Southern Tasmania contain five 110/11 kv terminal substations located at Kingston, Electrona, Knights Road, Kermandie and Huon River. Kingston Substation also has 110/33 kv capacity. Electricity to the Kingston area is supplied via a double circuit 110 kv transmission line that emanates from Chapel Street Substation. There is a 110 kv link between Knights Rd and Electrona substations. Huon River and Kermandie substations are connected to Knights Road Substation via a single circuit 110 kv transmission line. An overview of the Kingston geographical area and the existing transmission infrastructure that supplies the area is presented in Figure 5.18 Transend Networks Pty Ltd 2012 Page 95

100 Figure 5.18 Kingston area 110 kv transmission network To New Norfolk Substation Chapel St Substation T6 Creek Rd Substation Decommissioned 88kV line T41 To Knights Rd Substation Kingston Substation To Electrona Substation Transend has identified that reliability corrective action is required to the transmission network supplying load to the Kingston area in that a single asset failure on the 110 kv double circuit transmission line between Chapel St Substation and tower T41 could result in more than 3000 MWh of unserved energy by winter This does not meet the performance requirement of clause 5(1)(a)(v) of the ESI Regulations. The options outlined in Table 5.26 are currently being considered to address the identified issue. Table 5.26 Options being considered to address Kingston area reliability Option Type of option Detail 1 Network A new 110 kv transmission circuit between Creek Road Substation and the Kingston Tee (at tower T41), which will eventually supply Electrona Substation directly 2 Demand management Aurora has indicated a possible demand management option with a combination of load transfers via the distribution network and the use of mobile diesel generators 3 Generation Transend is not aware of any prospective embedded generators in the area Transend Networks Pty Ltd 2012 Page 96