Feasibility of a second Tasmanian interconnector · ‘Feasibility of a Second Tasmanian...

Feasibility of a second Tasmanian interconnectorFinal Study Dr John Tamblyn April 2017

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This report has been prepared for the purposes of providing advice to the Commonwealth and Tasmanian Governments. The views and opinions expressed in the report do not necessarily reflect those of the Commonwealth or Tasmanian Governments. This publication does not indicate commitment by Commonwealth or Tasmanian governments to a particular course of action.

The content of this report does not constitute advice to any third party. Although due care and skill has been applied in the preparation and compilation of the information and data in this publication, no reliance may be placed on it by any other party. No representation expressed or implied is made as to the currency, accuracy, reliability, completeness or fitness for purpose of the information contained in this publication. The reader should rely on its own inquiries to independently confirm any information and comment on which they may intend to act.

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Cover image (front): Gordon Dam, Tasmania. Photo: Department of the Environment and Energy

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iContents

Contents

Executive summary ............................................................................................................................................. v

1 Introduction ..................................................................................................................................................1

2 Context for the study .................................................................................................................................... 22.1 Transformation of the national electricity market .............................................................................................................2

2.2 Renewable energy development .............................................................................................................................................3

2.3 Energy security and reliability ..................................................................................................................................................4

2.4 Complementary work to the study ........................................................................................................................................5

3 Study approach, assumptions and methodology ....................................................................................... 73.1 Economic efficiency assessment framework.......................................................................................................................7

3.2 Study methodology .....................................................................................................................................................................8

3.3 Tasmanian Government 2IC specification work ............................................................................................................... 10

3.4 Interconnector cost assumptions .......................................................................................................................................... 12

3.5 Modelling and technical analyses ........................................................................................................................................... 13

3.6 Commercial and financial advice............................................................................................................................................ 17

3.7 Differences between AEMO and EY’s modelling approaches .................................................................................... 18

4 Results of modelling and analysis ..............................................................................................................204.1 AEMO modelling findings ......................................................................................................................................................... 21

4.2 AEMO’s analysis of market benefits resulting from a 2IC ............................................................................................ 22

4.3 EY market dispatch modelling results ............................................................................................................................... 24

5 Economic efficiency assessment ................................................................................................................ 325.1 Regulated 2IC market outcomes assessment ................................................................................................................. 32

5.2 Other potential market costs and benefits from a regulated 2IC ............................................................................. 33

6 Commercial and financial arrangements ................................................................................................... 376.1 Business models .......................................................................................................................................................................... 37

6.2 EY modelling methodology ................................................................................................................................................... 39

6.3 Outcomes of financial and commercial analysis .............................................................................................................. 41

6.4 Market sounding ..........................................................................................................................................................................44

6.5 EY findings .....................................................................................................................................................................................44

6.6 Other considerations ..................................................................................................................................................................45

ii Feasibility of a second Tasmanian interconnector

7 Renewable energy and energy security implications ................................................................................467.1 Role of interconnectors ............................................................................................................................................................. 47

7.2 Renewable energy development .......................................................................................................................................... 47

7.3 Energy security ............................................................................................................................................................................54

8 Implications for consumers ....................................................................................................................... 578.1 Allocation of costs ..................................................................................................................................................................... 58

9 Planning and approval requirements .........................................................................................................659.1 Basslink approval process ........................................................................................................................................................ 65

9.2 Considerations for a 2IC ............................................................................................................................................................68

10 Conclusions and recommendations ...........................................................................................................70Recommendation ..................................................................................................................................................................................72

Appendix A: Terms of Reference ..................................................................................................................................... 73

Appendix B: Stakeholder consultations .......................................................................................................................... 74

Appendix C: Australian Energy Market Operator Report: Second Tasmanian Interconnector ...................................... 77

Appendix D: Ernst & Young Report: Market dispatch cost benefit modelling ..............................................................135

Appendix E: Ernst & Young Report: Financial and Commercial Analysis—Second Tasmanian Interconnector ........... 191

iiiContents

AcronymsAcronym Term

2IC A second interconnector between Tasmania and Victoria

AC Alternating current

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

BDB Basslink Development Board

BDSC Basslink Development Steering Committee

BSA Basslink Services Agreement

CCGT Combined cycle gas turbine

COAG Council of Australian Governments

DC Direct current

DOEE Department of the Environment and Energy

EY Ernst & Young

FCAS Frequency control ancillary services

FCSPS Frequency control special protection scheme

GW / GWh Gigawatts / Gigawatt hours

HVDC High voltage direct current

IRR Internal rate of return

JAP Joint Advisory Panel

KV Kilovolt

LCC Line commuted converter

LRMC Long-run marginal costs

MLEC Modified load export charges

MPAA Major Projects Approval Agency

MW / MWh Megawatts / Megawatt hours

NCSPS Network control special protection scheme

NEFR National Electricity Forecasting Report

NEL National Electricity Law

NEM National Electricity Market

NEO National Electricity Objective

NER National Electricity Rules

NPV Net present value

NSCAS Network support and control ancillary services

NTNDP National Transmission Network Development Plan

OCGT Open cycle gas turbine

OTTER Office of the Tasmanian Economic Regulator

PPA Power purchase agreement

POSS Project of State Significance

PV Photovoltaic

QNI Queensland–New South Wales Interconnector

iv Feasibility of a second Tasmanian interconnector

Acronym Term

RET Renewable Energy Target

RIT-T Regulatory Investment Test for Transmission

SCER Standing Council on Energy and Resources

SPS System Protection Scheme

SRAS System restart ancillary services

SRMC Short-run marginal costs

TEST Tasmanian Energy Security Taskforce

TNSP Transmission network service provider

TVPS Tamar Valley Power Station

VRET Victorian Renewable Energy Target

VNI Victoria–New South Wales Interconnector

Dr John Tamblyn Dr John Tamblyn has an extensive background in the regulation of public utilities and in energy policy. He is currently the Chair of the COAG Energy Council Appointments Selection Panel and was the inaugural Chair of the Australian Energy Market Commission (AEMC).

Dr Tamblyn was one of two expert advisors appointed by the then Standing Council on Energy and Resources (SCER) to provide advice on the establishment of the

National Energy Consumer Advocacy Body (now Energy Consumers Australia). He was a member of the expert panel that conducted the 2012 review of the energy market Limited Merits Review regime for SCER. Dr Tamblyn is also a former member of the Solar Flagships Council.

Before chairing the AEMC, he gained significant experience in regulation of public utility services, including the positions of Chairman of the Essential Services Commission (Victoria) and Regulator-General (Victoria). He has also held senior positions in the Australian Competition and Consumer Commission.

Dr Tamblyn served on Tasmania’s Electricity Supply Industry Expert Panel, which advised the Tasmanian Government on options for improving the performance of the Tasmanian electricity supply industry.

vExecutive Summary

Executive summaryIn April 2016, the Australian and Tasmanian governments established this study of the feasibility of a second electricity interconnector (2IC) between Tasmania and Victoria. The study was initiated in response to energy supply challenges in Tasmania during 2015–16 caused by an extended outage of Basslink combined with low hydro water storage levels resulting from low rainfall.

The Terms of Reference for this study call for a feasibility assessment of a 2IC and advice on whether it would; address energy security issues, facilitate development of Tasmania’s large scale renewable energy resources and integrate with the Victorian electricity market and the wider National Electricity Market (NEM). The study was also to advise on implications for electricity consumers and related regulatory and financing issues.

Studies of a 2IC and the possible role it could play in developing Tasmania’s renewable energy resources are not new. For example, the Tasmanian Government commissioned an earlier study in 2010–11.1

This study is being undertaken at a time when the NEM as a whole is undergoing substantial transformation. Rapid technological changes, increasing penetration of renewable energy, more decentralised generation, reduced synchronous generation and shifting patterns of consumer demand are reshaping the NEM.

Energy market events in Tasmania in 2015–16 and South Australia in 2016 have led to a greater focus by governments on ensuring that all Australians can access a reliable and secure supply of energy. Energy reliability and security is a particular priority for Tasmania as a relatively energy intensive state where energy is vital for home heating and to support its major industrial businesses.2

Interconnectors have a role to play in managing energy market changes by enabling the transfer of energy and power system security services between regions. Interconnectors can also facilitate the more efficient development and distribution of intermittent renewable energy across the interconnected NEM.

A number of related policy and regulatory reviews have been initiated in response to these changing market dynamics. They include:

• the Independent Review into the Future Security of the National Electricity Market

• the Tasmanian Energy Security Taskforce (TEST) work on energy security risk mitigation measures for Tasmania

• ElectraNet’s South Australian Energy Transformation Regulatory Investment Test for Transmission (RIT-T)3 process

• the Australian Energy Market Operator (AEMO) and the Australian Energy Market Commission (AEMC) power system security reviews.

This shifting policy and regulatory environment has been an important consideration throughout the study.

1 Marchment Hill 2011, RELink preliminary proof of concept final report, p. 4.

2 Tasmanian Energy Security Taskforce 2016, Interim Report, p. 8

3 The RIT-T is a cost–benefit analysis which identifies the transmission investment option that meets an identified need, which maximises net economic benefits. It therefore serves to protect consumers from inefficient investments where costs outweigh benefits. It requires consideration of a range of credible options that meet the identified need.

vi Feasibility of a second Tasmanian interconnector

This study builds on the preliminary report, which governments released in June 2016. It provides an assessment of whether a 2IC is likely to be an economically feasible4 investment which could support energy security and reliability in the NEM and the efficient transition of the NEM to a lower emission generation mix.

The National Electricity Objective (NEO) and the RIT-T provided the analytical framework for assessing whether, and in what circumstances, a 2IC would be an economically efficient investment. This approach ensured that, when conducting this study, a whole of NEM perspective was taken, with the long-term interests of consumers in mind.

To understand the drivers and circumstances that might support investment in a 2IC, power system and market dispatch modelling was obtained, together with financial and commercial advice. Input was also obtained from the Tasmanian Government, AEMO and the Clean Energy Finance Corporation as well as through targeted stakeholder consultations.

Economic feasibility assessment

Assessment of the economic feasibility of a 2IC has proven to be a difficult and uncertain task. It is challenging to forecast, with the requisite degree of confidence, future energy market conditions that will apply over a 2IC’s 40 year or more economic life. That uncertainty is exacerbated by the ongoing transformation of the NEM and the long lead time required for planning and construction of a 2IC. As the study considers the period to 2066, that uncertainty has a significant impact on the ability to make a confident assessment of the viability of a 2IC.

Market modelling by AEMO and Ernst & Young (EY) sought to address this uncertainty by analysing the projected NEM-wide costs and benefits that would be generated by a 2IC under plausible future energy market conditions. They also analysed case studies that set out different possible future investment environments.

Market benefits of a 2IC

The modelling identified two key sources of benefits from a 2IC:

1. A 2IC would indefinitely defer between 450 and 600 megawatts (MW) of thermal generation investment in the NEM which would otherwise be required to maintain reliability in Victoria as its brown coal generation is retired. However, this capacity deferral would not occur until the early 2030s, meaning that the benefits of reduced capital investment would be discounted significantly.

2. A 2IC would also generate variable cost savings in the NEM. These savings are primarily attributable to more efficient use of Tasmanian hydro storage and generation facilities. The additional capacity of a 2IC would allow increased exports of dispatchable renewable energy to Victoria during periods of high demand and value when higher-cost generation would otherwise have been required. It would also allow more imports of energy at low value times, maintaining dam levels for later high value use. Together a 2IC and Basslink would enhance the capability for Tasmania’s water storages and hydro facilities to be used much like a large battery, by flexibly sending out or absorbing power to and from Tasmania, to maximise its value to Tasmania and the rest of the NEM.

Additional benefit was also identified from improved utilisation of other lower-cost Tasmanian generation assets, including the Tamar Valley Power Station’s combined cycle gas turbines.

4 In this study economic feasibility is assessed by considering whether a 2IC is an economically efficient investment. While the accepted dimensions of economic efficiency (allocative, productive and dynamic) were in mind when analysing the net benefits from a 2IC, a more comprehensive assessment in those terms was not feasible because the study was unable to assess the net benefits of other credible options that may have generated greater benefits for the same or lower costs.

viiExecutive Summary

Other significant market benefits

A 2IC would also deliver reliability benefits to Victoria and Tasmania by providing reliability support to Victoria at times of peak demand and to Tasmania during periods of drought and low water storage levels. Tasmania would also benefit from increased ‘resilience’ to potential failures of Basslink by retaining connection to the NEM in that event, avoiding the need for voluntary and involuntary load shedding. A 2IC, incorporating advances in interconnector technology, could also transfer power system security services between Tasmania and the rest of the NEM. While power system security benefits were not fully considered in the AEMO and EY modelling, they are likely to be in greater demand and accorded a higher value in future as the penetration of intermittent renewable generation continues to increase. AEMO has noted, however, that as the mainland NEM has significant synchronous generation and is interconnected by an alternating current network, it has access to sufficient frequency control ancillary services to meet requirements for the foreseeable future.

A 2IC would facilitate development of Tasmania’s rich wind resources. The modelling indicated that a 2IC would increase the financial viability of renewable generation in Tasmania and reduce the risk of it being constrained by transmission limitations. The modelling showed that without a 2IC in operation Tasmanian wind generation could increase by up to 730 MW by 2036 and with a 2IC an additional 365 MW could be developed over the same period. Much of this wind development is expected to occur in the late 2020s and 2030s due to the earlier build of wind generation in Victoria (incentivised by the Victorian Renewable Energy Target) and South Australia (assuming additional interconnection is built).

While the market benefit assessments varied markedly according to the different scenarios and case studies being modelled, two case studies resulted in significant improvements in the market benefits from a 2IC. The development of an additional interconnector between South Australia and the eastern states before a 2IC is developed would result in larger market benefits than those achieved when each interconnector was assessed separately. Stronger interconnection between NEM regions was found to facilitate more efficient transfer of un-correlated renewable energy flows between NEM regions. The market benefits of a 2IC would also increase markedly if there was a significant reduction in Tasmanian electricity demand because the resulting surplus generation could be exported rather than being wasted because of constrained interconnection capacity.

Capital and operating costs of a 2IC

The capital and operating costs involved in constructing and operating an undersea interconnector are substantial compared to the cost of overhead interconnectors. The total capital cost of a 2IC (including network augmentation costs) has been estimated at up to $1.1 billion, with estimated ongoing operational and maintenance costs of $16.7 million per annum. These cost estimates are preliminary and may change during the more detailed planning, construction and regulatory approval processes. Thus, while a 2IC would be capable of delivering material benefits to the NEM and Tasmania, those benefits would need to outweigh the substantial capital and operating costs of a 2IC by a significant margin in most modelled scenarios to establish a persuasive case in support of a 2IC investment.

Net benefit assessment

The modelling identified two future NEM development scenarios in which a 2IC would produce market benefits sufficient to outweigh the capital and operating costs by a significant margin in net present value terms. They were where:

• an additional South Australian interconnector was built before a 2IC came into operation

• there is a significant reduction in future Tasmanian electricity demand.

viii Feasibility of a second Tasmanian interconnector

Under a further scenario (AEMO’s neutral demand scenario) modelled net benefits were only marginally positive, with projected net market benefits of just $20 million. In the remaining scenarios and case studies modelled the net benefit assessments were negative to varying degrees. Overall, these results indicate that the economic feasibility of a 2IC remains uncertain and is likely to be economically justified in some plausible future market circumstances and not in others.

Based on the modelling results and analysis of other relevant considerations, the overall conclusion is that, while a 2IC would deliver significant net economic benefits to the NEM under certain plausible scenarios, under other modelled scenarios the potential benefits from a 2IC would be unlikely to exceed the significant capital and operating costs of a 2IC and related network augmentation.

As noted above, the modelling did not include and evaluate certain potential benefits from a 2IC which are allowable in a RIT-T assessment including, for example, competition benefits, some aspects of power system security and reliability benefits, and options value benefits. These benefits were omitted from the analysis because they are currently complex to quantify and value. Power system security benefits in particular, are likely to be in greater demand and valued more highly in future than they have been historically. Where only marginal differences are identified between costs and benefits, more detailed analysis of these potential benefits may be warranted to assign an imputed value to them.

While the modelling forms an important basis for developing conclusions about the feasibility of a 2IC, it also has limitations due to the necessity for simplifying assumptions about future policy frameworks, market conditions and responses of market participants in making projections of future market outcomes from investment initiatives. There is also scope for different weightings to be placed on the categories of benefit generated by investment in a 2IC compared to those reflected in the modelling. For example, at a time of heightened pressure on the security and reliability of the NEM, the community and governments may place greater value on the energy security and reliability benefits of a 2IC than has been captured in the modelling results. Similarly, the value of investing in a 2IC may be enhanced if there is reason to regard it as a replacement asset for Basslink at some point in its economic life.5

As already noted, the study is being conducted at a time of heightened uncertainty regarding the energy market conditions that are likely to apply during the economic life of a 2IC. The outcomes of ongoing policy reviews, ElectraNet’s RIT-T process and future AEMO National Transmission Network Development Plan (NTNDP) reports will all contribute to clarifying the future NEM investment environment. Ongoing monitoring of these and related NEM developments would be appropriate to identify changes to energy market frameworks and conditions that would give added support to the case for strengthening interconnection across the NEM, including by investing in a 2IC.

Other considerations

The study also examined the implications of a 2IC for the broader issues identified in the Terms of Reference. This examination was conducted on the assumption that a 2IC would be economically efficient and financially viable. In particular, the study considered optimal commercial arrangements for a 2IC’s financing and operations and cost recovery from consumers.

Commercial and financial arrangements

Interconnectors can either be regulated or merchant. They recover revenue from consumers in different ways. If a 2IC meets the RIT-T, it could be a regulated interconnector and earn regulated revenue set by the Australian

5 Basslink commenced operation in 2006. Basslink was established by two main contracts. The Basslink Operations Agreement, between the Tasmanian Government and Basslink Pty Ltd, is designed to ensure that Basslink is available to Tasmania for a period of 40 years. The Basslink Services Agreement, between Hydro Tasmania and Basslink Pty Ltd, establishes the rights and obligations of both parties in respect to the operation of Basslink. The initial term of the BSA was set at 25 years, with an option to extend the term for a further 15 years.

ixExecutive Summary

Energy Regulator (AER). A regulated 2IC was found to be the more attractive option from an investment and financing perspective due to its predictable revenue stream and lower risk. However the market modelling suggests that satisfying the RIT-T would be a challenge.

Alternatively, if a 2IC were operated as a merchant interconnector its costs would be recovered through arbitrage revenues earned from wholesale market trading on the difference between Tasmanian and Victorian regional spot market prices. Modelling indicated the potential for higher revenues from a merchant model rather than from a regulated model, but the merchant revenues would be volatile and risky.

Investors have indicated that a 2IC will need to either be a regulated interconnector or if operated as a merchant asset, be supported by a facility or availability charge similar to the Basslink arrangement, in order to provide a viable and fundable commercial model.

Implications for consumers

The development of a 2IC would have implications for consumers. While a 2IC would impose costs on consumers, it would also provide them with market benefits. The market benefits would not necessarily be as significant as the costs, but over the longer-term a 2IC would facilitate market efficiency benefits and contribute to reliability and security of supply.

A regulated 2IC would recover its costs through regulated revenues determined by the AER, regardless of the 2IC’s utilisation. These costs would be allocated to Victorian and Tasmanian consumers according to the proportionate direction of flows across the 2IC and would be recovered primarily through the network component of consumers’ bills. By facilitating greater flows between Victoria and Tasmania, a regulated 2IC would also reduce inter-regional constraints, resulting in convergence of wholesale energy prices.

A merchant 2IC’s costs would be recovered through wholesale market trading revenues. The impact on consumers would depend on the owner’s strategy in bidding the 2IC. Cost impacts would also depend on spot price differences between the regions, the volume of the flows between them and competitive conditions in wholesale and retail markets.

While a 2IC would deliver benefits as well as costs to consumers, the critical issue for the study is whether the NEM-wide benefits would exceed the NEM-wide costs. In the case of a regulated 2IC, that question would be addressed by a formal RIT-T assessment. The issue does not arise formally in the case of a merchant 2IC. However, the study’s market modelling indicated that NEM-wide benefits would be lower for a merchant 2IC than for a regulated 2IC, due in part to the bidding strategies that may be used to maximise arbitrage trading revenues.

Conclusion

The NEM is undergoing rapid transformation. The increasing penetration of non-synchronous forms of renewable generation is driving the need for responses that will maintain power system security. This presents opportunities for Tasmania to export balanced and dispatchable renewable energy, based on its hydro resources, to other NEM regions.

Interconnectors can play an important role in facilitating this energy market transition. Governments are examining, through policy review and network planning, whether further strengthening of interconnection across the NEM would be justified when viewed as a system wide strategy. As one example, in its 2016 NTNDP report, AEMO found that positive net benefits could be achieved from the development of a 2IC following construction of an additional interconnector from South Australia to the eastern states. Modelling for this study confirmed that outcome. However, these potential benefits would come at a significant cost and decisions on interconnection investment must be made on the basis of well-informed assessments of their potential costs and benefits.

x Feasibility of a second Tasmanian interconnector

The current energy market environment is subject to uncertainty. The uncertainty of the future investment environment for a 2IC is further exacerbated by the length of its economic life of 40 years or more and the long lead times for planning and construction. While the modelling results suggest that under current anticipated market conditions a 2IC may not be economically feasible, it has not been possible to fully reflect the implications of prevailing market uncertainty in those projections. Also, other relevant market benefits, such as power system security and reliability benefits, have not been fully captured by the modelling and may be given greater weight by electricity consumers and governments in current market conditions.

In view of this prevailing market uncertainty, it would be appropriate to monitor future NEM developments to identify changes to policy and regulatory frameworks and energy market conditions that would provide added support for the strengthening of interconnection across the NEM, including by investing in a 2IC. AEMO is best placed to undertake this monitoring through its NTNDP reports and related network planning work, in consultation with Hydro Tasmania and TasNetworks as appropriate.

As the current suite of reviews is completed, providing greater certainty about future energy market frameworks, AEMO’s future NTNDPs will be in a better position to evaluate the feasibility of additional interconnection across the NEM. Future NTNDP assessments will also provide a comprehensive NEM-wide basis for forming a view on the prospective economic feasibility of a 2IC as a precondition for initiating more detailed work on the proposal. Other preconditions, being a reduction of Tasmanian electricity demand or approval of additional interconnection between South Australia and the eastern states, would also provide a credible basis for initiating further detailed work.

Should monitoring establish one or more of the relevant preconditions, a detailed business case should be developed by the Tasmanian Government, taking into account developments in the NEM investment environment since this study was undertaken.

Recommendation

I therefore recommend that the Tasmanian Government develop a detailed business case for a second Tasmanian interconnector when ongoing monitoring establishes that one or more of the following preconditions has been met:

1. The Australian Energy Market Operator, in consultation with Hydro Tasmania and TasNetworks, concludes in a future National Transmission Network Development Plan that a second interconnector would produce significant positive net market benefits under most plausible scenarios.

2. Additional interconnection is approved for construction between South Australia and the eastern states.

3. A material reduction occurs in Tasmanian electricity demand.

1Introduction

1 Introduction In April 2016 the Australian and Tasmanian governments established this feasibility study on whether a second electricity interconnector (2IC) between Tasmania and Victoria could improve Tasmania’s energy security and facilitate the development of Tasmania’s large scale renewable energy resources.

The Terms of Reference for the study, at Appendix A, call for an examination of the extent to which a 2IC would address energy security issues; facilitate development of Tasmania’s large scale renewable energy resources; and integrate with Victoria and the wider National Electricity Market (NEM). The study was also to advise on implications for electricity consumers and related regulatory and financing issues.

The study was undertaken by Dr John Tamblyn, with support from a taskforce led by the Department of the Environment and Energy, including secondees from the Commonwealth Treasury and the Australian Energy Market Commission (AEMC). Dr Tamblyn replaced the previous head of the study, the Hon Warwick Smith AM LLB, in September 2016 and the reporting date for the study was extended to the end of January 2017.6 Mr Smith’s preliminary report was publicly released by the Hon Greg Hunt, the then Minister for the Environment, on 21 June 2016.

Studies on a 2IC and the role it could play in supporting development of Tasmanian renewable energy resources are not new. In 2010−11 the Tasmanian Renewable Energy Industry Development Board commissioned a preliminary proof of concept study on a 2IC.7 It found that a 2IC would have only a modest impact on the development of additional renewable energy generation and recommended that more detailed modelling not proceed at that time.8

The Tasmanian Government, with the assistance of Hydro Tasmania and TasNetworks, has also completed its own preconditions assessment for a 2IC between Tasmania and Victoria.

Building on this previous work, this study examined the costs and benefits of a 2IC for the NEM, having regard to the Terms of Reference. The purpose of the study is to assess whether the construction and operation of a 2IC is likely to be an economically efficient investment which would serve the long-term interests of electricity consumers, including by promoting energy security and reliability and supporting the transition to a lower emission energy mix in the NEM.

With this purpose, the study examined whether there are potential future development paths for the NEM which would make investment in a 2IC viable as either a regulated or a merchant interconnector.9

6 The Hon Josh Frydenberg MP 2016, New head of Tasmanian interconnector feasibility study, http://www.joshfrydenberg.com.au/guest/mediaReleasesDetails.aspx?id=255 (accessed 13 December 2016).



9 In the NEM, merchant interconnectors earn revenue by arbitrage trading in the spot markets of two NEM regions, whereas a regulated interconnector earns a regulated revenue stream determined by the Australian Energy Regulator (AER), having first satisfied the Regulatory Investment Test for Transmission (RIT-T).

http://www.joshfrydenberg.com.au/guest/mediaReleasesDetails.aspx?id=255

http://www.joshfrydenberg.com.au/guest/mediaReleasesDetails.aspx?id=255

2 Feasibility of a second Tasmanian interconnector

2 Context for the study2.1 Transformation of the national electricity marketThe NEM is undergoing substantial change as the result of an increase in renewable energy generation and related reduction of synchronous generation capacity, together with the adoption of rapidly changing energy technologies, development of more decentralised power generation and shifting patterns of consumer demand.

These changes are testing the capacity of existing energy market arrangements, including Australia’s ageing generation fleet and energy network infrastructure, to maintain the security and reliability of power supply in the NEM.

The main catalyst for the study was the combined impact of:

• historically low Hydro Tasmania water storage levels resulting from the record low rainfall over the 2015 spring−summer period

• the Basslink cable outage from 20 December 2015 to 13 June 2016.10

These events highlighted Tasmania’s unique energy constrained system and its dependence on a single connection to the rest of the NEM.11 This was the first extended outage of Basslink since it was commissioned in April 2006. Before the 2015−16 outage, in its nearly 10 years of operation Basslink had experienced 65 outages lasting from less than hours to just over nine days. The majority of the outages had a duration of less than a day.12 The exact cause of the subsea cable fault that led to the 2015−16 Basslink outage has been described as ‘cause unknown’.13

During the outage, reliability and security of supply was maintained at considerable cost by returning the Tamar Valley Power Station (TVPS) to service, installing temporary diesel generation and requiring major industrial consumers to reduce their demands on the system.14

At a time when Tasmania was unable to import electricity from the rest of the NEM, its ability to generate its own electricity to meet demand was also greatly reduced because of record low rainfall and the resulting historically low water storage levels. The net cost of responding to the energy supply challenge was estimated by Hydro Tasmania to be between $140 million and $180 million.15 This highlighted the importance of effective management of Hydro Tasmania’s water storages. This is one of the issues being reviewed by the Tasmanian Energy Security Taskforce (TEST) process.16

10 Basslink Pty Ltd 2016, Basslink has returned to service, http://www.basslink.com.au/wp-content/uploads/2016/06/Media-statement-13-June-final1.pdf (accessed 18 January 2017).

11 Tasmania’s energy system is considered unique in the NEM because it is energy constrained rather than capacity constrained. This means Tasmania’s energy system has more than enough installed generation capacity to meet peak demand, but fuel sources (principally water) to supply this generation can sometimes be in short supply. See Office of the Tasmanian Economic Regulator (OTTER) 2015, Energy in Tasmania—Performance report 2014−15, pp. 53−54.

12 Tasmanian Energy Security Taskforce 2016, Consultation paper, p. 9.

13 Basslink Pty Ltd 2016, Basslink fault cause investigation completed, http://www.basslink.com.au/wp-content/uploads/2016/12/161205-Media-statement.pdf (accessed 15 December 2016).

14 Hydro Tasmania reports that the cost of running gas generation was approximately $47 million. It was approximately $64 million for diesel generation. Hydro Tasmania 2016, Annual report 2016, p. 15.

15 Hydro Tasmania 2016, Annual report 2016, p. 12.

16 Tasmanian Energy Security Taskforce 2016, Consultation paper, p. 8.

http://www.basslink.com.au/wp-content/uploads/2016/06/Media-statement-13-June-final1.pdf

http://www.basslink.com.au/wp-content/uploads/2016/12/161205-Media-statement.pdf

http://www.basslink.com.au/wp-content/uploads/2016/12/161205-Media-statement.pdf

3Context for the study

These events, and the black system event in South Australia on 28 September 2016,17 have prompted governments to consider a range of initiatives to improve the security and reliability of the NEM. One measure that is under active consideration is the role that strengthened interconnection can play in supporting energy security and in renewable energy development. The preliminary report of the Independent Review into the Future Security of the National Electricity Market highlighted the need for power system integration. It noted that power system security and reliability can be improved by investing in new network assets to allow connected regions to access a diversity of generation supply across the NEM.18

The transformation that is occurring in the NEM is not unique to Australia. Globally, a number of governments are evaluating their electricity systems and facilitating the construction of additional interconnectors between electricity grids to boost security of supply and integrate more renewable energy into their power systems.19

The Australian Energy Market Operator (AEMO) has stated that a more interconnected NEM could improve system resilience.20 Improving resilience would better enable the NEM to withstand major high-impact, low-probability disturbances such as interconnector failures.

AEMO also notes that increased interconnection across the NEM has the potential to provide a range of other benefits, including increased efficiency in generation production costs, greater reliability and security outcomes and reduction in capacity investment related to new generation.21

2.2 Renewable energy developmentThe shift towards a lower emissions generation mix in the NEM is being driven by the following Australian Government targets:

• the Australian Government’s commitment, through the Paris Agreement,22 to reduce Australia’s carbon emissions by 26 to 28 per cent below 2005 levels by 203023

• the Renewable Energy Target (RET), which requires at least 33 000 gigawatt hours (GWh) of Australia’s electricity generation to come from renewable sources by 2020. This requires an estimated 6000 megawatts (MW) of new renewable energy to be built by 2020.24

This shift in generation mix towards renewable energy generation, as detailed in Figure 1, is changing the operation of the NEM.

17 On 28 September, the electricity supply in South Australia was lost when a black system event occurred due to severe weather. A black system event is defined in the National Electricity Rules as ‘The absence of voltage on all or a significant part of the transmission system or within a region during a major supply disruption affecting a significant number of customers’. See Expert Panel 2016, Independent Review into the Future Security of the National Electricity Market Preliminary Report, pp. 31−33.

18 Expert Panel 2016, Independent Review into the Future Security of the National Electricity Market preliminary report, p. 27.

19 For example, the European Union has set a target of 10 per cent electricity interconnection by 2020. This means that all European Union countries should have electricity interconnectors in place that allow at least 10 per cent of the electricity generated by their power plants to be exported to neighbouring countries. See EurActive 2015, Energy union aims for elusive 10% power grid interlinkage, http://www.euractiv.com/section/energy/news/energy-union-aims-for-elusive-10-power-grid-interlinkage/ (accessed 16 January 2017).

20 AEMO 2016, NTNDP, p. 3.

21 AEMO 2016, NTNDP, p. 27.

22 The Paris Agreement was agreed under the United Nations Framework Convention on Climate Change (UNFCCC) at the 21st Conference of the Parties in Paris (30 November to 12 December 2015). The Paris Agreement sets in place a durable and dynamic framework for all countries to take climate action from 2020, building on existing international efforts in the period up to 2020. See United Nations Framework Convention on Climate Change, The Paris Agreement, http://unfccc.int/paris_agreement/items/9485.php (accessed 17 January 2017).

23 Department of the Environment and Energy (DOEE) 2016, Australia’s 2030 Emission Reduction Target, https://www.environment.gov.au/climate-change/australias-emissions-reduction-target (accessed 15 December 2016).

24 Clean Energy Council 2016, Renewable Energy Target, https://www.cleanenergycouncil.org.au/policy-advocacy/renewable-energy-target.html (accessed 13 January 2017).

http://www.euractiv.com/section/energy/news/energy-union-aims-for-elusive-10-power-grid-interlinkage/

http://www.euractiv.com/section/energy/news/energy-union-aims-for-elusive-10-power-grid-interlinkage/

http://unfccc.int/paris_agreement/items/9485.php

https://www.environment.gov.au/climate-change/australias-emissions-reduction-target

https://www.environment.gov.au/climate-change/australias-emissions-reduction-target

https://www.cleanenergycouncil.org.au/policy-advocacy/renewable-energy-target.html


Figure 1: Projected changes in installed generation capacity in the NEM, 2016−17 to 2035−3625

Interconnectors can play a role in supporting renewable energy integration by enabling more efficient transfer of renewable generation. Interconnectors can also more efficiently facilitate supplementation of generation from dispatchable sources (such as coal, gas and hydro) at times when renewable generation is not available. Ultimately, interconnectors diversify and expand the range of energy sources available to meet demand across the NEM. This is likely to be of greater importance in the future, when there will be a higher proportion of renewable energy.

Tasmania has abundant and high-quality renewable energy resources. In 2014−15, over 99 per cent of generation in Tasmania was from renewable energy.26 There is an opportunity for Tasmania to make a greater contribution to the NEM’s transition towards a lower emission generation mix through exporting more renewable energy (primarily wind, supported by hydro) to the rest of the NEM. The combination of Tasmania’s hydro and wind resources provides unique advantages, as the hydro reservoirs can be operated much like a large scale energy storage facility. When the wind is blowing, wind turbines can generate directly into the electricity grid, allowing water storages to be maintained for hydro generation when there is little wind available.27

2.3 Energy security and reliability Energy security has varying meanings and can be used interchangeably depending on the context and contemporary concerns. Consistent with the approach taken by AEMO and the AEMC, this study has interpreted energy security in terms of power system security—that is, the ability to maintain the operation of the power system within relevant technical parameters encompassing frequency, voltage and fault levels.28

Reliability of energy supply is related to, but distinct from, power system security and refers to the likelihood of being able to supply all consumer energy requirements in the NEM or a NEM region with the generation and network capacity that is currently available.29 This includes an adequate availability of dispatchable generation; and transmission and distribution network capacity to deliver required electricity to demand centres as needed.

25 Based on data provided by AEMO from its neutral economic growth scenario. See AEMO 2016, NTNDP, p. 25.

26 OTTER 2016, Energy in Tasmania report 2015−16, p. 6.

27 Hydro Tasmania 2014, The power of nature—Tasmania’s renewable energy from water and wind, p. 7.

28 AEMC 2016, Consultation paper—System Security Market Frameworks Review, p. 2.


5Context for the study

The increasing penetration of renewable energy generation creates technical challenges for the maintenance and restoration of the required power security settings in the NEM. Renewable energy technologies do not currently provide the same power system security services that synchronous generation, such as coal, gas and hydro, can provide. Effective alternative sources of power system security services will therefore be needed in the future as the proportion of synchronised generation declines in the NEM.

The value of power system security services in the NEM has been low historically. The revenue generators earned for providing ancillary services has been small compared to revenue from electricity sales. In 2015, the total value of ancillary services purchased in the NEM was $112 million, or 1.4 per cent of the $8.3 billion traded on the NEM.30

The value of security services may increase as the share of renewable energy in the NEM increases. The AEMC is considering changes to market and regulatory frameworks to support the provision of additional system security services, including market or contractual mechanisms for the purchase of system security services, such as inertia, on a competitive basis.31

The preliminary report of the Independent Review into the Future Security of the National Electricity Market highlighted the need for careful integration of renewable energy generation into the NEM, noting that intermittent generators typically lack the capability of synchronous generators to provide spinning inertia and deliver instantaneous or medium-term security and frequency control services.32

The declining role of synchronous generation in the NEM is reducing the ability to correct frequency disturbances in some circumstances, and frequency control ancillary services (FCAS) will need to be obtained from other sources to compensate. Interconnectors can supply FCAS across regional boundaries, but individual regions still need to source an adequate indigenous supply of FCAS if they are separated from the rest of the NEM.33

2.4 Complementary work to the study The Basslink outage and the tripping of the South Australia to Victoria (Heywood) Interconnector on 28 September 2016 have demonstrated that there can be significant consequences for reliability when interconnectors fail. For this reason, increasing consideration is being given to the potential for augmenting existing interconnection across the NEM. This could strengthen the stability and resilience of the NEM by enabling the efficient transfer of energy and security services between NEM regions.34

This study is part of that wider assessment of the future role of interconnectors as the transformation of the NEM continues. The following work could also have direct or indirect implications for that role:

• ElectraNet is conducting the South Australian Energy Transformation Regulatory Investment Test for Transmission (RIT-T) process, which is due in late 2017.

• TEST is currently assessing energy security risk mitigation measures for Tasmania.35 It released an interim report in December 2016, and its final report to the Tasmanian Government is due by mid-2017.

• The Australian Government is undertaking a review of its climate change policies during 2017.36





34 AEMO 2016, CEDA—AEMO Chairman—Dr Tony Marxsen speech, p.21, https://www.aemo.com.au/-/media/Files/Media_Centre/2016/CEDA_Chairman-speech_12-Dec-2016.pdf (accessed 15 December 2016).

35 Tasmanian Government Department of State Growth, Tasmanian Energy Security Taskforce, http://www.stategrowth.tas.gov.au/tasmanian_energy_security_taskforce (accessed 19 December 2016).

36 DOEE 2016, Review of Australia’s climate change polices, http://www.environment.gov.au/climate-change/review-climate-change-policies (accessed 13 December 2016).

https://www.aemo.com.au/-/media/Files/Media_Centre/2016/CEDA_Chairman-speech_12-Dec-2016.pdf

https://www.aemo.com.au/-/media/Files/Media_Centre/2016/CEDA_Chairman-speech_12-Dec-2016.pdf

http://www.stategrowth.tas.gov.au/tasmanian_energy_security_taskforce

http://www.stategrowth.tas.gov.au/tasmanian_energy_security_taskforce

http://www.environment.gov.au/climate-change/review-climate-change-policies


• Various related work is being conducted by the Council of Australian Governments (COAG) Energy Council, AEMO and the AEMC. This includes:

– the work of the independent panel charged with conducting an Independent Review into the Future Security of the National Electricity Market

– the COAG Energy Council’s agreed improvements to the RIT-T37

– review of the technical and regulatory aspects of the NEM energy security mechanisms being conducted by AEMO and AEMC.

The outcomes of these intersecting energy market policy reviews and regulatory initiatives is uncertain. They may have a substantial bearing on the NEM’s investment environment, particularly over the long-term, and therefore on the economic efficiency of a 2IC.

37 COAG Energy Council 2016, Meeting communique, p. 2, http://www.scer.gov.au/sites/prod.energycouncil/files/publications/documents/Energy%20Council%20Communique%20-%2014%20December%202016%20Version%201.0.pdf (accessed 14 December 2016).

http://www.scer.gov.au/sites/prod.energycouncil/files/publications/documents/Energy%20Council%20Communique%20-%2014%20December%202016%20Version%201.0.pdf


7Study approach, assumptions and methodology

3 Study approach, assumptions and methodology

This chapter outlines the general methodology used to assess the economic feasibility of a 2IC. It describes the approach taken and the modelling and analysis commissioned to support the study. In this study, economic feasibility is assessed by considering whether a 2IC would be an economically efficient investment.38

3.1 Economic efficiency assessment frameworkTo understand whether a 2IC would be an economically efficient investment, the study has considered whether, and in what circumstances, a 2IC is likely to be in the long-term interests of electricity consumers. The study has therefore assessed the economic efficiency and financeability of a 2IC under a range of plausible scenarios for the future development of the NEM.

In this study, the term ‘economically efficient’ refers to an investment which, if made, would be efficient in the long-term interests of electricity consumers in the NEM, meaning that its expected benefits to consumers would outweigh its expected costs. ‘Economically efficient’ as it relates to an investment is different from the notion of financeability. The former relates to whether the investment would be in the long-term interests of consumers; the latter relates to whether investors would be willing to fund the investment.

The National Electricity Objective (NEO)39 provides an appropriate framework for these considerations, as its core focus is on achieving efficient investment that is in the long-term interests of electricity consumers with respect to price, reliability and security of energy supply across the NEM.

The NEO reflects the overall objective of the Australian Energy Market Agreement.40 Using it as guidance requires the analytical framework for the study to:

• take a NEM-wide perspective

• consider economically efficient long-term outcomes

• focus on outcomes that promote the long-term interests of consumers.

The RIT-T41 is the test used to determine whether a transmission investment is economically efficient. It is set out in the National Electricity Rules (NER), and it tests for economic efficiency by determining whether major network investments would provide net positive benefits for electricity consumers in discounted net present value (NPV) terms.42

38 Economists interpret economic efficiency in terms of the following dimensions: allocative efficiency, where resources are allocated to their highest value uses; productive efficiency, where outputs are maximised for given inputs; and dynamic efficiency, where ongoing innovation and investment maximises efficient resource allocation over time. While these dimensions of efficiency were in mind when analysing the net benefits from a 2IC, a more comprehensive assessment in terms of all three dimensions of efficiency was not feasible because the study was unable to assess the net benefits of other credible options that may have generated greater net benefits at the same or lower cost.

39 AEMC 2016, National electricity market, http://www.aemc.gov.au/Australias-Energy-Market/Markets-Overview/National-electricity-market (accessed 15 January 2017). The NEO, as stated in the Australian Energy Market Agreement, is ‘to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of electricity with respect to—price, quality, safety, reliability, and security of supply of electricity; and the reliability, safety and security of the national electricity system’.

40 The Australian Energy Market Agreement sets out the legislative and regulatory framework for Australia’s energy markets. It provides for national legislation that is implemented in each participating state and territory.

41 On 14 December 2016, the COAG Energy Council agreed to a number of improvements to the RIT-T, which remain to be adopted in the rules. See COAG Energy Council 2016, Meeting communique, p. 2, http://www.scer.gov.au/sites/prod.energycouncil/files/publications/documents/Energy%20Council%20Communique%20-%2014%20December%202016%20Version%201.0.pdf (accessed 14 December 2016).

42 The study has based its analysis on the RIT-T and application guidelines (version 1), June 2010. See AER 2010, RIT-T and application guidelines 2010, https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/regulatory-investment-test-for-transmission-rit-t-and-application-guidelines-2010 (accessed 15 January 2017).

http://www.aemc.gov.au/Australias-Energy-Market/Markets-Overview/National-electricity-market



https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/regulatory-investment-test-for-transmission-rit-t-and-application-guidelines-2010

https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/regulatory-investment-test-for-transmission-rit-t-and-application-guidelines-2010


The RIT-T identifies the transmission investment option (or alternative non-network option) that meets an identified need and maximises net economic benefits. It therefore serves to protect consumers from the cost and other consequences of inefficient investments where costs outweigh benefits. It requires consideration of a range of alternative credible options that could meet an identified need.43 This identified need is the objective a transmission network service provider (TNSP) is seeking to achieve in proposing that a particular investment be made in its transmission network.

In practice, the RIT-T has to be satisfied before the Australian Energy Regulator (AER) can approve a major network investment such as an interconnector as a regulated asset to be funded from regulated revenues. For regulated interconnectors, the AER periodically sets the amount of revenue that can be recovered each year. The revenues are then recovered directly from consumers through the network tariff component of their bills.

For the study, a discounted cash flow analysis of the projected costs and benefits of a 2IC was conducted under different assumptions about future demand and supply conditions in the NEM. The test was adopted for the purpose of assessing whether an investment in a 2IC would be economically efficient and whether or not a 2IC could be shown to deliver market benefits in excess of its costs. While this approach is consistent with the RIT-T, the NPV analysis was confined to the market costs and benefits of the 2IC itself, and other credible options were not analysed. Thus, even if the market benefits of a 2IC exceeded its costs, it may still not pass the RIT-T if other options having higher net benefits were available.

An interconnector that has not passed the RIT-T may still be constructed if it was financially viable as a merchant asset. Merchant interconnectors earn revenue by trading in the spot markets of the NEM regions they connect. The objective is to maximise profits from arbitrage trading—that is, by buying energy in one region when prices are lower and selling it to the other region at a higher price.44,45

3.2 Study methodology As discussed above, to assess whether a 2IC would be feasible, it is necessary to understand the likely costs and benefits it would generate in the NEM under plausible assumptions about the future development of the NEM. It also requires an understanding of whether, and under what circumstances, investors would be prepared to invest in a 2IC. To gain an understanding of these issues, power system and market dispatch modelling and analysis was commissioned from AEMO and Ernst & Young (EY). The modelling reports are at Appendices C, D and E.

The modelling approaches used were based on a comparison of power system responses and market cost and benefit outcomes with and without a 2IC in operation. The sensitivity of modelling outcomes was assessed under different scenarios about future energy market conditions. Modelling scenarios were also developed to assess changes in power system and energy market responses to different combinations of Basslink and a 2IC operating as regulated or merchant assets.

To understand arrangements that might support the financing of a 2IC, expert analysis of possible commercial, financial and procurement approaches was also sought. The interconnector costs, revenues and benefits from the power system and market modelling formed a significant input into this analysis of the possible commercial operating models for the interconnector. The views of potential investors were also sought to inform the various potential commercial and financial models.

43 Credible options are defined in clause 5.6.5D of the NER as an option or group of options that address the identified need; is (or are) commercially and technically feasible; and can be implemented in sufficient time to meet the identified need.

44 AEMC 2014, Decision report: Last resort planning power—2014 review, p. 20.

45 For example, if a merchant interconnector was to buy one MWh for $50 in Tasmania and sell it for $80 in Victoria, the interconnector would receive a return of $30.


A flowchart summarising the approach of the study, including key inputs and modelling conducted, is at Figure 2.

Figure 2: Flowchart of study approach


The study’s preliminary report set out a number of questions on energy security, renewable development, and costs and benefits for consumers. These questions formed the basis of targeted consultation sessions with energy market bodies, consumer groups, industry representatives and government stakeholders between October and December 2016. The insights from stakeholders have been integral in the development of the study. A summary of these consultations is at Appendix B.

3.3 Tasmanian Government 2IC specification workThe Tasmanian Government, supported by Hydro Tasmania and TasNetworks, has developed specifications for a potential 2IC, and these have been incorporated into the study’s analytical framework.46 This included a preliminary specification of the preferred 2IC route, technical specifications and capital cost estimates.

A high-level assessment of NEM market benefits from a 2IC was conducted as part of the Tasmanian Government’s preliminary work. This analysis found that a scenario with significant excess Tasmanian generation capacity47 would be needed before net positive economic benefits would be generated in the NEM. Modelling for the study explored this scenario further.

The interconnector specifications developed for the Tasmanian Government are outlined in Table 1.

Table 1: Tasmanian Government specifications Details Parameters

Interconnector Tasmania location Smithton

Interconnector Victoria location Tyabb

Interconnector technology High-voltage direct current (HVDC) based on new voltage source converter technology, able to provide voltage control and continuous frequency control ancillary services.

Interconnector size (MW) 600 MW

Time to develop interconnector 8 years

Interconnector economic lifespan 40 years (noting that AEMO has used 50 years in its modelling).

Interconnector voltage +/− 320 kilovolt (KV)

Length of cable 293 km

HVDC costs $560 m

Associated Tasmanian and Victorian network augmentation costs

$237 m

Expected total project cost $888 m (this includes connection costs in both regions).

Min. capital cost $799 m

Max. capital cost $1110 m

Operational & maintenance costs $16.7 m per year

FOREX basis for costs €0.65

Associated network augmentations Would include augmentation to the 220 kV network in north-west Tasmania and some connection works in Victoria. Further augmentation costs might be incurred depending on the location of the additional generation and agreed connection points—these are likely to be separate from interconnector costs.

46 Prime Minister’s Office 2016, Feasibility study of second interconnector to focus on improving energy security and maximising Tasmania’s renewable energy resources, https://www.pm.gov.au/media/2016-04-28/feasibility-study-second-interconnector-focus-improving-energy-security-and (accessed 15 January 2017).

47 Excess generation equates to around 500 MW of continuously operating generation, which equates to 1200 MW of wind generation, assuming a 40 per cent capacity factor.

https://www.pm.gov.au/media/2016-04-28/feasibility-study-second-interconnector-focus-improving-energy-security-and


Figure 3 shows the route of a 2IC as proposed by the Tasmanian Government, as well as the Victorian and Tasmanian transmission networks at the landing points. Figure 4 shows the technical network configuration for the connection of a 2IC to the Victorian and Tasmanian transmission networks. More detailed technical studies would be needed following confirmation of the route and connection corridor if a 2IC were approved.

Figure 3: Proposed route of a 2IC, with Tasmanian and Victorian transmission networks48

48 Information provided by the Tasmanian Government. Figure based on AEMO 2017, Second Tasmanian interconnector, p. 13.


Figure 4: Proposed 2IC electrical connection and network configuration49

3.4 Interconnector cost assumptions As the basis of its cost assumptions in its modelling, EY adopted the interconnector capital expenditure figures that AEMO used in its 2016 National Transmission Network Development Plan (NTNDP) and the operating expenditure figures provided by the Tasmanian Government. These figures, adjusted to 2016 dollars, are shown in Table 2.

Table 2: Interconnector cost assumptions50

Capital expenditure Operating expenditure NPV with 7% discount rate NPV with 10% discount rate

$930 m in real June 2015 dollars

(adjusted to $940 m in real June 2016 dollars)

$16.7 m/year in real June 2015 dollars

(adjusted to $16.87 m/year in real June 2016 dollars)

$940 m + $224 m = $1164 m in real

June 2016 dollars

$940 m + $164 m = $1104 m in real

June 2016 dollars

These cost figures have been consistently applied across the modelling. They do not reflect the total costs of developing an interconnector, in that they do not include financing and project development costs. These costs are discussed in Chapter 6.

With regard to the discounting methodology applied to AEMO and EY’s modelling results, including interconnector costings, both sets of results are presented in 2016 dollars throughout the report. However, it should be noted that these numbers are discounted differently to reflect the different modelling time periods. AEMO discounted NPVs to 2016 in 2016 dollars, as this best suited the general purposes of the NTNDP. In contrast, EY discounted NPVs to 2026 valued in 2016 dollars because 2026 is the projected start date for a 2IC.

49 AEMO 2017, Second Tasmanian interconnector, p. 14.

50 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 14, and EY 2016, Financial and commercial analysis— Second Tasmanian interconnector, p. 14.


This difference in discounting approaches changed the total NPV values of the results. For example, a value discounted to 2016 is approximately 50 per cent of the value of the same figure discounted to 2026, where a 7 per cent discount rate (real, pre-tax) is applied. Similarly, if a 10 per cent discount rate is applied then a value discounted to 2016 is approximately 38 per cent of the value of the same figure discounted to 2026. The impact this had on EY’s modelling results is discussed in further detail in Section 3.7.

3.5 Modelling and technical analyses

3.5.1 AEMO modelling and associated technical analyses

AEMO publishes NTNDPs which provide an independent, strategic view of how the power system is projected to evolve over a 20 year horizon. AEMO makes these projections by modelling in detail how the power system might change in response to changes in supply and demand.

In its 2016 NTNDP, AEMO developed three possible future scenarios. These scenarios, at Table 3, were based on assumptions about potential changes in future economic conditions and patterns of energy supply and demand. They involve scenarios of neutral and weak economic growth, as well as different emission reduction targets to 2030.51

Table 3: AEMO modelling scenariosModelling scenario Description

NTNDP neutral scenario Assumes operational consumption52 changes in line with the 2016 National Electricity Forecasting Report (NEFR)53 neutral demand sensitivity.

NTNDP low grid demand scenario

Assumes technology cost reductions leading to greater growth of small distributed generation sources and energy efficiency uptake and corresponding low operational consumption growth, consistent with the weak demand sensitivity of the 2016 NEFR.

NTNDP 45 per cent emissions reduction scenario

Assesses the changes in the development of the electricity market should higher carbon abatement be targeted from the stationary energy sector (to reduce carbon emissions by 45 per cent below 2005 levels by 2030). Otherwise, consistent with the NTNDP neutral scenario.

In the 2016 NTNDP, AEMO developed a series of case studies to investigate the effects of upgrading or developing additional interconnector capacity across the NEM, including a 2IC between Tasmania and Victoria. AEMO’s case studies assessed the NEM-wide costs and benefits that would be generated with and without various interconnectors in operation under different scenarios for economic and market conditions and policy settings, consistent with the methodology required by the RIT-T.

The case studies are described in Table 4. For each, AEMO conducted:

• long-term least-cost expansion modelling showing the expected supply changes in response to each modelling scenario

• short-term time-sequential modelling to provide gross market benefits from the case studies associated with each modelling scenario (excluding competition benefits) as well as additional insights into changes to system operation with the 2IC and additional wind energy generation in place

• supporting technical analyses to determine any technical factors which might constrain or otherwise affect the modelling or subsequent cost and benefit assessment outcomes.

51 AEMO 2016, NTNDP, pp. 5−6.

52 Operational consumption refers to electricity used over a period of time that is supplied by the transmission grid. See AEMC 2015, Annual market performance review final report 2015, p. iii.

53 AEMO 2016, National electricity forecasting report, http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/2016-National-Electricity-Forecasting-Report-NEFR.pdf (accessed 15 January 2017).

http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/2016-National-Electricity-Forecasting-Report-NEFR.pdf

http://www.aemo.com.au/-/media/Files/Electricity/NEM/Planning_and_Forecasting/NEFR/2016/2016-National-Electricity-Forecasting-Report-NEFR.pdf


Table 4: AEMO case studiesCase study Description

Upgrade QNI and VNI interconnectors (‘Base Case’)54

Incremental augmentation to the existing QNI and VNI interconnectors.

2IC Introduction of a second TAS-VIC interconnector as well as the augmentations identified in the Base Case.

Additional South Australian interconnector55

Introduction of an additional South Australian interconnector as well as the augmentations identified in the Base Case.

Both 2IC and additional interconnection with South Australia

Introduction of both of the above proposed interconnectors as well as the augmentations identified in the Base Case.

2IC with 1200 MW additional Tasmanian wind generation

Introduction of a 2IC and concurrent build of 1200 MW of wind generation in Tasmania as well as the augmentations identified in the Base Case.

At the request of the taskforce, AEMO modelled an additional case study involving the concurrent development of a 2IC and 1200 MW of additional wind generation in Tasmania. This was to specifically assess the Tasmanian Government’s preliminary assessment that the case for a 2IC would be strengthened by the development of excess Tasmanian generation.

3.5.2 EY market dispatch modelling and cost−benefit analysis

EY was engaged to conduct market dispatch modelling and associated cost−benefit analysis to assess likely changes in the operation of the NEM due to the development of a 2IC. For various combinations of a 2IC and Basslink operating as regulated or merchant interconnectors, the modelling and analysis assessed:

• the likely market dispatch and bidding outcomes, including interconnector and generator revenues

• the total costs and benefits to the NEM and financial revenues and costs for potential project financiers (depending on whether 2IC and Basslink are operating as regulated or merchant interconnectors)

• the sensitivity of costs and benefits to changes in market conditions and emission reduction targets.

EY’s modelling covered the period from 2026 (the assumed commencement date for a 2IC) to 2065−66. Up to 2035−36, EY utilised in part AEMO’s modelling inputs for consistency with the NTNDP. EY’s modelling built upon AEMO’s modelling and extended the time horizon out to 2065−66 using half-hourly market simulations.

Scenario selection

The scenarios that EY modelled are summarised in Table 5. These scenarios involved comparing a base case56 with no 2IC in operation with scenarios that involved Basslink and a 2IC operating as either both regulated or both merchant assets.57

54 The Queensland to New South Wales interconnector (QNI) is a 330 kV alternating current (AC) interconnection between Dumaresq in New South Wales and Bulli Creek in Queensland. There is also a smaller regulated AC interconnector link between Terranora and Mudgeeraba, partly controlled by a direct current (DC) link, called Directlink in New South Wales. The VIC–NSW interconnector (VNI) consists of the 330 kv lines between Murray and Upper Tumut, Murray and Lower Tumut, Jindera and Wodonga, the 220 KV line between Buronga and Red Cliffs, and the 132 kV bus tie at Guthega.

55 South Australia has an AC interconnector between Victoria and South Australian (Heywood) and a direct current (DC) link between Red Cliffs in Victoria and Monash in South Australia.

56 EY’s market dispatch modelling scenarios are based on and extrapolate AEMO’s modelling scenarios for the NTNDP. They include AEMO’s base case assumptions of QNI and VNI upgrades.

57 Scenarios which assume the operation of Basslink as a regulated interconnector are purely hypothetical. Basslink is operated as a merchant interconnector under a facility fee arrangement which allows Hydro Tasmania to bid the interconnector’s capacity into the NEM. There is no suggestion that Basslink’s owner is contemplating its conversion to regulated status.


EY did not model other potential operating combinations, such as Basslink operating as a regulated interconnector while the 2IC operates as a merchant interconnector. This is because the modelling outcomes would be heavily influenced by the assumed operating relationship between Basslink and a 2IC, and there could be a number of variations on that relationship.

To understand how potential future market conditions could influence the NEM-wide costs and benefits from a 2IC, EY modelled the following scenarios:

• a 40 per cent reduction in Tasmanian electricity demand

• low Tasmanian rainfall

• an emission reduction target that is higher than the current target.

EY’s modelling of a merchant 2IC’s financial viability assessed the arbitrage revenues the 2IC could earn from spot market trading. EY also modelled the impact that a 2IC’s trading activities would have on the costs and revenues of other stakeholders, including Basslink, Hydro Tasmania and Tasmanian electricity consumers. Those outcomes from merchant 2IC trading were then compared to the distribution of revenues and costs that would be expected if a 2IC were operated as a regulated asset.

In modelling the potential arbitrage trading revenues of a merchant 2IC, EY made a number of simplifying assumptions, including that a 2IC and Basslink would adopt a cooperative revenue-maximising bidding strategy which would be accommodated by Hydro Tasmania and other market participants. It also assumed that bidding by a 2IC and Basslink would be restricted to $0/MWh on interconnector imports.58

The analysis of the viability of a merchant 2IC was concerned with the private revenues that an investor in the asset could earn from arbitrage trading and the resulting cash flows between it and other stakeholders. It is not directly comparable with the modelling of NEM-wide costs and benefits in order to test the economic viability of a regulated 2IC. Although NEM-wide market benefits may result from a merchant 2IC, those benefits would not be captured in arbitrage trading revenues and would not be relevant to an investor’s assessment of financial viability.

For its merchant interconnector analysis, EY added an alternative scenario assuming that the market in regions of the NEM other than Tasmania is consistently oversupplied with generation over the modelling period. It adopted this approach to test how robust merchant interconnector revenues are to wholesale market conditions in the rest of the NEM, noting historical trends which show that wholesale market prices have been consistently below the long-run marginal cost of new entrant generation in recent times.

EY’s scenarios are based on AEMO’s neutral scenario, extrapolated to 2065−66, except for the higher emission reduction scenarios, which are based on AEMO’s 45 per cent emissions reductions by 2030 scenario. For the alternative scenario, where the market is constantly oversupplied, EY added a consistent amount of open cycle gas turbine (OCGT) and combined cycle gas turbine (CCGT) generation to the base case scenario. EY assessed NPVs of market benefits and costs using both 7 and 10 per cent discount rates, in line with RIT-T cost and benefit analysis guidance published by Grid Australia59 and to match a 7 per cent discount rate used by AEMO in its 2016 NTNDP.

58 EY notes that modelling imports for a merchant 2IC is more problematic given the interaction with water plans and hydro limitations. EY found that large profits could be earned by a merchant 2IC by withdrawing import flow at times where resources in Tasmania were limited due to low storage levels and low wind generation. EY found that this was costly from the perspective of very high wholesale prices in Tasmania and difficulties in managing Hydro Tasmania’s water storages. Because of this, EY restricted the bidding of a 2IC on imports to $0/MWh.

59 Grid Australia 2011, RIT-T cost benefit analysis Grid Australia handbook, http://www.gridaustralia.com.au/index.php/docman-items/rit-t-cost-benefit-analysis-handbook/129-grid-australia-rit-t-cost-benefit-analysis-handbook-draft/file, (accessed 20 December 2016).

http://www.gridaustralia.com.au/index.php/docman-items/rit-t-cost-benefit-analysis-handbook/129-grid-australia-rit-t-cost-benefit-analysis-handbook-draft/file

http://www.gridaustralia.com.au/index.php/docman-items/rit-t-cost-benefit-analysis-handbook/129-grid-australia-rit-t-cost-benefit-analysis-handbook-draft/file


Table 5: EY modelling scenariosEY Scenario name Scenario description Modelling assumptions

Base case

Base case

Basslink only

2IC is not developed. Uses thermal retirements and renewables generation planting from AEMO, based on 28 per cent emissions reduction by 2030 on 2005 levels.

No 2IC, Basslink operating under current protocols (effectively as a regulated interconnector).

Regulated Basslink and 2IC operation

Basslink and 2IC operate as regulated interconnectors.

Uses renewables generation planting from Base Case Basslink Only scenario.

Uses thermal retirements from AEMO, 28 per cent emissions reduction by 2030.

2IC operational from 1 July 2026 as regulated 2IC.

Basslink and 2IC bid at $0 (regulated behaviour).

Merchant Basslink and 2IC operation

Basslink and 2IC operate as merchant interconnectors.

Uses same renewables and thermal generation planting as Regulated Basslink and 2IC operation scenario.

2IC operational from 1 July 2026 as a merchant 2IC. Basslink and 2IC bid at or above $0 to maximise combined profit in each period.

TasWind

TasWind Basslink only

1200 MW of wind is developed in Tasmania by 2026, 2IC is not developed.

Uses thermal retirements and renewables generation planting from AEMO, 28 per cent emissions reduction by 2030, 1200 MW of wind built in Tasmania in 2026.


TasWind regulated Basslink and 2IC operation

1200 MW of wind is developed in Tasmania by 2026, Basslink and 2IC operate as regulated interconnectors.

Uses thermal retirements and renewables generation planting from AEMO, 28 per cent emissions reduction by 2030, 1200 MW of wind built in Tasmania in 2026.

2IC operational from 1 July 2026 as regulated 2IC. Basslink and 2IC bid at $0 (regulated behaviour).

TasWind merchant 2IC and Basslink operation

1200 MW of wind is developed in Tasmania by 2026, Basslink and 2IC operate as merchant interconnectors.

Uses same generation planting as TasWind Regulated Basslink and 2IC Operation, with 2IC operational from 1 July 2026 as merchant 2IC.

Basslink and 2IC bid at or above $0 to maximise combined profit in each period.

TasDemand

TasDemand Basslink only

Loss of 40 per cent of Tasmanian electricity demand, 2IC is not developed.

Uses generation planting from Base Case Basslink Only—except no new Tasmanian wind after 2020.

Retires 40 per cent of Tasmanian demand uniformly throughout each study year.


TasDemand regulated Basslink and 2IC operation

Loss of 40 per cent of Tasmanian electricity demand, Basslink and 2IC operate as regulated interconnectors.

Uses generation planting from Basslink Only—except no new Tasmanian wind after 2020.


2IC operational from 1 July 2026 as a regulated 2IC. Basslink and 2IC bid at $0 (regulated behaviour).


EY Scenario name Scenario description Modelling assumptions

Reduction in Tasmanian demand—merchant Basslink and 2IC operation

Loss of 40 per cent of Tasmanian electricity demand, Basslink and 2IC operate as merchant interconnectors.

Uses same generation planting as the TasDemand Regulated Basslink and 2IC Operation.


2IC operational from 1 July 2026 as merchant 2IC. Basslink and 2IC bid above $0 to maximise combined profit in each period.

LowRain

LowRain— Base case

Long-term decline in rainfall in Tasmania, 2IC is not developed.

Uses renewable and thermal development plan from Base Case Basslink Only.

High probability of dry years, lower probability of wet years.


LowRain Regulated Basslink and 2IC operation

Long-term decline in rainfall in Tasmania, Basslink and 2IC operate as regulated interconnectors.

Uses renewable and thermal development plan from Base Case Basslink Only.


2IC operational from 1 July 2026 as regulated 2IC. Basslink and 2IC bid at $0 (regulated behaviour).

LowRain—merchant Basslink and 2IC operation

Long-term decline in rainfall in Tasmania, Basslink and 2IC operate as merchant interconnectors.

Uses same generation planting as Low Rain Regulated Basslink and 2IC Operation.


2IC operational from 1 July 2026 as merchant 2IC. Basslink and 2IC bid above $0 to maximise combined profit in each period.

StrongAction

StrongAction—Base case

45 per cent by 2030 national emissions reduction target, 2IC is not developed.

Uses thermal retirements and renewables planting from AEMO, 45 per cent emissions reduction by 2030.


StrongAction— regulated Basslink and 2IC operation

45 per cent by 2030 national emissions reduction target, Basslink and 2IC operate as regulated interconnectors.

Uses thermal retirements and renewables planting from AEMO, 45 per cent emissions reduction by 2030

2IC operational from 1 July 2026. Basslink and 2IC bid at $0 (regulated behaviour).

3.6 Commercial and financial adviceSeparate from the market modelling, EY also provided analysis and advice on the financial and business models that could support a 2IC’s operation. The financial assessment is not aimed at determining whether a 2IC is economically efficient; instead, it tests whether, and under what market conditions and business models, a regulated 2IC or merchant 2IC would be financeable.

EY also completed market soundings with potential investors of varying sizes and with different interests in funding a 2IC.

EY’s approach and advice on commercial and financial structures is examined in Chapter 6.


3.7 Differences between AEMO and EY’s modelling approachesAEMO’s modelling provides general information that NEM participants use for a variety of purposes. It has a broad focus—it identifies likely power system changes and emerging network constraints; and highlights options that might address these constraints over a 20 year forward outlook. EY’s modelling was commissioned specifically for the study and has considered more detailed scenarios and regulatory arrangements than those modelled by AEMO.

EY’s modelling built on AEMO’s work and its technical specifications of the power system and the interconnected network of the NEM. However, there are some differences between the two modelling approaches which mean that they are often not readily comparable. The main differences are outlined in Table 6.

Table 6: Key differences between AEMO and EY modellingAEMO EY

AEMO’s modelling period is from 2016−17 to 2035−36. EY’s modelling period is from 2026−27 to 2065−66 in order to consider the costs and benefits of the 2IC over a modelled 40 year economic life.

AEMO’s modelling assumed that generators are dispatched according to their short-run marginal costs.

EY assumed that generators will make strategic spot market bids which seek to maximise their revenues while having regard to the market positions and bidding strategies of other generators.

AEMO incorporated detailed assessment of the capabilities of the transmission network throughout the planning horizon, including the impacts of an evolving NEM supply and demand.

EY’s market modelling simplifies these complex network capabilities to a subset of transmission limitations impacting on interconnector flows. Therefore, it may provide material differences in the benefits (or lack of benefits) of interconnectors.

AEMO modelled a low grid demand scenario in which demand gradually declines across the entire NEM (including Tasmania).

EY modelled the impact of an immediate and significant reduction in Tasmanian demand.

AEMO identified and valued potential ‘resilience benefits’ from interconnector investments in the NEM (which give a value to the capacity to respond to low-probability, high-impact events such as the recent Basslink outage).

EY did not consider resilience benefits as they have not traditionally been included in RIT-T analysis.

AEMO has modelled the Tasmanian hydro generation as a 6-pond model with individual hydro generators linked to one of the six geographically grouped storages. The storage energy available to the units are updated with publicly available data at the time of commencing NTNDP modelling. Energy inflow data for each Tasmanian hydro water storage is determined from long-term historical yield information.

In consultation with Hydro Tasmania, EY developed detailed modelling of the operation of its hydro generation assets, recognising that the flexibility of these assets has a large bearing on the operation of a 2IC and Basslink.

EY’s modelling assessed the sensitivity of a 2IC’s viability to different regulatory arrangements, including operation of a 2IC and Basslink as either regulated or merchant assets.

AEMO and EY modelled, in a time sequential manner, the dispatch of the NEM, including the inherent volatility of intermittent renewable generators. However, the timing of the renewable resources across the NEM may differ between models, particularly with regard to the contribution of renewable generators to meeting peak demand conditions. This potential difference may impact on the value that wind generation in particular provides in deferring capital investment in peaking thermal generation.


A key reason that EY’s 2IC results differ from AEMO’s is that they have been discounted to 2026, rather than to 2016, as discussed in Section 3.4. Also, AEMO discounted only 11 years of annualised cost because of its shorter analysis period, whereas EY discounted the costs over its 40 year analysis period. EY noted that discounting to 2016, while changing the magnitude of the benefits to costs, maintains the same ratio between benefits and costs. An example is shown in Table 7.

Table 7: Base case regulated interconnector outcomes (NPV)—impact of discounting60

7% discount rate—discounted to 2026




Market benefits $809 m $411 m $634 m $245 m

Interconnector costs −$1164 m −$592 m −$1104 m −$426 m

Net benefit −$356 m −$181 m −$470 m −$181 m

Ratio of benefit to cost 69% 69% 57% 57%

60 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 22 (Table 11).


4 Results of modelling and analysisThis chapter presents the results and key findings of the modelling that AEMO and EY developed to support the study, other than EY’s financial and commercial analysis, which is discussed in Chapter 6. AEMO’s modelling report is at Appendix C. EY’s market dispatch modelling report is at Appendix D.

KEY FINDINGS

• Modelling and analysis by AEMO and EY identified two future NEM development scenarios where a 2IC would produce significantly positive net market benefits. They were where:

– an additional South Australian interconnector is built before a 2IC comes into operation

– there is a significant reduction in future Tasmanian electricity demand.

• AEMO’s results indicated that a 2IC could produce marginally positive net benefits under its neutral economic growth scenario, but it would produce negative net benefits under its other scenarios.

• EY’s modelling indicated that a regulated 2IC would not generate positive net market benefits in the scenarios it modelled other than under an assumption of significant reduction in Tasmanian electricity demand.

• Both modelling results identified that the principal source of NEM-wide benefit from a 2IC would be the deferral of higher-cost generation investment and variable cost savings from more flexible and efficient use of Tasmania’s hydro generation.

• AEMO’s results also showed that market benefits from a 2IC would improve and result in positive net market benefits under most scenarios if other interconnections were implemented across the NEM as well as a 2IC.

• EY’s scenario modelling demonstrated that the market benefits generated by a 2IC were sensitive to modelling assumptions about future supply and demand conditions. For example, lower than expected Tasmanian rainfall or a higher emissions reduction target would reduce the modelled benefits.

• EY’s modelling indicated potential for higher revenues from a merchant rather than a regulated 2IC, but the merchant revenues would also be highly volatile and risky. A regulated 2IC’s revenues would be more predictable and lower risk, which would be attractive for financiers. However, satisfying the RIT-T would be difficult on the basis of the market modelling projections.

21Results of modelling and analysis

4.1 AEMO modelling findingsAEMO assessed the costs and market benefits of a 2IC through to 2036 as described in Chapter 3. AEMO’s key insights from its modelling and analysis are presented in Box 1.

BOX 1: AEMO’s key modelling findings61

Assuming neutral economic growth, a 2IC is projected to deliver gross market benefits of $361 million over the next 20 years to 2035−36 by:

• delivering $85 million savings in fuel and variable operating and maintenance costs due to hydro and wind generation in Tasmania primarily displacing higher-cost gas generation in the rest of the NEM

• facilitating the gradual development of additional renewable generation in Tasmania (mainly wind) to support supply changes in the NEM, resulting in $6 million in market benefits due to reduced environmental scheme costs

• deferring the need for gas generation investments in the NEM, producing $134 million in market benefits

• reducing reliance on voluntary demand curtailment and involuntary load shedding, producing $87 million in market benefits

• delivering $48 million in market benefits (including reliability benefits) if Basslink was out of service for an entire year, discounted for the low probability of this high-impact event.

Over the same period, the annualised cost of the 2IC is estimated to be around $341 million.62 As the resulting net market benefits under the neutral demand scenario were just $20 million, further analysis would be required to justify investment in the long-term interests of electricity consumers.

Greater interconnection would deliver significant synergies. Net market benefits of a 2IC would increase if an additional South Australian interconnector were built first. This would mainly be because the development of more interconnection would more effectively utilise the diversity of renewable generation across the regions. The need for higher-cost gas generation would be reduced by allowing renewable generation in one region to complement the intermittency of renewable generation in another.

The net market benefits of a 2IC would be negative under the low grid demand and higher emissions reductions scenarios. The 2IC would only be economically justified in scenarios where it would deliver capital deferral benefits63 in addition to fuel cost savings. If future operational demand were low, or emerging technologies such as utility-scale batteries became widespread, the ability for the 2IC to defer new generation build would diminish.

Building additional renewable generation in Tasmania may lead to oversupply. Building new renewable generation in Tasmania (1200 MW of wind), timed to coincide with commissioning of the 2IC, would not increase projected market benefits. New renewable generation is projected to be developed in Victoria to meet the proposed Victorian Renewable Energy Target (VRET). In that case any additional generation from Tasmania would lead to oversupply in the southern regions (Victoria, Tasmania and South Australia). This would either drive further generation withdrawals or require stronger interconnection between Victoria and New South Wales.

While a 2IC may provide additional power system security services such as FCAS, AEMO noted that these support services are adequately provided by existing generators in Tasmania and Victoria.

61 AEMO 2017, Second Tasmanian interconnector, pp. 1−2.

62 Total cost is estimated to be about $940 million, with an economic life of 50 years and weighted average cost of capital of 8.76 per cent. Assuming a 7 per cent social discount rate, the $341 million cost represents the net present value (NPV) of annualised costs for the period to 2035−36, with the interconnector operational from July 2025.

63 Capital deferral benefits are the benefits to the NEM from delaying or avoiding the costs of building additional infrastructure (either network or non-network infrastructure) to ensure supply efficiently meets demand.


4.2 AEMO’s analysis of market benefits resulting from a 2ICAs noted in Chapter 3, AEMO has modelled the market benefits and costs of a 2IC under its Base Case scenario for its 2016 NTNDP, which included anticipated upgrades of interconnection between Queensland and New South Wales (QNI) and between Victoria and New South Wales (VNI).

These projections indicate that a 2IC would deliver incremental net market benefits beyond those benefits delivered in AEMO’s Base Case of $20 million per year under a neutral economic growth scenario.64 There was an incremental net benefit of negative $147 million for the low grid demand scenario and negative $57 million for the 45 per cent emissions reduction scenario.65 This suggests the net market benefits from a 2IC would be marginal under the neutral economic outlook scenario and negative under other plausible scenarios of future NEM development modelled by AEMO.

AEMO’s modelling found that a significant portion of the projected benefits of a 2IC would be from the more efficient use of existing generation assets in Tasmania, because the additional transfer capacity that a 2IC would provide would allow Hydro Tasmania’s facilities to generate more during periods of highest value and to import energy during periods of lowest value. This would result in both dispatch efficiency benefits when hydro generation replaces dispatch of more costly OCGT generation in Victoria; and capital cost reductions in the NEM due to deferral of investment in costly peaking gas generation.66 A 2IC would provide marginally positive net market benefits only in scenarios where these significant capital deferral and fuel cost savings are both realised. A 2IC’s ability to defer new generation build in the NEM would be diminished in scenarios where operational demand growth is low (as in the low grid demand scenario) or where emerging technologies such as utility-scale battery storage reduce the requirement for new gas generation (as in the 45 per cent emission reduction by 2030 scenario).

4.2.1 Synergies of a more interconnected NEM

AEMO modelled the market benefits resulting from new interconnection across the NEM, including between South Australia and Victoria or New South Wales, and assessed the impact this could have on net benefits generated by a 2IC.

The net benefits from interconnector investment across the NEM compound when other interconnection investment occurs. This is mainly because renewable generation would be able to flow across regions more effectively, smoothing patterns of intermittency and reducing the need for higher marginal cost generation such as gas generation.67 This is illustrated in Table 8, which highlights the net benefits of different interconnection scenarios under the neutral economic growth, low grid demand and 45 per cent emissions reduction scenarios.

Under AEMO’s neutral economic growth scenario, a new interconnector between South Australia and Victoria would produce incremental net market benefits of $136 million, compared to net benefits of $20 million for the 2IC between Tasmania and Victoria. However, the combined net benefits increase to $179 million if both interconnectors are modelled together.

64 Incremental benefits are those benefits which a 2IC would provide above or below the benefits modelled by AEMO in its base case scenario, which includes developing other interconnector upgrades between Queensland, News South Wales and Victoria.

65 AEMO 2017, Second Tasmanian interconnector, pp. 37, 42, 44.

66 AEMO 2017, Second Tasmanian interconnector, pp. 36, 40−41.

67 AEMO 2016, NTNDP, p. 33.


In practice, however, each incremental interconnection investment would need to undergo a full RIT-T assessment before those investments could proceed. Recognising that these are long-term investments with asset lives stretching to the 2050s and 2060s and beyond, AEMO emphasised that its post-2030 benefits assessments are subject to high levels of uncertainty. If the NEM evolves in a way that reduces the role of the inter-regional trade facilitated by interconnectors, these projected incremental benefits could be reduced or eliminated.

Table 8: Net benefits of various interconnection options under different AEMO case studies

Case study

NPV of gross market benefits

to 2035−36

NPV of annualised cost

to 2035−36

Overall net benefit of the

case study

Incremental net benefit above

base case

Neutral economic growth scenario68

2IC + QNI + VNI $531 m $387 m $143 m $20 m

New SA Link + QNI + VNI $595 m $335 m $260 m $136 m

New SA Link + 2IC+ QNI + VNI $978 m $676 m $302 m $179 m

Low grid demand scenario69

2IC + QNI + VNI $357 m $418 m −$61 m −$147 m


New SA Link + 2IC+ QNI + VNI $758 m $707 m $51 m −$35 m

45 per cent carbon target scenario70

2IC + QNI + VNI $611 m $387 m $224 m −$57 m


New SA Link + 2IC+ QNI + VNI $1354 m $676 m $678 m $397 m

68 Adapted from AEMO 2017, Second Tasmanian interconnector, p. 37 (Table 8).




4.3 EY market dispatch modelling results As noted in Chapter 3, EY modelled changes to NEM-wide costs and benefits resulting from the operation of a 2IC under both regulated and merchant scenarios. It also modelled the private costs and revenues associated with operating a merchant 2IC to test its financial viability as an unregulated asset.71

4.3.1 EY regulated 2IC modelling findings

Key insights from EY’s modelling of a 2IC as a regulated interconnector are stated in Box 2.

BOX 2: EY’s key modelling findings—regulated 2IC72

• A 2IC is unlikely to generate market benefits that exceed its cost, except in a scenario with reduced Tasmanian electricity demand.

• There are two key sources of market benefits from a 2IC (in scenarios other than the Tasmanian demand reduction scenario) where the primary source of benefits is from the improved utilisation of surplus Tasmanian generation:

– A 2IC would defer between 450 MW and 600 MW of thermal generation in the NEM which would otherwise be required to maintain reliability in Victoria once brown coal generation is retired. This capacity deferral does not occur until the early 2030s, meaning that the benefits of reduced capital investment would be discounted significantly.

– A 2IC would also facilitate variable cost savings primarily due to more efficient use of water storages and generation facilities to increase export to Victoria during periods where higher-cost generation would otherwise be required. There would also be some benefit from improved utilisation of other lower-cost Tasmanian generation assets, including the TVPS.

• Although a 2IC would facilitate additional wind generation investment in Tasmania, the market benefits from this investment would be relatively minor.

• Higher rainfall in Tasmania would increase the volume of Tasmanian surplus energy available for export. This would increase the potential for variable cost savings in the NEM. The opposite outcome would be expected in periods of low rainfall and water storage levels.

• The modelling of a higher emissions reduction target scenario showed a reduction in benefit from a 2IC because earlier brown coal retirements are replaced by earlier battery storage development, reducing the benefit from more flexible use of Tasmanian water storage and generation facilities.

71 This finding assumes that the VRET is implemented in full. Different market outcomes could arise under different assumptions of Victorian renewable energy growth.

72 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, pp. 2−3.


The results of EY’s modelling are shown in the tables below. Table 9 shows the gross market benefits from a 2IC for 7 and 10 per cent discount rates. Table 10 presents the interconnector cost assumptions.73 Table 11 shows the overall net market benefits once costs have been considered.

Table 9: Gross market benefits from a 2IC for EY modelling scenarios74 Scenario description 7% discount rate 10% discount rate

Regulated 2IC development $809 m $634 m

Fixed 1200 MW of new wind capacity in Tasmania by 2026 $522 m $257 m

40% reduction in Tasmanian demand $2017 m $1528 m

Lower average rainfall in Tasmania $647 m $379 m

45% emissions reduction by 2030 $833 m $592 m

Table 10: Interconnector cost assumptions75

7% discount rate 10% discount rate

Capital cost $940 m $940 m

Operating and maintenance $224 m $164 m

Total cost $1164 m $1104 m

Table 11: Net market benefits from a 2IC for EY modelling scenarios76

Scenario description 7% discount rate 10% discount rate

Regulated 2IC development −$356 m −$470 m

Fixed 1200 MW of new wind capacity in Tasmania by 2026 −$642 m −$848 m

40% reduction in Tasmanian demand $853 m $424 m

Lower average rainfall in Tasmania −$518 m −$725 m

45% emissions reduction by 2030 −$331 m −$512 m

Table 11 indicates that the market benefits of a 2IC would be outweighed by its costs for all scenarios other than the scenario with reduction of Tasmanian demand. That scenario would produce positive net market benefits because a 2IC would enable the resulting surplus energy to be exported. This would avoid spillage of water from Hydro Tasmania’s storages that could otherwise occur without a 2IC, particularly in high rainfall years.

Table 11 also shows that the net market benefits that a 2IC provides are sensitive to plausible market and environmental assumptions. For example, the scenarios that assume lower than expected Tasmanian rainfall or a higher emission reduction target would both reduce the benefits from a 2IC.

Consistent with AEMO’s analysis, EY ‘s modelling found that the primary source of market benefits from a 2IC would be from more efficient use of existing generation assets in Tasmania, which would lead to both variable cost reductions and benefits from capital cost deferrals.

73 The results for the Fixed 1200 MW of new wind capacity in Tasmania by 2026 scenario presented in Tables 9 and 11 compare the market benefits of developing a 2IC and 1200 MW of wind against a counterfactual of no wind and no 2IC development (rather than a counterfactual of 1200 MW wind and no 2IC development). This is based on EY’s view that it is unrealistic to assume that 1200 MW of wind would be built in Tasmania without a 2IC. In practice, the market benefits from a 2IC would be higher if there is additional wind development in Tasmania. AEMO modelling projects that up to 730 MW of wind could be built without a 2IC.

74 Derived from EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, pp. 29 and 40 (Tables 20 and 35, NPV in June 2016 dollars).

75 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 2 (Table 2, NPV). As explained in Section 3.4, EY’s 2IC cost assumptions differ from those used by AEMO, as they have been discounted on a different basis.

76 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 2 (Table 1, NPV in June 2016 dollars).


This is illustrated in Figure 5, which presents a comparison of flows between Tasmania and Victoria with and without a 2IC in an example year (2027−28), assuming higher Tasmanian wind generation. Combined Basslink and 2IC flows are shown in blue, while operation of Basslink alone is shown in purple. The shaded area between the two lines represents additional value that would be gained from the extra transfer capacity a 2IC would offer, beyond that of Basslink.

Figure 5: Comparison of VIC–TAS electricity flows with and without a (regulated) 2IC for 2027–2877

The additional export energy that the development of a 2IC could facilitate in 2027–28 is 1400 GWh.78 The difference of flow from +500 MW to +1200 MW shows that there are likely to be periods where the 2IC is capable of extracting additional value through increased Tasmanian hydro generation exports. EY estimated that the improved use of Tasmanian generation exports, facilitated by a 2IC, could lead to capital cost savings of $286 million because of the deferral of 450 MW of additional investment in new OCGT capacity in Victoria.79

Sensitivity of market benefits to the operation of the Tamar Valley Power Station

EY’s modelling also showed that market benefits from a 2IC would be enhanced by continued operation of the TVPS.80 That was because TVPS is a lower-cost CCGT than the OCGT peaking plants that would otherwise be required, and its availability could reduce the variable costs of dispatch and so increase market benefits. EY’s modelling found that TVPS could operate to increase exports to the rest of the NEM, offering an additional 200 MW of Tasmanian generation capacity for export. EY found that, as a CCGT, TVPS would be more efficient and therefore less costly to operate than much of the gas generation in the rest of the NEM. Running TVPS could therefore reduce variable costs, which would increase market benefits.81

77 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 20 (Figure 3).

78 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 20.





EY’s modelling shows that the market benefits of a 2IC would improve by around $200 million if TVPS were operational in Tasmania. Of these benefits, around $100 million would be from variable cost savings and around $100 million would be from capital cost deferrals from the construction of OCGT generation in Victoria.82

Tasmanian wind resources

EY’s modelling indicated that 1100 MW of additional wind generation (above the existing level) could be accommodated in Tasmania.83 However, although a 2IC would facilitate additional wind generation investment in Tasmania, the market benefits from this investment would be relatively minor. Wind resources in Tasmania are abundant and of high quality. However, the benefits of developing these resources would be limited because of:

• transmission losses in exporting wind generation from Tasmania at exports above the current export capacity of Basslink

• high levels of wind generation in Tasmania, which would interact with the ability of the hydro generators to manage run-of-river water inflows and storage levels and may limit their ability to cost-effectively use hydro resources

• export of Tasmanian wind to Victoria, which would already have significant wind generation due to the impact of the VRET.84

Other market benefits and costs not captured in EY’s modelling

EY noted that there are several sources of additional benefits and costs that may result from a 2IC that have not been captured in the market benefits presented in its report.85 These additional sources of benefits would be assessed and valued (at least qualitatively) in a full RIT-T analysis and could improve a 2IC feasibility assessment under different future states of NEM development.

These potential benefits and costs include:

• the value of a 2IC as part of a more interconnected transmission network across the NEM—EY’s modelling included the capital and operating costs of a 2IC and the direct costs of connecting a 2IC to the existing transmission network. EY modelling of market benefits did not extend to possible compounding benefits from a 2IC investment arising from prior sequential investments in other interconnection assets, although its analysis assumes augmentation of QNI and VNI. EY did not consider the impact of additional renewable generation development on transmission development and connection costs.

• avoidance of the need for more conservative operation of Tasmania’s hydro generation facilities—in the absence of a 2IC, it may be necessary to operate Hydro Tasmania’s water storages and generation facilities more conservatively to mitigate the reliability risk from periods of low rainfall, insufficient wind or gas generation availability and failure of Basslink. While this would help to insure against reliability shortfalls, there would be a cost in terms of reduced trading revenue and less efficient utilisation of the Tasmania’s dispatchable renewable energy resources. That cost could be avoided with a 2IC in operation and could be viewed as a market benefit arising from a 2IC.

• any escalation in costs would reduce the net market benefit case—EY used the cost estimate for a 2IC provided by the Tasmanian Government for its net benefit modelling. However, there is a material risk that the capital and environmental approval-related costs would escalate during the development process. This is demonstrated by the experience of Basslink, where costs increased by almost $375 million by commencement of operations (this is discussed further in Chapter 9).86





86 Electricity Supply Industry Expert Panel 2011, Basslink: Decision making, expectations and outcomes, p. 5.


• energy reliability and ancillary services—a 2IC would provide benefits due to increased energy reliability (in case of future Basslink outages) and through provision of another source of ancillary services to the market. Energy reliability and ancillary services are discussed in greater detail, alongside discussion of other costs and benefits that have not been quantitatively modelled by EY and AEMO, at Section 5.2.

4.3.2 EY merchant 2IC modelling findings

The key findings of EY’s modelling of a 2IC and Basslink operating as merchant interconnectors are stated in Box 3.

BOX 3: EY’s key modelling findings—merchant 2IC87

• EY’s modelling showed the potential for a merchant 2IC to earn high arbitrage trading revenues, which were projected to exceed its capital and operating costs. However, these revenues would also be volatile and risky. This would have adverse implications for financeability. EY’s modelling results were heavily dependent on the assumptions chosen, including the assumed bidding behaviour of the interconnectors and Hydro Tasmania.

• A merchant 2IC model would generate lower NEM-wide market benefits than the regulated 2IC. This is due in large part to a capacity-withholding strategy assumed to be used to maximise arbitrage trading revenues.

• The modelling showed that a regulated 2IC would have lower revenues than a merchant 2IC, but they would be more predictable and lower risk.

• If a 2IC was a merchant asset, Tasmanian spot prices would tend to remain below Victorian spot prices, with much of the difference being captured in arbitrage trading revenues. For a regulated 2IC, spot prices in the two regions would tend to converge.

• In the merchant asset case Tasmanian wholesale energy costs would tend to be lower than in the regulated 2IC case, and Hydro Tasmania’s revenues would tend to be lower.

• However, the allocation of revenues and costs between these stakeholders in the merchant 2IC case is heavily dependent on the assumed bidding behaviour of the interconnectors and Hydro Tasmania. Different allocations of revenues would result from different behavioural assumptions.

As described previously, a merchant 2IC would earn revenues from the arbitrage opportunities between the spot prices in Victoria and Tasmania. That means, the greater this spot price differential, the greater the revenues. EY found that a merchant 2IC would act to preserve this spot price differential to the extent possible, even if it meant withholding flow on the interconnector.

Victorian spot prices are generally higher than those in Tasmania. Therefore, a merchant 2IC would mostly cause power to flow north, buying power in Tasmania and selling it in Victoria. This was the driver for many of EY’s findings. A merchant 2IC would earn greater revenues whenever the Victorian spot prices were higher and the Tasmanian spot prices were lower; and it would earn lower revenues where spot prices in the two regions converge.

As the revenues of a merchant 2IC would depend on the spot price outcomes in Tasmania and Victoria, these projected revenues are highly dependent on the assumptions EY made about market conditions and the behaviour of the interconnectors and Hydro Tasmania. EY’s analysis is based on the following assumptions:

• Hydro Tasmania would bid its generation into the spot market at the water value in Tasmania.88 On this assumption, Hydro Tasmania would be restricted from using any market power. If Hydro Tasmania were




to bid strategically by reference to the spot price differential to Victoria, it could appropriate the spot price differential for itself and significantly reduce 2IC’s revenues.89 While this assumption was necessary to simplify the modelling, it is not clear that it would be accurate in practice.

• A 2IC would be operated independently of Hydro Tasmania. This impacts on a 2IC’s modelled bidding behaviour.90 An independent 2IC would operate to preserve the spot price differential between Victoria and Tasmania. If a 2IC were instead to be operated by Hydro Tasmania, in most cases it would earn higher revenues across its whole portfolio by bidding the 2IC at or close to $0/MWh, increasing the flow on the interconnector and bringing the Tasmanian spot price closer to the (higher) Victorian price.91 Hydro Tasmania could then bid its generation in Tasmania at higher prices. However, there would be limited periods in which a combined Hydro Tasmania, Basslink and 2IC portfolio would benefit from bidding both interconnectors at higher prices to achieve higher revenues at reduced export volumes to the rest of the NEM.

• A 2IC and Basslink would not compete with each other.92 If they did compete, the revenues of each could be reduced.

• A 2IC would be restricted to bidding its capacity at $0/MWh when power is flowing south, meaning it would be prevented from earning revenue when Tasmania is importing. EY noted that a 2IC could make large profits at times of shortages of supply in Tasmania (by restricting southward power flows). To simplify the modelling, it assumed a 2IC would be prevented from bidding strategically on import flows.

Modelling outcomes

Tables 12 and 13 show revenues that a 2IC and Basslink would earn for the merchant interconnector scenarios modelled by EY, assuming 7 and 10 per cent discount rates. To test how robust merchant interconnector revenues would be to oversupplied wholesale market conditions in non-Tasmanian NEM regions, EY also completed an additional sensitivity scenario (shown as ‘Non-Tasmanian generation oversupply’).

Table 12: Merchant interconnector revenue—7% discount rate93

2IC Basslink Total

Merchant 2IC development $2110 m $772 m $2881 m

1200 MW of new wind capacity in Tasmania by 2026 $2244 m $848 m $3092 m

40% reduction in Tasmanian demand $4869 m $2579 m $7448 m

Lower average rainfall in Tasmania $2014 m $705 m $2720 m

Non-Tasmanian generation oversupply $1357 m $420 m $1776 m

Table 13: Merchant interconnector revenue—10% discount rate94

2IC Basslink Total

Merchant 2IC development $1481 m $549 m $2030 m

1200 MW of new wind capacity in Tasmania by 2026 $1591 m $609 m $2200 m

40% reduction in Tasmanian demand $3453 m $1844 m $5297 m

Lower average rainfall in Tasmania $1409 m $502 m $1911 m

Non-Tasmanian generation oversupply $966 m $304 m $1270 m

89 A numerical example of how this could occur is given in Box 7 in Chapter 6.

90 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p.4.






Analysis of merchant 2IC modelling outcomes

The results of Tables 12 and 13 show that, under the simplifying assumptions made by EY, the total revenue of the two merchant interconnectors would be considerable, and would exceed the cost of a 2IC in most scenarios.95

EY found that the merchant interconnectors would achieve these revenues by withholding capacity on the interconnectors during periods of export from Tasmania when Victorian demand and prices were high.96 By limiting the quantity of Tasmanian generation flowing to Victoria, upward pressure would be placed on the Victorian spot price as the ‘missing’ power in Victoria is replaced by higher-cost (usually gas) generation from the rest of the NEM. At the same time, reducing hydro exports would build water storage levels in Tasmania, and this would lower the value of its stored water over time. The net result would be to lower Tasmanian wholesale electricity market prices and to raise Victorian wholesale prices—the difference would be captured in arbitrage trading revenues that the interconnectors earned. This would not be the case if Hydro Tasmania was the operator of the 2IC and bid its capacity on the basis of the assumptions outlined previously.

EY did not consider arbitrage trading revenues from bidding by the interconnectors during periods of imports from Victoria to Tasmania in its findings because of its simplifying modelling assumptions. If the interconnectors were to bid on imports into Tasmania during low Victorian pool price periods, this would in practice raise the regional spot price differential and result in additional revenues to a 2IC and to Basslink, particularly during periods where Tasmanian hydro resources are low.

EY found that high levels of wind in Tasmania would act to increase merchant 2IC revenue, as wind would be expected to bid at low prices.97 If Tasmanian wind generation were added, it would further reduce wholesale prices in Tasmania and increase the price differential between Tasmania and Victoria, particularly in trading intervals of high Tasmanian wind production.98 However, this finding did not take into account whether the Tasmanian wind generation would be profitable in this scenario.

Similarly, loss of demand in Tasmania would result in an oversupply of generation.99 This would have a large impact in that it would reduce the spot price in Tasmania and increase the spot price differential with Victoria. This is the scenario in which a merchant 2IC’s revenues would be highest. Alternatively, an oversupply of generation in Victoria would lower spot prices in Victoria and bring them closer to those in Tasmania. This would reduce the differential and therefore reduce the 2IC’s revenues.

Lower rainfall in Tasmania would also reduce the amount of water in hydro storages and increase water values.100 Under EY’s assumption that Hydro Tasmania continued bidding at its opportunity cost of water, its bids would increase and the spot price in Tasmania would rise, converging towards the Victoria spot price and lowering the 2IC’s revenues.

The overall purpose of this analysis was not to predict the price and revenue outcomes for a merchant 2IC that are likely under different scenarios. Rather, it was to illustrate how sensitive those price and revenue outcomes are to changing wholesale market conditions, especially in Victoria, and to the bidding strategies of other market participants, particularly Hydro Tasmania. The scenario where there is an oversupply of generation in Victoria and the 2IC’s revenues are much lower highlights this point.

EY commented that, while market modelling appeared to forecast scenario outcomes with perfect foresight, recent history has shown that the drivers of wholesale market outcomes can be hard to predict.101 The modelling results emphasised that, while the revenues of a merchant 2IC are potentially higher than the 2IC’s costs, those









revenues are also inherently volatile and risky. This uncertainty has a large impact on the financeability of a merchant 2IC, as discussed in Chapter 6.

Impact on market benefits of a merchant 2IC

EY modelled the NEM-wide market benefits that would be provided by a merchant 2IC compared to a regulated 2IC. EY found that a merchant 2IC would generate much lower market benefits than a regulated 2IC. For example, for a 7 per cent discount rate, a regulated 2IC would have market benefits of $809 million. This would be reduced to $183 million if the 2IC was operated on a merchant basis.102 This is due to the expected bidding strategy of a merchant 2IC. EY found that a merchant 2IC would withhold flows from Tasmania to Victoria on numerous trading intervals, increasing revenue through widening the spot price differential.103 This would reduce NEM-wide market benefits below their potential due to the impact of the merchant bidding behaviour on the ability of Tasmania’s hydro generation and storage facilities to be utilised to displace higher cost generation in the rest of the NEM.

4.3.4 Financial impacts of a 2IC on Tasmanian energy market participants

EY also modelled revenue outcomes for participants in the Tasmanian electricity market for different commercial models.104

EY found that when both interconnectors were operated as merchant interconnectors, they could earn substantial revenues from spot market trading, with relatively minor impacts on the cash flows of Hydro Tasmania and Tasmanian consumers.105 In contrast, if both interconnectors were regulated, Hydro Tasmania would earn large net wholesale market revenues. However, this would partly be offset by the increase in costs to Tasmanian consumers.106

These results reflect the different bidding strategies that would be likely in each case. In the case of merchant interconnectors, EY assumed they would bid cooperatively to maintain spot price differences between Tasmania and Victoria with limited consequences for the level of Tasmanian wholesale prices. Maintaining the spot price differential results in large interconnector revenues, with the modelled revenues exceeding the costs of a 2IC.107

If both interconnectors were regulated Hydro Tasmania was assumed to bid the interconnectors at $0/MWh, which would act to increase Tasmanian wholesale prices towards Victorian wholesale prices.108 The modelled revenues of Hydro Tasmania exceeded the combined cost of a 2IC and the additional costs of supplying Tasmanian demand for most of the scenarios modelled by EY.109

The cash flow modelling was based on EY’s simplifying assumptions which are supportive of the commercial viability of a 2IC, though in practice may not be reflective of market behaviour and outcomes. The actual revenue and wholesale price outcomes will depend on future wholesale market conditions and participant bidding behaviour, particularly in Victoria.110 EY found that in an oversupplied generation market in the NEM, merchant interconnector revenues would fall by approximately 40 per cent.111 As merchant interconnectors would be subject to substantial market volatility and risk compared to regulated interconnectors, this will be a relevant consideration for financing decisions of private investors. For these reasons, EY’s revenue modelling results can only be interpreted as the likely direction of revenue flows, rather than the magnitudes of actual revenue. Commercial structure and financing considerations are examined further in Chapter 6.

102 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 40, Table 35.


104 These participants included Hydro Tasmania, Tasmanian consumers, Basslink and a 2IC.



107 Based on analysis of EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, pp. 2 and 34 (Tables 2, 23 and 24).


109 Based on analysis of EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, pp. 2 and 43 (Tables 2, 36 and 37).




5 Economic efficiency assessmentThis chapter presents the study’s economic efficiency assessment of the market outcomes of a 2IC.

KEY FINDINGS

• A 2IC could deliver significant net economic benefits to the NEM, but its economic feasibility remains uncertain when its significant capital costs are weighted against the potential benefits. A 2IC is likely to be economically justified in limited future market circumstances when assessed in terms of AEMO and EY’s modelling results, the potential risks of 2IC cost escalation and the high level of investment uncertainty arising from the substantial change and review that is currently occurring in the NEM.

• The modelling did not include and evaluate all potential benefits from a 2IC which are allowable in a RIT-T assessment. These included competition benefits, some aspects of power system security and reliability benefits and options value benefits. More detailed analysis of these potential benefits would be appropriate where the net market benefits from a 2IC are assessed as marginal.

• There would be merit in closely monitoring market conditions and undertaking further detailed work on a 2IC should more favourable market conditions emerge—for example, if additional interconnection from South Australia is approved.

5.1 Regulated 2IC market outcomes assessment The evidence and analysis that is available, including AEMO and EY modelling of plausible scenarios for future NEM development paths and consideration of other potential costs and benefits, shows that while a 2IC could deliver significant positive net economic benefits to the NEM under certain scenarios, under others net benefits would be negative, indicating that the economic viability of a 2IC remains uncertain at this time.

This conclusion is based on:

• the substantial capital cost, operating cost and related network augmentation costs of a 2IC, which exceeds its market benefits for many of the modelled future NEM scenarios

• the potential for increased capital and construction costs

• the investment risks associated with uncertain NEM settings and conditions over a 2IC’s lifespan.

5.1.1 Modelling projections

AEMO found that a 2IC would generate market benefits in the 2030s and beyond that would exceed its costs under some plausible scenarios of the future development of the NEM. It found marginally positive or otherwise negative net market benefits under other modelled scenarios of the incremental benefits of a 2IC. Positive net market benefits were found by EY under one scenario (a 40 per cent reduction in Tasmanian demand). However, for most scenarios it modelled, there were negative net market benefits. Findings also highlighted the investment risks involved in that market benefits may not eventuate if adverse market conditions arise.

While the modelling provides an important basis for assessing the economic efficiency of a 2IC, it has its limitations and there are other factors that need to be considered. To complete the modelling it has been necessary to make simplifying assumptions about future policy frameworks, market conditions and market participant behavior which may not be realistic in practice. There is considerable uncertainty as to how the NEM

33Economic efficiency assessment

might evolve and it has not been possible to fully capture the implications of this uncertainty in the modelling scenarios. There is also scope to place different weighting on the market benefits and costs of a 2IC than those captured in the modelling. For example, following recent events in the NEM, electricity consumers and governments may place greater weight on the power system security and reliability benefits that a 2IC might provide. Also, some potentially relevant market benefits and costs were not considered in the modelling and are instead addressed qualitatively in this chapter.

5.1.2 Capital and operating costs of a 2IC

At this early stage of consideration, there are still some capital and construction cost uncertainties. The cost estimates that the Tasmanian Government provided are preliminary, and should be taken to have a potential margin of error.112 The capital and operating costs involved in constructing and operating an undersea interconnector are substantial compared to the cost of overhead interconnectors and may change during the more detailed planning, construction and regulatory approval processes for a 2IC. Costs may also change as a result of market and regulatory factors—for example, adverse foreign currency and materials cost fluctuations.

During consultation, several stakeholders warned of these risks and suggested that cost estimates may increase. They recommended that, in recognition of these risks, a conservative approach be adopted to estimating interconnector costs and the conditions under which a 2IC may be economically efficient.

5.1.3 NEM development uncertainty

As noted in Chapter 2, the NEM is undergoing rapid transition towards a lower emission generation mix, raising challenges for integrating the rapid growth of renewable generation while maintaining reliability of energy supply and security of power system operations. This is creating uncertainty about the future investment climate for a 2IC. This uncertainty is exacerbated by the long lead times involved in constructing a 2IC and operating it over an economic life of 40 years or more.

Over the next few years, much more detailed and relevant information about the longer-term NEM investment climate will become available, including from; the outcome of ongoing reviews, the result of ElectraNet’s South Australian Energy Transformation RIT-T and AEMO’s future NTNDP reports.

Ongoing monitoring will be appropriate to identify future changes that would establish the preconditions for an informed decision on the future viability of a 2IC investment. For example, AEMO’s modelling suggested that there would be merit in reconsidering the case for a 2IC if other interconnection improvements occurred across the NEM. The modelling results also indicated that a reduction in demand in Tasmania would improve the case for a regulated 2IC. There may also be additional market benefits if long-term forward gas prices are higher than expected because this may further reduce the competitiveness of gas generation relative to the more efficient Tasmanian hydro generation that a 2IC would facilitate.113 This proposition would need to be tested by further modelling and analysis.

5.2 Other potential market costs and benefits from a regulated 2ICThis section considers certain benefits and costs that are allowable under the RIT-T process that were not modelled by EY or AEMO and that could have a material impact on the feasibility of a 2IC if they were able to be valued and included in the cost−benefit assessment. Where modelling finds only a marginal difference between market costs and benefits, more detailed analysis could be warranted to impute a value to these costs and benefits.

112 Hydro Tasmania advised that the interconnector construction and operating cost figures provided by the Tasmanian Government have an error margin of plus or minus 30 per cent. This error margin includes currency exchange, regulatory change and labour cost risk.

113 Whether or not the competitiveness of gas generation will improve or decline over time will depend on cyclical and structural changes in the gas market. The COAG Energy Council is currently reviewing gas markets in order to improve supply, market operations, transportation and market transparency.


Ancillary services

Ancillary services are used to manage the power system by maintaining or restoring key technical and operational features of the system, including standards for frequency, voltage, network loading and system restart processes.

A 2IC may provide benefits in delivering FCAS between Victoria and Tasmania. However, these were not valued and assessed in the modelling for the study. This is because FCAS and related ancillary services markets are complex and are currently not priced in a manner which reflects their likely future value in the NEM. The emergence of new ancillary service technologies and any necessary redesigned ancillary services markets are under consideration in the Independent Review into the Future Security of the National Electricity Market and reviews of energy security mechanisms that AEMO and AEMC are conducting.

In any future analysis of a 2IC’s viability, consideration of ancillary services costs and benefits should also include any consequences and costs a 2IC would have for the System Protection Schemes (SPS) in Tasmania. For example, there may be additional complexities and costs involved in extending the current contractual arrangements that underpin the existing SPS so that they also cover contingencies resulting from a 2IC outage. More information regarding SPS can be found in Box 4.

BOX 4: System Protection Schemes114

SPS were introduced when Basslink was established. The schemes include a frequency control SPS (FCSPS) and a network control SPS (NCSPS) to manage very large contingencies such as the credible contingency of the Basslink interconnector tripping on import or export. The FCSPS monitors interconnector flow and calculates the required load or generation tripping that is necessary to mitigate the loss of the interconnector. The NCSPS prevents the thermal overloading of transmission network elements following a specified contingency.

Reliability benefits

The components of reliability of supply include an adequate supply of dispatchable generation to meet demand and adequate capacity of reliable transmission and distribution networks.115 Insufficient reliability of supply can impact on consumers through greater involuntary load shedding or voluntary load curtailment. It also creates possible generation dispatch inefficiencies if backup generation needs to be mobilised. An investment that strengthens reliability by reducing the risk of load shedding would provide market benefits relevant to a RIT-T assessment.

AEMO found that a 2IC would provide $87 million in reliability benefits116 and $48 million in net market benefits associated with increased resilience of the Tasmanian network to potential interconnector failures.117 Here, resilience refers to the power system’s ability to respond to low-probability, high-impact events such as interconnector outages. Response to these events can be costly. This is demonstrated by the outage of Basslink, when approximately $47 million was spent on additional gas generation and $64 million was spent on additional diesel generation.118

While EY modelled some reliability benefits that would be provided by a 2IC, it did not put a value on the role of a 2IC in reducing the probability of Tasmania being islanded from the rest of the NEM due to a future Basslink outage.

114 OTTER 2015, Energy in Tasmania—Performance report 2014−15, p. 20.



117 AEMO 2016, NTNDP, p. 31.

118 Hydro Tasmania 2016, Annual report 2016, p. 15.

35Economic efficiency assessment

Competition benefits

Competition benefits refer to the net changes in market benefits arising from the impact of a 2IC on the competitive behaviour of participants and resulting market outcomes in the NEM. There are challenges in quantifying competition benefits because it requires assumptions about changing NEM supply and demand conditions, the structure of generation fleets, generation entry and exit decisions and the competitive bidding behaviour of market participants.

Hydro Tasmania has considerable latent market power in Tasmania, as it produces the dominant share of all generation output within the region. A 2IC would limit this market power and improve competition because an increase in the capacity for power flows between the Tasmanian and Victorian regions would result in the Victorian price setting an upper limit on Tasmanian spot market prices at times when this interconnection capacity was unconstrained.

A 2IC may also have secondary competition effects on the financial market in the NEM that would need to be considered under a RIT-T. For example, greater quantities of cheaper electricity imports from Tasmania may mean that thermal generators in Victoria could be retired earlier.

During consultations a number of stakeholders commented that investment in a 2IC would create a market structure more suited to merging of the Tasmanian and Victorian regions into a single NEM region. Under this view, a combined Victorian and Tasmanian region would subject Hydro Tasmania to greater competition for dispatch with other generators. This would reduce Hydro Tasmania’s latent market power in Tasmania and facilitate more competitive hedge contracting between generators and retailers in Victoria and Tasmania. It was also suggested that Tasmanian wind farms would have the opportunity to negotiate power purchase agreements (PPAs) with Victorian retailers in a combined Victorian and Tasmanian region. Further discussion of a single NEM region is included in Box 5.

Option values

Option value refers to a market benefit that results from retaining flexibility in the market where changed circumstances or new information may arise which would undermine or increase the expected benefits and economic viability of a project.

There could be positive market benefits from the development of a 2IC in the future—for example, in scenarios where there is significant interconnection across other regions or a future reduction in Tasmanian electricity demand. Other credible options may emerge in the future which are able to deliver comparable NEM outcomes to a 2IC in less time and at lower cost. A decision to build a 2IC involves a substantial capital cost and is irreversible. If it is built and operated as a regulated interconnector, the costs would be recovered from consumers over the life of the asset, regardless of its future utilisation and economic viability.

Therefore, it may be prudent to retain decision-making flexibility by evaluating and adopting smaller, more incremental investments that achieve comparable NEM benefits in the short to medium-term while delaying further evaluation and commitment to a 2IC investment until the long-term NEM investment environment becomes clearer. That approach would be regarded as offering an option value benefit under the RIT-T.

The cost of network losses

Network losses refer to the electricity which is lost in transport from sources of supply to demand centres. The market benefits capture some of the impact on transmission losses to the extent that losses across interconnectors affect the generation that is needed to be dispatched in each trading interval. A more complete analysis of the impact of a 2IC on transmission losses would require detailed load flow modelling to be completed.


BOX 5: Potential competition benefits from a single Tasmanian−Victorian NEM region

The construction of a 2IC would create an opportunity to re-examine the merits of establishing a combined Victorian and Tasmanian region in the NEM.

The issue was examined in 2012 by the Electricity Supply Industry Expert Panel.119 The panel concluded that Hydro Tasmania possessed significant latent market power in the Tasmanian region. That latent market power could be deterring retailers from entering into Tasmania because of concern that Hydro Tasmania may exercise its market power in the future to their detriment. The panel noted that the creation of a combined Victorian and Tasmanian region would expose Hydro Tasmania to competition from Victorian generators for dispatch on the basis of a new (combined) regional reference node in Victoria. This should reduce Hydro Tasmania’s latent market power while promoting more competitive spot and contract market outcomes in the combined region. If this promoted retailer entry and investment in Tasmania, competition and dynamic efficiency would be enhanced in the Tasmanian energy market.

The panel also noted that Basslink would become a significant network constraint within the combined region. This would create opportunities for disorderly bidding by Hydro Tasmania whenever Basslink was constrained. That could involve submission of bids below SRMC so that dispatch would occur during high-demand/high-price periods; and above SRMC to avoid dispatch during excess-supply/low-price periods. This could have potentially adverse consequences for productive and allocative efficiency.

However, if a 2IC were in operation that would effectively double the interconnector capacity between Tasmania and Victoria. The much larger unconstrained power flow capacity would presumably strengthen the competition benefits from establishing a combined region while at the same time reducing the opportunities for disorderly bidding and the associated risk of resulting productive and allocative inefficiencies.

However, the panel also noted that a rule change would be required to combine the regions and that conversion of Basslink to regulated status would also be necessary (or a rule change would be needed to allow a merchant interconnector to operate within a region).120

5.3 Merchant interconnector market outcomes assessment

EY found that a merchant 2IC would generate enough revenue to recover its financing and operating costs (including a risk adjusted return) under a commercial model which assumes a 2IC and Basslink would act cooperatively to maximise profits and there is no competition from Hydro Tasmania on interconnector revenues.

A superficial view of those results may suggest that a merchant 2IC is a financially viable investment proposition. However, EY’s assessment is based on a very specific set of assumptions and commercial arrangements which favour the development of a 2IC.

The financial and commercial arrangements that underpin the operation of a merchant 2IC are key to determining whether a 2IC may be built. Potential investors would need to consider these models carefully.

Merchant 2IC investors would also need to consider the risks of capital and construction cost escalations and investment risks associated with uncertain NEM settings, as highlighted for a regulated 2IC earlier in this chapter. These risks would equally apply for consideration of the market outcomes for a merchant 2IC.

Further discussion of commercial and financial models for a merchant 2IC is included in Chapter 6.

119 Electricity Supply Industry Expert Panel 2012, Final report volume I, p. 146.

120 Electricity Supply Industry Expert Panel 2011, Draft report, p. 247.

37Commercial and financial arrangements

6 Commercial and financial arrangements

This chapter describes the potential commercial models under which a 2IC could operate in order to assess whether a regulated or merchant 2IC would be financeable. The commercial model chosen would have a significant impact on revenues that a 2IC would earn. This chapter draws conclusions about the financeability of different models.

Where this chapter has discussed the financeability of a regulated 2IC, it has assumed that the RIT-T has been passed.

KEY FINDINGS

• The feasibility of a 2IC would depend on which commercial model was chosen for its operations, including whether it was operated as a regulated or merchant interconnector, because its revenues and returns would depend on those arrangements. Also, a 2IC’s viability and revenue earning potential cannot be viewed in isolation from the operations and commercial arrangements of Basslink.

• While a merchant 2IC offers higher revenues and returns than a regulated 2IC, it would also involve a much higher level of risk for investors. This is because it would derive its revenues from the difference in spot prices between Tasmania and Victoria, which are volatile and hard to predict. This risk would make a merchant 2IC less attractive to investors.

• A regulated 2IC would provide lower overall returns, but it also has a lower risk level because it would earn relatively certain regulated revenues for the life of the asset. This lower level of risk would make a regulated 2IC more attractive to investors.

• The introduction of a 2IC would affect the commercial viability of Basslink. This may require its owners to consider other commercial and ownership options or to seek to renegotiate the existing Basslink Services Agreement (BSA).

• Ultimately, to be commercially viable in the current environment a 2IC will need to be developed as a regulated interconnector or as a merchant interconnector supported by a facility fee component similar to Basslink.

6.1 Business modelsThe feasibility and financeability of a 2IC would depend on whether it was a regulated or merchant interconnector and on the commercial model chosen for its management and operation. The choice of model affects both the scale of potential revenues and their riskiness and volatility. This in turn will affect the financeability of the investment.

The risk of a 2IC for investors refers to the certainty of revenues. It is a key element in financeability. A regulated 2IC would be expected to carry less risk for an investor than a merchant 2IC.

The choice of commercial model for a 2IC would also depend on the commercial and market relationship it would have with Basslink. The revenue and returns for each interconnector would be highly dependent on the model and operational arrangements for the other interconnector. This would include their respective ownership and regulatory arrangements and whether they had a cooperative or competitive relationship in their energy market


activities. These considerations would include whether both interconnectors were regulated or merchant assets, whether they would be separately or jointly owned, and the relationships they had with Hydro Tasmania.121

The choice of commercial model would also be affected by the energy market structure in Tasmania. Hydro Tasmania, as the dominant generator, has substantial market power in the Tasmanian spot and contract markets. That could raise concerns for an independently owned and operated merchant 2IC given Hydro Tasmania’s ability to influence the price at which a merchant 2IC could purchase electricity. For that reason, consideration may be needed as to whether the operations of a merchant 2IC would need to be underwritten by a facility fee arrangement with Hydro Tasmania similar to the current BSA. A description of the BSA is given in Box 6.

BOX 6: Basslink Services Agreement

The BSA is an agreement between Basslink Pty Ltd and Hydro Tasmania which establishes the rights and obligations of both parties with respect to the operation of Basslink. The BSA provides for Basslink Pty Ltd to swap its market-based revenue for an agreed fixed facility fee plus performance-related payments. It also gives Hydro Tasmania the rights to control the way in which Basslink Pty Ltd bids its interconnector capacity, although this has been partially curtailed by Tasmanian legislation. The initial term of the BSA was set at 25 years, with an option to extend a further 15 years.122

6.1.1 Identified commercial models

EY identified seven possible commercial models (five of which are referenced at Table 14) for the operation of a 2IC.

EY also provided advice on different procurement models that could be adopted to manage the tendering, construction, ownership and operation stages of the implementation process for a 2IC. Those issues are included in EY’s report, at Appendix E, but are not addressed in this chapter.

Base case 2 referred to conditions being imposed on those who operate a 2IC so that Basslink would be the primary source of flow and the 2IC would only be used as an overflow cable. This would help to preserve Basslink’s business case.

In addition to the commercial models in Table 14, EY identified two hybrid models, where a 2IC could be partially regulated or partially merchant. These models attempted to improve the viability of a 2IC by allocating risk differently among different stakeholders:

• Partially regulated—a partially regulated 2IC would require changes to the NER to be implemented and has therefore not been a focus of the study.

• Partially merchant—a partially merchant 2IC model would not need to pass the RIT-T because it would generate its own revenue stream through wholesale market trading. However, it would require some financial contribution from a third party in order to be financially viable. This could include a facility fee or availability payment (similar to the payments from Hydro Tasmania to Basslink under the BSA).123

121 Any changes to the ownership or regulatory arrangements for Basslink would depend on commercial decisions of Basslink’s owner.

122 Electricity Supply Industry Expert Panel 2012, Final Report Volume II, p. 18.

123 It was suggested during stakeholder consultations that a capital contribution or commitment to pay a facility fee from government could enhance a 2IC’s feasibility for investors. However, such a direct or indirect contribution or commitment from government would likely distort network and generation investment decision-making and could raise perceptions of sovereign risk for current and future private investors in the NEM. Therefore, government contributions or facility fee commitments would need careful consideration, being mindful of these risks.


Table 14: EY identified commercial models124

Commercial model Key features

Base case 1

• Basslink—merchant

• 2IC—merchant.

•

1. Basslink operates as a pure merchant interconnector (no availability charge is earnt).

2. 2IC enters the market as a merchant interconnector.

3. Unless there is a single owner, both interconnectors would compete for flow to ensure efficient use of the assets.

Base case 2


• 2IC—merchant.

•

1. Basslink remains a merchant interconnector while earning an availability charge (mimics current operations).

2. 2IC enters the market as a merchant interconnector.

3. Commercial restrictions on 2IC require it to operate as an overflow cable only (only utilised when Basslink is at capacity).

Alternative case 1


• 2IC—regulated.

1. Basslink remains a merchant interconnector (with availability charge).

2. 2IC meets RIT-T to become a regulated interconnector.

3. 2IC’s regulated revenue determined by the AER.

Alternative case 2

• Basslink—regulated

• 2IC—merchant.

1. Basslink becomes a regulated interconnector with regulated revenues.

2. 2IC to operate as a merchant interconnector.

Alternative case 3

• Basslink—regulated

• 2IC—regulated.

1. Basslink becomes a regulated interconnector with regulated revenues.

2. 2IC regulated, revenue determined by the AER.

6.2 EY modelling methodology EY conducted qualitative and quantitative analysis using the models described above. This analysis identified what the revenues and costs would be for private investors in a 2IC and Basslink under different scenarios:

• being both operated as regulated or merchant interconnectors

• with and without availability payments similar to those provided under the BSA to Basslink.

This financial analysis drew on market outcomes identified in EY’s market modelling work, but the analysis differed from the modelling work in some important respects—for example, it focused on the risks and returns to investors from the interconnectors rather than on revenues and market outcomes when it was modelling merchant interconnector impacts.

A consequence of these different purposes was that the NPV assessments were also very different. The market modelling considered market outcomes resulting from dispatch, fuel savings, the generation mix, future investment and other market benefits across the NEM. The financial analysis considered the NPV of cash flows available to investors in the interconnectors. For a merchant interconnector this would depend on market trading outcomes, and the analysis did not address the economic efficiency of those outcomes in a RIT-T sense. The outcomes of the NPV assessment would therefore be quite different.

124 EY 2016, Financial and commercial analysis—Second Tasmanian interconnector, p. 3.


Regulated versus merchant

The approach to EY’s financial analysis was different for regulated and merchant interconnectors.

For a regulated interconnector, the interconnector would earn a regulated return that is set by the AER, regardless of utilisation. The interconnector would be effectively passive in terms of how it was operated, and the power flows would be determined by the dispatch outcomes and spot price difference between the two regions. The revenue return set by the AER would allow recovery of capital financing costs and operating costs, including a risk-reflective rate of return. Market modelling was therefore not needed to determine these regulated revenues.

However, assessing the revenue a merchant interconnector would earn is more complex because whether the interconnector was dispatched (and therefore received revenue) would depend on its bids in comparison to the bids of other market participants, including Hydro Tasmania. For this reason the merchant revenue outcomes must be modelled.

Key assumptions

EY made a number of assumptions which underpin its financial analysis. They were:

• For the regulated interconnector models, it assumed that a 2IC had passed the RIT-T. It did not imply that a 2IC would meet that test in practice.125

• For the models that involve merchant interconnectors, EY assumed that the interconnectors acted cooperatively and that Hydro Tasmania would bid at its opportunity value of water.

• Costings for interconnector build and operation were provided by the Tasmanian Government.

6.2.1 Qualitative analysis methodology

For the qualitative assessment, EY identified key criteria to use as the basis for its evaluation (Table 15). An importance rating was used to more accurately represent the value of each criterion.

Table 15: EY financial and commercial analysis—key evaluation criteria126

Criteria Exploration Importance

Risk transfer Which business model provides the greatest level of effective risk transfer to operators/owners of a 2IC?

High

Operational utilisation/incentives

Which business model(s) encourage the greatest level of interconnector utilisation/operational efficiency?

Medium

Energy security Do any of the potential business models improve or hinder the energy security benefits that an additional interconnector could provide?

Medium

Financing costs Which business model offers the lowest financing costs? Low

Suitability for funding Which business model is bankable? Medium

Market appetite Is there market appetite for the business model? High

In conducting the qualitative analysis, EY tested each of the commercial models in Table 14 against the criteria in Table 15 to produce an overall score for each one. This score was then weighted based on the relative importance rating of the different criteria as determined by EY.




6.2.2 Quantitative analysis methodology

EY tested each of the operating models in a bespoke financial model to determine:

• ability to support a capital structure

• project and equity internal rates of return (IRR)

• cost impact of each operating model.

The revenue input for each model was derived from the market modelling undertaken by EY. Other key assumptions are shown in Table 16.

Table 16: EY financial and commercial analysis—key assumptions127

Assumptions Input

2IC capital costs A$930 million (June 2015$)

2IC operating costs A$16.7 million annually (June 2015$)

2IC construction period 6 years beginning 2020

2IC operational start date 2026

Inflation rate (CPI) 2.0% p.a

Costs of equity funding 15.0% p.a (post tax nominal)

Costs of debt funding 5.03% p.a (post tax nominal)

Weighted average cost of capital 8.78% p.a (post tax nominal)

Capital structure (gearing) 75% debt; 25% equity

Loan term 20 years

Debt service coverage ratio (DSCR target) >1.50x

6.3 Outcomes of financial and commercial analysis

6.3.1 Qualitative outcomes

EY found that, of all the models tested, regulated interconnector models had the lowest degree of risk transfer to investors and more stable, regulated revenues. Revenues set by the AER are more predictable and easier to raise debt against and would more readily support financing and investment. There was some remaining risk that the AER could adjust the framework for regulated revenues and returns, but that risk did not appear significant.

In contrast, EY found that merchant interconnectors had less stable revenues and higher levels of risk. In part, this was because it was challenging to forecast the price differential between Victoria and Tasmania over the longer-term, making future revenue forecasting complex and uncertain. This would in turn make it more difficult for investors to finance the investment. Financiers would seek a risk premium as compensation for this higher level of risk and would be likely to require a larger equity contribution. This would mean that the proportion of debt to debt plus equity (the level of gearing) would also be lower and financing costs higher compared to a regulated model with more stable cash flows. The risks and costs involved in a merchant 2IC would therefore be significantly higher than for a regulated 2IC.

Although not quantitatively modelled, EY commented that where the two interconnectors were competing on a merchant basis under separate ownership, the levels of risk would be particularly significant. Being in



competition, they would be likely to drive down their aggregate revenues, exposing the investors to significant revenue and asset stranding risk. In a competitive situation a 2IC, with a higher marginal loss factor, could be expected to be dominant over Basslink because it would be able to bid more competitively. Basslink could therefore be expected to suffer revenue losses if it were in head-to-head competition with a 2IC.

The potential bidding behaviour and strong market position of Hydro Tasmania could also be a cause of concern for investors in merchant interconnectors. Without the involvement of Hydro Tasmania in the operation of the two interconnectors or some obligation to bid at its opportunity cost of water, Hydro Tasmania could bid its generation into the Tasmanian spot market at prices marginally below the Victorian spot price and thus appropriate most of the revenue potential of both merchant interconnectors (an example of this is provided in Box 7 below). Since the revenues of a regulated interconnector would be independent of utilisation, this would not be a concern in that case.

BOX 7: An example of Hydro Tasmania’s ability to affect merchant interconnector revenues

Consider an example where interconnector losses were ignored, the wholesale price in Victoria is $100/MWh and water values in Tasmania are $20/MWh. Assume there was 1200 MW of interconnector capacity available and a surplus of supply in Tasmania of 1000 MW.

If the interconnector were merchant, it could bid a price differential of $79. This would still be dispatched in Victoria, as the cost of this export is effectively the $20 spot price in Tasmania plus the $79 merchant interconnector bid. In this scenario, the wholesale price in Tasmania would move to $21 and the merchant interconnector would earn revenue on the $79 wholesale price differential.

However, if Hydro Tasmania bid its generation into the spot market in Tasmania at $98, the differential between the Tasmanian and Victorian spot prices would be $2. If the interconnector were to bid at $1, it would still be dispatched as the total of the Tasmanian spot price and the interconnector bid would be less than the price in Victoria. However, the interconnector’s revenue would be minimal compared to the example in the previous paragraph.

EY found that the hybrid cases could offer benefits to investors. A partially merchant model would involve some form of third-party assistance, which would lower the level of return required to remain viable as a merchant interconnector.

Other key observations on EY’s qualitative analysis include:

• Models involving two merchant interconnectors would only be viable if either Hydro Tasmania operated both interconnectors in some capacity or Hydro Tasmania was able to guarantee electricity flows at a discount to market prices for the interconnector that is not operated by Hydro Tasmania.

• If a 2IC was merchant and subject to commercial restrictions to preserve Basslink’s business case, it would be even more limited in its ability to generate revenue and attract finance.

• A model where both Basslink and a 2IC were regulated would support a level of funding and IRRs that would attract investors. However, because line losses would be lower for a 2IC than for Basslink, this could result in Basslink being used as an overflow cable only.

6.3.2 Quantitative outcomes

EY’s quantitative results based on the methodology and assumptions in the financial analysis described above are set out in Table 17. Note, however, that the results depend on restrictive assumptions about cooperative behaviour by the two interconnectors and accommodating responses by Hydro Tasmania. Also, the analysis of a


2IC and Basslink as regulated interconnectors assumed that both would satisfy the RIT-T and be able to recover their capital financing and operating costs from revenues regulated by the AER. In practice, that may be difficult for both interconnectors given the market modelling projections described in Chapter 4.

The columns in Table 17 reflect the commercial models described in Table 14. The rows show the overall NPVs of revenues for a 2IC and Basslink based on a 40 year economic life. These results are presented based on both a cost of capital of 7 per cent and a cost of capital of 10 per cent.

Below these rows are the overall Project IRR and the Equity IRR, leading to a conclusion as to whether the project would be debt fundable and then financeable overall.

Table 17: Investor suitability summary128

ScenarioBase

case 1Base

case 2Alternative

case 1Alternative

case 2Alternative

case 3Hybrid case 1

Hybrid case 2

Description Both merchant

Both merchant,

commercial restrictions

on 2IC

Basslink merchant,

2IC regulated

Basslink regulated,

2IC merchant

Both regulated

Partially merchant

Partially regulated

NPV (2016) of Interconnector Revenues @ 7% ($m)—2IC

$1662 m $598 m $1152 m $1662 m $1152 m $662 m $1314 m

NPV (2016) of Interconnector Revenues @ 7% ($m)—Basslink

$598 m $1013 m $1013 m $791 m $791 m − −

NPV (2016) of Interconnector Revenues @ 10% ($m)—2IC

$827 m $304 m $619 m $827 m $619 m $353 m $695 m

NPV (2016) of Interconnector Revenues @ 10% ($m)—Basslink

$304 m $515 m $515 m $407 m $407 m − −

Project IRR 12.7% 3.9% 9.9% 12.7% 9.9% 9.9% 11.2%

Equity IRR 18.2% 1.7% 15.0% 18.2% 15.0% 15.0% 18.1%

Debt fundable? Yes No Yes Yes Yes Yes Yes

2IC financeable? No No Yes No Yes No Yes

These results suggest that most options, whether they involved regulated or merchant interconnectors, would deliver significantly positive NPVs given the cash flows projected for private operators of a 2IC. EY acknowledged the supportive influence of the underlying assumptions but noted that, if these NPVs could be achieved in practice, they would support high levels of gearing and deliver equity returns of 10 per cent or more.

Options that involved the development of a merchant interconnector were found to offer the highest levels of return to investors, although the levels of risk may be prohibitive. The modelling indicated that regulated interconnectors would make lower overall returns but still remain highly financeable due to their more certain, lower risk returns.129


129 As noted in Chapter 4, a merchant interconnector could increase revenues by bidding to maintain or increase spot price differentials, but the result would be less flexible and efficient use of Tasmania’s hydro facilities and foregone NEM-wide benefits in terms of lower variable dispatch costs.


EY found that only one option—the dual-merchant option with commercial restrictions on 2IC—would not be debt fundable. This is because it would preserve the business case for Basslink at the expense of a 2IC.

These quantitative results provide important insights. However, they need to be interpreted with caution because, to an extent, they reflect the supportive modelling assumptions that have been adopted.

6.4 Market soundingIn order to validate the findings of the qualitative assessment process, EY conducted a series of market soundings to discuss with market participants the market conditions, regulatory arrangements and business models under which they would be willing to finance a 2IC. In line with the qualitative assessment, market participants generally indicated that merchant models were unlikely to be commercially viable or financeable. Market participants strongly preferred the regulated income model to a merchant option and believed that regulated revenues would provide superior outcomes.

However, market participants noted that the RIT-T is a challenging test to meet and that a 2IC might not pass it under current settings. If this were the case, market participants indicated that a structure that allowed for ongoing regular payments, such as the partially merchant model, could also be viable.

6.5 EY findings

6.5.1 General findings on models

EY observed that a simplistic view of the qualitative and quantitative results presented in its report would suggest that, as merchant interconnectors appear to be the most profitable, they would encourage the highest level of investor interest.

However, EY concluded that the level of market-exposed risk for a merchant investor is considerable and may well be prohibitive from the perspective of investors and financiers. This market risk has a number of dimensions:

• A merchant interconnector would make its revenue from the spot price differentials between Victorian and Tasmanian regions, which are very difficult to forecast and highly volatile.

• The price differential risk would be exacerbated to the extent that Hydro Tasmania bids its generation at prices marginally below the Victorian spot price rather than in order to facilitate the revenue-maximising strategies of the interconnectors.

• If a 2IC and Basslink were in competition for the arbitrage trading revenues, this would drive their combined revenues down.

The challenges of operating and financing merchant interconnectors are demonstrated by the fact that no merchant interconnectors are currently operating in Australia without some form of revenue guarantee (for Basslink, the BSA provides this guarantee).

Regulated interconnector models, on the other hand, avoid many of these risks through having a revenue profile that is predetermined through regulation. As a result, regulated interconnectors are considerably more financeable than merchant interconnectors, assuming they are able to satisfy the RIT-T requirements.

Hybrid models offer some of the benefits of regulation for investors, such as the lower risk profile, but at the same time offer some of the advantages of merchant interconnectors.

Overall, in the current environment, for an interconnector to be viable it would need to be supported by some form of regulated return or availability charge (similar to the BSA) to avoid the riskiness that would otherwise be inherent in returns.


6.5.2 Other findings

Other key findings of EY include:

• The potential inter-relationships between a 2IC and Basslink are such that it is not possible to consider a commercial model for 2IC without considering how it would affect Basslink and how Basslink would affect it. A 2IC would inevitably impact Basslink in some way.

• The preferable model appears to be one in which there is a single owner for a 2IC and Basslink. Separate ownership would only be likely if both assets were regulated.

6.6 Other considerationsThere are several other considerations in relation to the financing of a 2IC that go beyond the EY report.

EY identified the strong interdependence of outcomes between a 2IC and Basslink. Where a 2IC was regulated, Basslink would be unlikely to continue to be viable as a merchant interconnector, so consideration should be given to converting it to regulated status. However, there are a number of steps before Basslink could become a regulated asset—for example, it would need to satisfy the RIT-T.

If Basslink were to remain a merchant interconnector and an arrangement similar to the current Basslink BSA were to be put in place for a 2IC, this could trigger or require a renegotiation of Basslink’s BSA, particularly if Hydro Tasmania were to be given control of both interconnectors. That, and related commercial matters, would require discussion with Basslink’s owners.


7 Renewable energy and energy security implications

This chapter examines the implications of a 2IC for the development of large scale renewable generation in Tasmania and for the management of power system security in Tasmania and the wider NEM.

KEY FINDINGS ON RENEWABLE ENERGY

• Modelling showed that a 2IC would increase the financial viability of renewable generation in Tasmania and reduce the risk of it being constrained by transmission limitations.

• If a 2IC were in operation, Tasmania’s relatively rich wind resources could be more readily exported to the broader NEM. Also a 2IC would increase Tasmania’s ability to import electricity during lower price periods. This would mean that Hydro Tasmania would have greater flexibility within its generation portfolio to maximise the value of its stored water, while also reducing NEM-wide costs.

• AEMO’s modelling showed that, even if a 2IC is not developed, Tasmanian wind generation capacity could increase by up to 730 MW between now and 2036.

• However, it also indicated that a 2IC would enable an additional 365 MW of generation capacity to be developed over the same period.

KEY FINDINGS ON ENERGY SECURITY

• Greater interconnection can facilitate inter-regional transfer of some services that support energy security. However, sufficient underlying power system security and strength has to be maintained to support interconnectors.

• A 2IC could transfer additional ancillary services, such as FCAS, from Tasmania to the rest of the NEM. However, adequate supplies of these services are already available. A 2IC could also reduce the need to rely on Tasmanian generators to provide ancillary services, allowing the generators to operate more flexibly to provide efficiency benefits.

• A 2IC could increase power system security risks in Tasmania. The Tasmanian transmission network has a number of system strength, inertia and voltage control challenges which may increase with a 2IC in operation.

The Terms of Reference call for an assessment of whether a 2IC would:

• address energy security issues

• facilitate development of Tasmania’s prospective large scale renewable energy resources

• allow delivery of balanced, dispatchable renewable energy into the NEM

• integrate with the Victorian electricity market and the wider NEM.

47Renewable energy and energy security implications

A relevant consideration for the study is the extent to which strengthened interconnection in the NEM, particularly between Tasmania and Victoria, would contribute to efficient renewable energy development and provision of power system security services in Tasmania and the NEM. These issues are examined in this chapter on the assumption that a 2IC would be economically efficient and would be built and in operation from 2026. This assumption has been adopted for the purposes of this chapter and should be distinguished from the analysis and findings in Chapters 4 and 5, which are concerned with whether a 2IC would be economically efficient to construct and operate.

7.1 Role of interconnectorsInterconnectors are an increasingly prominent feature of global energy systems. They can be used to maintain energy security and reliability of supply while integrating increasing flows of intermittent renewable energy into the generation mix. According to the International Energy Agency (IEA), interconnectors can be a cost-effective option when seeking to combine an increasing share of variable renewable energy with the need to maintain a highly secure electricity supply.130

As noted earlier, the NEM is undergoing a period of rapid transformation and is moving into a new era for transmission planning. That is, transmission networks that were originally designed for transporting energy one way from remote coal generators to demand centres are now evolving to support large scale renewable generation development in new areas and two-way power flows emanating from distributed generation installations. Transmission networks will also increasingly be needed for power system support services, such as frequency and voltage support, to maintain a reliable and secure electricity supply.131

Interconnectors can play a role in the transition of power system security by facilitating the growth and transportation of intermittent renewable energy across NEM regions while promoting power system security by enabling interregional transfers of security services from available synchronised generators and other emerging equipment and installations.

7.2 Renewable energy developmentThe transformation of the NEM towards a lower generation mix is already underway—renewable energy is making up an increasing proportion of the national generation capacity. The RET and state and territory government renewable energy targets are driving changes in the NEM.

Under the Paris Agreement, there is to be a reduction in carbon emissions by 26 to 28 per cent below 2005 levels by 2030. AEMO has projected that Australia’s 2030 emissions reductions targets will be met mostly by replacing coal generation with large scale renewable energy generation as coal generation withdraws from service.132 AEMO states that, by 2036, 63 per cent (15.5 GW) of the existing coal generation fleet may retire. This would result in 49.5 GW of new generation, which may include wind (19 per cent), large scale photovoltaic (PV) (27 per cent), gas (24 per cent) and rooftop PV (30 per cent).133

130 IEA 2016, Re-powering markets: Market design and regulation during the transition to low-carbon, pp. 173, 177.

131 AEMO 2016, NTNDP, p. 3.

132 AEMO 2016, NTNDP, p. 4.

133 AEMO 2016, NTNDP, p. 24.


Hydro has an important role to play in supporting the changing generation mix because it has the advantage of being a renewable energy source that is also fully dispatchable—that is, Tasmania’s hydro power can be controlled and dispatched in response to AEMO’s instructions in order to maintain the balance between supply and demand within and between NEM regions. This is in contrast to wind and rooftop solar PV generation, which is non-dispatchable and whose output varies depending on the availability of wind and sunshine at different times of the day.134,135

7.2.1 Facilitating large scale renewable energy development in Tasmania

Tasmania has abundant high-quality, large scale renewable resources with the potential to contribute to a lower emission generation mix in the NEM. In particular, Tasmania has substantial hydro generation capacity—it has 30 power stations generating an average of 9000 GWh of renewable energy per year.136

Beyond hydro, wind farms provide the most significant Tasmanian large scale renewable energy generation source. Tasmania has an abundance of locations with high-quality wind resources that also coincide with areas of relatively low population density. In contrast, many other Australian wind development opportunities are located closer to established communities with greater potential for community opposition.137 Tasmania currently has 308 MW of installed capacity from three wind farms.138

The combination of Tasmania’s wind and hydro resources is also advantageous because Tasmania’s hydro storages can provide large scale energy storage capability. When the wind is blowing, wind farms can generate into the electricity grid, allowing water storage levels to be maintained for later use when it is more valuable or when less wind energy is available.139

A question for the study is how best to develop and use Tasmania’s current and prospective large scale renewable resources. Although there is potential in Tasmania for development of a range of renewable sources, such as large scale solar farms, biomass, wave and geothermal energy, wind power is the most likely resource for development in the short to medium term. Wind is expected to remain one of the most cost-efficient forms of renewable energy,140 and Tasmania has highly productive wind resources and prospective areas for future development.

Under its neutral economic growth scenario, AEMO projected the development of up to 730 MW of new wind capacity in Tasmania by 2036 even without a 2IC.141,142 Without further interconnection, AEMO projected that Tasmania can accommodate no more than 1100 MW of existing and new wind farms before becoming constrained by transmission limitations.143

134 Some large scale renewable generators are semi-dispatchable in that their generation can be curtailed by AEMO but they cannot be relied upon to start or increase generation when needed.

135 AEMO 2016, NTNDP, p. 72.

136 Hydro Tasmania 2016, Submission to the Tasmanian Energy Security Taskforce consultation paper, p. 9.

137 Information supplied by Hydro Tasmania.

138 Tasmanian Energy Security Taskforce, Consultation paper, p. 11.

139 Hydro Tasmania 2011, The Power of Nature—Tasmania’s renewable energy from water and wind, p. 10

140 CO2CRC 2015, Australian power generation technology report, p. V.


142 AEMO’s modelling projections do not consider in detail the costs and practicalities of wind generation development, financing and construction and connection to the Tasmanian network. The installed capacity of wind generation in Tasmania may vary once these and other market factors are considered.



AEMO’s modelling did not expect installation of any large scale solar PV capacity in Tasmania, but it projected that up to 330 MW of additional rooftop PV would be connected over the next 20 years, independent of a 2IC.144 Figure 6 shows the installed capacity for Tasmania projected by AEMO under its neutral scenario base case over the next 20 years.

Figure 6: Projected total installed capacity in Tasmania by fuel type to 2035–36145

Over 300 MW of wind farm developments have been proposed in Tasmania (Granville Harbour (100 MW), Cattle Hill (200 MW) and Low Head (30 MW)). There is also the potential for wind farms at Robbins Island and elsewhere in north-west Tasmania. Existing (blue) and possible (green) wind farms and possible pumped hydro (purple) in Tasmania are identified in Figure 7.




Figure 7: Existing and possible wind farms and pumped hydro in Tasmania146

146 AEMO 2017, Second Tasmanian interconnector, p. 15. This map shows only potential new renewable energy generation modelled by AEMO for this study.


7.2.2 Challenges of market structure in Tasmania

While Tasmania has significant wind resources, there are complex issues that need to be considered in its development. In particular, the market structure in Tasmania creates some challenges for wind farm development. Wind farms rely on being able to secure long-term PPAs to underpin their investment and must be able to find a PPA counterparty.

There are three broad options for a counterparty for a wind farm development in Tasmania:

1. Hydro Tasmania

2. a counterparty in Tasmania, such as Aurora or a major industrial load

3. a counterparty from elsewhere in the NEM.

Hydro Tasmania is the dominant counterparty for PPAs in Tasmania. This is the case for three reasons. First, its market power in the wholesale market in Tasmania allows it to mitigate price impacts when wind farms are not producing electricity and to deploy other sources of generation to offset the intermittency of wind. Secondly—and this point is related to the first—these other sources of generation are principally hydro, which are flexible and able to ramp up quickly. For these reasons, Hydro Tasmania is better placed than other purchasers of PPAs to take ‘volume risk’ (the risk of low output from the wind farm) under a PPA. Thirdly, Hydro Tasmania has less risk in using power purchased under a PPA in Tasmania to offset demand it has in the rest of the NEM through its retailer, Momentum, because it is able to bid Basslink under the BSA.

The fact that the other counterparties listed above do not have these characteristics means that they cannot offer PPAs on terms as competitive as Hydro Tasmania can. For example, Aurora has load in Tasmania, but it does not have a natural hedge against the intermittency of wind. Also, potential counterparties in the rest of the NEM would be exposed to basis risk in purchasing electricity under a PPA in Tasmania because the spot price in Tasmania can diverge from the spot price in Victoria.

Hydro Tasmania’s market dominance gives it a commercial advantage in negotiations with wind farm investors because it effectively removes the ability of wind farm developers to find other offtakers for their electricity. This makes wind investment within Tasmania more challenging for developers.

It should be noted that the discussion above relates to the sale of energy, not renewable energy certificates (RECs) under the RET. Since there is only one price for RECs, they can be more readily traded across borders and therefore there is more competition.

7.2.3 The 2IC’s role in developing Tasmania’s dispatchable renewable energy resources

AEMO has noted that a 2IC would increase the financial viability of renewable generation in Tasmania, reducing the risk of it being constrained because of transmission limitations and increasing access to the broader NEM.147 AEMO’s modelling showed that a 2IC could facilitate approximately 365 MW of additional Tasmanian wind generation capacity by 2036 relative to the base case of up to 730 MW new wind.148 Tasmania’s relatively rich wind resources are more capable of export with a 2IC, while Tasmania’s ability to import electricity during off-peak periods increases the flexibility of the Hydro Tasmania generation portfolio to maximise the value of stored water while reducing NEM dispatch and investment costs.149


148 AEMO 2017, Second Tasmanian interconnector, pp. 21, 23.



AEMO has suggested that the reliance on wind generation from Tasmania will increase over time as coal generation progressively retires. As wind penetration increases in a particular region in the NEM, there will be a diminishing return on further developments because the correlation of wind generation in locations that are geographically close together is relatively high. Conversely, increasing the geographical diversity of intermittent generation developments is expected to smooth the variability of renewable energy flows.150 In that respect, investment in a 2IC could make an efficient contribution by allowing a higher volume of Tasmania’s dispatchable renewable energy to be exported into the interconnected NEM.

A key benefit of a 2IC is that Tasmania’s wind and hydro resources could be used more effectively. Modelling by EY and AEMO indicated that a 2IC would enable Tasmania’s hydro generation to be more easily exported to the rest of the NEM at times of greater value—during high-demand periods or when renewable generation was low. This would lead to conservation of water during low-value periods for subsequent export during high-demand, high-value periods. A 2IC would therefore allow Tasmanian water storage facilities to be operated in a manner similar to a large generator or storage for other NEM regions by flexibly providing or absorbing power to and from Tasmania as needed.

More efficient use of Tasmania’s hydro resources, facilitated by a 2IC, could provide market benefits in terms of both variable cost reductions, where lower cost dispatchable renewable energy could be substituted for more expensive gas generation; and capital cost deferrals, where better use of Tasmania’s hydro facilities defers the need for investment in high-cost gas generation in the rest of the NEM.

AEMO has commented that, with 600 MW of increased interconnection capability to export available hydro generation, up to 600 MW of gas generation could be deferred in the rest of the NEM.151 With increased interconnection, the export of additional wind generation can be expected to supply energy to the NEM that CCGT otherwise would be needed to provide.152

However, it is important to note that the hydro generation in Tasmania does not have unlimited flexibility. In particular, the Mersey Forth, Derwent and Anthony Pieman schemes have a number of generators with very limited storage. This means that, at times, non-discretionary hydro output can be significant, particularly during high seasonal inflows. If this occurs at times of high wind output, this may constrain export flows and cause either water to be spilled or wind generation to be curtailed. Either possibility effectively reduces the benefits of Tasmania’s hydro flexibility and superior wind resource.153

7.2.4 Impacts on timing and magnitude of expansion of Tasmania’s renewable energy

Tasmania has good wind resources and a 2IC could unlock some development. However, there are factors that may impact the timing and magnitude of wind development.

Tasmania’s location presents some challenges. If Tasmania’s wind capacity was expanded in conjunction with a 2IC, much of the generation that results will be exported across both the existing Basslink and a 2IC. Line losses would occur in transporting power to the interconnectors across the regional boundaries and from the connection points in Victoria to demand centres. This would reduce some of the advantage of Tasmania’s high wind capacity factors.154







In addition, AEMO’s modelling found that building new renewable generation in Tasmania (1200 MW of wind) timed to coincide with commissioning of a 2IC (around 2025–26) would not increase its projected market benefits. Although this case delivers benefits, the additional capital investment costs outweigh the benefits gained. This is largely due to the oversupply of renewable generation in the southern regions (South Australia, Victoria and Tasmania). Prior to the 2IC, renewable generation is already built in South Australia (facilitated by the RET) and Victoria (facilitated by the VRET and RET).155

Without further interconnection between Victoria and New South Wales, or further brown coal retirements, the additional Tasmanian wind generation will compete, at times, with other renewable generation in the rest of the NEM and is therefore not as beneficial as it would otherwise have been in the absence of these other renewable energy policies.156

The VRET establishes targets for renewable energy to represent 25 per cent of total Victorian generation by 2020, rising to 40 per cent by 2025.157 AEMO’s modelling projected that the VRET will deliver about 4800 MW of additional renewable generation in Victoria and is expected to encourage renewable generation proponents to locate within Victoria in preference to other regions.158

Modelling by AEMO suggested that, for Tasmania, the VRET may lower the value of the 2IC and defer substantial renewable generation build in the region until later in the period. Exporting local renewable generation from Tasmania to the rest of the NEM is more valuable if it displaces coal and gas generation rather than other renewable generation sources.159

The timing of wind build in Tasmania would also be influenced by the earlier development of an additional South Australian interconnector. Given the timing differences of the two interconnectors (a South Australian link by 2021−22 and a Tasmanian link by 2025−26), AEMO’s modelling shows that Tasmanian wind generation developments are likely to be delayed by South Australia’s first-mover advantage. However, while early development of the South Australian link is forecast to lead to delayed development for Tasmanian wind farms, the long-term development is likely to be enhanced by the prospect that developers will seek increased diversity in their wind generation portfolios.160

As the typical daily pattern for wind in Tasmania complements the profiles in regions such as South Australia, the operation of the two interconnectors would help to capture those efficiencies. For example, while Tasmanian wind capacity has greater daytime production, South Australia’s wind capacity has greater production near peak load times in the evening and overnight.161 These differences can help to smooth intermittency of wind generation in aggregate across the NEM if there is strengthened interconnection.

In summary, while a 2IC offers the potential to further develop Tasmania’s renewable energy resources to supply more efficient dispatchable renewable energy to the NEM, there are factors that are likely to delay the timing of these developments. While the expansion of Tasmania’s renewable energy capacity has not been shown to be a major outcome or benefit that would result from a 2IC, AEMO and EY modelling showed that the more efficient operation of Tasmania’s existing dispatchable and renewable resources is the principal market benefit to the NEM that is likely to result from a 2IC.




158 AEMO 2017, Second Tasmanian interconnector, p.20.



161 AEMO 2016, NTNDP, p. 33.


7.3 Energy securityThe move towards a lower emissions generation mix with a higher proportion of renewable energy generation is making it more difficult to maintain the operation of the power system within the relevant technical parameters of power system security encompassing frequency, voltage and fault levels.162 Currently, renewable energy technologies do not contribute in the same way as synchronous generation such as coal, gas and hydro to maintaining these technical parameters.

AEMO manages power system security through a number of measures, including ancillary services markets and contracts163 (where power system security refers to the operation of the power system within the technical parameters referred to above). This can be distinguished from reliability, which refers to the probability of supplying all consumer energy needs with the existing generation capacity and network capability. The components of power system security are presented in Box 8.

BOX 8: Components of power system security

Frequency: Frequency is a measure of the instantaneous balance of supply and demand. Changes in electricity supply and demand can increase or decrease the frequency. AEMO manages frequency in a number of ways, including by procuring FCAS. FCAS is typically provided by synchronous generation such as coal, hydro or gas.

Inertia: The power system has a level of inertia, which helps resist changes of frequency and mitigate the effects of a disturbance of the power system. Inertia is naturally provided by large spinning conventional generators such as hydro, coal and gas generators that are synchronised to the frequency of the system.

System strength: System strength is a broad measure of the maximum current that is expected to flow in response to a short-circuit at a given point in the power system. A reduction in system strength may occur as the generation mix changes.

7.3.1 Benefits of a 2IC for energy security in the broader NEM

Interconnectors can contribute to energy security in the regions they connect. For example, an alternating current (AC) interconnector, such as Heywood between South Australia and Victoria, allows two regions to be synchronously connected and allows inertia and power system security services to be shared between the two regions.

A 2IC would reasonably be expected to incorporate advances in interconnector technology since Basslink’s construction. In particular, new voltage sourced converter (VSC) technology is now commercially available.

VSC technology has advantages over the line commuted converter (LCC) technology used by Basslink. It offers instantaneous changes in the direction of power flows and capacity to provide continuous FCAS and voltage support through injecting or absorbing reactive power.164 It could also provide Network Support and Control Ancillary Services and system restart capabilities.165 In contrast, Basslink does not operate at a power flow of below 50 MW and requires a period with no power transfer before it can change the direction of its power flow.


163 All NEM ancillary services can be grouped under one of the following three major categories: frequency control ancillary services (FCAS)—to maintain the frequency on the electricity system close to 50 cycles per second (50 hertz); network support and control ancillary services (NSCAS)—to control the voltage and power flow through the network; and system restart ancillary services (SRAS)—reserved for situations which there has been a complete or partial system blackout and the electricity system must be restarted.

164 Information provided by Hydro Tasmania.

165 EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 32


During this no power transfer period the Tasmanian network must source all of its FCAS locally. Basslink also requires higher system strength to operate than a VSC would need.166

AEMO’s modelling considered the NEM-wide benefits of a 2IC using VSC technology. As noted in Chapter 4, AEMO concluded in its 2016 NTNDP that additional power system security support is not needed in the rest of the NEM because these support services are adequately provided by existing hydro generators in Tasmania and Victoria.

7.3.2 Impacts of a 2IC on energy security in Tasmania

Potential contribution of a 2IC to energy security in Tasmania

In Tasmania, key sources of FCAS are Basslink, Hydro Tasmania’s hydro generating units (which can also be run as synchronous condensers) and the TVPS.167 To manage larger contingencies there are other options, including the SPS (described in Chapter 5) which would trip load or generation to meet system requirements.168

AEMO’s 2016 NTNDP indicates that the current levels of regulation FCAS in Tasmania exceed the projected need.169 The exception to this is if there was a significant reduction in Tasmanian demand, which would affect the viability of the SPS. In these circumstances, a 2IC could improve frequency control in Tasmania and allow for increased imports from Victoria to Tasmania.170

Despite this, there may be power system security benefits in having a 2IC. While power system requirements are currently able to be met by Hydro Tasmania, this does come at a cost. Foremost among these is that, when hydro units are run to support the system, they do not operate optimally in terms of energy production. Not only is the amount of energy produced reduced but also the units would run inefficiently and the amount of wear and tear would increase. Further, operating a hydro unit as a synchronous condenser consumes energy.171 Activating the SPS would come at the cost of lost production. A 2IC could operate to provide additional FCAS in Tasmania and avoid these impacts.

Energy security challenges of a 2IC in Tasmania

A 2IC could increase the power system security challenges in Tasmania. Tasmanian regions, such as George Town, can experience voltage control difficulties.172 At times of low spot prices in Victoria or low water storage levels in Tasmania, a 2IC would enable higher imports from Victoria, leaving fewer hydro generators in service in Tasmania. AEMO found that this could result in reduced system inertia, lower availability of FCAS and weaker system strength in Tasmania. If a 2IC were to be developed, these power system security challenges would have to be overcome through measures such as construction of new transmission lines, use of synchronous condensers or the installation of dynamic reactive support at the George Town substation.173

166 Information provided by Hydro Tasmania.

167 OTTER 2016, Energy in Tasmania report 2015−16, p. 11.

168 Hydro Tasmania 2016, Managing a high penetration of renewables—A Tasmanian case study, p. 8—provided as part of a submission dated 13 October 2016 to the AEMC System Security Market Frameworks Review.

169 AEMO 2016, NTNDP, p. 65.


171 Hydro Tasmania 2016, Managing a high penetration of renewables—A Tasmanian case study, p. 4—provided as part of a submission dated 13 October 2016 to the AEMC System Security Market Frameworks Review.

172 AEMO 2016, NTNDP, p. 99.



7.3.3 Alternative options

A 2IC is one potential option that would address Tasmania’s energy security and reliability concerns. TEST is considering other energy risk management measures for Tasmania, including:

• new prudent water storage thresholds

• the opportunity for further renewable energy development in Tasmania

• the future role of gas generation

• consumer participation opportunities, including emerging technologies.174

Tasmania will need to implement short-term and medium-term measures in light of the TEST final report. Therefore, it is likely that many of the TEST recommendations will be implemented well before a 2IC could be completed. The incremental Tasmanian energy security benefits that might result from a 2IC in the longer-term may be reduced significantly when the benefits of these short-term and medium-term initiatives are taken into account.

It would probably be necessary to maintain and continue to operate the CCGT unit of the TVPS to maintain energy security and reliability without the redundancy of a 2IC. Modelling for the study indicates that there are significant market benefits which could be obtained from a 2IC if the TVPS were to be kept operational, particularly in an environment where generation such as brown coal leaves the market.175

Further, governments will need to consider the consequences of Basslink reaching the end of its (estimated) 40 year economic life. Total loss of Basslink could involve risk to reliability and security of supply, loss of generation and revenue opportunities for Hydro Tasmania and other associated consequences (such as higher electricity supply costs).176 The benefits of investing in a 2IC may increase if there is a reason for regarding it as a replacement asset for Basslink at some point during its economic life.

While a 2IC could provide some power system security and reliability benefits (as discussed in Chapter 5) and a redundancy option for Basslink, these benefits would be incremental to those likely to be provided much earlier by options implemented as a result of recommendations of TEST. These alternatives for enhancing Tasmanian power system security and reliability of supply are likely to be more efficient, lower cost and be implemented before the 2IC is commissioned.

174 TEST 2016, Interim Report, pp. 58, 93, 136, 143



57Implications for consumers

8 Implications for consumers This chapter considers the implications a 2IC would have for electricity consumers, including how the total costs involved are likely to be recovered and allocated between consumers in Tasmania and Victoria. It examines the different cost implications for consumers depending on whether the 2IC operates as a regulated or a merchant interconnector.

KEY FINDINGS

• The costs of a 2IC would be recovered from consumers through either the wholesale or the network component of consumer bills.

• The allocation of the costs would differ depending on whether a 2IC was a regulated or a merchant asset. A merchant 2IC would recover its costs through spot market trading. A regulated 2IC’s costs would be recovered through regulated revenues approved by the AER.

• For a regulated 2IC, the revenues would be recovered from Victorian and Tasmanian consumers according to the proportionate direction of flows across the interconnector.

• A regulated 2IC would also have the effect of reducing constraints between Victoria and Tasmania, resulting in convergence of wholesale prices between the two regions.

• The impacts on consumers of a merchant 2IC would depend on the owner’s strategy in bidding the interconnector.

• If the bidding strategy was to maximise the differential between Tasmanian and Victorian spot prices, Tasmanian spot prices would be kept relatively low when the 2IC was exporting and relatively high when it was importing.

• If the bidding strategy was more passive (as it may be with a BSA type of arrangement in operation) the wholesale price outcomes would be similar to those for a regulated 2IC.

• A 2IC would also offer benefits to consumers, including in respect of reliability of supply and market competition, as discussed in Chapter 4.

As in Chapters 6 and 7, this chapter assumes a 2IC would be economically efficient for the purpose of considering the likely costs and benefits for electricity consumers of a regulated or a merchant 2IC.177

Importantly, while a 2IC would impose costs on consumers, it would also provide them with market benefits. While these would not necessarily be as tangible as the costs, over the longer-term a 2IC would facilitate efficiency benefits and contribute to reliability and security of supply. By reducing constraints between Tasmania and Victoria, it would also provide market competition benefits. The potential market benefits of a 2IC are discussed in greater detail elsewhere in the study, where the conclusion is that, based on the modelling projections that are currently available, those benefits are unlikely to outweigh the costs in many of the scenarios analysed.

177 This assumption is in contrast to the approach and analysis undertaken in Chapters 4 and 5, which addressed the question of whether or not a regulated 2IC investment would be economically efficient.


8.1 Allocation of costs The costs of a 2IC would be significant. They would involve:

• interconnector construction and operation

• related network augmentations.

It is estimated that up to $1.1 billion178 would be required for the construction of the 2IC itself and associated network augmentation.

In considering the likely cost implications for consumers, it is relevant to note there are different cost components to consumer bills. These can broadly be grouped into three categories:

• competitive market costs (including retailer costs such as hedging)

• regulated network costs

• environmental policy costs.179

Figure 8 represents a generalised breakdown of the cost components in the electricity supply chain, including their relative proportion.

Figure 8: Generalised components of electricity supply chain costs180

178 Information provided by the Tasmanian Government, as discussed in Section 3.3. As noted in Chapter 5, cost estimates are preliminary in nature and have the potential to vary considerably.

179 Based on AEMC 2016, Residential electricity price trends report, p. 76.

180 AEMC 2016, Residential electricity price trends report, p. 191 (adapted from Figure I.1).


This breakdown of the electricity supply chain costs demonstrates how the costs associated with a 2IC are likely to impact on retail prices and consumer bills. In general, regulated network costs are recovered in revenues set by the AER and passed through to consumers in retail prices. However, if a 2IC’s costs are recovered through the wholesale market (if a 2IC is a merchant asset), the extent to which those costs will be borne by consumers depends on competition at both the generation and retail levels. For example, the impact on consumers will depend on how the 2IC and other generators bid, price outcomes in the market and retailers’ hedging strategies and costs.

A 2IC could indirectly affect the costs relating to environmental policies that are included in Figure 8. The RET, for example, is a subsidy for renewable energy paid for by consumers. Its costs are recovered from consumers through retail bills. What these costs will be depends on the rate of renewable energy development and the future price for RECs. If the 2IC facilitates the development of wind energy, it may affect the costs passed through to consumers under these policies.

8.1.1 Interconnector construction and operation costs

Whether the 2IC is regulated or merchant will determine which element of the electricity supply chain its costs would be recovered through, and therefore how these costs impact on consumer bills.

Regulated interconnector

Regulated revenuesA regulated 2IC would be able to recover its costs through regulated revenues determined by the AER, regardless of the interconnector’s utilisation.181 It would only be approved as a regulated asset if it had satisfied the RIT-T by demonstrating that the costs to electricity consumers as a whole were outweighed by the expected benefits it would provide.

In most cases, regulated revenue is calculated every five years for TNSPs.182 The AER sets these revenues to enable the recovery of capital expenditure and financing costs (assessed on the regulated asset base and projected investments) and operating costs. The regulated revenues are then converted into transmission charges. These are passed through to retailers, which recover them from consumers as part of the network component of consumer bills.

Transmission chargesThe NER provides the mechanism by which transmission charges (including for the recovery of regulated interconnector costs) are determined. The AER determines the revenues to be earned by a regulated interconnector over five years. Those revenues would be converted into costs to be recovered annually from consumers at each end of the interconnector. A portion of these costs (usually 50 per cent) would be recovered equally from Victorian and Tasmanian consumers. The remainder would be recovered on a locational basis, with reference to the proportionate use of the 2IC in serving the connected regions.183 For example, if the 2IC flowed towards Victoria 80 per cent of the time then 80 per cent of this locational component would be recovered from the Victorian region (subject to any further inter-regional charging, as described in Box 9).

181 AEMC 2014, Decision report—Last resort planning power—2014 review, p. 20.

182 AER, Our role in networks, https://www.aer.gov.au/networks-pipelines/our-role-in-networks (accessed 13 December 2016).

183 AEMC 2016, National Electricity Rules, Chapter 6A: Economic Regulation of Transmission Services Rules, clause 6A.23.3, pp. 864−867.

https://www.aer.gov.au/networks-pipelines/our-role-in-networks


The costs allocated to each region in respect of the 2IC would then be recovered by the TNSP in that region from consumers at its transmission connection points. These costs would be added to the costs that the TNSP recovers from consumers in respect of its own network.184 These additional charges would be allocated to connection points on the same basis.185 Most of these connection points are points of intersection with distribution networks. The distribution networks would pass the cost through to retailers, who in turn pass the costs on to consumers.

There is a mechanism by which a portion of transmission costs within one region of the NEM can be allocated to another region. This would include costs allocated from one region to another where the network assets in one region support power flows to other regions. This is described further in Box 9.

BOX 9: Inter-regional transmission charging

Inter-regional charging was introduced into the NER in 2013 in the form of a modified load export charge (MLEC). This mechanism gives TNSPs a way to recover from neighbouring regions the costs associated with the use of assets that support inter-regional flows.186 The mechanism aims to better reflect the benefits that transmission provides in supporting energy flows between regions in the NEM.

Inter-regional charging applies to all transmission costs within a region. This makes it relevant to costs associated with both the construction and operation of a regulated 2IC as well as any associated network augmentation.

The proportion of costs allocated from one region to another is determined by analysing electricity flows and the assets which support flows into other regions. The allocation of costs between regions is determined on a net basis, reflecting that all regions both import and export electricity.187

Inter-regional charges form a relatively small proportion of overall transmission costs. During the 2016−17 financial year, the net amount that Tasmania188 will recover from the Victorian region is approximately 3.79 per cent of the total Tasmanian transmission costs.189 These costs do not include the recovery of costs for Basslink as it is not a regulated asset.

Effect on spot pricesA regulated 2IC is also likely to have an impact on the wholesale market, including price outcomes, which will in turn affect Victorian and Tasmania electricity consumers. As demonstrated by Figure 9, Victorian and Tasmanian spot prices, while linked, are not identical.

184 Murraylink Transmission Company Pty Ltd 2012, Pricing methodology 2013 to 2023, requirement (d), p. 3.

185 Analysis derived from the following sources: AEMC 2016, National Electricity Rules, Chapter 6A: Economic Regulation of Transmission Services Rules, clause 6A.23.3, pp. 864−867; AEMO 2015, Approved amended pricing methodology for prescribed shared transmission services from 1 July 2014 to 30 June 2019, pp. 17−24; TasNetworks 2015, Approved pricing methodology 1 July 2015 to 30 June 2019, pp. 6−17.

186 AEMC 2013, Inter-regional transmission charging, http://www.aemc.gov.au/News-Center/What-s-New/Announcements/Inter-regional-Transmission-charging (accessed 13 December 2016).

187 AEMC 2013, Rule determination: National Electricity Amendment (Inter-regional transmission charging) rule 2013, p. i.

188 The MLEC payable to Tasmania from the Victorian region is $7 056 107 (net MLEC is $6 573 970). Net MLEC has been calculated using the following sources: TasNetworks 2016, Modified load export charge from 1 July 2016 to 30 June 2017, p. 1; AEMO 2016, Modified load export charge for Victoria from 1 July 2016 to 30 June 2017, p. 1.

189 TasNetworks’ 2016−17 annual expected Maximum Allowed Revenue (smoothed) is $173.2. See AER 2015, Final decision: TasNetworks transmission determination 2015−2019, p. 10.

http://www.aemc.gov.au/News-Center/What-s-New/Announcements/Inter-regional-Transmission-charging

http://www.aemc.gov.au/News-Center/What-s-New/Announcements/Inter-regional-Transmission-charging


Figure 9: Quarterly volume weighted average spot prices in Tasmania and Victoria190

A regulated 2IC earns revenue regardless of utilisation, so it has no incentive to operate strategically. Its presence will therefore serve to reduce the constraints between Victoria and Tasmania and increase the unconstrained power flows between Victoria and Tasmania. This will bring the spot prices in these regions closer together, as demonstrated in Figure 10.

190 AER 2016, Quarterly volume weighted average spot prices, https://www.aer.gov.au/wholesale-markets/wholesale-statistics/quarterly-volume-weighted-average-spot-prices (accessed 13 December 2016). Figure 9 also demonstrates the price spike which occurred due to the outage of Basslink.

https://www.aer.gov.au/wholesale-markets/wholesale-statistics/quarterly-volume-weighted-average-spot-prices

https://www.aer.gov.au/wholesale-markets/wholesale-statistics/quarterly-volume-weighted-average-spot-prices


Figure 10: Effect of interconnectors on electricity spot prices191

There would be a number of consequences of the convergence of the Victorian and Tasmanian spot prices. EY indicates that greater unconstrained access to the Victorian market would increase the value of water in Tasmania and would be likely to result in Hydro Tasmania selling energy at higher wholesale prices.192

Further, with a 2IC in operation, long-term trends in Victorian spot prices would be expected to be reflected in Tasmanian spot prices in the future. For example, retirements of coal generation in Victoria are expected to increase spot prices in Victoria. The AEMC’s 2016 price trends report forecasts that the retirement of Hazelwood

191 AEMC 2016, Residential electricity price trends report, p. 25 (Box 2.2).



would lead to a 36 per cent increase in Victorian wholesale electricity purchase costs193 from 2016−17 to 2017−18.194 Any further generation retirements in Victoria would affect the spot prices in Tasmania if there was stronger interconnection between Victoria and Tasmania.

The potential for retirement of generation in Victoria should be considered in the context of the VRET, which may initially suppress prices as new renewable generation enters, but could result in subsequent price rises as this development hastens the retirement of Victorian thermal generators.

Stronger interconnection with a regulated 2IC could be expected to have a dampening effect on the anticipated Victorian spot price increases for the reasons illustrated in Figure 10. However, as a 2IC would be a relatively small proportion of Victoria’s electricity supply, this dampening effect is not expected to be large. In contrast, a 2IC would represent a relatively larger proportion of Tasmania’s overall electricity supply, so it may have a stronger effect on Tasmanian spot prices.

Merchant interconnector

The revenue earnings and subsequent costs to consumers of a merchant 2IC would be subject to its utilisation and to competition at the wholesale and retailer levels. The recovery of a 2IC’s costs in arbitrage trading revenues would depend on the direction and volume of electricity flows across the interconnector and the extent of spot price differences between the regions over time. These revenues would be more volatile and higher risk in contrast to a regulated 2IC.

Ultimately, the impacts on spot prices, and therefore the costs for consumers, would depend on the strategy the owner or operator adopts for how it bids a 2IC. In general, as a merchant 2IC would rely on the spot price differential between Tasmania and Victoria to earn its revenues, it would be incentivised to bid in a way that would maintain or even widen the differential. For example, this would mean that, if a 2IC was flowing north, it would increase revenues by keeping Tasmanian prices low and Victorian prices higher. At a time of supply shortage in Victoria, it could withdraw capacity, exacerbating the supply shortage and putting upward pressure on Victorian prices. This should mean wholesale prices flowing through to Tasmanian consumers would remain low. EY modelling on the basis of this bidding strategy supports this conclusion.195

On the other hand, there may be circumstances in which the owner of a 2IC would adopt a bidding strategy of bringing the spot prices in Tasmania and Victoria closer together. For example, if Hydro Tasmania were to control the bidding of a 2IC in the way it does for Basslink, EY modelling indicated that Hydro Tasmania would benefit more by bidding the 2IC at or close to zero to ensure the Tasmanian and Victorian spot prices would converge. This means Tasmanian wholesale prices would rise and Hydro Tasmania would earn more from the rest of its generation portfolio in Tasmania. In this case, spot prices in Tasmania would rise in a similar way to when the 2IC was regulated, and higher costs would flow through to Tasmanian consumers.

As discussed in Chapter 6, the financeability of a 2IC would be improved from an investor perspective if a third party such as Hydro Tasmania were contracted to pay a facility fee or availability charge to the owner of a merchant 2IC. This could extend to Hydro Tasmania receiving the rights to trade a 2IC, in which case the more likely strategy would be for it to bid the 2IC at $0/MW to bring the Tasmanian and Victorian spot prices together. This convergence in spot prices may impact costs for Tasmanian consumers.

193 Wholesale electricity purchase costs include spot prices and contract prices.

194 AEMC 2016, Residential electricity price trends report, p. 29.

195 EY assumed that a 2IC would be prevented from withholding capacity to raise Tasmanian prices and energy costs when a 2IC was importing. See EY 2017, Market dispatch cost benefit modelling of a second Bass Strait interconnector, p. 33.


8.1.2 Network augmentation costs

A 2IC is likely to require substantial network augmentation in Tasmania to accommodate additional power flows, including from new generators.196

In general, the costs relating to network augmentations would be recovered from consumers within the region where those augmentations take place and would be subject to AER revenue and tariff regulation decisions. Where approved by the AER, these augmentation costs would be recovered in network tariffs based on AER approved revenues and the tariff-setting methodology described above.

Inter-regional transmission charging could result in a portion of the augmentation costs being allocated to consumers in other regions.

196 AEMO found that a 2IC did not materially change projected transmission network augmentation in the rest of the NEM. See AEMO 2017, Second Tasmanian interconnector, p. 13.

65Planning and approval requirements

9 Planning and approval requirements

This chapter explores the potential governance arrangements which could assist with the business case, technical specifications and regulatory approval stages if the market circumstances emerge in the future that support making a commitment to develop a 2IC. It draws on work by the Electricity Supply Industry Expert Panel in 2012 to highlight the issues and learning from the development of Basslink. The Australian Government’s Major Projects Approval Agency has also identified potential cross-jurisdictional processes that a 2IC proponent may need to navigate.

KEY FINDINGS

• The development of a 2IC would be a major project development in Australia which would need to comply with relevant regulatory approvals across multiple levels of government.

• It would probably be declared a Project of State Significance in Tasmania because it would be a major development with statewide implications.

• If future market conditions indicate that a 2IC would be viable, the Tasmanian Government could consider establishing governance arrangements similar to those adopted for Basslink. The process undertaken for Basslink provides useful insight, especially regarding the management of potential delays in the regulatory approval processes.

• The initial groundwork on environmental and regulatory approvals, including a RIT-T if a 2IC was to be regulated, could be facilitated by establishing a development board.

• The Major Projects Approval Agency could play a role in assisting a 2IC proponent to navigate the relevant regulatory requirements and could facilitate engagement with communities, government and business.

• A coordinated approach could potentially streamline the development and approval process for a 2IC, saving time and money.

9.1 Basslink approval processBasslink is the only major subsea electricity cable to have been constructed in Australia. The development and approval stage took five years (1997–2002) and the construction of the interconnector took an additional three years (2002−2005). Figure 11 illustrates the approval and construction process for Basslink.


Figure 11: Basslink approval and construction process197

197 Adapted from Basslink Pty Ltd 2016, The Basslink Interconnector—History, http://www.basslink.com.au/basslink-interconnector/history/ (accessed 9 January2017) and Electricity Supply Industry Expert Panel 2012, Basslink: Decision making, expectations and outcomes, Chapters 1 and 2.

http://www.basslink.com.au/basslink-interconnector/history/


Key bodies which facilitated the development and approval processes for Basslink are discussed below.

Basslink Development Steering Committee

The Tasmanian Government established the Basslink Development Steering Committee (BDSC) in June 1997. The BDSC provided the state with advice on the economic, technical and environmental feasibility of Basslink with a view to having a merchant interconnector built and operating within four years.198 The BDSC found that interconnection with Victoria would be technically feasible and economically viable for proponents.

The BDSC also recommended that the Tasmanian Government call for expressions of interest from proponents interested in developing an interconnector.

Basslink Development Board

In response to the BDSC findings, the Tasmanian Government established the Basslink Development Board (BDB) in 1998. The BDB was responsible for taking the lead in developing Basslink as a commercial opportunity199 in the NEM as well as conducting the selection process to identify the project proponent. The BDB shortlisted expressions of interest, allowing potential proponents to propose development of either a merchant or a regulated interconnector.

The two final proponents that the BDB identified expressed doubts regarding the development of Basslink as a regulated interconnector. Their concerns related, in part, to the uncertainty and lack of clarity associated with the market benefits test200 which Basslink would be required to satisfy in order to receive regulated revenue, as well as the lengthy approval process. This reduced the attractiveness of developing Basslink as a regulated interconnector, and the Basslink process proceeded on the basis that it would be a merchant interconnector. The BDB also worked with project proponents to resolve issues regarding the commercial model to be adopted and the management of sovereign and counterparty risk.

Once the BDB transferred development of the project to the proponent, its role changed to ensuring that the obligations of each party were met and that the project reached financial close as soon as possible. It also continued to manage stakeholder relations.

Nominal company

A company, Basslink Pty Ltd, was established in 1998 to initiate work on matters such as preliminary environmental planning and impact assessment studies. This meant that an existing company which was already on the path to attaining regulatory approvals could be transferred to the eventual proponent when all contractual arrangements were finalised.

Joint Advisory Panel and other regulatory assessment processes

The construction of Basslink impacted on three jurisdictions: Tasmania, Victoria and the Commonwealth (as the cable went through Commonwealth waters in the Bass Strait). An independent Joint Advisory Panel (JAP) was set up to facilitate a single combined assessment process for the interconnector. The panel was made up of representatives from each jurisdiction. Its aim was to expedite the necessary environmental and regulatory approvals.


199 The Expression of Interest document refers to ‘a commercially viable business, developed in the NEM within a Build, Own, Operate framework’ without ‘any financial contribution by the Government, either direct or contingent’.

200 This test was similar in concept to the current RIT-T and was applied by the Australian Competition and Consumer Commission as the transmission network regulator at that time.


The combined approval and assessment was originally estimated to take around 10 months, but eventually it took 30 months from the time the project proponent was selected to get the final approval from the JAP. This resulted in a significant increase in Basslink’s project development costs and a significant extension of the project completion timeline. Basslink was eventually commissioned some three years later than originally proposed.

The Electricity Supply Industry Expert Panel found that the total cost of Basslink increased from approximately $500 million to almost $875 million by commencement of operations in 2006.201 The majority of these increased costs were incurred during the approval process from 2000 to 2002 as a result of various design changes required to meet environmental and development approvals.202 Major changes included the provision of a metallic return in the interconnector’s design, changes to route and subsea cable burial, and various additional development and construction costs.

9.2 Considerations for a 2ICThe development of a 2IC would be a major project development in Australia, and it would need to comply with all relevant regulatory approvals across multiple levels of government.

A 2IC proponent would need to factor in construction time as well as the time and cost of attaining regulatory approvals, such as planning and environmental approvals.

Although regulatory and approval requirements and processes will have changed since the development of Basslink, the governance arrangements used for the Basslink process may be a useful starting point in planning implementation processes for a 2IC if market conditions emerge that would make it viable. A coordinated approach would allow the requirements of all governments to be met in an efficient and timely manner. An illustrative action plan is provided at Box 10. The action plan shows the range of actions that could be taken to develop appropriate management arrangements and governance structures to oversee planning, decision-making and implementation for the investment in a 2IC.

Project of State Significance

If a 2IC was feasible and was to be built, it would probably be deemed a Project of State Significance in Tasmania (POSS). A POSS is declared when Tasmanian projects are recognised as major developments with statewide implications. A POSS would be assessed under the Tasmanian State Policies and Projects Act 1993.203

If the Minister for State Growth in Tasmania considers that a 2IC is a POSS, the Minister may recommend that the Governor of Tasmania declares the proposal to be a ‘project of State significance’. The project must then be approved by the Tasmanian Parliament before an assessment can begin. If the 2IC were to be approved, the Minister would direct the Tasmanian Planning Commission to undertake an integrated assessment of the proposal.204


202 Electricity Supply Industry Expert Panel 2011, Basslink: Decision making, expectations and outcomes, pp. 20−22.

203 Tasmanian Department of State Growth 2015, Projects of state significance, http://www.stategrowth.tas.gov.au/ti/home/major_projects/projects_of_state_significance (accessed 13 December 2016).

204 Tasmanian Department of State Growth 2015, Projects of state significance, http://www.stategrowth.tas.gov.au/ti/home/major_projects/projects_of_state_significance (accessed 13 December 2016).

http://www.stategrowth.tas.gov.au/ti/home/major_projects/projects_of_state_significance





Major Projects Approval Agency

The Major Projects Approval Agency (MPAA) is an Australian Government initiative which provides a single point of entry for businesses that are considering major investments in Tasmania and the Northern Territory. The MPAA could assist the developer of a 2IC by providing information on all government regulatory approval requirements and on the approval obligations for a 2IC. It could also work with regulators to facilitate effective and efficient approvals. The involvement of the MPAA would assist the developers of a 2IC to navigate the approvals process.

BOX 10: Illustrative action plan

If future changes in market conditions and frameworks improved the viability of a 2IC investment, the Tasmanian Government could proceed with the following actions.

Organisation Action

1. Tasmanian Government • Establish a steering committee.

2. The steering committee • Develop a business case to provide recommendations on how the government should proceed (with Victorian Government agreement).

If a 2IC is found to have net market benefits through that business case, the following actions could be taken.

Organisation Action

1. Tasmanian Government • Set up an entity (2IC development board) to progress the approvals processes for a 2IC.

2. Development board • Develop a 2IC on behalf of the state and identify a proponent to take the project forward.

• Establish a nominal company to progress project.

3. Nominal company • Undertake the RIT-T if the 2IC is to be regulated.

• Establish a joint advisory panel (Victoria, Tasmanian and Commonwealth governments) to progress approvals.

• Continue to refine interconnector preparatory work, including associated network technical specifications and route selection.

• Initiate preliminary environmental planning and impact assessment studies such as visual assessment, flora and fauna, cultural heritage, geology and hydrology, marine and coastal, social impacts and electro-magnetic fields.


10 Conclusions and recommendationsThe NEM is undergoing a rapid transition towards a lower emissions generation mix, making it difficult to predict, with the requisite degree of confidence, the energy market supply and demand conditions and regulatory settings that will apply during the economic life of a 2IC. While AEMO’s annual NTNDP remains the best source of information on likely future energy market conditions, it covers only a 20 year period. Currently anticipated changes in energy market conditions suggest that a wide range of potential development paths could emerge for the NEM over the next 20 years and more. Therefore, a business as usual projection of the future energy market conditions would not be appropriate. The heightened uncertainty regarding the future investment environment for a 2IC has been acknowledged as a reality in the study.

The analysis undertaken sought to address this uncertainty by projecting the NEM-wide costs and benefits that could be generated by a 2IC under a range of plausible assumptions about future energy market conditions. This analysis established that a 2IC would deliver significant economic benefits to the NEM, and to Tasmania, by facilitating more efficient use of Tasmania’s existing hydro and gas generation facilities. However, while under some modelled scenarios, the potential benefits exceeded the capital and operating costs of a 2IC and related network augmentation, under others the modelled benefits were exceeded by the costs.

The modelling analysis identified two future NEM development scenarios in which a 2IC would achieve a significantly positive net benefit feasibility assessment. The modelling found that a 2IC would deliver positive net benefits if there was a significant future reduction in Tasmanian electricity demand because the resulting surplus generation could be exported rather than being wasted due to constrained interconnection. The development of an additional interconnector linking South Australia with the eastern states before a 2IC is constructed was also found to result in larger net economic benefits than those resulting from each of the interconnectors when assessed separately. This effect was further amplified when these investments were combined with additional interconnector upgrades from New South Wales to Victoria and New South Wales to Queensland, resulting in larger positive net market benefits from a 2IC under most of the scenarios modelled. AEMO concluded in its 2016 NTNDP that integrated strengthening of the interconnected power grid in this way would deliver synergies by facilitating complementary utilisation of the diversity of renewable generation among the NEM regions.

While the modelling analysis has been informative in understanding the market dynamics and forming views about the economic feasibility of a 2IC, the modelling did not evaluate a number of potential benefits from a 2IC that would be allowable under a RIT-T analysis, including competition benefits, some power system security and reliability benefits and option value benefits. Power system security benefits in particular are likely to be in greater demand and valued more highly in the future than they have been historically. There is also potential for different weightings to be placed on the various categories of benefit generated by a 2IC compared to those assigned in the modelling. For example in current market circumstances, electricity consumers and governments may place a higher value on the energy security and reliability benefits from a 2IC than is captured in the modelling results.

A 2IC would also facilitate development of Tasmania’s productive wind energy resources by increasing the capacity for export of balanced and dispatchable renewable energy to the rest of the NEM. However, most of that wind development was forecast to occur in the late 2020s and 2030s due to earlier build of renewable generation in Victoria and South Australia. A 2IC would provide reliability benefits to Tasmania and Victoria, supporting reliability in Tasmanian at times of drought and low water storage levels and in Victoria during peak demand periods. A 2IC could also transfer power system security services between Tasmanian and Victoria, although those benefits would be incremental to their current availability through Basslink and other sources in the NEM. They would also be incremental to power system security benefits provided by initiatives likely to result from the TEST review, which may be implemented earlier and at lower cost.

71Conclusions and recommendations

The feasibility of a 2IC would also depend on whether a regulated or merchant commercial model is chosen for its operation. The choice of model would affect the scale of the revenues earned and their volatility and riskiness which would in turn affect the financeability of the project. While modelling indicated that a merchant 2IC could potentially earn higher revenues and profits than a regulated 2IC, the merchant revenues would be highly volatile and risky. For that reason, financing advice indicated that a regulated 2IC would be more attractive and financeable from an investor perspective due to its predictable regulated revenue stream and lower risk. However, a 2IC would need to satisfy the RIT-T to achieve regulated status, which would be a challenge under current market projections.

Regardless of how the NEM develops, a 2IC would have cost implications for electricity consumers. If a 2IC were regulated, the costs would be recovered from consumers through the regulated network component of their bills. These costs would be allocated to Tasmanian and Victorian consumers according to the proportionate direction of flows across the 2IC, with the region receiving more of the flows paying more of the costs. A merchant 2IC’s costs would be recovered through wholesale market trading revenues. Cost impacts on consumers would depend on the spot price differences between the regions, the volume of flows between them and competitive conditions in the wholesale and retail markets.

While a 2IC would result in benefits as well as costs for consumers, the critical issue for consumers is whether the NEM-wide benefits would exceed the NEM-wide costs. In the case of a regulated 2IC, this question would be addressed by a formal RIT-T assessment. The issue does not arise formally in the case of a merchant 2IC, but modelling indicated that NEM-wide benefits would be lower for a merchant 2IC than for a regulated 2IC, due in part to an assumed capacity withholding strategy used to maximise arbitrage trading revenues.

Decisions that arise from the various energy market policy and regulatory reviews will have an important bearing on the development of the NEM and the future role of interconnectors. Policy consideration is currently being given to whether further strengthening of interconnection across the NEM can be justified when viewed as a system-wide strategy. The outcomes from these reviews will assist in clarifying the future NEM investment environment for long-term interconnection assets such as a 2IC.

Ongoing monitoring of these and related NEM developments would be appropriate to identify changes to energy market frameworks and conditions that would give added support to the case for strengthening interconnection across the NEM, including by investment in a 2IC.

AEMO is best placed to undertake this monitoring through its annual NTNDP reports and related network planning work, drawing on Hydro Tasmania and TasNetwork’s knowledge of the Tasmanian energy market environment, as necessary, to inform its consideration of the future role a 2IC could play. The future NTNDP planning framework will provide a NEM-wide context within which to form a considered view on the prospective economic feasibility of a 2IC as a precondition for initiating more detailed analytical work on the proposal. Other preconditions for initiating further detailed work would include a significant reduction in Tasmanian electricity demand and approval of the construction of additional interconnection between South Australia and the eastern states.

Should monitoring establish one or more relevant preconditions, a detailed business case should then be prepared by the Tasmanian Government, taking into account developments in the NEM since this study was undertaken.


RecommendationI therefore recommend that the Tasmanian Government develop a detailed business case for a second Tasmanian interconnector when ongoing monitoring establishes that one or more of the following preconditions has been met:

1. The Australian Energy Market Operator, in consultation with Hydro Tasmania and TasNetworks, concludes in a future National Transmission Network Development Plan that a second interconnector would produce significant positive net market benefits under most plausible scenarios.

2. Additional interconnection is approved for construction between South Australia and the eastern states.

3. A material reduction occurs in Tasmanian electricity demand.

73Appendix A

Appendix A: Terms of ReferenceThe Australian and Tasmanian governments will conduct a feasibility study into whether a second Tasmanian interconnector could improve Tasmania’s energy security and facilitate renewable energy investment.

The study will:

1. Analyse the extent to which a second Tasmanian interconnector would:

• address energy security issues;

• facilitate the development of Tasmania’s prospective large scale renewable energy resources;

• allow the development of dispatchable and balanced renewable energy into the National Electricity Market (NEM); and

• integrate with the Victorian electricity market and wider NEM.

2. Investigate how best to use and develop Tasmania’s current and prospective large scale renewable energy resources, noting the system security benefits provided by Tasmania’s hydroelectricity generation.

3. Advise on regulatory and financing issues and potential cost impacts on electricity consumers.


Appendix B: Stakeholder consultationsIn completing the study, targeted stakeholder consultations were undertaken with a range of energy market bodies, consumer groups, industry representatives and government stakeholders in Canberra, Sydney, Melbourne, Adelaide and Hobart. A public call was also made for submissions. The purpose of the consultations was to understand the diverse views, interests, opportunities and concerns about a 2IC. A general summary of stakeholder opinions is below.

Defining the problem

One of the consistent themes in the stakeholder consultations was that there was a lack of clarity concerning the problem at hand. Many stakeholders asked the question: ‘What problem is a 2IC trying to solve?’ Stakeholders highlighted that it is difficult to assess the feasibility of a 2IC without first understanding the purpose of a 2IC and the problem it will address—that is, whether a 2IC would address energy security in the NEM or encourage the development of renewable energy generation or a combination of both.

Renewable energy considerations

A consistent message from stakeholders was that renewable energy is becoming an increasingly significant part of the NEM. However, there are challenges in managing this transition, and the future direction of change in the NEM is uncertain. This is predominately due to the uncertainty about future emission reduction policies in Australia as well as uncertainty around the time frames for retirement of coal generators.

Stakeholders acknowledged that Tasmania has some of the country’s best wind resources and that there was generally minimal resistance to local wind farm developments from communities. Stakeholders were also of the view that growth and development of large scale wind generation in Tasmania was contingent on the construction of a 2IC and associated network augmentations. Some stakeholders supported the notion that building a 2IC would stimulate wind investment in Tasmania and, in turn, allow the export of balanced and dispatchable renewable generation to Victoria.

Other stakeholders noted it might be more efficient to invest in wind generation in Victoria. They pointed out that the overall cost of this would be lower than the cost of building a 2IC and more wind generation in Tasmania. Stakeholders noted that further integration of wind in Tasmania would be likely to mean that additional network augmentation was needed, which would further increase the overall NEM-wide costs of a 2IC.

Many stakeholders highlighted the lack of competition in Tasmania’s energy market due to Hydro Tasmania’s market power. This creates challenges for wind farm developers in Tasmania in securing long-term power purchase agreements (PPAs).

75Appendix B

Costs and benefits to consumers

Some stakeholders raised concerns about how the costs of a 2IC would be allocated, in terms of geographical location, and whether the benefits for consumers would outweigh the costs. Many stakeholders expressed an opinion that a 2IC would not be feasible based on the benefits to Tasmanians alone and that benefits would have to flow to several regions of the NEM for the project to be feasible. Stakeholders in Tasmania noted it could be difficult to communicate the costs to Tasmanian consumers in particular, since individual consumers were quite unaffected by the Basslink outage.

Stakeholders also noted that estimated costs for a large scale project such as an interconnector were likely to escalate during planning, approvals and construction, which would reduce initial estimates of net market benefits.

Energy security and reliability

One of the main concerns that stakeholders had about energy security and reliability was the costs associated with the project. Several stakeholders acknowledged that a 2IC could contribute to power system security and reliability. However, the majority of views suggested that stakeholders believed that improving the energy security of both Tasmania and the greater NEM can be achieved without a 2IC and that the predicted cost of a 2IC could instead be invested in other smaller projects with similar benefits. Stakeholders indicated that gas would potentially be a better option for improving energy security in Tasmania. Stakeholders also discussed the extent to which a 2IC would enhance the energy security of Victoria and the wider NEM, particularly in reference to the transfer of balanced and dispatchable renewable energy from Tasmania.

Some stakeholders noted that the security benefits that a 2IC could provide would only be the marginal benefits it could provide if Basslink was at capacity.

Time uncertainties

Stakeholders raised concerns that the lengthy planning, approvals and construction period required to commission an interconnector would lead to a risk that technology changes and natural evolution of the NEM may mean that a 2IC would be made redundant before it is completed. Stakeholders noted the time factor also meant that the interconnector would not be able to contribute to the Renewable Energy Target. Stakeholders considered that there is significant uncertainty surrounding policy settings, technology changes and the pace of energy market transformation, which may significantly alter the prospects of a 2IC.

Financing and commercial arrangements

There was a general agreement among stakeholders that the appetite for investment in a 2IC would be greater if the asset was regulated, as opposed to merchant, due to the lower risks associated with a regulated asset.

Feedback from stakeholders suggested that there may be interest among investors in financing both a 2IC and associated wind projects. This would be contingent on whether there were appropriate policy incentives to stimulate demand and whether there was a market for wind farm developers to sign PPAs.

Noting that the existing Basslink is a merchant interconnector, a question arose as to the interaction that Basslink would have with a 2IC. Stakeholders commented this would be highly dependent on whether the 2IC is regulated or merchant, because each outcome would result in a different relationship.

Appendix C 77

Appendix C: Australian Energy Market Operator Report: Second Tasmanian InterconnectorAEMO’s report: Second Tasmanian Interconnector, Report for the Tasmanian Energy Taskforce, January 2017.

SECOND TASMANIAN INTERCONNECTOR

REPORT FOR THE TASMANIAN ENERGY TASKFORCE

January 2017


Australian Energy Market Operator Ltd ABN 94 072 010 327 www.aemo.com.au [email protected]

NEW SOUTH WALES QUEENSLAND SOUTH AUSTRALIA VICTORIA AUSTRALIAN CAPITAL TERRITORY TASMANIA WESTERN AUSTRALIA

IMPORTANT NOTICE

Purpose AEMO has prepared this document to provide input into the Tasmanian Taskforce’s report into the feasibility of a second Bass Strait interconnector. It reflects market and power system modelling and analysis based on information available to AEMO as at 14 October 2016, unless another date is specified.

Disclaimer This report contains data provided by or collected from third parties, and conclusions, opinions, assumptions or forecasts that are based on that data. AEMO has made every effort to ensure the quality of the information in this report but cannot guarantee that the information, forecasts and assumptions in it are accurate, complete or appropriate for your circumstances. This report does not include all of the information that an investor, participant or potential participant in the gas market might require, and does not amount to a recommendation of any investment. Anyone proposing to use the information in this report should independently verify and check its accuracy, completeness and suitability for purpose, and obtain independent and specific advice from appropriate experts. This document or the information in it may be subsequently updated or amended. This document does not constitute legal or business advice, and should not be relied on as a substitute for obtaining detailed legal advice about the National Electricity Law, the National Electricity Rules, or any other applicable laws, procedures or policies. Accordingly, to the maximum extent permitted by law, AEMO and its officers, employees and consultants involved in the preparation of this document: make no representation or warranty, express or implied, as to the currency, accuracy, reliability or

completeness of the information in this document; and are not liable (whether by reason of negligence or otherwise) for any statements or representations

in this document, or any omissions from it, or for any use or reliance on the information in it. © 2017 Australian Energy Market Operator Limited. The material in this publication may be used in accordance with the Copyright Permissions policy available on AEMO’s website.


© AEMO 2017 1

EXECUTIVE SUMMARY AEMO has produced this report at the request of the Department of the Environment and Energy, to support the Tasmanian Energy Taskforce (the Taskforce) in its feasibility study into whether a second Tasmanian interconnector could improve Tasmania’s energy security and facilitate renewable energy investment. It summarises AEMO’s market and power system modelling and analysis, conducted to provide input into the Taskforce’s final report. As the national transmission planner, AEMO has taken a strategic approach to this assessment, focusing on efficient development across the National Electricity Market (NEM) in the long-term interests of consumers. This includes consideration of how the NEM is likely to evolve in the future and what effects a second Tasmanian interconnector, or other interconnectors, would have on this evolution and power system operation.

AEMO has assessed:

The market benefits of a second interconnector between Tasmania and Victoria. The network augmentations and other power system changes required to facilitate the concurrent

development of a second interconnector and substantial additional wind generation in Tasmania. The potential benefits of further interconnector developments between Victoria and South

Australia, and the concurrent development of a second Bass Strait interconnector.

The analyses in this report identify the costs and market benefits associated with increased interconnection at a high level, and should not be interpreted as satisfying the requirements of a complete regulatory investment test for transmission (RIT-T) process.

AEMO’s key observations

Assuming neutral economic growth, a second interconnector with Tasmania is projected to deliver gross market benefits of $361 million over the next 20 years to 2035−36 by: Delivering $85 million savings in fuel and variable operating and maintenance costs, due to

production from hydro and wind generation in Tasmania primarily displacing higher-cost natural gas generation in the mainland NEM.

Facilitating the gradual development of additional renewable generation in Tasmania (mainly wind) to support supply changes in the mainland ($6 million in reduced environmental scheme costs).

Deferring the need for gas-powered generation (GPG) investments in the mainland NEM ($134 million market benefits).

Reducing reliance on voluntary demand curtailment and involuntary load shedding ($87 million market benefits).

Delivering $48 million of market benefits (including reliability benefits) in the event that the Basslink interconnector was out of service for an entire year.

Over the same period, the annualised cost of the second Bass Strait interconnector is estimated to be around $341 million.1 With projected net market benefits of just $20 million, further analysis would be required to justify this investment in the long-term interest of consumers.

Greater interconnection delivers synergies. Projected net market benefits of a second Bass Strait interconnector increase if an additional South Australian interconnector is built first. This is mainly because the development of more interconnection uses the diversity of renewable generation across the regions more effectively. It reduces the need for higher-cost gas

1 Total cost is estimated to be about $940 million, with an economic life of 50 years and weighted average cost of capital of 8.76%. Assuming a 7%

social discount rate, the $341 million cost represents the net present value (NPV) of annualised costs for the period to 2035–36, with the interconnector operational from July 2025.


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generation by allowing renewable generation in one region to complement the intermittency of renewable generation in another region.

The market benefits of a second Bass Strait interconnector are not robust. The interconnector is only economically justified in scenarios where it delivers capital deferral benefits in addition to fuel cost savings. If future operational demand is low, or emerging technologies such as utility-scale batteries become widespread, the ability for the interconnector to defer new generation build diminishes.

Building additional renewable generation in Tasmania may lead to oversupply. Building new renewable generation in Tasmania (1,200 megawatts (MW) of wind), timed to coincide with commissioning of the second Bass Strait interconnector, would not increase projected market benefits. New renewable generation is projected to be developed in Victoria to meet the proposed Victorian Renewable Energy Target (VRET)2, in which case any additional generation from Tasmania would lead to oversupply in the southern regions (Victoria, Tasmania, and South Australia). This would either drive further generation withdrawals or require stronger interconnection between Victoria and New South Wales.

Additional power system security support is not needed in Victoria. While a second Bass Strait Interconnector may provide power system security benefits such as frequency control ancillary services (FCAS), these support services are adequately provided by existing generators in Tasmania and Victoria.

Low system strength and inertia may need to be addressed in Tasmania. With increased interconnection and greater penetration of renewable generation, Tasmania's hydro generators will be able to operate more flexibly. Therefore, under certain conditions, there may be fewer hydro units online to provide system inertia and system strength in Tasmania. This could be addressed by using existing hydro and GPG operating as synchronous condensers, or implementing new network or non-network solutions such as new synchronous condensers, fast frequency services from wind generation, and battery storage.

Network investment will be needed in Tasmania. A second interconnector would require a new 220 kilovolt (kV) double circuit transmission line from Sheffield to Smithton (in Tasmania) and connection to the existing 220 kV Victorian transmission network at Tyabb (in Victoria), all of which has been included in the projected cost of the interconnector. There are no other material differences in intra-regional transmission network augmentation needs across the NEM, with or without a second Bass Strait interconnector.

Modelling scenarios AEMO has modelled additional interconnection and wind generation, as requested by the Taskforce, using three scenarios, Neutral, Low Grid Demand, and ‘45% Emissions Reduction’. These scenarios are same as those being modelled for AEMO’s annual National Transmission Network Development Plan (NTNDP)3, which provides an independent, strategic view of the efficient development of the NEM transmission grid over a 20-year planning horizon. Both economic growth scenarios assume the COP21 emission reduction commitment and the VRET are achieved. The ‘45% Emissions Reduction’ scenario assumes that greenhouse gas emissions in the electricity sector are reduced by 45% below 2005 levels by 2030.

2 The VRET specifies that renewable energy will represent 25% of total Victorian generation in 2020, rising to 40% by 2025. Victorian Government,

“Victoria’s renewable energy targets”, 2016. Available at: http://earthresources.vic.gov.au/energy/sustainable-energy/victorias-renewable-energy-targets. Viewed: 13 September 2016.

3 AEMO. 2016 National Transmission Network Development Plan, December 2016. Available at: http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Transmission-Network-Development-Plan.

COP21 commitment – Australia set a target at the Paris 21st Conference of Parties (COP21) to reduce carbon emissions by 26% to 28% below 2005 levels by 2030. The Council of Australian Governments (COAG) Energy Council has agreed that the contribution of the electricity sector should be consistent with national emission reduction targets.


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A number of case studies have been considered for all three scenarios, with each giving insight into the potential value provided by a particular interconnector development. Over the 20-year modelling horizon, significant change to the NEM generation mix is expected as various policies at state and federal level encourage increased uptake of renewable generation. This is while demand is forecast to remain relatively flat. The magnitude of the changing supply mix differs between the three scenarios, due to differences in demand outlooks: The Neutral scenario produces an evolving supply mix, with increased wind and solar projects

offsetting retirements of coal generators, particularly in New South Wales and Victoria. GPG augments renewable capacity to maintain system reliability in this scenario.

The 45% Emissions Reduction scenario projects an accelerated NEM evolution, with more synchronous generation withdrawals and greater renewable generation penetration.

The Low Grid Demand scenario projects a more rapid retirement of coal capacity on economic grounds, as electricity consumption reduces from current levels. Reduced opportunities are projected to exist for long-term renewable developments compared to the neutral scenario, although some GPG would still be required to replace lost firm capacity from retired coal-fired generation.

Under all three scenarios, there are projected net market benefits associated with increased capability of the existing VIC–NSW and QNI4 interconnectors in the 2020s ($123 million for the Neutral scenario, $86 million for the Low Grid Demand scenario, and $281 million for the 45% Emissions Reduction scenario). These augmentation options are included in all analyses including the ‘Base case’ in this report.

Results and insights The sections below discuss the results of AEMO’s analysis, across: The projected effects of interconnection development under the Neutral, Low Grid Demand, and

45% Emission Reduction scenarios. An assessment of requirements for transmission augmentation in Tasmania, as well as

any material changes to the mainland transmission network, with and without a second Bass Strait interconnector.

Potential system security issues in Tasmania or Victoria associated with the case studies.

Projected effects of alternate interconnection development options

Neutral scenario

This table summarises some critical points to note under Neutral scenario case studies, relative to the case where there are no interconnector upgrades.

4 Alternating current interconnector between Queensland and New South Wales.


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Table 1 Case study insights for the Neutral scenario, relative to no interconnector upgrades

Case study NPV of gross market benefits to 2035−36

NPV of annualised cost to 2035−36

Net Market Benefit

Incremental net market benefit (compared to Base case)

Key insights

Base case $170 M $47 M $123 M -

The upgrades to QNI and VIC–NSW interconnectors provide net market benefits primarily through fuel cost savings.

These augmentations supplement New South Wales’ supply as existing generation withdraws.

Second Bass Strait interconnector + Base case upgrades

$531 M $387 M $143 M $20 M

This interconnector development is projected to provide capital deferral benefits and reduce the need for voluntary demand curtailment

It will deliver modest fuel cost savings, given greater flexibility to operate Tasmanian hydro generation to offset high-cost plant at peak times on the mainland.

Additional South Australian Interconnector + Base case upgrades

$595 M $335 M $260 M $136 M

This interconnector development is projected to deliver fuel cost savings, given greater ability to renewable resources in South Australia at times when GPG would otherwise be required. It will also deliver system security benefits by reducing the risk of a widespread black system in South Australia, following the unanticipated loss of generation within the region.

Second Bass Strait interconnector and South Australian link + Base case upgrades

$978 M $676 M $302 M $179 M

The development of both interconnectors provides the most benefits, as the increased geographic diversification of resources has a compounding effect, resulting in the lowest fuel costs of any case studied.

This case study leads to an increase in South Australia wind production, increased flexibility in Tasmanian hydro production, and capital deferral.

Second Bass Strait interconnector plus accelerated development of wind generation in Tasmania + Base case upgrades

$377 M $387 M -$11 M -$134 M

The development of the interconnector and wind in Tasmania delivers modest fuel cost savings, with greater capacity for Tasmanian renewables (hydro and wind) to meet load on the mainland.

The case comes at a higher overall build cost however (for both generation capacity and the interconnector itself) than the Base case, as the case both hastens and increases overall renewable build in Tasmania.

The analysis indicates that synergies are achieved through greater interconnection, highlighting the importance of a national, strategic coordinated approach to planning. The combined net market benefits of both an additional South Australian interconnector and the second Bass Strait interconnector are likely to be greater than the sum of their separate effects. The development of more interconnection uses the diversity of renewable generation across the regions more effectively. It reduces the need for higher–cost gas generation by allowing renewable generation in one region to back up renewable generation in another region.

This analysis includes an estimate of the market benefits associated with: More efficient generation dispatch resulting in fuel cost savings. Changes in potential Large-scale Renewable Energy Target (LRET) penalty costs.


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Capital cost savings due to deferred investments. Reduced maintenance costs. Maintaining connection with the mainland in the event of a prolonged (year-long) loss of Basslink.

It does not include any potential benefits related to competition, or any potential change in ancillary service costs. To assess these type of benefits, more detailed assessment would be necessary, and is out of scope for this review.

45% Emissions Reduction scenario

The projected value of a second Bass Strait interconnector is lower in the 45% Emissions Reduction scenario. Despite delivering greater fuel cost savings in this scenario, due to an accelerated retirement of brown coal generation, the interconnection provides minimal capital deferral benefits. Increased uptake of large-scale battery storage in all cases dampens the benefit of the additional capacity access provided via the interconnector. Assuming the interconnector was operational by 2025−26, the net present value (NPV) of gross market benefits to 2035−36 is projected to be about $284 million, compared to the projected annualised cost of the interconnector over the 10-year period of $341 million. Similar to the Neutral scenario, the highest net market benefits are projected if an additional South Australian interconnector is built before the second Bass Strait interconnector.

Low Grid Demand scenario

Under the Low Grid Demand scenario, AEMO’s analysis indicates negative net market benefits, as the cost of the interconnector may not be recovered through fuel cost savings and capital deferral benefits. The capital deferral benefits are not as high in the Low Grid Demand scenario, as there is less requirement to build new generation. Assuming the interconnector is operational by 2025−26, the NPV of gross market benefits to 2035−36 is projected to be about $194 million, compared to the projected annualised cost of the interconnector over the 10-year period of $341 million. The projected value of building an additional South Australian interconnector before the second the Bass Strait interconnector is also lower in this scenario.

Transmission outlook

Transmission network expansion for new connections

A second Bass Strait interconnector is modelled from July 2025, with 600 MW transfer capacity and connection points at Smithton (Tasmania) and Tyabb (Victoria). High voltage direct current (HVDC) based on voltage source converter (VSC) technology was considered for modelling of the second interconnector. The existing transmission network at Tyabb could accommodate connection of a second Bass

Strait interconnector. The Tasmanian transmission network would require a new double circuit 220 kV transmission line

from Sheffield to Smithton for the connection of second Bass Strait interconnector. The projected cost of a new double circuit 220 kV line from Sheffield to Smithton and a new 220 kV

substation near Smithton and connection to Victorian transmission network at Tyabb were included in the $940 million estimated project cost.

Network limitations in Tasmania

The following potential network limitations have been identified. Market benefits associated with relieving these limitations have not been assessed in this study:

In the Neutral, Low Grid Demand, and 45% Emissions Reduction scenarios, a projected economic dispatch limitation was identified on the Sheffield–Palmerston 220 kV circuit, as it would exceed continuous ratings during system normal operation. In the Base case, this network constraint is


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projected to be driven by high generation in North-West and West Coast Tasmania. In the second Bass Strait interconnector case study, this constraint is projected to be driven by high generation in Southern Tasmania, coupled with high export via the second interconnector.

In the Neutral and 45% Emissions Reduction scenarios for all case studies, a projected economic dispatch limitation was also identified on the Sheffield–Georgetown 220 kV circuit, as it would exceed continuous ratings during system normal operation. This projected constraint is mainly driven by high generation from North-West and West Coast Tasmania, coupled with high export to Victoria via the existing Basslink interconnector.

Options to address projected economic dispatch thermal limitations would include line uprating of existing 220 kV circuits for a higher thermal rating, a second Sheffield–Palmerston 220 kV circuit, and a third Sheffield-Georgetown 220 kV circuit.

No network thermal limitations were identified to meet maximum demand, in either the Neutral or Low Grid Demand scenarios.

Network limitations in the mainland NEM

The deferral of peaking generation capacity resulting from a second Bass Strait interconnector is not expected to materially change projected transmission network augmentation requirements in the mainland NEM.

Power system security Greater interconnection with the mainland would provide hydro generation with more flexibility to generate at times of greater value – that is, during high demand periods or when renewable generation was low. This increased use at times of high value would likely lead to conservation of water during low-value periods, potentially increasing the number of periods when no hydro plant was generating. Additional wind generation in Tasmania is projected to amplify this change in hydro use. Lack of hydro units generating at certain times may lead to power system security challenges such as reduced system inertia, FCAS capability, and system strength in the Tasmanian power system. As a consequence, frequency and voltage control could be expected to become more challenging in Tasmania. For all scenarios, possible solutions to address these power system security challenges include: A number of existing hydro generators and GPG in Tasmania could provide inertia services and

system strength services by operating in synchronous condenser mode. There are currently no market-based incentives for these services.

There is a market mechanism to procure adequate FCAS capability through NEMDE (the NEM Dispatch Engine). This mechanism would result in rescheduling generation in Tasmania and Bass Strait interconnector transfers, to increase FCAS availability in Tasmania.

The mainland is interconnected by an alternating current network, and under normal operating conditions there should continue to be sufficient synchronous generators (considering potential retirements) to provide the necessary FCAS, without the need for additional interconnection. Low Grid Demand scenario assumptions include increasing probability of retirement of a number of large industrial loads in the NEM, including in Tasmania.5 In this scenario, the lack of available large industrial load is projected to affect the existing frequency control special protection scheme (FCSPS) and lead to frequency control issues. To meet this projected challenge without a second Bass Strait interconnector, import from Victoria to Tasmania would need to be reduced. With FCSPS not in service, a second interconnector could improve frequency control and allow increased imports from Victoria to Tasmania. This would increase the market benefit of the second Bass Strait interconnector in the Low Grid Demand scenario.

5 AEMO. 2016 National Transmission Network Development Plan, December 2016, and 2016 National Electricity Forecasting Report, June 2016.

Available at: http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Transmission-Network-Development-Plan and http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Electricity-Forecasting-Report.


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CONTENTS

EXECUTIVE SUMMARY 1

1. INTRODUCTION 10 1.1 Studies carried out by AEMO 10

2. KEY ASSUMPTIONS AND METHODOLOGY 12 2.1 Key Tasmanian assumptions 12 2.2 Market modelling methodology 16

3. GENERATION OUTLOOK 19 3.1 Neutral scenario 19 3.2 45% Emissions Reduction scenario 25 3.3 Low Grid Demand scenario 30

4. MARKET BENEFIT ANALYSIS 36 4.1 Neutral scenario 37 4.2 ‘45% Emissions Reduction’ scenario 42 4.3 Low Grid Demand scenario 43

5. TASMANIAN TRANSMISSION OUTLOOK 46 5.1 Transmission limitations 46 5.2 Special Control Schemes in Tasmania 48 5.3 Network limitations in the mainland NEM 48 5.4 Emerging system security challenges 48

6. CONCLUSIONS 50

MEASURES AND ABBREVIATIONS 51 Units of measure 51 Abbreviations 51

GLOSSARY 52

TABLES

Table 1 Case study insights for the Neutral scenario, relative to no interconnector upgrades 4 Table 2 AEMO modelling scenarios 10 Table 3 Interconnector options considered 11 Table 4 Case studies 11 Table 5 Possible location and size of new wind and pumped hydro generation in Tasmania 14 Table 6 Storage energy (in GWh) of the three types of generation in Tasmania 16 Table 7 Market benefits of various interconnector options under the Neutral scenario – summary 37 Table 8 Market benefits of various interconnector options under the Neutral scenario – benefit detail 37 Table 9 Market benefits of various interconnector options under the 45% Emissions Reduction

scenario – summary 42


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Table 10 Market benefits of various interconnector options under the 45% Emissions Reduction Scenario – benefit detail 42

Table 11 Market benefits of various interconnector options under the Low Grid Demand scenario –summary 43

Table 12 Market benefits of various interconnector options under the Low Grid Demand Scenario – benefit detail 44

Table 13 Potential economic dispatch limitations 47

FIGURES

Figure 1 Second Bass Strait interconnector route and connection points 13 Figure 2 Second Bass Strait interconnector – electrical connection 14 Figure 3 Location of new wind generation and pumped hydro station 15 Figure 4 Projected total installed capacity by fuel type (Neutral scenario – Base case) 20 Figure 5 Projected total installed capacity of large scale intermittent renewable generation, by region

(Neutral scenario – Base case) 21 Figure 6 Projected total installed capacity in Tasmania by fuel type (Neutral scenario – Base case) 22 Figure 7 Wind installation differences for Tasmania across each case study (Neutral scenario) 23 Figure 8 OCGT installed capacity differences for the NEM 24 Figure 9 CCGT development differences for the NEM for each case study 24 Figure 10 Total installed capacity by fuel type to 2035–36, 45% Emissions Reduction scenario 26 Figure 11 Projected total installed capacity of large scale intermittent renewable generation, by

region (45% Emissions Reduction scenario – Base case) 27 Figure 12 Projected total installed capacity in Tasmania by Fuel Type (45% Emissions Reduction

scenario – Base case) 28 Figure 13 Wind installation differences for Tasmania across each case study (45% Emissions

Reduction scenario) 29 Figure 14 OCGT development differences for the NEM for each case study (45% Emissions

Reduction scenario) 29 Figure 15 CCGT development differences for the NEM for each case study (45% Emissions

Reduction scenario) 30 Figure 16 Battery storage development differences for the NEM for each case study (45% Emissions

Reduction scenario) 30 Figure 17 Total installed capacity by fuel type to 2035–36, Low Grid Demand scenario – Base case 31 Figure 18 Projected total installed capacity of large scale intermittent renewable generation, by

region (Low Grid Demand scenario – Base case) 32 Figure 19 Projected total installed capacity in Tasmania by fuel type (Low Grid Demand scenario –

Base case) 33 Figure 20 Wind installation differences for Tasmania across each case study (Low Grid Demand

scenario) 34 Figure 21 OCGT development differences for the NEM for each case study (Low Grid Demand

scenario) 34 Figure 22 CCGT development differences for the NEM for each case study (Low Grid Demand

scenario) 35 Figure 23 Average wind farm operation per region, by time of day 40 Figure 24 Average wind farm operation per region, by month 40


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Figure 25 Generation duration curve for hydro generation in Tasmania, pre and post-augmentation 41 Figure 26 Average generation by time of day for hydro facilities in Tasmania 41


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1. INTRODUCTION AEMO has produced this report at the request of the Department of the Environment and Energy, to support the Tasmanian Energy Taskforce (the Taskforce) in its feasibility study into whether a second Tasmanian interconnector could improve Tasmania’s energy security and facilitate renewable energy investment. It summarises AEMO’s market and power system modelling and analysis conducted to provide input into the Taskforce’s final report. As the national transmission planner, AEMO has taken a strategic approach to this assessment, focusing on efficient development across the National Electricity Market (NEM) in the long-term interests of consumers. This includes consideration of how the NEM is likely to evolve in the future and what effects a second Tasmanian interconnector, or other interconnectors, would have on this evolution and power system operation. The analyses identify the costs and market benefits associated with increased interconnection at a high level, and should not be interpreted as satisfying the requirements of a complete regulatory investment test for transmission (RIT-T) process.

1.1 Studies carried out by AEMO AEMO publishes a National Transmission Network Development Plan (NTNDP) annually that provides an independent, strategic view of the efficient development of the NEM transmission grid over a 20-year planning horizon. AEMO has built on the studies carried out for this publication to conduct further studies in support of the objectives of the Tasmanian taskforce.

1.1.1. Scenarios considered The modelling scenarios considered by AEMO are shown in Table 2. All scenarios assume that the COP216 emission reduction commitment and the Victorian Renewable Energy Target (VRET)7 are achieved. The Neutral and Low Grid Demand scenarios assume a pro-rata share of the COP21 target is borne by electricity consumers. However, the 45% Emissions Reduction scenario assumes a stronger carbon reduction target from the stationary energy sector. Operational consumption projections in all scenarios are from the 2016 National Electricity Forecasting Report (NEFR).8 More detail about the scenarios, including key inputs and assumptions, is discussed in Chapter 2.

Table 2 AEMO modelling scenarios

Modelling scenario Description

Neutral scenario Assumes operational consumption changes in line with the 2016 NEFR Neutral demand sensitivity.

Low Grid Demand scenario

Assumes technology cost reductions leading to greater growth of small distributed generation sources and energy efficiency uptake and corresponding low operational consumption growth, consistent with the Weak demand sensitivity of the 2016 NEFR.

45% Emissions Reduction scenario

Assesses changes in the development of the electricity market should higher carbon abatement be targeted from the stationary energy sector (reduce carbon emissions by 45% below 2005 levels by 2030). Otherwise, consistent with the NTNDP Neutral scenario.

6 COP21 commitment – Australia set a target at the Paris 21st Conference of Parties (COP21) to reduce carbon emissions by 26% to 28% below

2005 levels by 2030. The Council of Australian Governments (COAG) Energy Council has agreed that the contribution of the electricity sector should be consistent with national emission reduction targets.

7 The VRET specifies that renewable energy will represent 25% of total Victorian generation in 2020, rising to 40% by 2025. Victorian Government. “Victoria’s renewable energy targets”, 2016. Available at: http://earthresources.vic.gov.au/energy/sustainable-energy/victorias-renewable-energy-targets. Viewed: 13 September 2016.

8 AEMO. 2016 National Electricity Forecasting Report, June 2016. Available at: https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Electricity-Forecasting-Report.


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1.1.2. Interconnector development case studies The development of additional interconnectors will likely lead to changes in evolution of the supply side of the market. With increased opportunities to export electricity, regions of high renewable resource availability may develop more generation than would be otherwise economically justifiable if constrained due to transmission limitations. In this way, interconnectors serve to exploit the geographic diversity of intermittent generation sources, leading to efficient generation siting decisions from a resource perspective. A number of possible augmentations to increase interconnection in the NEM were considered in AEMO’s studies, informed by co-optimised generation and transmission expansion modelling. A summary of the options selected through modelling for inclusion in case studies is shown in Table 3.

Table 3 Interconnector options considered

Interconnector Forward direction

Increase from present notional limit (MW) Forward direction

Increase from present notional limit (MW) Reverse direction

Timing in Neutral

Timing in Low Grid Demand

Timing in 45% Emissions Reduction

QNI9 NSW–QLD 450 300 2028–29 2026–27 2025–26

VIC–NSW10 VIC–NSW 170 0 2029–30 2023–24 2029–30

Additional South Australian Interconnector

VIC/NSW–SA 325 to 650 325 to 650 2021–22 2021–22 2021–22

Second Bass Strait interconnector

TAS–VIC 600 600 2025–26 2025–26 2025–26

Table 4 shows the modelled case studies considered for each of the three defined scenarios. Each case study investigated the impact of various combinations of interconnector developments, as outlined in the table. The ‘2BSI + 1200MW wind’ case study was designed to explicitly test whether the benefits of a second Bass Strait interconnector increased if more renewable generation was built in Tasmania.

Table 4 Case studies

Case study Abbreviation Description

Upgrade QNI & VIC–NSW interconnectors (‘Base case’)

Base case Incremental augmentation to the existing QNI and VIC–NSW interconnectors

Second Bass Strait interconnector

2BSI Introduction of a second TAS–VIC interconnector as well as the augmentations identified in the Base case

Additional South Australian interconnector

New SA Link Introduction of an additional South Australian interconnector as well as the augmentations identified in the Base case

Both second Bass Strait IC and additional interconnection with SA

New SA Link + 2BSI

Introduction of both of the above proposed interconnectors as well as the augmentations identified in the Base case

Second Bass Strait Interconnector with additional Tasmanian wind generation

2BSI + 1200MW wind

Introduction of a second TAS–VIC interconnector and concurrent build of 1,200 MW of wind generation in Tasmania as well as the augmentations identified in the Base case

9 QNI – Present notional limit 300 MW in forward direction and 1,078 MW in reverse direction. AEMO. Interconnector Capabilities for the National

Electricity Market, September 2015. Available at: http://www.aemo.com.au/-/media/Files/PDF/Interconnector-Capabilities-v2.pdf. 10 VIC-NSW – Present notional limit 700 MW in forward direction and 400 MW in reverse direction. AEMO. Interconnector Capabilities for the

National Electricity Market, September 2015. Available at: http://www.aemo.com.au/-/media/Files/PDF/Interconnector-Capabilities-v2.pdf.


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2. KEY ASSUMPTIONS AND METHODOLOGY This chapter describes the approach and key assumptions used by AEMO in conducting the studies described in this report.

2.1 Key Tasmanian assumptions

2.1.1 A second Bass Strait interconnector This report investigated a 600 MW transfer capacity of second Bass Strait interconnector. A feasible option to transfer 600 megawatts (MW) over about 300 km distance is high voltage direct current (HVDC) technology. This report considers HVDC with voltage source converter (VSC) technology. This technology can operate with low system strength, manage over voltages, and provide continuous frequency support services much better than the existing HVDC line-commutated current-sourced converter (LCC) technology of Basslink. A number of routes are possible for the second HVDC submarine cable and connection points in Victoria and Tasmania. In this high level study, a route between Smithton (in North-West Tasmania) and Tyabb (in South-East Victoria) has been modelled. Smithton has large wind power generation potential with a relatively high capacity factor compared to wind power generation from other locations. Tyabb is closer to the major load centre in Victoria. Figure 1 shows the route of the modelled second interconnector. A number of separate routes are possible for connection of second interconnector. A detailed RIT-T type of study may consider other possible routes and connection points.


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Figure 1 Second Bass Strait interconnector route and connection points

An additional 220 kilovolt (kV) double circuit transmission line Sheffield to Smithton (approximately 130 km) would be required to facilitate connection of a second Bass Strait interconnector. This 220 kV line also needs to accommodate a large amount of wind power generation in North-West Tasmania. A new substation and converter station would be required at Smithton or in North-West Tasmania. The existing 220 kV network in Victoria can accommodate additional transfer between Tasmania and Victoria. A new converter station would be required at Tyabb or in the vicinity. Figure 2 shows the network configuration for connection of the proposed second Bass Strait interconnector.


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Figure 2 Second Bass Strait interconnector – electrical connection

2.1.2 New generation locations in Tasmania To minimise generation and transmission network costs, new generation is assumed to be located efficiently, considering spare network capacity, network connection costs and the quality of the local wind and solar resources (or availability of fuel sources for thermal plants). AEMO consulted TasNetworks and Hydro Tasmania for possible location and size of these new wind power generation and hydro storage pumps. Table 5 shows new wind power generation and hydro storage pumps with increased hydro power generation, which were investment options for consideration in this study. These are presented in Figure 3.

Table 5 Possible location and size of new wind and pumped hydro generation in Tasmania

Generation type Location Possible connection point Capacity (MW)

Wind power generation North-West Tasmania Smithton – a new 220 kV substation Up to 1,000

NET (North-East) Low-head wind farm

Georgetown substation 30

ST (Southern) Waddamana substation 200

WCT (West Coast) Farrell substation 100

Pumped hydro generation Various locations within Tasmania Generation and pumps up to

220 MW


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Figure 3 Location of new wind generation and pumped hydro station

Musselroe Wind Farm168 MW

Woolnorth Studland Bay /Bluff Point 140 MW

WFPossible North WestTasmania wind farms up to1000 MW

WF

WF

WF

Possible Low HeadWind Farm 30 MW

Possible Cattle Hill WindFarm 200 MW

WF

Possible Granville HarbourWind Farm 100 MW

PH

Possible pumped hydro upto 220 MW

WF


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2.1.3 Hydro-electric generation modelling Tasmanian hydroelectric generation is modelled by means of individual hydroelectric generating systems linked to one of three common storages: Long-term storage. Medium-term storage. Run of river.

Table 6 identifies how individual generators are allocated across these storages and provides an indication of the storage energy available to the units. Energy inflow data for each Tasmanian hydro water storage is determined from historical monthly yield information provided by Hydro Tasmania. In both the capacity outlook model and time-sequential model, AEMO used a scaled version of average monthly yield, extracted from records spanning 81 years, to deliver an annual inflow of 8,700 gigawatt hours (GWh).

Table 6 Storage energy (in GWh) of the three types of generation in Tasmania

Storage type Storage energy (GWh) Stations

Long-term 11,200 Gordon, Poatina.

Medium-term 3,200 Lake Echo, Tarraleah, Tungatinah, Liapootah, Wayatinah, Catagunya, Fisher, Lemonthyme, Mackintosh, Bastyan, John Butters.

Run of river 140 Meadowbank, Trevallyn, Wilmot, Cethana, Devils Gate, Reece, Tribute.

2.2 Market modelling methodology

2.2.1 Capacity outlook AEMO’s generation outlook simulated the future generation mix by incorporating a least-cost expansion of large-scale generation of the NEM over a 20-year outlook period, from 2016–17 to 2035–36. The expansion plan aims to identify the least-cost mix of generation to ensure adequate supply to meet demand at the current NEM reliability standard.11 The outlook projects the generation mix by fuel type, location, and timing of investments and withdrawals. The generation outlook provides a view of zonal generation required to meet forecast maximum demand and operational consumption. A unique generation outlook was required for each demand sensitivity and interconnector case study modelled. Over the projection period, the generation outlook optimised generation investments, withdrawals, and operational cost, taking into account requirements to: Dispatch generation to meet operational maximum demand plus minimum reserve level across

each year. Ensure sufficient generation reserve is available to meet the reliability standard.

Meet legislated and advanced policy objectives (Australia’s COP21 commitment, Large-scale Renewable Energy Target (LRET), and VRET).

Operational maximum demand requirements Forecast maximum demand and minimum reserve levels determine the future generation and interconnector capacity required. Annual consumption and the demand profile affect the generation mix used to meet demand. This study uses AEMO’s 2016 NEFR12 to provide consumption and 10% probability of exceedance (POE)13 maximum demand forecasts for each NEM region, and assumes 11 The reliability standard targets a maximum expected unserved energy of 0.002% of native consumption per region, in any financial year.

Australian Energy Market Commission (AEMC) Reliability Panel. NEM Reliability Standard – Generation and Bulk Supply. Available at: http://www.aemc.gov.au/getattachment/f93100d9-72d2-46fb-9c25-ac274a04ae58/Reliability-Standards-(to-apply-from-1-July-2012).aspx.

12 AEMO. National Electricity Forecasting Report, June 2016. Available at: https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Electricity-Forecasting-Report.

13 POE is the likelihood of a forecast being exceeded – a 10% POE forecast is expected to be exceeded, on average, only one year in 10.


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minimum capacity reserves set to the size of the largest online generator, as a proxy for ensuring the reliability standard would be met and set.

Generation requirements In determining the efficient generation mix required in the outlook, AEMO assumed all generators were offering to generate (bidding) at their short run marginal cost (SRMC). Each generator’s assumed SRMC was based on the information published on AEMO’s online NTNDP Database.14 This assumed perfect competition in the market, and generators being fully flexible to respond to market signals.

Interconnector upgrade scenarios AEMO analysed a number of interconnector upgrade options including augmentation of interconnectors that link New South Wales with both Queensland and Victoria, new interconnection between Victoria and South Australia, and a second Bass Strait interconnector. Dispatch differences between these options were modelled using alternative network constraints to reflect the differing network capabilities of the two alternatives in time-sequential modelling. Preliminary modelling of all scenarios was conducted, allowing for incremental interconnector upgrade to gain understanding of the most likely timing of the link augmentation. This timing was subsequently locked down into the simulations.

Legislated policy objectives A number of government legislated policies and commitments were modelled in the 2016 NTNDP, including the COP21 commitment, the LRET, and the VRET. The COP21 commitment requires a 26% to 28% reduction of national emissions by 2030 based on

the 2005 emission level. The LRET is modelled using updated Large-scale Generation Certificate (LGC) inventories. The

policy defines a target renewable generation level in 2020, with liabilities persisting up until 2030.

The Victorian government is in the process of legislating the VRET, that incentivises at least 25% of generation from the region to be sourced from renewable technologies by 2020, and at least 40% by 2025. The developments incentivised by the policy to 2020 are expected to contribute to the LRET objective, while developments beyond 2020 are expected to have their LGCs voluntarily surrendered. Beyond 2020, therefore, the policy should contribute to a higher overall renewable penetration than the LRET requires (as is the case with existing Australian Capital Territory reverse auction outcomes). This advanced policy also requires an 80%–20% split between new wind and new solar technologies installed to meet the policy.

2.2.2 Generation dispatch – time-sequential modelling The generation outlook aims to simulate efficient installation and retirement of generation and transmission investment. Some short-term operational issues, such as the hourly chronology of generation dispatch, transmission network congestion, and hydro-storage coordination, have not been taken into account. This necessitated running a time-sequential model to validate the plausibility of the capacity outlook model results. A time-sequential model used the results of the capacity outlook model, and a forecast of network limitations, to simulate hour-by-hour generation dispatch across the NEM. This highlighted network congestion that may arise from retiring or building generation in a certain location, as well as other issues the capacity outlook model is not designed to capture. The modelling followed an iterative process, whereby the generation outlook was changing to alleviate some of the network limitations that arose from retiring or building generation in particular locations. The time-sequential model considered generator operational costs only in dispatching the market, as investment decisions were captured by the capacity outlook model. This simulated a perfectly

14 AEMO. NTNDP Database. Available at: https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-

Transmission-Network-Development-Plan/NTNDP-database.


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competitive market using an SRMC bidding model, rather than a reflection of strategic bidding behaviours influenced by portfolio considerations. In practice, offers from generators will be influenced by a number of real-world factors for the business owning the generator, including: Bids for other generators in the portfolio. The generator’s start-up times and costs. The generator’s flexibility to respond to signals. The retail load being supplied by the business. The business’ wholesale contract prices and position, and risk profile.

AEMO used a competitive bidding time-sequential model to simulate levels of inertia, dispatch, and fault levels on the network over the outlook period. The model provides an improved approximation of generation levels as compared to the SRMC model. The time-sequential model incorporated the regulation currently in place to maintain the expected Rate of Change of Frequency (RoCoF) of the South Australian power system, in relation to the non-credible double circuit trip of the Heywood Interconnector, at or below 3 hertz per second (Hz/s).15 Flow limits on the Heywood Interconnector were based on the total inertia online in the South Australian region, to ensure the South Australian power system could continue operating after a double circuit outage of the Heywood Interconnector. In cases where an additional AC link between South Australia and either Victoria or New South Wales was built, the constraint limiting flow on the Heywood interconnector was revoked.

15 AEMO Electricity Market Notice 55358, 12 October 2016. Available at: https://www.aemo.com.au/Market-Notices.


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3. GENERATION OUTLOOK The next 20 years will be characterised by unprecedented transformation in the power industry as it transitions to a low carbon future. This is driven by three key factors: Legislated and advanced emissions reduction policy objectives (Australia’s COP21 commitment,

LRET, and VRET). The reducing financial viability of ageing, emissions-intensive coal generation. Meeting forecast system operational consumption, characterised by relatively low growth as the

penetration of distributed generation increases. AEMO’s assessment has used market modelling, combined with generators’ public announcements of their intentions to withdraw at the end of expected plant lifetime (assumed to be 50 years), to assess a possible future generation mix under each scenario. Differences in the magnitude of the changing supply mix between the case studies of the three scenarios are detailed in this chapter.

3.1 Neutral scenario

3.1.1 Projected capacity mix – Base case Over the 20–year modelled period, AEMO projects a decreasing market share for baseload coal generation, and an increasing penetration of intermittent renewable generation, as the market continues to evolve. Under the Neutral scenario’s Base case: 63% (15.5 gigawatts (GW)) of the existing coal generation fleet may retire by 2036.16 Up to 45.3 GW of new generation may be required by 2036, comprising wind (20%), large-scale

photovoltaic (PV) (29%), gas-powered generation (GPG) (27%), and rooftop PV (25%). Figure 4 shows the projected total installed generation capacity in the NEM, categorised by fuel type, for the next 20 years in the Base case. Emissions reduction incentives drive the projections of new installations. New installations are therefore mainly using intermittent renewable technologies, however additional firm capacity is also required to satisfy reliability requirements. An increase in installed NEM capacity is forecast despite a relatively flat demand projection under the Neutral scenario, as a result of the increase in intermittent generation installations.

16 The Neutral scenario modelled the retirement of Hazelwood Power Station as a staged retirement between 2017–18 and 2020–21. This is

different to the recently announced closure scheduled for March 2017.


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Figure 4 Projected total installed capacity by fuel type (Neutral scenario – Base case)

Effects of the Victorian Renewable Energy Target The advanced VRET policy aims to deliver 25% of total Victorian electricity generation from renewable technologies by 2020, and 40% by 2025. AEMO’s modelling suggests the policy will deliver about 4,800 MW of additional renewable generation to Victoria. It is understood that at least 20% of the new renewable generation will aim to use solar PV technologies. The policy is forecast to influence NEM development, providing incentive for renewable generation proponents to locate in Victoria rather than other regions. For Tasmania, the VRET target may lower the value of the second Bass Strait Interconnector and defer substantial renewable generation build in the region until later in the period. Exporting local renewable generation from Tasmania to the mainland is more valuable if it displaces coal and gas generation rather than other renewable generation sources.

The figures below demonstrate the regional development of intermittent generation in the Neutral scenario’s Base case. The figures show that the southern regions are forecast to continue to dominate the renewable landscape in the next ten years, particularly as the VRET drives Victorian developments. In the longer term, New South Wales is forecast to increase its share of renewable generation. However, for Tasmania, the share of renewable generation remains relatively steady.

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Figure 5 Projected total installed capacity of large scale intermittent renewable generation, by region (Neutral scenario – Base case)

Development in Tasmania – Base case The specific development forecast for Tasmania is shown in Figure 6, and in the inset in Figure 5. Up to 730 MW of new wind capacity is projected to be installed in Tasmania over the next 20 years, even without the second Bass Strait interconnector. No large-scale solar PV capacity is expected to be installed, while up to 330 MW of rooftop PV is projected to connect in Tasmania, independent of the interconnector. Figure 6 shows the installed capacity in Tasmania projected over the forecast period.

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Figure 6 Projected total installed capacity in Tasmania by fuel type (Neutral scenario – Base case)

The 208 MW Tamar Valley Power station is assumed to remain mothballed under the Base case, with fixed operating and maintenance costs of approximately $2.1 million incurred each year. Given its mothballed status, its capacity is not included in the figure above.

3.1.2 Projected Tasmanian capacity mix in other case studies Development of the proposed second Bass Strait interconnector is forecast to increase the financial viability of renewable generation in Tasmania, reducing the risk of being constrained off due to transmission limitations, and increasing access to the broader NEM. Tasmania’s relatively rich wind resources are more capable of export with a second link, while Tasmania’s ability to import electricity during off-peak periods increases the flexibility available to the Hydro Tasmania generation portfolio to maximise the value of stored water, and reduce NEM-wide system costs. An additional South Australian interconnector reinforces South Australia’s ability to both export wind generation during periods of high production, and to import electricity when wind production is low. For Tasmania, the presence of another South Australian interconnector is projected to reduce Tasmania’s wind resource development in the next ten years. Given the anticipated timing differences of the two interconnectors (a South Australian link by 2021–22 and a Tasmanian link by 2025–26), Tasmanian developments would likely be impacted by South Australia’s first-mover advantage. Development of both links will enable all of these projected benefits to be realised. While an early development of the South Australian link is forecast to lead to delayed development for Tasmanian wind farms (with more development in South Australia instead), long-term development is likely to be enhanced by the prospect that developers will seek increased diversity in their wind generation portfolios. The typical daily pattern for wind in Tasmania complements the profiles in other regions, helping to smooth the intermittency of wind generation in aggregate across the NEM.

Figure 7 below shows the existing and modelled development path for wind in Tasmania under each case study. Each case study assumes the same level of generation retirement across the 20-year planning horizon.

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© AEMO 2017 23

The figure demonstrates that: Between 600 MW and 1,200 MW of additional new wind capacity is forecast in Tasmania over the

next 20 years. Without further interconnection, Tasmania can accommodate no more than 1,100 MW of wind

farms before becoming constrained by transmission limitations. The second Bass Strait interconnector expansion is forecast to drive approximately 365 MW of

additional wind capacity in Tasmania relative to the Base case with no transmission development, only approximately 60% of the increased export capability.

The second Bass Strait interconnector case study delivers almost as much wind capacity in the long run as the ‘2BSI + 1200MW wind’ case study, which requires 1,200 MW of wind installed in time for the interconnector’s commissioning. This highlights that the timing of new Tasmanian renewable generation development need not coincide with the timing of the link to deliver market benefits.

The timing and magnitude of wind build in Tasmania is influenced by the modelled earlier development of another South Australian interconnector.

Figure 7 Wind installation differences for Tasmania across each case study (Neutral scenario)

The above analysis highlights that wind generation from Tasmania will be relied on more over time as coal capacity progressively retires. As wind penetration increases in a particular region, there will be a diminishing return on further developments, as the correlation of generation in geographically near locations is relatively high. As such, increasing diversity of intermittent generator developments is expected to provide increased value to the generation mix, and a second Bass Strait interconnector can facilitate Tasmania’s increased contribution to that diverse supply mix.

3.1.3 Effect of interconnector options on NEM capacity mix In addition to facilitating more renewable generation in Tasmania, a second Bass Strait interconnector would also provide benefit to the mainland by increasing the capacity for Tasmania to support Victoria during high demand periods. Arguably, with 600 MW of increased capability to export Tasmania’s excess hydro capacity, up to 600 MW of GPG developments could be deferred on the mainland. Figure 8 and Figure 9 below show the GPG expansion for the NEM, for open cycle gas turbine (OCGT) and combined cycle gas turbine (CCGT) expansion respectively. The figures show that, for the cases with a second Bass Strait interconnector developed, there is some deferral of OCGT new build. In

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© AEMO 2017 24

particular, 600 MW is deferred in the 2030s in the second Bass Strait interconnector and ‘2BSI + 1200MW wind’ case studies, relative to the Base case. The case study with both the South Australian and Tasmanian interconnectors developed also delays 300 MW of peaking gas for several years in the 2030s.17

Figure 8 OCGT installed capacity differences for the NEM

Figure 9 below shows that to complement the benefits of deferring peaking investments, development of any additional interconnector is projected to reduce the need for CCGT developments by the study end. CCGTs are developed to not only provide capacity support at times of peak, but to typically operate at higher capacity factors, providing high volumes of energy to consumers, offsetting the reduction in coal generation.

Figure 9 CCGT development differences for the NEM for each case study

17 Due to end effects, care should be taken not to draw strong inferences from differences observed between cases in the last years of the study.

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With increased interconnection, additional wind generation can be expected to provide the energy that CCGTs otherwise would need to provide. In the Neutral scenario, the additional interconnection with either Tasmania or South Australia does defer Victorian CCGT development by 2035–36. Any delays in the retirement of coal-fired generators would reduce the need for additional CCGTs and potentially reduce the benefits of greater interconnection.

3.2 45% Emissions Reduction scenario

3.2.1 Projected capacity mix – Base case Under the 45% Emissions Reduction scenario, AEMO’s assessment projects total NEM installed capacity to increase by 71% to 2035–36 (as shown in Figure 10 below). Under this scenario, AEMO projects, by 2035–36, the retirement of 18.2 GW of coal plant and the installation of: 27.5 GW of large-scale renewable generation, comprising 14.8 GW of large-scale PV and

12.7 GW of wind. 11.7 GW of GPG. 12.0 GW of rooftop solar PV. 3.5 GW of battery storage.

Compared to the Neutral scenario, this scenario projects more coal-fired generation retirements and greater intermittent renewable generation development to meet the stronger carbon abatement target. The 45% Emissions Reduction scenario includes the announced retirement of Hazelwood Power Station from 2017 and return to service of mothballed plant in South Australia, consistent with AEMO’s 2016 Electricity Statement of Opportunities (ESOO) update.18 The scenario demonstrates that with increased penetration of renewable capacity, and a reduced capacity of firm thermal capacity, the value of battery technology is increased. Battery ‘firms up’ renewable generation and allows energy shifting of wind and solar generation from periods of high operation to periods of low operation. This reduces fuel costs, and provides some support for grid reliability (subject to the capabilities of batteries and the duration of high demand events). Alternatively, greater interconnection between regions may be beneficial (including greater interconnection to New South Wales), but this has not been tested.

18 AEMO. Electricity Statement of Opportunities Update, November 2016. Available at: http://www.aemo.com.au/Electricity/National-Electricity-

Market-NEM/Planning-and-forecasting/NEM-Electricity-Statement-of-Opportunities.


© AEMO 2017 26

Figure 10 Total installed capacity by fuel type to 2035–36, 45% Emissions Reduction scenario

Figure 11 below demonstrate the regional development of intermittent generation in this higher emissions reduction scenario’s Base case. The figures show that the higher emissions reduction pathway incentivises a balanced development of renewable generation across NEM regions. For Tasmania, though, the share of renewable generation is expected to reduce relative to other regions.

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Figure 11 Projected total installed capacity of large scale intermittent renewable generation, by region (45% Emissions Reduction scenario – Base case)

The specific development forecast for Tasmania is shown in Figure 12 and the inset in Figure 11. Up to 730 MW of new wind capacity is projected to be installed in Tasmania over the next 20 years, even without the second Bass Strait interconnector. This is equal to the Neutral scenario. Without increased interconnection to the mainland, Tasmania’s renewable sector is at risk of losing pace with the growth forecast for the rest of the NEM. No large-scale solar PV capacity is expected to be installed, while up to 330 MW of rooftop PV is projected to connect in Tasmania, independent of the interconnector.

Figure 12 shows the Tasmanian developments over the forecast period.

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Figure 12 Projected total installed capacity in Tasmania by Fuel Type (45% Emissions Reduction scenario – Base case)

3.2.2 Projected Tasmanian capacity mix of other case studies Figure 13 below shows the modelled development path for wind in Tasmania under each case study. Like in the Neutral scenario, the figure demonstrates that up to 1,200 MW of additional new wind capacity in Tasmania is forecast. This is despite the projected increased penetration of renewable capacity across the NEM in response to the transitionary pressures of the higher emissions reduction target. The case with both interconnectors augmented (to Tasmania and South Australia), shows delayed Tasmanian developments, with initial focus on South Australian developments, given the earlier interconnector commissioning. However, by 2035–36, the local Tasmanian generation developments are equivalent in the second Bass Strait interconnector and combined interconnector case studies.

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Figure 13 Wind installation differences for Tasmania across each case study (45% Emissions Reduction scenario)

3.2.3 Effect of interconnector options on NEM capacity mix Figure 14 and Figure 15 below show the GPG expansion for the NEM, for OCGT and CCGT expansion respectively. The figures show no discernible differences in the level of new GPG development projected between cases (although slight differences in the timing of new build are observed). With a capacity mix relying more on intermittent generation and battery storage, increased interconnection is projected to contribute less to supporting peak load conditions between regions and therefore not projected to defer any new peaking capacity installations. It is only with combined interconnection expansion that CCGT capital deferral benefits are forecast to be realised by 2035–36.

Figure 14 OCGT development differences for the NEM for each case study (45% Emissions Reduction scenario)

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Figure 15 CCGT development differences for the NEM for each case study (45% Emissions Reduction scenario)

This scenario presents a strong development outlook for battery storage. However, the projected benefits of storage are largely independent of the interconnection developed, as shown in Figure 16 below.

Figure 16 Battery storage development differences for the NEM for each case study (45% Emissions Reduction scenario)

3.3 Low Grid Demand scenario

3.3.1 Projected capacity mix – Base case Under the Low Grid Demand scenario, AEMO’s Base case assessment projects total NEM installed capacity to increase by 8.5 GW to 2025–26 and remain relatively steady to 2035–36 (as shown in Figure 17 below).

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Under this scenario, AEMO projects, by 2035–36, the retirement of 18.8 GW of coal plant and the installation of: 13.4 GW of rooftop solar PV. 2.5 GW of large-scale solar PV. 4.7 GW of GPG. 5.8 GW of wind generation.

Figure 17 Total installed capacity by fuel type to 2035–36, Low Grid Demand scenario – Base case

The Low Grid Demand scenario projects that 3.3 GW additional coal plant may retire to 2035–36 compared to the Neutral scenario19, due to the reducing financial viability of the coal plant. In this scenario, the entire brown coal generation fleet is retired in the next 20 years, as low grid demand leads to oversupply, which suppresses prices and creates volume risk. The Low Grid Demand scenario includes strong penetration of rooftop PV, projected to reach 30% of installed capacity (17.4 Terawatt (TW)) by 2035–36. The figures below demonstrate the regional development of intermittent generation in the Low Grid Demand scenario’s Base case. The figures show that the largest regions by load are forecast to dominate new renewable developments. The effect of the VRET is also clearly visible, with Victoria increasing its share of NEM-wide intermittent renewable generation capacity to 50%. For Tasmania, the share of renewable generation (excluding hydro) is expected to decrease as no new renewable generation is developed in the region.

19 The Low Grid Demand scenario modelled the retirement of Hazelwood Power Station as a staged retirement between 2017–18 and 2020–21.

This is different to the recently announced closure scheduled for March 2017.

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Figure 18 Projected total installed capacity of large scale intermittent renewable generation, by region (Low Grid Demand scenario – Base case)

The specific development forecast for Tasmania is shown in Figure 19 and the inset to Figure 18. It shows that in this scenario, with high distributed generation, energy efficiency, and lower underlying growth, no additional renewable capacity is expected to be developed in Tasmania in the Base case, without the second Bass Strait interconnector. Further, with low demand growth and higher distributed generation, the scenario leads to retirement of the 178 MW Bell Bay Three Power Station and Tamar Valley OCGT plant. The 208 MW Tamar Valley Power Station is assumed to remain on stand-by, however, to provide back-up in the event that a fault on the Basslink interconnector leads to electrical islanding of Tasmania. Up to 390 MW of rooftop PV is projected to connect in Tasmania, independent of the interconnector. Figure 19 shows projected Tasmanian developments over the forecast period.

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© AEMO 2017 33

Figure 19 Projected total installed capacity in Tasmania by fuel type (Low Grid Demand scenario – Base case)

3.3.2 Projected Tasmanian capacity mix of other case studies For the Low Grid Demand scenario, the generation capacity forecast for Tasmania remains the same across all cases. Even the development of the second Bass Strait interconnector is projected to not attract more investment in the region. Any value provided by the interconnector, therefore, is isolated to increasing the value derived from the existing hydro facilities, rather than providing increased access to Tasmania’s additional renewable resources. An additional South Australian interconnector is projected to reinforce South Australia’s ability to export wind generation during periods of high production and import electricity when wind production is low. However, as for Tasmania, South Australia’s development of new wind capacity is forecast to be much reduced, with only about 90 MW developed when the additional interconnector is installed. In this scenario, the forecast effect of the VRET is even more dramatic. The VRET dominates renewable developments in this scenario, with approximately 5,000 MW of additional renewable (wind and large-scale solar PV) built in Victoria.20 As such, with limited operational demand growth, the policy effectively saturates the renewable energy market. A greater proportion of the LRET is met through renewable generation located in Victoria to meet both LRET and VRET, while not building any more capacity than necessary. There is also more projected LRET non-compliance in this scenario. The modelling also forecasts developers re-focusing on regions with low existing renewable penetration or where new capacity is needed to meet demand – behind the Victorian developments, both New South Wales and Queensland are also forecast to increase renewable capacity to meet the LRET.

20 The proposed policy targets a percentage of generation in the region, not load.

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As modelled in each scenario, the ‘2BSI + 1200MW wind’ case study delivers an additional 1,200 MW of wind in Tasmania by the commissioning date of the interconnector. This is in contrast to all other case studies, which do not develop additional wind capacity in Tasmania. This is shown in Figure 20 below.

Figure 20 Wind installation differences for Tasmania across each case study (Low Grid Demand scenario)

3.3.3 Effect of interconnector options on NEM capacity mix Like the Neutral scenario, the development of the second Bass Strait interconnector does provide for reduced GPG development on the mainland. All cases involving the second Bass Strait interconnector serve to reduce the need for CCGT developments on the mainland, by improving use of existing resources in Tasmania. This is shown in Figure 21 and Figure 22 below.

Figure 21 OCGT development differences for the NEM for each case study (Low Grid Demand scenario)

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Figure 22 CCGT development differences for the NEM for each case study (Low Grid Demand scenario)

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4. MARKET BENEFIT ANALYSIS This chapter presents AEMO’s assessment of the economic value of the interconnector options examined in each scenario case study. This analysis does not meet the requirements of a full RIT-T assessment, but provides a high level overview of the potential benefits that each interconnector may provide, focusing on the allowable market benefits in a RIT-T.21 The allowable market benefits included in this assessment include: Changes in fuel consumption arising through different patterns of generation dispatch and changes

in network losses, including changes in variable operations and maintenance expenditure associated with dispatch. These are referred to as “Dispatch efficiency benefits” and have been calculated assuming perfect competition, with dispatch based on SRMC bidding.

Changes in voluntary and involuntary load curtailment, referred to as “Reliability benefits”. These have been assessed at a high level only, as multiple Monte Carlo simulations were not performed.

Changes in capital investment in non-transmission elements, referred to as “Capital investment efficiency benefits”, including savings associated with: Differences in the timing of new plant. Differences in capital cost. Differences in fixed operational and maintenance costs.

Changes in penalties paid or payable for not meeting the LRET, referred to as “Environmental scheme benefits”.

This report also refers to “resilience benefits”. These relate to benefits derived from increasing the power system’s resilience to low probability, high impact events such as interconnector failures. Resilience benefits are not a separate category of benefits, but a subset drawn from existing categories of RIT-T allowable market benefits. Potential resilience benefits are: For South Australia, the increased resilience to severe and widespread involuntary load

shedding in the region following synchronous separation of South Australia from the rest of the NEM.

For Tasmania, the increased resilience to generation dispatch inefficiencies throughout the NEM associated with a prolonged (yearlong) failure of the existing Basslink interconnector, weighted by the probability of such a prolonged outage occurring (assumed to be 5%).

In calculating resilience benefits for South Australia, a value of customer reliability (VCR) multiplier of 1.5 has been applied to quantify the cost of disruption, which includes a modest allowance for both direct and indirect economic impacts to reflect the severity of the outage. The following potential benefits have not been included in this assessment: Competition benefits. Changes in ancillary service costs (with the exception of the dispatch efficiency benefits associated

with revoking the RoCoF constraint in cases where there is additional South Australian interconnection).

Changes in any additional option value not covered by the above definitions. The net present value (NPV) of market benefits and costs has been calculated over 20 years to 2035–36 using a 7% social discount rate.22 The interconnector costs have been annualised to provide a NPV comparison of costs over the same time period, and are assumed to be competitively priced. For market benefit analysis, network constraints have been included to capture operating costs under realistic network congestion.

21 Australian Energy Regulator (AER). Final regulatory investment test for transmission, https://www.aer.gov.au/system/files/Final%20RIT-T%20-

%2029%20June%202010.pdf. Viewed 2 December 2016. 22 Department of the Prime Minister and Cabinet, Office of Best Practice Regulation. Cost Benefit Analysis Guidance Note, Page 7, published

1 February 2016, available at: https://www.dpmc.gov.au/resource-centre/regulation/cost-benefit-analysis-guidance-note. Viewed 14 December 2016.


© AEMO 2017 37

4.1 Neutral scenario Table 7 below summarises the market benefits of the various interconnector upgrades and augmentations under the different Neutral scenario case studies.

Table 7 Market benefits of various interconnector options under the Neutral scenario – summary



Overall net benefit

Base case $170m $47m $123m

2BSI $531m $387m $143m

2BSI + 1200MW wind $377m $387m -$11m

New SA Link $595m $335m $260m

New SA Link + 2BSI $978m $676m $302m

The table above shows that all case studies, with the exception of the ‘2BSI + 1200MW wind’ case study, provide a projected positive net market benefit in the Neutral scenario. Given that AEMO’s assessment does not try to capture all potential market benefits, further assessments of each interconnector option are warranted.

4.1.1 Detailed benefit assessment of various interconnector options While Table 7 above shows the overall net benefits, it does not detail the specific benefits provided by each interconnector development. Each interconnector development will vary in its ability to provide each ‘category’ of benefits, and it is useful to understand the difference between case studies. Table 8 provides a breakdown of market benefits in each category considered in this analysis.

Table 8 Market benefits of various interconnector options under the Neutral scenario – benefit detail

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Dis

patc

h ef

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lity

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nves

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Base case $117m $27m $31m -$4m $0m $170m $47m $123m $0m

2BSI $202m $114m $165m $2m $48m $531m $387m $143m $20m

2BSI + 1200MW wind

$338m $114m -$136m $11m $50m $377m $387m -$11m -$134m

New SA Link $324m -$1m -$6m $117m $161m $595m $335m $260m $136m

New SA Link + 2BSI $451m $85m $111m $123m $209m $978m $676m $302m $179m

The benefits above include the inherent benefit in each case study of the interconnector upgrades assumed for the Base case, that is, the benefits provided by the QNI and VIC–NSW upgrades. The table also shows the incremental net market benefits, over and above the benefits attributable to the QNI and VIC–NSW interconnection augmentations.

Benefits of the second Bass Strait interconnector As shown in Table 8, in the Neutral scenario the second Bass Strait interconnector is forecast to deliver: $85m in dispatch efficiency benefits. $87m in reliability benefits. $134m in capital investment efficiency benefits.


© AEMO 2017 38

$6m in reduced environmental scheme costs. $48m in improved Tasmanian resilience to the potential outage of the Basslink interconnector.

The largest of these projected benefits relates to the ability for the interconnector to delay or defer capital investment on the mainland, as discussed in Chapter 3. A new interconnector with South Australia cannot provide a similar benefit, given that South Australia’s generation mix is mainly intermittent, and therefore a new link would not ‘firm up’ that intermittent capacity to benefit the remaining NEM to the same extent. This increased capacity to export firm hydro generation also provides additional projected reliability benefits, as the risk of voluntary and involuntary load curtailment is forecast to reduce in the cases where a new Tasmanian link is installed. The second Bass Strait interconnector reinforces connection between Tasmania and the mainland, reducing Tasmania’s exposure to extreme outcomes if that interconnector fails. Increased resilience to potential failures of the Basslink interconnector is projected to provide further benefits. These benefits are not as significant as those provided by a new South Australian interconnector, as the risk of interconnector failure producing load shedding is low (so long as water storages are reasonable at the time of failure23). Therefore, while dispatch efficiency would be significantly lower without the Basslink interconnector in service, the value of these costs is far lower than the value of reliability.

Benefits of the ‘2BSI + 1200MW wind’ case study Building new renewable generation in Tasmania (1,200 MW of wind), timed to coincide with commissioning of the second interconnector, would not increase projected market benefits of the second Bass Strait interconnector. Although this case delivers additional dispatch efficiency, environmental scheme, and resilience benefits, the additional capital investment costs outweigh the benefits gained. This is largely due to oversupply of renewable generation in the southern regions (South Australia, Victoria, and Tasmania). Prior to the second Bass Strait interconnector, renewable generation is already built in South Australia (facilitated by LRET) and Victoria (facilitated by VRET and LRET). Without greater interconnection between Victoria and New South Wales, or further brown coal retirements, additional wind generation in Tasmania is projected to compete, at times, with other renewable generation on the mainland, and is therefore not as beneficial as it would otherwise have been in the absence of these other renewable energy policies.

Benefits of development of both interconnector options Table 8 shows that the most beneficial development is forecast to be the combined development of the additional South Australian interconnector and the second Bass Strait interconnector. Developing both links, while the most costly option, requiring almost double the capital investment, is forecast to provide maximum dispatch efficiency benefits, environmental scheme benefits, and resilience benefits. It also produces large projected savings in reliability costs and capital costs. As seen in Table 8, the projected value of developing both links is greater than the sum of its parts. That is, developing both links together is forecast to provide greater combined benefits than if each link was developed separately. This relates to further increases in dispatch efficiency associated with the increased diversity of renewable resources. In a market where intermittent generation sources will provide a large volume of energy, the benefits of diversifying the intermittent resource become increasingly important.

23 The levels of Hydro Tasmania storages at the time of any given Basslink outage, and the rainfall inflows during the period of outage, will impact

the overall cost of any Basslink outage (as well as the timing and duration of any such outage). The 2015–16 Basslink coincided with low annual rainfall conditions, which presented additional challenges compared to the case if storages were higher. AEMO’s modelling for this assessment assumes ‘average’ rainfall inflows.


© AEMO 2017 39

Generation diversity benefits For any investment portfolio, it is prudent to ‘hedge bets’ and not be overexposed to any one solution. For share market investors, this will usually take the form of a diversified portfolio spanning many industries and sectors, including ‘blue chip’ defensive stocks and high dividend yield stocks, while also targeting areas of potential growth. By investing in this way, the underlying risk of the portfolio is reduced, while opportunity also exists to spread exposure to potential gains. The same applies for the electricity sector – having a mix of geographically diverse technologies, particularly intermittent technologies such as wind and solar, will reduce investment risks associated with lack of resource availability in any one location, or for any one technology. It also lowers costs to consumers by smoothing the aggregate intermittency and reducing the need to dispatch higher marginal cost generation plant such as GPG. Figure 23 below shows the average time of day generation from wind farms is available in different regions, based on historical data observed in 2013–14.24 The figure shows that the resource profiles of wind farms in South Australia and Tasmania are quite different – while Tasmanian wind has greater daytime production, South Australia’s wind generation profile has greater operation near peak load times in the evening and overnight. This will mean that, on average, South Australian wind generation will provide greater dispatch efficiency gains, as it is more likely that developing additional wind will offset higher-cost GPG. The Tasmanian wind resource, with increased availability during daylight hours, will be competing more with rooftop and large-scale solar PV and baseload thermal plant. As rooftop PV installations increase and minimum demand starts to be observed during the middle of the day, this may lead to negative prices if inflexible baseload plant continue to operate at minimum loading. Therefore, additional wind from Tasmania could be of less value to the mainland than additional wind from South Australia, up to a point. Once good resource spots have been exploited, or too much wind is located in one geographic location, diversity in renewable resources will become more highly valued. Figure 24 provides further clarity on the diversity of the wind resource across regions. The figure shows that Tasmania typically produces near its annual average during the winter months, when local demand is greatest, but also produces relatively high output during summer, the time where traditionally hot temperatures on the mainland drive high demand (and therefore when GPG production is most needed). Even if South Australian wind were perceived to be better correlated with the operational demand curve, there is still inherent value in developing it from more locations. For every MW of wind in South Australia, there is a diminishing benefit of installing more capacity in that location, as that additional capacity will also compete with the existing wind. The figures show that New South Wales wind patterns are also favourable when compared against peak demand periods. However, to build enough wind capacity to meet the region’s energy requirement, batteries would need to be installed, or export capacity would need to be further augmented, to avoid wind being constrained off due to network limitations at times of high production.

24 The 2013−14 year has been used as the reference year for all the modelling, from which demand, solar, and wind traces have been derived.


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Figure 23 Average wind farm operation per region, by time of day

Figure 24 Average wind farm operation per region, by month

Improving use of existing Tasmanian Hydro One of the projected effects of a second Bass Strait interconnector is an increased ability for Hydro Tasmania generation facilities with flexible storages to generate more during periods of highest value, and to import energy during periods of lowest value. From a market benefits perspective, increasing hydro production during periods of high GPG production would lead to increased dispatch efficiency benefits. Figure 25 below shows the ‘duration curve’ of the hydro generation in Tasmania in 2024−25 and 2028−29 for all cases in the Neutral scenario. A duration curve represents the percentage of time hydro generation was at or above a given level. The figure shows that, without the development of the second Bass Strait interconnector (the Base case), the hydro portfolio is projected to operate more at low production levels, and less at high production levels.

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© AEMO 2017 41

Figure 25 Generation duration curve for hydro generation in Tasmania, pre and post-augmentation

The value of this peakier hydro generation utilisation can be observed by looking at average hydro generation by time of day. Figure 26 shows that the second Bass Strait interconnector is projected to allow Tasmanian hydro plant to generate more during morning and evening peaks, when prices are expected to be higher, and less during off-peak periods. The lower hydro capacity factor observed during daytime off-peak in the second Bass Strait case is due to the higher local wind generation assumed in this case (which typically generated more during off-peak periods in the 2013−14 reference year used in this study).

Figure 26 Average generation by time of day for hydro facilities in Tasmania

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Tasmanian Hydro Generation Duration Curves (Neutral Sensitivity)

2025 Base Case 2029 Base Case 2029 2BSI + 1200 MW wind2029 2BSI 2029 New SA Link+2BSI

0%

10%

20%

30%

40%

50%

60%

70%

0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00

Capa

city

Fac

tor (

%)

Base Case 2BSI New SA Link New SA Link + 2BSI

morning peak daytime (solar) off-peak evening peak

overnight off-peak


© AEMO 2017 42

4.2 45% Emissions Reduction scenario Table 9 below summarises the market benefits of the various interconnector upgrades and augmentations under the 45% Emissions Reduction scenario’s case studies.

Table 9 Market benefits of various interconnector options under the 45% Emissions Reduction scenario – summary



Overall net benefit

Base case QNI VNI $327m $47m $281m

2BSI $611m $387m $224m

2BSI + 1200MW wind $611m $387m $224m


New SA Link + 2BSI $1,354m $676m $678m

The Base case in the 45% Emissions Reduction scenario is more beneficial than in either of the other scenarios. The stronger abatement target drives more black coal retirement in Queensland, increasing the value of the QNI augmentation to better use resources between Queensland and New South Wales.

4.2.1 Detailed benefit assessment of various interconnector options The benefits of each case study are broken down by benefit category in Table 10 below.

Table 10 Market benefits of various interconnector options under the 45% Emissions Reduction Scenario – benefit detail

Cas

e st

udy

Dis

patc

h ef

ficie

ncy

bene

fits

Rel

iabi

lity

bene

fits

Cap

ital i

nves

tmen

t ef

ficie

ncy

bene

fits

Envi

ron-

men

tal

sche

me

bene

fits

Res

ilien

ce b

enef

its

NPV

of g

ross

mar

ket

bene

fits

to 2

035−

36

NPV

of a

nnua

lised

co

st to

203

5-36

Ove

rall

net m

arke

t be

nefit

Incr

emen

tal n

et

mar

ket b

enef

its

Base case QNI VNI

$99m $187m $45m -$4m $0m $327m $47m $281m $0m

2BSI $251m $335m -$1m -$1m $27m $611m $387m $224m -$57m

2BSI + 1200MW wind

$251m $335m -$1m -$1m $27m $611m $387m $224m -$57m

New SA Link

$497m $168m -$8m $70m $161m $888m $335m $553m $272m

New SA Link + 2BSI

$686m $295m $114m $72m $188m $1,354m $676m $678m $397m

The benefits above include the inherent benefit in each case study of the interconnector upgrades assumed for the Base case. The table also shows the incremental net market benefits, over and above the benefits attributable to the QNI and VIC–NSW interconnection augmentations.

Benefits of the second Bass Strait interconnector As shown in Table 10, in the 45% Emissions Reduction scenario the second Bass Strait interconnector is forecast to deliver:

$152m in dispatch efficiency benefits. $148m in Reliability benefits.


© AEMO 2017 43

$46m greater capital investment costs. $3m lower environmental scheme costs. $27m in improved Tasmanian resilience to the potential outage of the Basslink interconnector.

The second Bass Strait interconnector provides more projected dispatch efficiency benefits in this scenario than any other. As coal-fired generation retires on the mainland, the improved utilisation of hydro generation and intermittent renewable generation attributed to greater interconnection reduces reliance on costly gas-fired generation. Overall, however, the assessed net market benefit is negative. The interconnector provides projected benefits which are approximately $57m less than the interconnector development costs, due to a modest increase in capital investment efficiency and fewer resilience benefits. The higher build costs relate to the timing of renewable generation development, rather than fewer GPG capacity deferrals; the interconnector provides greater incentive to install wind capacity more quickly than the Base case, increasing build costs and therefore reducing capital investment efficiency benefits. The resilience benefits are lower since the accelerated retirement of coal-fired generation means more GPG is required irrespective of whether Basslink is in service or not. The outage of Basslink simply means that more GPG is required in one region and less in the other. Additional detailed investigations should identify whether this shortage in benefits is recoverable through other cost categories, and whether alternative generation development plans (including new interconnection between Victoria and New South Wales) could produce a more positive result.

Benefits of the ‘2BSI + 1200MW wind’ case study This scenario produces the same development pathway for the ‘2BSI + 1200MW wind’ case study as it does for the purer second Bass Strait interconnector case study. As such, there is no difference between outcomes between these two cases.

Benefits of development of both interconnector options Table 10 shows that the most beneficial development is forecast to be the combined development of the additional South Australian interconnector as well as the second Bass Strait interconnector, as is also forecast for the Neutral scenario. As in the Neutral scenario, the value of development of both links is greater than the sum of its parts. Interestingly, while both the second Bass Strait interconnector and additional SA interconnector cases forecast increased capital investments relative to the Base case, by developing both links the projection is for reduced capital investments. That is, while one link has not produced a forecast capital deferral benefit, developing both links does appear to deliver large capital investment efficiency benefits.

4.3 Low Grid Demand scenario Table 11 below summarises the market benefits of the various interconnector upgrades and augmentations under the different Low Grid Demand scenario case studies.

Table 11 Market benefits of various interconnector options under the Low Grid Demand scenario –summary



Overall net benefit

Base case QNI VNI $163m $77m $86m

2BSI $357m $418m -$61m

2BSI + 1200MW wind -$269m $418m -$687m


New SA Link + 2BSI $758m $707m $51m


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The table above shows that the projected value of an additional Tasmanian interconnector is lower in this scenario. Any further investigations will need to consider the potential benefits of the interconnector under a range of possible futures, and as such the Taskforce should consider a diverse mix of scenarios in its next steps to ensure its conclusions are robust.

4.3.1 Detailed benefit assessment of various interconnector options Table 12 below breaks down the source of benefits under the Low Grid Demand scenario for each interconnector development.

Table 12 Market benefits of various interconnector options under the Low Grid Demand Scenario – benefit detail

Cas

e st

udy

Dis

patc

h ef

ficie

ncy

bene

fits

Rel

iabi

lity

bene

fits

Cap

ital i

nves

tmen

t ef

ficie

ncy

bene

fits

Envi

ron-

men

tal

sche

me

bene

fits

Res

ilien

ce b

enef

its

NPV

of g

ross

m

arke

t ben

efits

to

2035

−36

NPV

of a

nnua

lised

co

st to

203

5-36

Ove

rall

net m

arke

t be

nefit

Incr

emen

tal n

et

mar

ket b

enef

its

Base case QNI VNI

$111m $58m -$4m -$2m $0m $163m $77m $86m $0m

2BSI $237m $43m $44m -$3m $36m $357m $418m -$61m -$147m

2BSI + 1200MW wind

$858m $43m -$1,178m -$3m $11m -$269m $418m $687m -$773m

New SA Link

$416m $38m $19m $6m $150m $630m $366m $264m $178m

New SA Link + 2BSI

$438m $93m $44m -$3m $186m $758m $707m $51m -$35m

The benefits above include the inherent benefit in each case study of the interconnector upgrades assumed for the Base case, that is, the benefits provided by the QNI and VIC-NSW upgrades. The table also shows the benefits with the effects of those upgrades removed, that is, isolating the benefits of the interconnector augmentations themselves.

Benefits of the second Bass Strait interconnector As shown in Table 12, in the Low Grid Demand scenario, the second Bass Strait interconnector is forecast to deliver: $126m in dispatch efficiency benefits. $15m in reduced reliability benefits (that is, higher reliability costs). $48m in capital investment efficiency benefits. No impact to environmental scheme costs. $36m in improved Tasmanian resilience to the potential outage of the Basslink interconnector.

Given the lower demand, the capital investment efficiency benefits of the interconnector are lower in this scenario than in the Neutral scenario. This was expected, given the analysis presented in Chapter 3. There are still some capital investment efficiency benefits, but these come at the expense of higher reliability costs, due to voluntary demand curtailment being relied on more often.

Dispatch efficiency benefits however, are higher than in the Neutral scenario as the interconnector facilitates better use of existing hydro generation. With more coal-fired generation retirements in this scenario, this improved use allows hydro generation to displace costly gas-fired generation.


© AEMO 2017 45

The overall net market benefit of the interconnector is projected to be negative in this scenario, suggesting that the link would not provide economic value to consumers.

Benefits of the ‘2BSI + 1200MW wind’ case study Building new renewable generation in Tasmania (1,200 MW of wind), timed to coincide with commissioning of the second interconnector, in a market which has a much reduced need for additional generation, would be highly inefficient. While the additional wind investment is projected to provide very large dispatch efficiencies, these forecast gains are eroded by the capital investment itself.

Benefits of development of both interconnector options The increased benefit of a more diversified renewable generation portfolio with the development of both interconnectors is not as beneficial in this scenario. The generation mix is inherently more diversified in this scenario irrespective of the Tasmanian interconnector, with increased development of distributed generation across all regions, even though there is no new wind generation built in Tasmania. As such, while the link is projected to drive additional efficiencies, the cost of the link is forecast to outweigh the gains in market benefits attributed to the link.


© AEMO 2017 46

5. TASMANIAN TRANSMISSION OUTLOOK This chapter identifies potential limitations on the Tasmanian 220 kV transmission network, to accommodate increased new renewable generation in Tasmania and second Bass Strait interconnector using the scenarios outlined in Section 1.1.2. This chapter also presents assessments on: Changes to network development on the mainland required to accommodate a second Bass Strait

Interconnector. Emerging challenges to power system security and possible solutions.

5.1 Transmission limitations Two types of limitations are considered in the transmission development outlook – reliability limitations and economic limitations:

Reliability limitations occur if, at the time of regional maximum operational demand, the network does not have enough capacity to meet demand.

Economic limitations are where more expensive generation is dispatched ahead of cheaper generation to avoid network overloads.

Reliability limitations in the Tasmanian transmission network Since the Tasmanian demand forecast is almost flat in the Neutral and 45% Emissions Reduction scenarios, and reduced in the Low Grid Demand scenario, no reliability limitations were identified over the 20-year outlook period.

Economic dispatch limitations in the Tasmanian transmission network Presently, there are number of constraints in Tasmanian transmission network at times of high generation from hydro generators or wind generators or increased import from Victoria. These are managed by generation re-dispatch and special protection schemes. Connecting any more wind power generation is expected to increase network congestion, particularly at times of high wind power generation output. This may result in restricting wind and reducing efficient use of hydro generation. This report identifies the location of potential economic dispatch limitations in the Tasmanian transmission network that may arise in all scenarios over the next 20 years, if new generation development occurs in line with the generation outlook in Chapter 3. These are listed in Table 13.

Most of these limitations already exist in the network. Those relating to wind generation are expected to become more prominent if more wind generation is connected in these zones.


© AEMO 2017 47

Table 13 Potential economic dispatch limitations

Potential transmission limitations

Dispatch conditions Possible solutions Scenarios

Transmission limitations on the Palmerston – Sheffield 220kV line

High wind generation in North- West Tasmania. High import from VIC to TAS through second Bass Strait interconnector

Reduce wind and/or hydro generation from North-West and West; Reduce import to Tasmania via second Bass Strait interconnector Uprating of existing Sheffield–Palmerston 220 kV circuit for a higher thermal rating, or a second Sheffield-Palmerston 220 kV circuit.

Neutral and 45% Emissions Reduction. All case studies.

Transmission limitations on the Georgetown – Sheffield 220kV line

High wind generation from the North-West and West Tasmania area and, high Basslink export from TAS to VIC.

Reduce wind and/or hydro generation from North-West and West; Reduce Basslink export from TAS to VIC. Uprating of existing Georgetown – Sheffield 220 kV circuits for a higher thermal rating, or a third Georgetown-Sheffield 220 kV circuit.

Neutral, 45% Emissions Reduction. All case studies, except 2BSI and ‘2BSI + 1200MW wind’ studies.

Voltage collapse at Georgetown

High export from TAS to VIC at times of no GPG units in Tamar Valley and reduced number of hydro units in northern Tasmania (current issue to continue to future)

Reduce export from TAS to VIC; Constrain on generation in Tamer Valley and hydro units in northern Tasmania; Installation of additional reactive support at Georgetown substation.

All three scenarios. All case studies.

Transient over-voltage at Georgetown 220 kV

High export from TAS to VIC via Basslink at times of no GPG units in Tamar Valley and reduced number of hydro units in northern Tasmania (current issue to continue to future)

Reduce export from TAS to VIC; Constrain on generation in Tamer Valley and hydro units in northern Tasmania; Installation of additional dynamic reactive support at Georgetown substation.


Basslink inverter commutation instability due to low fault level at George Town 220 kV

High import from Victoria to Tasmania via Basslink and low or no GPG units online in Tamar Valley and low or no hydro units in northern Tasmania (current constraint to continue).

Constrain on generation in Tamer Valley and hydro units in northern Tasmania; Operate existing GPG and hydro units as synchronous condensers. Installation of new synchronous condensers. Generation re-dispatch or constrain Basslink import into Tasmania.


High rate of change of frequency (RoCoF)

High wind generation in Tasmania and/or increased import from Victoria to Tasmania and reduced Tasmania hydro units on line

Constrain on GPG and hydro units in Tasmania. Operate existing GPG and hydro units as synchronous condensers. Inertia support services from wind generation. Fast frequency services from non-network solutions.

Neutral and 45% Emissions Reduction. All case studies.

Unavailability of existing frequency control ancillary support (FCAS) services with retirement of smelters in Tasmania.

Reduce Basslink import from Victoria to Tasmania. Fast frequency support services from second Bass Strait interconnector. Fast frequency services from non-network solutions.

Low Grid Demand. All case studies.

The timing and scope of any projects required to address potential economic dispatch limitations will depend on detailed market assessment of the costs and benefits of any solution.


© AEMO 2017 48

5.2 Special Control Schemes in Tasmania It is assumed the existing network control system protection scheme (NCSPS) and frequency control system protection scheme (FCSPS) continue to be available for service, and both of these system protection schemes would be extended to control the power flow on the second Bass Strait interconnector. HVDC based on VSC technology, which was modelled for the second Bass Strait interconnector, is capable of rapid control of transfer between ±600 MW between Victoria and Tasmania. Low Grid Demand scenario assumptions include the retirement of a number of large industrial loads in the NEM, including in Tasmania. In this scenario, the lack of availability of large industrial load is projected to affect the existing FCSPS and lead to frequency control issues. To meet this projected challenge without a second Bass Strait interconnector, import from Victoria to Tasmania would need to be reduced.25 With the FCSPS not in service, a second Bass Strait interconnector could improve frequency control and allow increased imports from Victoria to Tasmania.

5.3 Network limitations in the mainland NEM Compared to the Base case, the second Bass Strait interconnector case (including the ‘2BSI + 1200MW wind’ case study) is projected to defer the need for about 300 to 700 MW of new GPG in Victoria’s Latrobe Valley, but no other major generation changes are projected in the mainland. In the Base case, the existing transmission lines in the Latrobe Valley area are projected to be sufficient to accommodate new GPG in the area. The reduction of 300 to 700 MW in Latrobe Valley GPG does not materially change projected transmission network augmentation requirements in the mainland NEM. Retirement of coal-powered generation in the mainland would reduce available Frequency Control Ancillary Services (FCAS) in the NEM. However, there is adequate supply of FCAS for normal operating circumstances where FCAS can be sourced from anywhere within the NEM.26 The mainland is interconnected by alternating current (AC) network and existing hydro generators in New South Wales, Queensland, and Victoria, and Basslink could provide sufficient FCAS to the mainland. Other potential sources of FCAS could include GPG, a second Bass Strait interconnector, wind power generation, large-scale solar PV, and battery storage.

5.4 Emerging system security challenges Increased wind power generation is likely to increase export to Victoria or reduce hydro generation in Tasmania. At times of low wholesale energy prices in Victoria or low water storage levels in Tasmania, Basslink and the second Bass Strait interconnector would facilitate high import from Victoria to Tasmania. Under such conditions, the number of hydro generators in service is likely to be reduced. This may lead to power system security challenges such as reduced system inertia, less FCAS capability, and less system strength in the Tasmanian power system. As a consequence, frequency and voltage control is expected to become more challenging in Tasmania. For all scenarios, possible solutions to address these power system security challenges include: A number of existing hydro generators and GPG in Tasmania could provide inertia services and

system strength services by operating in synchronous condenser mode, but there are currently no market-based incentives for these services.

There is a market mechanism to procure adequate FCAS capability through NEMDE (the NEM Dispatch Engine). This mechanism would result in re-dispatch of generators in Tasmania and Bass Strait interconnector transfer, to increase FCAS availability in Tasmania. The second Bass Strait interconnector was modelled with a VSC technology-based HVDC link, and this technology would

25 This limitation has not been included in the market modelling, but given that it would only restrict imports into Tasmania, it is not expected to

result in material differences in the analysis. 26 AEMO. 2016 Electricity Statement of Opportunities, August 2016, and 2016 National Transmission Network Development Plan, December 2016.

Available at: http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/NEM-Electricity-Statement-of-Opportunities and http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Transmission-Network-Development-Plan.


© AEMO 2017 49

enable the second Bass Strait interconnector to provide better FCAS, compared to FCAS through Basslink

Retirement of coal generation in the mainland would reduce available FCAS in the NEM. As referred to in the 2016 NTNDP, sufficient sources of FCAS capability are projected on the mainland and through the existing Basslink interconnector, without the need for additional interconnection.


© AEMO 2017 50

6. CONCLUSIONS Based on the high level assessment undertaken for this report, a second Bass Strait interconnector may just provide sufficient market benefits under the Neutral scenario to justify the estimated $940 million investment, but the benefits are not robust. Under both the Low Grid Demand and 45% Emissions Reduction scenarios, the projected net market benefits of this investment are negative. Despite greater dispatch efficiency improvements in these two scenarios (driven by assumed accelerated retirement of coal-fired generation), the second Bass Strait interconnector was not projected to deliver net market benefits due to diminished capital deferral value. Due to the sensitivity of this analysis to changes in market conditions, it is recommended that any further analysis on the benefits of Bass Strait interconnection include the following: Multiple reference years and Monte Carlo simulation modelling to better understand how sensitive

the market benefits are to variations in renewable generation availability, coincidence of demand between regions, and thermal generation outages.

Larger interconnector capacity options between Victoria and New South Wales. Consideration of competition benefits, and potentially wider economic benefits associated with

improving Tasmania’s resilience to Basslink outages. Evaluation of economic limitations in Tasmania that may currently constrain renewable generation. Assessment of the transmission upgrades required in Victoria to accommodate high renewable

generation penetration driven by the VRET. Additional scenarios to better understand the risks associated with this interconnector investment –

potentially looking at more utility-scale battery and less gas-fired generation post 2030, or delayed coal retirements.

Under all scenarios, the earlier commissioning of a new interconnector between Victoria and South Australia is projected to improve the long-term market benefits associated with a second Bass Strait interconnector. As well, greater interconnection provided synergies that meant the combined net market benefits were likely to be greater than the sum of the separate effects. In particular, multiple new interconnections were able to exploit geographic diversity in wind availability and solar PV output to reduce the level of intermittency at an aggregate level across the NEM, lowering reliance on high marginal cost generation plant such as GPG to back up renewable generation. This highlights the important of strategic, national, co-ordinated infrastructure planning to facilitate the transformation of the NEM at lowest cost to consumers.


© AEMO 2017 51

MEASURES AND ABBREVIATIONS

Units of measure

Abbreviation Unit of measure

GW Gigawatt

GWh Gigawatt hour

kV Kilovolt

MW Megawatt

TW Terawatt

Abbreviations

Abbreviation Expanded name

AC Alternating current

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

CCGT Closed Cycle Gas Turbine

COP21 21st Conference of Parties, Paris

ESOO Electricity Statement of Opportunities

FCAS Frequency control ancillary services

FCSPS Frequency control system protection scheme

GPG Gas-powered generation

HVDC High voltage direct current

LCC Line-commutated current-sourced converter

LGC Large-scale Generation Certificate

LRET Large-scale Renewable Energy Target

NCSPS Network control system protection scheme

NEFR National Electricity Forecasting Report

NEM National Energy Market

NEMDE NEM Dispatch Engine

NTNDP National Transmission Network Development Plan

NPV Net Present Value

OCGT Open Cycle Gas Turbine

POE Probability of Exceedance

PV Photovoltaic

RIT-T Regulatory investment test for transmission

ROCOF Rate of change of frequency

SRMC Short run marginal cost

VCR Value of customer reliability

VRET Victorian Renewable Energy Target

VSC Voltage source converter


© AEMO 2017 52

GLOSSARY This document uses many terms that have meanings defined in the National Electricity Rules (NER). The NER meanings are adopted unless otherwise specified.

Term Definition

ancillary services Services used by AEMO that are essential for: Managing power system security. Facilitating orderly trading. Ensuring electricity supplies are of an acceptable quality. This includes services used to control frequency, voltage, network loading and system restart processes, which would not otherwise be voluntarily provided by market participants on the basis of energy prices alone. Ancillary services may be obtained by AEMO through either market or non-market arrangements.

augmentation The process of upgrading the capacity or service potential of a transmission (or a distribution) pipeline.

consumer A person or organisation who engages in the activity of purchasing electricity supplied through a transmission or distribution system to a connection point.

customer See consumer.

demand See electricity demand.

demand-side participation The situation where consumers vary their electricity consumption in response to a change in market conditions, such as the spot price.

energy See electrical energy.

generating system A system comprising one or more generating units that includes auxiliary or reactive plant that is located on the generator’s side of the connection point.

generating unit The actual generator of electricity and all the related equipment essential to its functioning as a single entity.

generation The production of electrical power by converting another form of energy in a generating unit.

generation capacity The amount (in megawatts (MW)) of electricity that a generating unit can produce under nominated conditions. The capacity of a generating unit may vary due to a range of factors. For example, the capacity of many thermal generating units is higher in winter than in summer.

generator A person who engages in the activity of owning, controlling or operating a generating system that is connected to, or who otherwise supplies electricity to, a transmission or distribution system and who is registered by AEMO as a generator under Chapter 2 (of the Rules) and, for the purposes of Chapter 5 (of the Rules), the term includes a person who is required to, or intends to register in that capacity.

inertia Produced by synchronous generators, inertia dampens the impact of changes in power system frequency, resulting in a more stable system. Power systems with low inertia experience faster changes in system frequency following a disturbance, such as the trip of a generator.

installed capacity Refers to generating capacity (in megawatts (MW)) in the following context: A single generating unit. A number of generating units of a particular type or in a particular area. All of the generating units in a region.

interconnector A transmission line or group of transmission lines that connects the transmission networks in adjacent regions.

interconnector flow The quantity of electricity in MW being transmitted by an interconnector.

Large-scale Renewable Energy Target (LRET)

See national Renewable Energy Target scheme.

limitation (electricity) Any limitation on the operation of the transmission system that will give rise to unserved energy (USE) or to generation re-dispatch costs.

load A connection point or defined set of connection points at which electrical power is delivered to a person or to another networks or the amount of electrical power delivered at a defined instant at a connection pint, or aggregated over a defined set of connection points.

maximum demand The highest amount of electrical power delivered, or forecast to be delivered, over a defined period (day, week, month, season, or year) either at a connection point, or simultaneously at a defined set of connection points.


© AEMO 2017 53

Term Definition

National Electricity Law The National Electricity Law (NEL) is a schedule to the National Electricity (South Australia) Act 1996, which is applied in other participating jurisdictions by application acts. The NEL sets out some of the key high-level elements of the electricity regulatory framework, such as the functions and powers of NEM institutions, including AEMO, the AEMC, and the AER.

National Electricity Market (NEM)

The wholesale exchange of electricity operated by AEMO under the Rules.

National Electricity Rules (the Rules)

The National Electricity Rules (NER) describes the day-to-day operations of the NEM and the framework for network regulations. See also National Electricity Law.

National Transmission Network Development Plan (NTNDP)

An annual report to be produced by AEMO that replaces the existing National Transmission Statement (NTS) from December 2010. Having a 20-year outlook, the NTNDP will identify transmission and generation development opportunities for a range of market development scenarios, consistent with addressing reliability needs and maximising net market benefits, while appropriately considering non-network options.

National Transmission Planner

AEMO acting in the performance of National Transmission Planner functions.

National Transmission Planner (NTP) functions

Functions described in section 49(2) of the National Electricity Law.

net market benefit Refers to market benefits of an augmentation option minus the augmentation cost. The market benefit of an augmentation is defined in the regulatory investment test for transmission developed by the Australian Energy Regulator.

network The apparatus, equipment, plant and buildings used to convey, and control the conveyance of, electricity to consumers (whether wholesale or retail) excluding any connection assets. In relation to a network service provider, a network owned, operated or controlled by that network service provider.

network capability The capability of the network or part of the network to transfer electricity from one location to another.

network congestion When a transmission network cannot accommodate the dispatch of the least-cost combination of available generation to meet demand.

network constraint equation

A constraint equation deriving from a network limit equation. Network constraint equations mathematically describe transmission network technical capabilities in a form suitable for consideration in the central dispatch process. See also ‘constraint equation’.

network limit Defines the power system’s secure operating range. Network limits also take into account equipment/network element ratings.

network limitation Network limitation describes network limits that cause frequently binding network constraint equations, and can represent major sources of network congestion. See also network congestion.

network service Transmission service or distribution service associated with the conveyance, and controlling the conveyance, of electricity through the network.

network service provider A person who engages in the activity of owning, controlling or operating a transmission or distribution system and who is registered by AEMO as a network service provider under Chapter 2 (of the Rules).

non-network option An option intended to relieve a limitation without modifying or installing network elements. Typically, non-network options involved demand-side participation (including post contingent load relief) and new generation on the load side for the limitation.

power See ‘electrical power’.

power station In relation to a generator, a facility in which any of that generator’s generating units are located.

power system The National Electricity Market’s (NEM) entire electricity infrastructure (including associated generation, transmission, and distribution networks) for the supply of electricity, operated as an integrated arrangement.

power system reliability The ability of the power system to supply adequate power to satisfy customer demand, allowing for credible generation and transmission network contingencies.

power system security The safe scheduling, operation, and control of the power system on a continuous basis in accordance with the principles set out in clause 4.2.6 (of the Rules).

reactive energy A measure, in varhour (varh), of the alternating exchange of stored energy in inductors and capacitors, which is the time-integral of the product of voltage and the out-of-phase component of current flow across a connection point.


© AEMO 2017 54

Term Definition

reactive power The rate at which reactive energy is transferred. Reactive power, which is different to active power, is a necessary component of alternating current electricity. In large power systems it is measured in MVAr (1,000,000 volt-amperes reactive). It is predominantly consumed in the creation of magnetic fields in motors and transformers and produced by plant such as: Alternating current generators. Capacitors, including the capacitive effect of parallel transmission wires. Synchronous condensers. Management of reactive power is necessary to ensure network voltage levels remains within required limits, which is in turn essential for maintaining power system security and reliability.

region An area determined by the AEMC in accordance with Chapter 2A (of the Rules), being an area served by a particular part of the transmission network containing one or more major load centres of generation centres or both.

regulatory investment test for transmission (RIT-T)

The test developed and published by the AER in accordance with clause 5.6.5B, including amendments. The test is to identify the most cost-effect option for supplying electricity to a particular part of the network. It may compare a range of alternative projects, including, but not limited to, new generation capacity, new or expanded interconnection capability, and transmission network augmentation within a region, or a combination of these.

reliability The probability that plant, equipment, a system, or a device, will perform adequately for the period of time intended, under the operating conditions encountered. Also, the expression of a recognised degree of confidence in the certainty of an event or action occurring when expected.

renewable energy target (RET)

See LRET and VRET.

rooftop photovoltaic (PV) Includes both residential and commercial photovoltaic installations that are typically installed on consumers’ rooftops.

scenario A consistent set of assumptions used to develop forecasts of demand, transmission, and supply.

security Security of supply is a measure of the power system's capacity to continue operating within defined technical limits even in the event of the disconnection of a major power system element such as an interconnector or large generator.

substation

A facility at which two or more lines are switched for operational purposes. May include one or more transformers so that some connected lines operate at different nominal voltages to others.

supply The delivery of electricity.

synchronous condenser Synchronous condensers are synchronous machines that are specially built to supply only reactive power. The rotating mass of synchronous condensers will contribute to the total inertia of the network from its stored kinetic energy.

transmission network A network within any participating jurisdiction operating at nominal voltages of 220 kV and above plus: Any part of a network operating at nominal voltages between 66 kV and 220 kV that

operates in parallel to and provides support to the higher voltage transmission network. Any part of a network operating at nominal voltages between 66 kV and 220 kV that is not

referred to in paragraph (a) but is deemed by the Australian Energy Regulator (AER) to be part of the transmission network.

voltage instability An inability to maintain voltage levels within a desired operating range. For example, in a 3-phase system, voltage instability can lead to all three phases dropping to unacceptable levels or even collapsing entirely.

Appendix D 135

Appendix D: Ernst & Young Report: Market dispatch cost benefit modellingEY report: Market dispatch cost benefit modelling of a second Bass Strait interconnector, 13 January 2017.

Market dispatch cost benefit modelling of a second Bass Strait interconnector Department of the Environment and Energy 13 January 2017

A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation

Notice

Ernst & Young was engaged on the instructions of the Department of the Environment and Energy (“the Department”) on behalf of the Tasmanian Energy Taskforce to provide research and market dispatch cost benefit modelling (the “Services”) in relation to a proposed second Tasmanian interconnector (the "Project"), in accordance with the work order dated 21 September 2016.

The results of Ernst & Young’s work, including the assumptions and qualifications made in preparing the report, are set out in Ernst & Young's report dated 13 January 2017 ("Report"). The Report should be read in its entirety including the cover letter, the applicable scope of the work and any limitations. A reference to the Report includes any part of the Report. No further work has been undertaken by Ernst & Young since the date of the Report to update it.

Ernst & Young has prepared the Report for the benefit of the Department and has considered only the interests of the Department. Ernst & Young has not been engaged to act, and has not acted, as advisor to any other party. Accordingly, Ernst & Young makes no representations as to the appropriateness, accuracy or completeness of the Report for any other party's purposes.

No reliance may be placed upon the Report or any of its contents by any recipient of the Report for any purpose and any party receiving a copy of the Report must make and rely on their own enquiries in relation to the issues to which the Report relates, the contents of the Report and all matters arising from or relating to or in any way connected with the Report or its contents.

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Ernst & Young’s liability is limited by a scheme approved under Professional Standards Legislation.


Department of the Environment and Energy 13 January 2017

Market dispatch cost benefit modelling of a second Bass Strait interconnector

In accordance with work order dated 21 September 2016, pursuant to agreement COAG Energy Council Panel of Consultants (PRI-00003197 dated 31 July 2015) (“Agreement”), Ernst & Young (“we” or “EY”) has been engaged by the Department of the Environment and Energy (“you”, “the Department” or the “Client”) on behalf of the Tasmanian Energy Taskforce to provide research and market dispatch cost benefit modelling (the “Services”) in relation to a proposed second Tasmanian interconnector (the “Project”).

The enclosed report (the “Report”) sets out the outcomes of our work. You should read the Report in its entirety. A reference to the report includes any part of the Report.

Purpose of our Report and restrictions on its use

Please refer to a copy of the Agreement for the restrictions relating to the use of our Report. We understand that the deliverable by EY will be used for the purpose of assisting the Department in its investigation into the relative merits of a proposed second Tasmanian interconnector in relation to market dispatch costs and benefits in the National Electricity Market (the “Purpose”).

This Report was prepared on the specific instructions of the Department solely for the Purpose and should not be used or relied upon for any other purpose.

This Report and its contents may not be quoted, referred to or shown to any other parties except as provided in the Agreement. We accept no responsibility or liability to any person other than to the Department or to such party to whom we have agreed in writing to accept a duty of care in respect of this Report, and accordingly if such other persons choose to rely upon any of the contents of this Report they do so at their own risk. Third parties seeking a copy of this Report will require permission from EY, and will be required to sign an access letter in the format agreed to between EY and the Department.

Nature and scope of our work

The scope of our work, including the basis and limitations, are detailed in our Agreement and in this Report.

Our work commenced on 21 September 2016 and was completed on 13 January 2017. Therefore, our Report does not take account of events or circumstances arising after 13 January 2017 and we have no responsibility to update the Report for such events or circumstances.


Limitations

This modelling considers a number of combinations of input assumptions relating to future conditions, which may not necessarily represent actual or most likely future conditions. Additionally, modelling inherently requires assumptions about future behaviours and market interactions, which may result in forecasts that deviate from future conditions. There will usually be differences between estimated and actual results, because events and circumstances frequently do not occur as expected, and those differences may be material. We take no responsibility for the achievement of projected outcomes, if any.

We highlight that our analysis and Report do not constitute investment advice or a recommendation to you on a future course of action. We provide no assurance that the scenarios we have modelled will be accepted by any relevant authority or third party.

Our conclusions are based, in part, on the assumptions stated and on information provided by the Department during the course of the engagement. The modelled outcomes are contingent on the collection of assumptions as agreed with the Department and no consideration of other market events, announcements or other changing circumstances are reflected in this Report. Neither Ernst & Young nor any member or employee thereof undertakes responsibility in any way whatsoever to any person in respect of errors in this Report arising from incorrect information provided by the Department.

In the preparation of this Report we have considered and relied upon information from a range of sources believed after due enquiry to be reliable and accurate. We have no reason to believe that any information supplied to us, or obtained from public sources, was false or that any material information has been withheld from us.

We do not imply and it should not be construed that we have verified any of the information provided to us, or that our enquiries could have identified any matter that a more extensive examination might disclose. However, we have evaluated the information provided to us by the Department as well as other parties through enquiry, analysis and review and nothing has come to our attention to indicate the information provided was materially mis-stated or would not afford reasonable grounds upon which to base our Report.

This letter should be read in conjunction with our Report, which is attached.

Thank you for the opportunity to work on this project for you. Should you wish to discuss any aspect of this Report, please do not hesitate to contact Ian Rose, Ben Vanderwaal or Michael Fenech on 07 3011 3333.

Yours sincerely

Ben Vanderwaal Michael Fenech Executive Director Partner

Liability limited by a scheme approved under Professional Standards Legislation Ernst & Young | i

Table of contents 1. Executive summary ........................................................................................................ 1

2. Introduction .................................................................................................................. 7

3. Methodology and input assumption ................................................................................. 8

3.1 Market dispatch modelling methodology .................................................................... 8

3.2 Cost-benefit assessment ......................................................................................... 13

3.3 Interconnector revenue assessment ......................................................................... 14

3.4 Input assumptions .................................................................................................. 15

4. Scenarios .................................................................................................................... 16

4.1 Summary of scenarios ............................................................................................ 16

4.2 Base scenario ........................................................................................................ 17

4.3 Tasmanian wind expansion (TasWind) ....................................................................... 17

4.4 Tasmanian demand reduction (TasDemand) .............................................................. 18

4.5 Low rainfall (LowRain) ............................................................................................ 18

4.6 Strong emissions constraint (StrongAction) .............................................................. 18

5. Results – Regulated interconnector ................................................................................ 19

5.1 Base scenario ........................................................................................................ 19

5.2 Tasmanian wind generation expansion ..................................................................... 24

5.3 Tasmanian demand reduction .................................................................................. 27

5.4 Low rainfall ........................................................................................................... 28

5.5 Strong emissions constraint .................................................................................... 28

5.6 Discussion of other market benefits and costs .......................................................... 30

6. Results – Merchant interconnector ................................................................................. 33

6.1 Impact of bidding behaviour assumptions ................................................................. 33

6.2 Impact of interconnector ownership structure assumptions ........................................ 33

6.3 Summary of MNSP revenue outcomes ...................................................................... 34

6.4 Base scenario ........................................................................................................ 35

6.5 Other scenarios ..................................................................................................... 38

6.6 Impact of the MNSP on NEM market benefits ............................................................ 40

Liability limited by a scheme approved under Professional Standards Legislation Ernst & Young | ii

6.7 Relationship to EY financial modelling ...................................................................... 41

7. Financial impact of the second interconnector on Tasmanian market participants .............. 43

Base scenario regulated interconnector outcomes ............................................... 45

List of acronyms .............................................................................................. 47

Department of the Environment and Energy Market dispatch cost benefit modelling of a second Bass Strait interconnector

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1. Executive summary

EY has been asked by the Department of the Environment and Energy to undertake market modelling to evaluate the costs and benefits of a second interconnector between Tasmania and Victoria. Our analysis considers the impact of the development of the interconnector operating under both regulated and merchant structures.

In June 2016, the Tasmanian Energy Taskforce released a preliminary report that considered the feasibility of a second interconnector. The report highlighted the potential role that Tasmanian renewable energy resources could play as the National Electricity Market (NEM) transitions to a lower emissions future.

EY has conducted market modelling to consider two key questions:

• Operating as a regulated asset, under what scenarios would a second interconnector deliver market benefits that exceed the capital and operating costs of the second interconnector?

• Operating as a merchant asset (or Market Network Service Provider (MNSP)), what revenues could be earned by a second interconnector, and what would be the impact on other market participants?

To address these questions we have applied two different modelling approaches. To assess market benefits we consider the difference in total system cost (fuel, operating and maintenance, capital, etc.) between scenarios with and without the second interconnector. The assessment of MNSP revenues is calculated by modelling both Basslink and the second interconnector with the objective of maximising revenue earned by transporting energy between regions with different wholesale prices.

Detailed, half-hourly market simulations from 2026–27 to 2065–66 were conducted to inform these key questions. Up to the year 2035–36, modelling inputs have in part been provided by the Australian Energy Market Operator (AEMO) to increase consistency with work undertaken in parallel with the National Transmission Network Development Plan (NTNDP). EY’s modelling builds upon AEMO’s modelling in terms of extending the time horizon and in complexity, particularly with regards to the operation of the Hydro Tasmania fleet of energy-limited hydro generation.

In each scenario, we have modelled with and without the introduction of a second interconnector with 600 MW bi-directional capacity, starting operation in 2026–27.

Market benefits of a regulated interconnector

For the majority of scenarios considered, the second interconnector does not deliver market benefits in excess of its cost. This is shown in Table 1 which describes the scenarios chosen by the Department, and shows the total market benefits that are attributable to the second interconnector for the range of scenarios considered in which the second interconnector is regulated. (In these tables and throughout this Report, positive values indicate a benefit while negative values indicate a cost.) All prices in this Report refer to real June 2016 dollars unless otherwise labelled. The net present values are discounted to 2026–27 using real, pre-tax discount rates, unless otherwise stated. Only the TasDemand scenario delivers market benefits exceeding interconnector costs.


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Table 1: Net benefit with a regulated interconnector (NPV $m) Scenario description 7% discount rate 10% discount rate

Base

28% emissions reduction by 2030 Neutral demand

Renewable development matched with/without the second interconnector

-356 -470

TasWind Fixed 1,200 MW of new wind capacity in Tasmania prior to 2026–27 -642 -848

TasDemand 40% reduction in Tasmanian demand 853 424 LowRain Lower average rainfall in Tasmania -518 -725

StrongAction 45% emissions reduction by 2030, zero emissions by 2050 -331 -512

The net benefit values provided above account for the cost of the second interconnector. The components of the costs are provided in Table 2.

Table 2: Interconnector cost assumptions (NPV $m) Discount rate = 7% Discount rate = 10% Capital cost 940 940 Operating and maintenance 224 164 Total cost 1,164 1,104

The key insights from our analysis of the benefit of the second interconnector operating as a regulated asset are:

• Without the reduction in demand in Tasmania, the second interconnector is unlikely to drive market benefits in excess of its cost.

• Should there be a large reduction in demand in Tasmania, the market benefits of additional interconnection are significant, as without additional interconnection energy in Tasmania’s hydro systems would be wasted, particularly in years with high rainfall.

• There are two key sources of market benefits (other than in the Tasmanian demand reduction scenario):

• The interconnector defers between 450 MW and 600 MW of thermal generation on the mainland. This generation is required to maintain reliability in Victoria after the retirement of brown coal generation. Even in a scenario with strong emissions abatement targets (StrongAction), this capacity deferral does not occur until the early 2030s, meaning that the benefits of reduced capital investment are discounted. Discounting capital deferral benefits reduces the net market benefit.

• Variable cost savings due to the second interconnector are primarily attributable to the ability to more effectively use hydro storages to increase export to Victoria during trading intervals where high cost generation is, or would otherwise be, operating in Victoria. There is also some benefit from improved utilisation of other existing Tasmanian generation assets including Tamar Valley CCGT.

• These outcomes are dependent on the capital cost assumptions and gas cost assumptions used.

• Although the second interconnector does facilitate additional wind generation investment in Tasmania, the market benefits that result are relatively minor. Wind resources in Tasmania are superior to the mainland; however, the benefits of developing these resources are limited due to:


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• transmission losses in exporting wind generation from Tasmania at exports above the current export capacity of Basslink

• high levels of wind generation in Tasmania also interact with the ability of the hydro generators to manage water inflows and storage levels, and can limit the ability to cost effectively use hydro resources1

• Tasmanian wind is exported to Victoria which already has significant wind development due to the impact of the Victorian renewable energy scheme.

• Under the scenarios considered, the modelling suggests 1,100 MW of additional wind (above the existing level) is a reasonable limit on Tasmanian wind capacity with the second interconnector, as shown by the lower market benefits in the LowRain scenario relative to the Base scenario.

• Higher rainfall in Tasmania increases the volume of surplus energy in Tasmania. The second interconnector allows a more effective use of this surplus, increasing variable cost savings. In lower rainfall years, the utilisation of the additional export capacity reduces; however, the second interconnector may provide other benefits that are valuable in dry years that are not captured in the market benefits assessment. This occurs in all scenarios but is also demonstrated by lower market benefits in the LowRain scenario.

• The impact of more aggressive emissions abatement on market benefits is dependent on the amount and timing of energy storage (such as batteries) built in Victoria. In general, market benefits improve if the deferral in investment in new capacity as a result of the second interconnector occurs earlier. This did not occur with the stronger emissions constraint as earlier brown coal retirements are replaced by earlier battery storage development and the total amount of battery storage with and without the second interconnector is similar. There is no divergence in new thermal capacity until the early 2030s as occurred with the Base scenario emissions constraint. Consequently, there is no significant improvement in the value provided by the second interconnector in terms of capital deferment.

Comparison to NTNDP outcomes

The NTNDP provides an assessment of market benefits of the second interconnector. AEMO’s modelling indicates that the second interconnector could potentially deliver a net benefit in their base scenario. AEMO’s market benefits include environmental scheme benefits and resilience benefits that we have not quantified. When these benefits are excluded to put AEMO’s outcomes on a more similar footing to our outcomes, the remaining benefits in AEMO’s result accounts for approximately 90% of the cost of the second interconnector. In contrast, our modelling indicates that benefits account for approximately 69% of the cost of the second interconnector.

A direct comparison of our approach and AEMO’s is not possible given our limited knowledge of the details of their approach. However, possible differences in approach that could contribute to the reduced benefit in our outcomes are:

• AEMO’s market benefits include environmental scheme benefits and resilience benefits that are not captured in our modelled market benefits. We have qualitatively assessed the potential impact of a second interconnector on energy security.

• AEMO bid all generators at their short-run marginal cost (SRMC) whereas our modelling incorporates elements of competitive bidding behaviour.

1 Wind generation is highly correlated within Tasmania and loosely correlated with Victorian wind. Consequently, high levels

of wind generation may constrain Tasmania’s export capacity, even with the second interconnector, as the hydro generation in Tasmania does not have unlimited flexibility. Instances of high non-discretionary hydro output at times of high wind output will constrain export flows and cause either water to be spilt or wind generation to be curtailed, effectively reducing the advantage of Tasmania’s superior wind resource.


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• Our hydro modelling approach has been designed in collaboration with Hydro Tasmania in an attempt to capture the flexibility of the hydro generation fleet. AEMO’s models may have a higher or lower level of flexibility. Higher flexibility will increase second interconnector benefits while lower flexibility will decrease benefits.

• In their study, AEMO performed more detailed modelling of intra-regional transmission constraints. This may have increased market benefits by bringing forward capacity deferrals and reliability benefits.

• AEMO’s modelling uses 2013–14 as the reference year from which the demand, solar generation and wind generation timeseries have been derived. We use 2014–15 as the reference year. Different correlation between wind and solar generation and demand could lead to differing amounts or timings of entry of new capacity and thus potentially influence market benefits.

• AEMO’s study period extends from 2016–17 to 2035–36. Their evaluated market benefits therefore capture only eleven years of the second interconnector costs and benefits. In contrast, our modelling extends from 2026–27 to 2065–66 capturing 40 years of the second interconnector costs and benefits. However, our analysis of market benefits over the AEMO timeframe indicates that this is not a significant driver of differences in market benefits.

• Given time constraints, the results provided by AEMO as input to our modelling were draft outcomes. Generation development plans differ from those presented in AEMO’s final outcomes.

We have also considered a number of other market benefits that are not captured in market modelling. These benefits primarily relate to energy security and the ability of the second interconnector to provide ancillary services. Quantification of these benefits is challenging, but may be increasingly significant as synchronous generation retires. Quantification of other market benefits could be undertaken as part of a comprehensive RIT-T or investment due diligence assessment.

MNSP revenue

The assessment of the potential for a second interconnector to operate as an MNSP assumes that both the second interconnector and Basslink operate in cooperation to maximise total MNSP revenue. Furthermore, it is assumed that Hydro Tasmania is restricted from competing with the MNSPs — in modelling this means that Hydro Tasmania bids each generator at its water value (opportunity cost) in each period.

The analysis of the merchant scenarios is fundamentally different from the analysis of market benefits. This analysis focuses on the revenues that could be earned by the MNSP in isolation, with some consideration given to the impact on the broader market and specific market participants. The NPV of MNSP revenues is provided in Table 3.

Table 3: MNSP revenue (NPV $m – discount rate = 7%) Second interconnector Basslink Total Base 2,110 772 2,881 TasWind 2,244 848 3,092 TasDemand 4,869 2,579 7,448 LowRain 2,014 705 2,720 Oversupplied Base 1,357 420 1,776

Key insights:

• In every scenario, operating both Basslink and the second interconnector as profit maximising MNSPs results in large market revenues. Both the combined MNSP revenue and the second interconnector revenue exceed the cost of the second interconnector.


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• The majority of the scenarios consider changes that directly influence the Tasmanian electricity system. Scenarios that put downward pressure on wholesale prices in Tasmania (increased wind development and demand reduction) increase the expectation of MNSP revenue. Scenarios that increase wholesale prices in Tasmania (low rainfall) reduce MNSP revenues.

• MNSP revenue is highly sensitive to wholesale market conditions on the mainland. MNSP revenues are much lower in a market that is oversupplied with capacity such that wholesale prices are below the long-run marginal cost (LRMC) of new entrant generation.

Although MNSP revenues appear very positive in these results, there are a number of important considerations that need to be taken into account:

• The commercial model underpinning this analysis makes a number of assumptions that maximise potential MNSP revenues. Critically, the modelling assumes that Basslink and the second interconnector cooperate in maximising total revenue, rather than competing for potential revenue. Combined MNSP revenue would fall if the level of cooperation was reduced.

• The bidding behaviour of the interconnectors under the merchant model has a large impact on the Tasmanian wholesale market and other market participants as described below.

• The ability of the MNSPs to capture the price differential between Tasmania and Victoria requires Hydro Tasmania not to compete with the interconnectors.

Impact of the second interconnector on other market participants

The different bidding behaviours of the second interconnector in the regulated and merchant options have differing impacts on the Tasmanian wholesale market and hence the costs and revenues of its participants. Table 4 compares the impact of the merchant and regulated model on Hydro Tasmania and Tasmanian consumers.

• Under the regulated model, the second interconnector increases Hydro Tasmania’s wholesale market revenue and wholesale costs for Tasmanian consumers (not considering the any cost recovery of the second interconnector).

• Under the merchant model, the interconnectors have a significantly different effect on the Tasmanian wholesale market. The MNSPs derive revenue by capturing the price differential between Tasmania and Victoria eroding the benefit to Hydro Tasmania that occurs with the regulated option. The cost impact on Tasmanian consumers is also reduced.

• The impact on Hydro Tasmania is an important consideration given the ability of the MNSPs to capture the price differential between Tasmania and Victoria requires Hydro Tasmania not to compete with the interconnectors.

• Table 4 also shows that market benefits to the NEM are much lower under the merchant model. Profit-maximising bidding behaviour from the interconnectors can result in interconnector flows that are not beneficial from the perspective of minimising system costs.


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Table 4: Impact of second interconnector – Merchant vs regulated (NPV $m – discount rate = 7%) Impact of second

interconnector under merchant model

Impact of second interconnector under

regulated model

MNSP revenue – Second interconnector 2,110 - MNSP revenue – Basslink 772 - Increase in Hydro Tasmania wholesale market net revenue 221 6,171

Increase in total wholesale cost to TAS consumers (negative benefit) -73 3,908

Cost of the second interconnector -1,164 -1,164 NEM Market benefits 183 809

Financial modelling

EY have also been engaged to provide commercial and financial advice in respect to the assessment of commercial models for the second interconnector, ranging from fully regulated to fully merchant options. The outcomes of the financial modelling work form a separate report. Some of the market modelling outcomes are used as inputs to the financial modelling. However, the financial modelling considers a broader range of operational models such as converting Basslink to a regulated interconnector while operating the second interconnector as an MNSP. These have not been considered in the electricity market modelling.

The financial modelling relies on the same underlying data as the market modelling for the MNSP option. The financial modelling however examines the merits of a second interconnector by examining the private benefits that it would provide under an MNSP commercial model (i.e. those that can be captured by and accrue to the owner of the asset). Under the regulated model, those private benefits are somewhat divorced from the operation of the asset and the market benefits it delivers because private benefits flow indirectly through the regulated returns as determined by the Australian Energy Regulator (AER).

The financial analysis of the regulated interconnector is based on the assumption that the asset can meet the RIT-T — the analysis in this Report considers under what conditions this assumption is likely to be true. Under the MNSP model, however, those private benefits are largely a function of the owner’s ability to exploit arbitrage opportunities, and are therefore strongly dependent on wholesale market conditions. Furthermore, the private benefits depend on the extent to which the owner of the second interconnector can capture these when there is another interconnector (and associated commercial arrangements) that influence the extent to which deriving an acceptable commercial return is possible.

As a result, while the result of the financial modelling relies on the underlying market modelling data, it illustrates financial outcomes under a range of operating models not directly considered in the market modelling presented in this Report. The market modelling is best used to form a view on the merits of having a second interconnector. The financial modelling is best used to form a view on whether a private party might be willing to fund a second interconnector to derive a commercial return.

This means that the EY financial modelling report focuses on the ability of the owner of the second interconnector to derive and capture sufficient revenue to generate an acceptable commercial return to fund the asset, whereas this Report considers the impact of the second interconnector on systems costs and on other market participants.


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2. Introduction

The Department of the Environment and Energy has engaged EY to evaluate the potential benefits of a second interconnector between Tasmania and Victoria. EY has undertaken quantitative analysis of market modelling to determine the costs and benefits of a second interconnector across a range of scenarios and for alternative regulated and merchant models.

EY has also provided commentary on a range of other benefits that could arise due to the construction of a second interconnector that are not captured in wholesale market modelling. Where possible, EY has provided some assessment of the magnitude of these benefits.

This Report describes the key assumptions, input data sources and methodologies that have been applied in this modelling. This Report also summarises the outcomes of the modelling and provides the key insights from the scenarios modelled. In particular we highlight the most significant sources of market benefits and describe the drivers of both upsides and downsides for the second interconnector.

Our modelling uses input from AEMO’s 2016 NTNDP2 studies, supplied to EY prior to public release in draft form. Our work extends the timeframe of this modelling with half-hourly market simulations over a forty year timeframe, from 2026–27 to 2065–66. All prices in this Report refer to real June 2016 dollars unless otherwise labelled. All annual values refer to the fiscal year (1 July–30 June) unless otherwise labelled. The net present values are discounted to 2026–27, unless otherwise stated.

The focus of the modelling has been to determine the market benefits of a second interconnector, particularly those that are valued under the existing RIT-T3 methodology. In addition, our modelling considers the potential drivers for investment in a second interconnector as a merchant MNSP4. The modelling outcomes from these studies were provided to the EY financial modelling team. This team has conducted their own separate analysis involving a more detailed financial and commercial analysis of the second interconnector under different operational and ownership structures.

The Report is structured as follows:

• Section 3 outlines the methodology and input assumptions used in the modelling

• Section 4 provides an overview of the modelling scenarios

• Section 5 summarises the results of the analysis of market benefits of the second interconnector as a regulated asset

• Section 6 highlights the important outcomes from the modelling of the second interconnector as a merchant asset

• Section 7 summarises the impact of the second interconnector operating as a regulated and a merchant asset on other Tasmanian market participants.

2 National Transmission Network Development Plan

3 The Regulatory Investment Test for Transmission is a cost benefit analysis used to assess the viability of investment

options in electricity transmission assets. 4 Market Network Service Provider


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3. Methodology and input assumption

3.1 Market dispatch modelling methodology 3.1.1 Long-term generation development plan to 2035–36 AEMO provided long-term generation development plans under five scenarios as an input to the half-hourly time-sequential modelling presented in this Report.5 The scenarios provided are summarised in Table 5.

Table 5: Scenarios of long-term generation development plans provided by AEMO Emissions constraint

28% reduction in 2030 45% reduction in 2030

Tas-Vic interconnection

Basslink only (A) Tas wind development plan is an outcome of the modelling

(D) Tas wind development plan is an outcome of the modelling

Basslink and second interconnector

(B) Tas wind development plan is an outcome of the modelling & (C) Impose 1,200 MW new wind in Tasmania

(E) Tas wind development plan is an outcome of the modelling

AEMO used a long-term planning model which determines the least cost generation development plan that meets constraints including demand and an emissions constraint (Figure 1) over the period 2016–17 to 2035–36. All scenarios provided to EY use the AEMO neutral demand projections presented in the 2016 NEFR6. All scenarios also include small augmentations of QNI and the VIC-NSW interconnector.

Figure 1: AEMO CO2-e emissions target to 2035–36 and extrapolation to 2065–66

5 Given time constraints, the results provided by AEMO for a number of scenarios were draft outcomes. Generation

development plans differ from those presented in AEMO’s final outcomes. 6 National Electricity Forecasting Report


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3.1.2 Extrapolation of long-term generation development plan to 2065-66

The half-hourly time-sequential modelling presented in this Report covers the period from 2026–27 (when the second interconnector is assumed to commence operation) to 2065–66. For the portion of the study period overlapping with AEMO’s outcomes, we imposed their development plan for solar and wind and thermal generation retirements. We found that a reasonable amount of peaking gas capacity in AEMO’s development plans did not operate in our time-sequential simulations and so we removed the excess capacity from the plan. We targeted average USE7 in each region below the reliability standard of 0.002% of regional annual energy.

Beyond AEMO’s study period, we continued with thermal retirements in order to meet the linear extrapolation of the applicable emissions constraint (Figure 1) taking age and emissions intensity into consideration. Solar PV FFP8, Solar PV SAT9, wind and CCGTs were installed to meet energy requirements while being balanced to maintain the emissions constraint. OCGTs were installed to satisfy the reliability standard.

The extrapolation of the stronger emissions constraint reaches zero emissions in 2050–51. In order to achieve a zero net emissions system, significant storage capacity was assumed to be developed.

3.1.3 Time-sequential modelling 3.1.3.1 2-4-C®

We performed time-sequential dispatch simulations of the NEM on a half-hourly basis for the period 2026–27 to 2065–66. The simulations use EY’s electricity market dispatch engine 2-4-C® which emulates the dispatch engines used by power system operators. It dispatches generators (and bidding interconnectors and loads) according to their merit order, which is determined by their bids and transmission loss factors. Available generators in each half hour (those not on planned or unplanned outages) are dispatched in order from the lowest bid to the highest bid to meet half-hourly demand in each region, subject to network limitations and energy limits. Each half hour is referred to as a trading interval (TI). Figure 2 shows a flow diagram summarising the various inputs and tools used with 2-4-C®.

7 Unserved Energy, the measure used to define the reliability standard for the combined generation and transmission system

in the NEM, which should not exceed 0.002% of total demand for electricity in any region in any year. 8 Fixed Flat Plate

9 Single Axis Tracking


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Figure 2: Market dispatch and pricing with 2-4-C®

We modelled two peak demand trajectories, the 50% probability of exceedance (POE) peak demand and the 10% POE peak demand. We modelled 10 Monte Carlo iterations of forced outages of each demand profile. When annual average results are presented in this Report they are the weighted average with a 70% weighting assigned to the 50% POE and a 30% weighting assigned to the 10% POE market outcomes.

3.1.3.2 Hydro Tasmania modelling

A key driver of the utilisation of Basslink and the second interconnector is the operational profile of Hydro Tasmania’s hydro generators. Long-term storages on several of the schemes enable Hydro Tasmania to store inflows and choose when to use the water. They aim to use their limited water resource in the most profitable way, generating when Tasmanian demand is high and when Victorian wholesale prices are high and they can export power across the interconnector.

In reality, most of Hydro Tasmania’s generators are part of connected systems of multiple generators and variously-sized storages along various Tasmanian river systems. We used a simplified six pond model of the schemes where all generators within schemes are aggregated, as summarised in Table 6.

Table 6: Hydro Tasmania six pond model

Scheme Type Utilisation plan Total generating capacity (MW)

Total energy in storage (GWh)

Gordon Long-term storage Six month optimisation 354 4699 King Long-term storage Six month optimisation 140 234 South Esk Long-term storage Six month optimisation 445 7362 Anthony Pieman Short-term storage One week optimisation 482 203 Derwent Run-of-river Determined by inflows 469 1806 Mersey Forth Run-of-river Determined by inflows 290 167

The two run-of-river schemes have limited ability to store water and consequently generation profiles are primarily driven by inflows. We operated these generators based on the observed generation in 2014–15.

For the long-term storages and Anthony Pieman scheme, the operational profiles used in the time-sequential modelling were determined using the H2Opt module of 2-4-C. H2Opt plans water use over a specified period given scheme reservoir levels at the start of the period, inflows over the period and a specified target reservoir level at the end of the period. It computes a utilisation plan that uses the water in the optimal way by generating in the highest priced trading intervals such that

2-4-C® dispatch engineHalf-hourly dispatch and prices calculated as per real market

rules considering generator marginal loss factors, ramp rates, value of lost load, etc.

Generator bidding profiles from benchmark

Generator fuel costs and emissions intensity

Wind and solar energy resource

data

Generation planting and retirements

Generator maintenance and outage

profiles

Network constraint equations

Trace extrapolator

Half-hourly demand forecast meeting

annual energy and peak demand forecasts

Half-hourly projection of rooftop PV and

large-scale wind and solar generation

Reference year half-

hourly native demand

Annual energy and

peak demand forecasts

Details for existing and

proposed wind and solar farms

Representative locations of rooftop PV

installations

WEST and SEST

Reference year half-

hourly rooftop PV,

wind and solar

generation availability

Bids creation

Future bids escalated by changes in fuel, O&M

and emissions

costs Future prices on fuel and carbon emissions and

O&M costs

Monte Carlo simulations of

generator forced outages

Dynamic Bidding to capture

portfolio effects

H2Opt optimisation of energy-limited

plant


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shifting a megawatt hour (MWh) of generation from one TI to another within the optimisation window would increase the cumulative price across all trading intervals in the window.

H2Opt effectively plans the use of water in each of the storages. As part of this process, the model also computes the “water value” in each trading interval for each storage. The water value effectively represents the opportunity cost of using a unit of water in any trading interval. In a simplified example, the water value would represent the lowest wholesale price in all trading intervals in which H2Opt chooses to generate. The generators in the long-term storages and in the Anthony Pieman scheme bid this water value in each half-hour.

For the three long-term storages we used a six month optimisation window. For Anthony Pieman, we used a one week optimisation window. The combination of six-monthly optimisation windows for the long-term storages, weekly optimisation for Anthony Pieman and fixed profiles for the remaining run-of-river schemes provides a realistic level of flexibility for the Hydro Tasmania generation fleet. Inflows and target reservoir levels were based on historical data and discussions with Hydro Tasmania.

A utilisation plan was computed individually in each Monte Carlo iteration of forced outages.

We modelled a randomly generated sequence of wet, dry and average rainfall years. Further detail on this is given in Section 3.4.

3.1.4 Regulated interconnector modelling A regulated interconnector is effectively bidding $0/MWh in all trading intervals. This brings wholesale prices in the two interconnected regions together to the extent that this is possible. Unless interconnection is constrained, the wholesale price in the exporting region will be the wholesale price in the importing region, adjusted for losses. With abundant interconnection, we would therefore expect Tasmanian wholesale prices to shadow Victorian wholesale prices. With limited interconnection, Tasmania has a surplus of energy, due to the addition of more wind generation in Tasmania in all scenarios. This would mean that the water value of Hydro Tasmania’s generators would be very low, and wholesale prices in Tasmania would be very low, except in extreme circumstances such as drought.

The construction of the second interconnector increases water values in Tasmania. The water value will however be generally lower than the wholesale price in Victoria during many trading intervals, particularly when demand is high. With the second interconnector operating as a regulated interconnector, exports are generally unconstrained, and the wholesale price in Tasmania is marginally lower than the wholesale price in Victoria.

3.1.5 MNSP modelling For the MNSP scenarios, the modelling was conducted in two stages. In the first stage, we used the hydro-thermal optimisation module H2Opt to determine the operational profile of Hydro Tasmania’s hydro generators described in Section 3.1.3.2 and an associated water value. We then fixed this plan, bidding the six Hydro Tasmania schemes at their water value and simulated wholesale market price outcomes using the dynamic bidding module. This selects bids for the portfolio containing the second interconnector which maximise net pool revenue for the portfolio.

By bidding Hydro Tasmania generation based on the water value and the H2Opt water plan, Hydro Tasmania is effectively restricted from any use of market power. This includes competing with the MNSP interconnectors. This will be covered in more detail in this section.

In this modelling we operate Basslink and the second interconnector independently but consider them to be part of the same portfolio (i.e. not competing with each other). The implications of alternative ownership models are discussed in Section 6. In each half-hour, each link has an import bid of 10 price-quantity pairs and an export bid of 10 price-quantity pairs. The dynamic bidding


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module chooses a strategy for both links in each TI by trialling different bid curve combinations for the two links and selecting the option which gives the best net portfolio revenue.

On export from Tasmania, each or both of the two interconnectors can withhold capacity to higher prices. The effect of bidding higher prices can be varied, but generally can be categorised as withholding interconnector flow to capture wholesale price differential (between Tasmania and Victoria).

Effect of bidding export flows on wholesale prices

The interconnectors may bid a high price such that export across the interconnectors is lower than it would have been had the interconnectors been regulated (effectively bidding $0/MWh in all trading intervals). This could cause wholesale prices in Victoria to increase, and therefore increase the profit earned by the MNSPs by selling at high prices in Victoria, and buying at low prices in Tasmania.

Possible effects of withholding export flow from Tasmania to higher prices (relative to the regulated interconnector operation) include:

• A reduction in flow from Tasmania to Victoria. Specifically, the quantity of lower cost Tasmanian generation flowing into Victoria reduces; there is less gas generation dispatched in Tasmania, or water is not used (unused water is carried forward for use in a later period).

• An increase in higher cost generation (usually gas) in Victoria and the mainland to replace the ‘missing’ power from Tasmania.

The net result on wholesale prices is higher prices in Victoria and elsewhere on the mainland and lower prices in Tasmania. Under a regulated model, prices in Tasmania will move towards prices in Victoria during export periods (unless both interconnectors are constrained). Under a merchant model, Tasmanian wholesale prices may remain low while the MNSPs capture the price differential between Tasmania and Victoria.

Our modelling assumes that both interconnectors bid the same price differential in each period. This means that the split between flows and revenues is entirely dependent on the losses across the interconnectors and the MLFs at both the sending and receiving end. In periods with high price differentials, the relative importance of the MLF in the receiving end increases. The MLFs applied favour the second interconnector.

Bidding export flows to capture wholesale price differential

When the second interconnector and Basslink are operated as profit-maximising MNSPs, the effect on wholesale prices is very different to the regulated case. Rather than Tasmania importing the wholesale price from Victoria, the MNSPs will attempt to capture the difference between Victorian wholesale prices and the bid offers from Hydro Tasmania.

Consider a simplified example where we ignore interconnector losses, the wholesale price in Victoria is $100/MWh and water values in Tasmania are $20/MWh. Assume that there is 1,200 MW of interconnector capacity available, and a surplus of supply in Tasmania of 1,000 MW. If the interconnection was regulated, the wholesale price in Tasmania would be equal to the Victorian wholesale price, as the interconnector would export 1,000 MW – below its maximum capacity.

If the interconnector were merchant, it could bid a price differential of $79. This would still be “dispatched” in the mainland as the cost of this export is effectively the $20 wholesale price in Tasmania plus the $79 MNSP bid. In this scenario, the wholesale price in Tasmania would be $21, and the MNSP would earn revenue on the $79 wholesale price differential. Relative to the regulated example, Hydro Tasmania revenues decrease, the cost to Tasmanian consumers reduces, and there is profit earned by the MNSP.


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This example provides an illustration of the difficulty of modelling the MNSP. In particular, it is reliant on the bidding of Hydro Tasmania. If Hydro Tasmania had changed its bid to $99 in the example above, the MNSP would not have been able to earn any significant profit in this trading interval. A key consideration of the MNSP model is how it affects the relevant market participants, particularly Hydro Tasmania and Tasmanian consumers.

Bidding import flows

The example above details the approach to bidding export flows from Tasmania to Victoria. Modelling the MNSPs for flow into Tasmania is far more problematic given the interaction with water plans and hydro limitations.

In modelling it was found that large profits could be earned by the MNSP by withdrawing import flow at times where resources in Tasmania were limited due to low storage levels and low wind generation. This was found to be very costly from the perspective of very high wholesale prices in Tasmania and difficulties in managing water resources in the Hydro Tasmania storages. Due to these reasons we have restricted the bidding on the interconnector on imports to $0/MWh.

3.2 Cost-benefit assessment 3.2.1 Cost-benefit outputs from market modelling Ultimately we compute the overall market benefits of the second interconnector in each of four different scenarios. In each scenario, we compute the following market cost and benefit components for a Basslink only and second interconnector simulation. The sum of the following components is referred to as the market benefits:

• Capital costs of new generation capacity installed in each scenario • Total fixed O&M costs of all generation capacity in each scenario • Total variable costs (fuel costs + variable O&M costs) including cost of USE and DSP.

From the half-hourly time-sequential modelling we computed each component of annual cost in each scenario with the second interconnector and in a matched Basslink-only counterfactual. We then computed the difference between the second interconnector case and the counterfactual — this is the annual market benefits.

The annual market benefits include many of the categories of market benefit specified in the RIT-T. This includes all generator specific costs (fuel, direct costs such as capital, O&M) and the cost of voluntary and involuntary load shedding (valued at DSP price as bid and VCR10 respectively). For the purpose of this assessment, we do not value emissions differences although this component is eligible under the RIT-T.

The market benefits also capture some of the impact on transmission losses to the extent that losses across interconnectors affect the generation that is needed to be dispatched in each trading interval. A more complete analysis of the impact on transmission losses would require load flow modelling.

The market benefits of the second interconnector computed in each scenario need to be compared to the second interconnector costs (discussed in Section 3.2.3), and potentially other costs and benefits (discussed in Section 5.5).

10

Value of customer reliability. We have applied a value of $25,950/MWh. Sourced from: http://www.aemo.com.au/-/media/Files/PDF/VCR-Application-Guide--Final-report.pdf


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3.2.2 Calculating the NPV of market benefits Each component of market benefits is computed annually for each year of the forty year study period. In this Report, we summarise these revenue and cost streams using a single value computed as the NPV of each stream, discounted to 2026–27 at a specified discount rate.

We present outcomes using two alternative discount rates: 7% and 10% real pre-tax. These values are for illustrative purposes only. They are typical of the range of discount rates applied in least cost planning modelling. We have applied these two rates consistently across all scenarios to provide a consistent basis of comparison and do not seek to imply that the regulated or market interconnectors would necessarily require these returns.

3.2.3 Interconnector costs and net benefit The market benefits of the second interconnector must be compared against interconnector costs. We use the term net benefit to mean market benefits minus interconnector costs. In this Report, we use interconnector costs supplied by the Tasmanian Energy Taskforce. These values are provided in Table 7 alongside the values used by AEMO for comparison. The key differences relate to the application of the WACC and that AEMO have not assumed any fixed O&M, whereas our report assumes annual O&M payments in accordance with the assumptions supplied by the Taskforce.

Table 7: Costs of the second interconnector

Cost component Value used by AEMO Value used in this Report

Capital cost $930m in real June

2015 dollars11

$930m in real June 2015 dollars

adjusted to $940m in real June 2016 dollars

WACC for the second interconnector (real, pre-tax)

8.78%

Not applicable. We use the total capital cost in 2026–27 rather than annualising payments and calculating the NPV.

This avoids distortions created by applying a different WACC and discount rate.

Fixed O&M $0 $16.7m/year in real June 2015 dollars adjusted to $16.87m/year in real June 2016 dollars

Interconnector lifetime 50 years

As described above, the interconnector lifetime is not applicable as the full value of the capex is used in the

calculation of net benefit.

NPV with 7% discount rate NPV with 10% discount rate

Total interconnector cost = Capital + Fixed O&M

$930 in real June 2015 dollars

$940m + $224m= $1,164m in real June 2016

dollars

$940m + $164m= $1,104m in real June 2016

dollars

3.3 Interconnector revenue assessment Merchant interconnectors do not need to pass a RIT-T in order to be built. When modelling a merchant interconnector, the key modelling outputs are not the market benefits, but instead market revenue earned by the interconnector. This is the interconnector flow multiplied by the wholesale price difference between the connected regions in each half-hour, accounting for both inter-regional losses and marginal loss factors (MLFs). Given the discussion in Section 3.1.4, the impact on Hydro Tasmania generation revenue and the total cost of load to consumers are also considered.

11

AEMO convert this to an interconnector capital cost of $341m in real June 2015 dollars applicable in their study by calculating annual repayments based on a WACC of 8.78% and a financial lifetime of 50 years commencing 2025-26, and then calculating the NPV of these repayments in their study period (2016-17 to 2035-36) discounted to June 2016 at a discount rate of 7% real pre-tax.


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These outcomes were provided to the EY financial modelling team as inputs to their analysis of the ability of the private sector to fund the second interconnector. The relationship between the two pieces of work is described in more detail in Section 6.6.

3.4 Input assumptions We used the following assumptions which are consistent with AEMO where the study periods overlap:

• Annual energy and peak demand forecasts from the AEMO NEFR 2016 Neutral scenario, extrapolated linearly to 2065-66

• Linear emissions reduction trajectory consistent with long term reduction targets as shown in Figure 1

• Capital costs from the CO2CRC Australian Power Generation Technology Report extrapolated linearly to 2065-66

• Fuel costs from the AEMO Planning assumptions.12,13 These are provided to 2041. Our modelling holds costs constant from then until 2065-66.

For the second interconnector, we make the following assumptions:

• Converter station losses of 1% per converter • Connection to the Victorian grid at Tyabb, with the current MLFs applied to the

Victorian end14 • An MLF for the Tasmanian end of 1.0000 – consistent with Basslink. In reality this may be

lower depending on how the second interconnector connects to the Tasmanian transmission network.

• Bi-directional flow limit of 600 MW. With the second interconnector the existing Basslink interconnector has a maximum export flow of 594 MW. Given limitation on the existing cable for flows above 500 MW for any extended period of time, the maximum export capacity is assumed to be 500 MW without the second interconnector. This assumption creates an additional benefit to the second interconnector.

In all scenarios except the LowRain scenarios (described in Section 4), we use the same hydro inflows and targets for Hydro Tasmania which represent overall a medium rainfall long-term outlook. This includes a sequence of three successive dry years. In the LowRain scenarios, the probability of a dry year increases while the probability of both average and wet years decreases to represent overall a low rainfall long-term outlook. In the low rainfall sequence there are several instances of successive dry years including one instance of four dry years in-a-row.

12

February 2016 Gas Pricing Consultancy Databook (Core Energy Group). Available at https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Transmission-Network-Development-Plan/NTNDP-database. 13

2016 Coal Cost Data (Wood Mackenzie). Available at https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/National-Transmission-Network-Development-Plan/NTNDP-database. 14

We have not considered how the second interconnector flow and other generation developments might impact the MLF.


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4. Scenarios

4.1 Summary of scenarios The modelled scenarios requested by the Department are summarised in Table 8 and then further described in the remainder of Section 4. In all scenarios thermal new entrants and post-AEMO study period renewables installed based on cost and meeting reliability standard.

Table 8: Summary of modelled scenarios Modelling scenario

Description

Base Scenario

Base Case Basslink Only

• Uses thermal retirements and renewables generation planting from AEMO, 28% emissions reduction by 2030 on 2005 levels (AEMO scenario A).

• No second interconnector (2IC), Basslink operating under current protocols (effectively as a regulated interconnector).

Regulated Basslink and 2IC Operation

• Uses renewables generation planting from Base Case Basslink Only. • Uses thermal retirements from AEMO, 28% emissions reduction by 2030 (AEMO

scenario B). • Second interconnector operational from 1 July 2026 as regulated interconnector.

Basslink and second interconnector bid at $0 (regulated behaviour).

Merchant Basslink and 2IC operation

• Uses same renewables and thermal generation planting as Regulated Basslink and 2IC Operation.

• Second interconnector operational from 1 July 2026 as merchant interconnector. Basslink and second interconnector bid above $0 to maximise combined profit in each trading interval.

TasWind

TasWind Basslink Only

• Uses thermal retirements and renewables generation planting from AEMO, 28% emissions reduction by 2030, 1,200 MW of wind built in Tasmania in 2026 (AEMO scenario C).

• No second interconnector, Basslink operating under current protocols (effectively as a regulated interconnector).

TasWind Regulated Basslink and 2IC Operation

• Uses thermal retirements and renewables generation planting from AEMO, 28% emissions reduction by 2030, 1,200 MW of wind built in Tasmania in 2026 (AEMO scenario C).

• Second interconnector operational from 1 July 2026 as regulated interconnector. Basslink and second interconnector bid at $0 (regulated behaviour).

TasWind Merchant 2IC and Basslink Operation

• Uses same generation planting as TasWind Regulated Basslink and 2IC Operation. • Second interconnector operational from 1 July 2026 as merchant interconnector.

Basslink and second interconnector bid above $0 to maximise combined profit in each trading interval.

TasDemand

TasDemand Basslink Only

• Uses generation planting from Base Case Basslink Only – except no new TAS wind after 2020.

• Retires 40% of Tasmanian demand uniformly throughout each study year. • No second interconnector, Basslink operating under current protocols (effectively as

a regulated interconnector).

TasDemand Regulated Basslink and 2IC Operation

• Uses generation planting from Base Case Basslink Only – except no new TAS wind after 2020.

• Retires 40% of Tasmanian demand uniformly throughout each study year. • Second interconnector operational from 1 July 2026 as regulated interconnector.



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Modelling scenario

Description

TasDemand Merchant Basslink and 2IC Operation

• Uses same generation planting as TasDemand Regulated Basslink and 2IC Operation. • Retires 40% of Tasmanian demand uniformly throughout each study year. • Second interconnector operational from 1 July 2026 as merchant interconnector.


LowRain

LowRain Basslink Only

• Uses renewable and thermal development plan from Base Case Basslink Only. • High probability of dry years, lower probability of wet years. • No second interconnector, Basslink operating under current protocols (effectively as

a regulated interconnector).

LowRain Regulated Basslink and 2IC Operation

• Uses generation planting from Base Case Basslink Only. • High probability of dry years, lower probability of wet years. • Second interconnector operational from 1 July 2026 as regulated interconnector.


LowRain Merchant Basslink and 2IC Operation

• Uses same generation planting as LowRain Regulated Basslink and 2IC Operation. • High probability of dry years, lower probability of wet years. • Second interconnector operational from 1 July 2026 as merchant interconnector.


StrongAction

StrongAction Basslink Only

• Uses thermal retirements and renewables planting from AEMO, 45% emissions reduction by 2030 (AEMO scenario D).

• No second interconnector, Basslink operating under current protocols (effectively as a regulated interconnector).

StrongAction Regulated Basslink and 2IC Operation

• Uses thermal retirements and renewables planting from AEMO, 45% emissions reduction by 2030 (AEMO scenario E).

• Second interconnector operational from 1 July 2026. Basslink and second interconnector bid at $0 (regulated behaviour).

4.2 Base scenario The generation development plan in the Base Case Basslink Only scenario is based on AEMO’s Basslink only generation development plan in scenario A (Section 3.1.1) and the extrapolation method described in Section 3.1.2.

The generation development plan in the Regulated Basslink and 2IC Operation scenario is based on the Base Case Basslink Only generation development plan. We maintained the same wind, solar and CCGT development plan as in Base Case Basslink Only but deferred 450 MW OCGT installation in Victoria in Regulated Basslink and 2IC Operation relative to Base Case Basslink Only such that a similar level of USE was achieved.

We also simulated an alternative generation development plan based on AEMO’s Basslink and second interconnector generation development plan (scenario B). This plan was a draft outcome that contains additional wind and solar capacity in the early study years (at additional capital cost) and consequently slightly overachieves on the emissions constraint. An emissions saving is a potential additional benefit eligible under the RIT-T which is not valued in this Report. This scenario is explored in Appendix A.

4.3 Tasmanian wind expansion (TasWind) The generation development plan in the TasWind Regulated Basslink and 2IC Operation scenario is based on AEMO’s Basslink and second interconnector plus 1,200 MW new wind capacity in Tasmania


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generation development plan (scenario C). Both with and without the interconnector a fixed 1,200 MW of new wind capacity is included in Tasmania in 2025–26. AEMO’s least cost development plan did not install any further Tasmanian wind. The renewable generation on the mainland is unchanged with and without the second interconnector in this scenario.

Thermal new entrants and post-AEMO study period renewables were installed based on cost and meeting reliability standard. The net effect was that the second interconnector defers 450 MW of OCGT capacity in Victoria in TasWind Regulated Basslink and 2IC Operation relative to TasWind Basslink Only.

4.4 Tasmanian demand reduction (TasDemand) The TasDemand scenarios incorporated a 464 MW reduction in Tasmanian demand in every trading interval. This equates to 4,060 GWh annually representing a 40% reduction from 2016 annual operational consumption in Tasmania.

The TasDemand Basslink Only scenario was based on the Base Case Basslink Only scenario with a reduction in Tasmanian generation capacity. It contained only 320 MW of the 730 MW of new Tasmanian wind installed in Base Case Basslink Only and included retirement of Tamar Valley CCGT.

The TasDemand Regulated Basslink and 2IC Operation scenario was based on the Base Case Basslink Only scenario with no additional wind constructed after 2020 in Tasmania and a delay in the installation of 600 MW of new OCGT capacity in Victoria that was not needed in order to achieve the reliability standard.

4.5 Low rainfall (LowRain) The LowRain Basslink Only and LowRain Regulated Basslink and 2IC Operation scenarios are based on the Base Case Basslink Only and Regulated Basslink and 2IC Operation scenarios with Hydro Tasmanian inflows and storage targets representing lower rainfall long-term outlook than the other scenarios.

4.6 Strong emissions constraint (StrongAction) The generation development plan in the StrongAction Basslink Only and StrongAction Regulated Basslink and 2IC Operation scenarios are based on the generation development plan in AEMO’s two scenarios with a 45% emissions reduction by 2030 (scenarios D and E), and the extrapolation method described in Section 3.1.2.


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5. Results – Regulated interconnector

5.1 Base scenario In the Base scenario, market benefits are derived from both the deferral of investment in thermal capacity in Victoria and through reductions in production from high variable cost generation. Table 9 shows the components of market benefits and the net benefit of the second interconnector, as well as the sensitivity to discount rate. The table shows that the investment cost of the interconnector is not expected to be recovered through the assessed market benefits. In this table and throughout this section, positive values indicate a benefit while negative values indicate a cost.

Table 9: Base scenario regulated interconnector outcomes (NPV $m) Discount rate = 7% Discount rate = 10%

Variable costs 487 377 Fixed O&M 36 22 Capital costs 286 236 Total market benefits 809 634 Interconnector costs -1,164 -1,104 Net benefit -356 -470

The capital cost saving of $286m (7% discount rate) is due to the deferral of investment in new OCGT capacity in Victoria. With the retirement of Loy Yang A and B in 2032 and 2033, new capacity is required to maintain the reliability standard. The second interconnector allows 450 MW of additional capacity to be deferred. At times of peak demand, additional energy can be imported across the second interconnector to utilise the spare hydro and gas capacity available in Tasmania. The interconnector does not always supply 600 MW of additional capacity because at times of high demand in Victoria, demand may also be high in Tasmania. In some of these trading intervals, Tasmania does not have the 1,200 MW of surplus capacity required to utilise the full capacity of both interconnectors.

The capital cost saving represents the NPV of the full cost of 450 MW of new OCGT generation in 2033 discounted to 2026. If the need for new capacity was brought forward, e.g. through the earlier retirement of brown coal or gas-fired generation in Victoria, then the NPV of capital cost savings would increase. These outcomes are also dependent on the capital cost assumptions (see Section 3.4).

The variable cost savings arise primarily through the increased ability for Hydro Tasmania to shift the use of water between trading intervals due to the second interconnector. During trading intervals where low cost generation is operating in the mainland, the second interconnector allows increased imports into Tasmania. The water saved by the Hydro Tasmania generators can be used in later trading intervals where high cost generation is operating in the mainland.

As the penetration of wind and solar generation increases, there are likely to be trading intervals where there is an excess of intermittent, zero variable cost generation. The second interconnector allows some of this excess to be used by Tasmania, which effectively operates as a large battery to the mainland. This generation is effectively free as it would otherwise not have been used.

The second interconnector allows higher exports during trading intervals where high-cost generation is required to operate on the mainland, e.g. gas or liquid-fuelled generation. As coal generation retires, there is an increased need for replacement firm capacity such as OCGT generation, and an increased reliance on existing gas generators. These generators have relatively high variable costs. As such, reducing the production from these generators can result in significant variable cost savings. The magnitude of these savings is dependent on the gas price assumptions used (see Section 3.4).


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Table 10 shows the differences in generation and total variable cost due to the second interconnector. This shows that an increase in low cost generation, particularly from coal, the Tamar Valley CCGT (TV-CCGT) and renewable generation offsets OCGT generation valued at $93/MWh. Furthermore, total generation is reduced due to the new interconnector resulting in lower losses.

Table 10: Variable cost savings in Regulated Basslink and 2IC Operation (discount rate = 7%) Generation reduction

(discounted GWh15

) Variable cost saving

($m NPV) Average variable

cost $/MWh

TV-CCGT -4,576 -358 78 CCGT -939 -50 53 OCGT and peaking 9,981 955 96 Coal -2,372 -64 27 Renewable -1,742 3 -2 Total 487

Figure 3 shows a comparison between the distribution of the combined interconnector flow across the second interconnector and Basslink in Regulated Basslink and 2IC Operation and the Basslink flow in Base Case Basslink Only in 2027–28. This illustrates that without the second interconnector, there are many trading intervals where the export from Tasmania to Victoria is constrained. The difference between the yellow line and the grey line in this figure shows trading intervals where the second interconnector is capable of extracting additional value through increased exports. Similarly, the far right of this chart shows trading intervals where the second interconnector is able to import more aggressively from the mainland – this saved energy is used to supply the additional export.

The area between the two curves in the left of this figure represents additional export energy – in this year this equates to approximately 1,400 GWh of additional export. Table 10 showed that the additional exports generally resulted in a reduction in peaking generation, valued at approximately $96/MWh. The additional imports were supplied by a mix of renewable generation, coal, and CCGT with an average cost of approximately $49/MWh. The value of additional export at this fuel cost differential would be valued at approximately $66m, which is roughly equivalent to the $64m calculated in modelling as the variable cost saving in 2027–28 (see Figure 4). This simplified illustration demonstrates the basis for the variable cost savings provided above.

Figure 3: Interconnector flow comparison — Regulated Basslink and 2IC Operation vs Base Case Basslink Only — 2027–28

16

15

Discounted GWh: the GWh of production from each technology aggregate discounted to 2026 at the discount rate. This allows a simple comparison of total generation over the 40 year timeframe and the calculation of a unit cost per MWh. 16

See Section 3.4 for explanation of 500 MW export limit without second interconnector.


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5.1.1 Sensitivity to Tamar Valley CCGT In the Base scenario we have retained TV-CCGT, currently mothballed17 by Hydro Tasmania. Without the second interconnector, it is likely that TV-CCGT would need to be retained to maintain energy security and reliability. If the second interconnector were to be constructed, this could allow the retirement and sale of the generator and result in increased revenues and avoided maintenance costs. However, modelling indicates that more significant market benefits could be extracted from the second interconnector if the generator were to be kept operational, particularly in an environment where low cost generation such as brown coal on the mainland is forced to retire.

Both with and without the second interconnector, modelling shows that TV-CCGT could operate to increase exports to the mainland. As a CCGT, TV-CCGT is more efficient and therefore less costly than much of the peaking gas generation on the mainland. Running TV-CCGT can therefore reduce variable costs.

With the introduction of the second interconnector, TV-CCGT provides two key benefits. Firstly, the additional 200 MW of thermal capacity increases the surplus capacity in Tasmania and therefore increases the ability of Tasmania to export at times where supply-demand balance is tight on the mainland. Without TV-CCGT, the value of the deferral of new OCGT generation in Victoria would reduce by approximately $100m (at a 7% discount rate). Secondly, TV-CCGT runs at relatively high levels of utilisation in place of more expensive OCGT generation. The additional generation from TV-CCGT and the reduction in mainland OCGT generation that occurs due to the second interconnector accounts for approximately $100m of benefit (at a 7% discount rate).

If TV-CCGT were to be retired the market benefits of the second interconnector would reduce by approximately $200m. Furthermore, approximately half of this benefit relies on the ability of TV-CCGT to be flexible in responding to high wholesale prices on the mainland. This flexibility requires TV-CCGT to cycle an average of 1.1 times per day. This mode of operation is possible but may lead to increased wear and tear and therefore increased maintenance costs, and reduced efficiency. This could reduce the approximately $100m of variable cost savings that are extracted by exporting TV-CCGT generation across the second interconnector. The $100m of additional capital cost deferral is retained even if TV-CCGT cannot operate this flexibly, as this benefit relies on TV-CCGT being available on relatively few days in each year.

5.1.2 Sensitivity to rainfall Figure 4 shows the annual variable cost saving from the second interconnector in Regulated Basslink and 2IC Operation. It is evident that costs savings are generally larger in wet years. In a wet year, there is a larger surplus of energy in Tasmania, and the enhanced flexibility of the second interconnector allows a more effective use of this surplus energy. In a dry year, more energy needs to be conserved to meet Tasmanian demand, and therefore the enhanced export capacity is rarely utilised. The second interconnector may provide other benefits that are particularly valuable during dry years as described in Section 5.5.

This figure also shows a drop in benefits in the mid-2030s. This is around the time where OCGT capacity is deferred. This OCGT capacity is new and therefore more efficient than existing peaking generation. This means that at times, the effect of the second interconnector is that more expensive, existing OCGT runs more heavily, whereas without the second interconnector this energy would have been supplied by new entrant OCGT.

17

Tamar Valley CCGT has not operated since Basslink returned to service in June 2016. AEMO’s generation information from 18 November 2016 (https://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Planning-and-forecasting/Generation-information) has no available capacity in summer or winter in future years to 2026. However, it also states “Hydro Tasmania advises that the Tamar Valley CCGT (208 MW) is available for operation with less than 3 months' notice and will next return to service in summer 2016-17”.


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Figure 4: Annual generation variable cost savings in Regulated Basslink and 2IC Operation

5.1.3 Impact of discounting All results presented in the above analysis are discounted to the assumed commencement of the second interconnector’s operation in 2026. Results could be provided that are discounted to the current financial year. The AEMO report seen by EY discounts all benefits and costs to June 2016. Table 11 shows that when cash flows are discounted to 2016, market benefits and interconnector costs reduce, but the ratio between benefits and costs is maintained. Discounting will therefore change the magnitude of benefits relative to costs, but not change the ratio between costs and benefits, or the relativity between scenarios.

Table 11: Base scenario regulated interconnector outcomes (NPV $m) – Impact of discounting 7% discount rate

- discounted to 2026

7% discount rate - discounted to

2016

10% discount rate - discounted

to 2026

10% discount rate - discounted

to 2016 Market benefits 809 411 634 245 Interconnector costs -1,164 -592 -1,104 -426 Net benefit -356 -181 -470 -181 Ratio of benefit to cost 69% 69% 57% 57%

In their analysis, AEMO and the EY financial modelling team have discounted all costs, benefits and revenues to 2016–17. To convert a value discounted to 2026 to one discounted to 2016 at a 7% discount rate (real, pre-tax), apply a multiplier of 0.508. To convert from a value discounted to 2026 to one discounted to 2016 at a 10% discount rate, apply a multiplier of 0.386.

5.1.4 Comparison to AEMO NTNDP outcomes The NTNDP contains an assessment of market benefits of the second interconnector. Our modelling uses input from AEMO’s 2016 NTNDP studies, supplied to EY in draft form prior to public release. The key AEMO outcomes of interest are summarised in Table 12.18

18

AEMO NTNDP 2016, Table 5


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Table 12: AEMO assessment of market benefits to 2035–36 ($m), Base scenario, 7% discount rate discounted to 2016

AEMO study name

Dispatch efficiency benefits


Capital investment efficiency benefits

Environmental scheme benefits

Resilience benefits

NPV of gross

market benefits

to 2035-

36

NPV of annualised

cost to 2035-36

Overall net

market benefit

Base case QNI VIC-NSW

117 27 31 -4 0 170 47 123

2BSI + QNI VIC-NSW

202 114 165 2 48 531 387 143

Difference 85 87 134 6 48 361 340 20

This section compares our Base scenario outcomes with AEMO’s outcomes as published in the NTNDP. To put AEMO’s outcomes and ours on a common basis for comparison, we need to reconcile several key differences. Namely:

• AEMO’s outcomes are discounted to June 2016 while our outcomes are discounted to June 2026 as discussed in Section 5.1.3.

• Dispatch efficiency benefit is equivalent to our variable cost benefit excluding USE and demand side participation differences. USE and demand side participation differences are captured as reliability benefits.

• Our modelling does not capture environmental scheme benefits19 or resilience benefits. As our modelling starts in 2026, it is not appropriate to consider the impact of the interconnector on the LRET. Our analysis of benefits related to energy security and reliability are provided in Section 5.6.

Outcomes of AEMO’s market benefits and our market benefits on a more similar basis are summarised in Table 13. In this summary, all NPV outcomes are discounted to 2016 and environmental scheme benefits and resilience benefits are excluded from AEMO’s total benefit.

Table 13: Comparison of AEMO and EY assessment of market benefits ($m), Base scenario, 7% discount rate discounted to 2016

Result Dispatch efficiency benefits


Capital investment efficiency benefits

Environmental scheme

benefits & Resilience benefits

NPV of gross

market benefits

NPV of interconnector

cost

Overall net

market benefit

Ratio of market benefits to costs

AEMO 85 87 134 excluded 306 340 -34 0.90 EY 219 29 164 0 411 592 -181 0.69

On this basis AEMO’s benefits represent 90% of interconnector costs while our market benefits represent 69% of interconnector costs. There are several major differences in modelling approach that contribute to the reduced benefit in our outcomes.

A direct comparison of our approach and AEMO’s is not possible given our limited knowledge of the details of their approach. Possible impactful areas of difference are:

• Bidding behaviour. AEMO’s modelling assumes generators are dispatched according to their short-run marginal costs. In contrast, our time-sequential model determines dispatch based on

19

Environmental benefits in AEMO’s modelling result from changes in the penalties paid for not meeting the LRET.


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competitive bidding behaviours that include withholding capacity to prices exceeding short-run marginal cost, which is more reflective of the behaviour of generators in the NEM where portfolios exert transient market power, have fuel limitations and are influenced by contracting positions.

• Hydro modelling. The operation of Basslink and the second interconnector (where applicable) are constrained by the flexibility of Hydro Tasmania’s portfolio of generators. In developing these studies, we worked closely with Hydro Tasmania to create a model with a credible level of flexibility that captured year-to-year rainfall variability. This model is explained in detail in Section 3.1.3.2. AEMO’s models may have a higher or lower level of flexibility. Higher flexibility will increase second interconnector benefits while lower flexibility will decrease benefits.

• Intra-regional transmission constraints. In their study, AEMO performed more detailed modelling of intra-regional transmission constraints. This may have increased market benefits by bringing forward capacity deferrals and reliability benefits.

• Reference years. AEMO’s modelling uses 2013–14 as the reference year from which the demand, solar generation and wind generation timeseries have been derived. We use 2014–15 as the reference year. This may have increased or decreased market benefits as each reference year will have a different level of wind and solar production at times of high demand. We suggest a comprehensive RIT-T study should consider multiple reference years to determine the extent to which demand, wind and solar profiles influences the market benefits of a second interconnector.

• Study time frame. Another key area of difference is modelling time-frame. AEMO’s study period extends from 2016–17 to 2035–36. Their evaluated market benefits therefore capture only eleven years of the second interconnector costs and benefits. In contrast, our modelling extends from 2026–27 to 2065–66 capturing 40 years of the second interconnector costs and benefits. Our analysis of market benefits over the AEMO timeframe indicates that this is not a significant driver of differences in market benefits.

• Use of AEMO draft outcomes. Given time constraints, the results provided by AEMO as input to our modelling were draft outcomes. Generation development plans differ from those presented in AEMO’s final outcomes.

5.1.5 EY financial modelling – regulated outcomes The EY energy market modelling team has provided a subset of the results of the electricity market modelling to the EY financial modelling team. In their modelling of the regulated interconnector, the EY financial modelling team has not considered any of the market benefits described above. Rather the EY financial team’s analysis for Alternative Case 3 assumes that the second interconnector does earn regulated status, and based on this assumption calculates the financial outcomes for the regulated asset owner. Our modelling does not attempt to comment on these financial impacts and instead considers the market wide impact of the interconnector on the NEM.

When comparing dollar values between our report and the financial team’s report also note that we present all NPVs in real June 2016 dollars discounted to 2026 using a 7% or 10% real pre-tax discount rate. They present NPVs in real June 2016 dollars discounted to 2016 using a 7% or 10% nominal discount rate.

5.2 Tasmanian wind generation expansion A potential benefit of the second interconnector is that it allows an expansion in investment in wind generation in Tasmania. Although wind resources in Tasmania are strong, there are a number of factors that may limit the benefits of expanding wind development in Tasmania. The impact of each of these factors has not been assessed quantitatively, but is evident in the results presented in this section (in particular Table 16).


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Firstly, much of the additional generation that results from an expansion in wind generation will be exported across the two interconnectors. The losses that occur when transferring power over the Tasmanian network to the interconnectors, across the regional boundaries, and from the connection points in Victoria to demand centres reduce some of the advantage of high capacity factors in Tasmania.

Secondly, wind generation in Tasmania will likely need to be developed in a relatively concentrated area to avoid the need for transmission augmentation. This will mean that wind generation within Tasmania is highly correlated, and also likely to be loosely correlated with Victorian wind. Even with the second interconnector, high levels of wind generation may constrain Tasmania’s export capacity. The hydro generation in Tasmania does not have unlimited flexibility. In particular, the Mersey Forth, Derwent and Anthony Pieman schemes have a number of generators with very limited storage. This means that at times, non-discretionary hydro output can be significant, particularly during high seasonal inflows. If this occurs at times of high wind output, this may constrain export flows and cause either water to be spilt or wind generation to be curtailed. Either possibility effectively reduces the benefits of Tasmania’s superior wind resource.

The modelling also incorporates the impact of the proposed Victorian renewable energy auction scheme. This means that wind and solar generation development in Victoria is significant by the time the second interconnector is constructed. Given the loose correlation between Tasmanian and Victorian wind, high exports from Tasmania to Victoria frequently occur during trading intervals where renewable generation is already high in Victoria. This reduces the impact that additional Tasmanian wind has on reducing variable costs of production.

The TasWind scenario assumes that 1,200 MW of additional wind (relative to the existing capacity) is constructed in Tasmania – with or without the second interconnector. The effect of this additional wind generation is to increase the market benefits of the second interconnector, as shown in Table 14.

Table 14: TasWind Regulated Basslink and 2IC Operation outcomes (NPV $m) — relative to TasWind Basslink Only

Discount rate = 7% Discount rate = 10% Market benefits 1,194 929 Interconnector costs -1,164 -1,104 Net benefit 29 -176

In the TasWind case, we have not modelled any difference in renewable investment between the TasWind Basslink Only and TasWind Regulated Basslink and 2IC Operation scenarios. The only difference in generator planting is that the second interconnector defers 450 MW of OCGT development in Victoria. A comparison between the components of market benefits from the second interconnector between these two scenarios is shown in Table 15.

Table 15: Market benefits by category — Base vs TasWind scenario (NPV $m — discount rate = 7%)

Cost savings in Regulated Basslink and 2IC Operation

relative to Base Case Basslink Only

Cost savings in TasWind Regulated Basslink and 2IC

Operation relative to TasWind Basslink Only

Variable costs 487 872 Fixed O&M 36 36 Capital costs 286 286 Total 809 1,194

This table shows a large increase in the variable cost savings that result from the second interconnector. Variable cost savings are particularly large during years with high hydrological inflows. In all years, but particularly in years with high inflows, there is insufficient export capacity available from Basslink only to allow the full utilisation of wind and hydro resources in Tasmania. In modelling, with only one interconnector, wind is curtailed (but in reality, this could mean hydro is


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spilt – the cost impact of this decision is immaterial to market benefits). This means that the second interconnector not only allows more effective use of wind and hydro resources, but also allows the resources available to not be wasted. This reduces variable costs in the NEM, and increases market benefits.

It is unrealistic to assume that 1,200 MW of wind would be built in Tasmania without the second interconnector. The market benefits presented above in Table 14 and Table 15 are therefore unrealistic. A more appropriate comparison to suggest whether there is a significant benefit to unlocking Tasmanian wind development through the second interconnector is to compare TasWind Regulated Basslink and 2IC Operation with Base Case Basslink Only. This is shown below in Table 16.

Table 16: TasWind Regulated Basslink and 2IC Operation outcomes (NPV $m) – relative to Base Case Basslink Only

Discount rate = 7% Discount rate = 10%

Cost savings in Regulated

Basslink and 2IC Operation relative

to Base Case Basslink Only

Cost savings in TasWind

Regulated Basslink and 2IC

Operation relative to Base Case Basslink Only




Cost savings in TasWind



Market benefits 809 522 634 257 Interconnector costs -1,164 -1,164 -1,104 -1,104

Net benefit -356 -642 -470 -848 Clearly the benefits of the second interconnector reduce if 1,200 MW of wind is built in Tasmania, relative to the Base scenario. This is due to the limitations on Tasmanian wind expansion addressed above, in particular increased losses and constrained exports from Tasmania. Figure 5 shows an example year where it can be seen that even with two interconnectors, export from Tasmania is frequently constrained with 1,200 MW of additional wind generation in Tasmania. For comparison, this figure shows that in Regulated Basslink and 2IC Operation the frequency of export constraint is lower; this is particularly true in the earlier years of the study where there is a larger difference between the capacity of wind in Tasmania.

Figure 5: Interconnector flow comparison – TasWind Regulated Basslink and 2IC Operation vs Regulated Basslink and 2IC Operation — 2027–28


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It is not unexpected that the additional Tasmanian wind investment does not provide an additional benefit. AEMO’s Base scenario modelling (discussed in Appendix A) optimises the level of wind investment in Tasmania, subject to their assumptions and methodology. Their Base scenario outcomes indicate that a total of 1,100 MW is the optimal amount of wind built in Tasmania with the second interconnector. Our modelling is in agreement with AEMO’s result in that 1,200 MW of new wind in Tasmania is unlikely to improve the market benefits attributable to the second interconnector. Appendix A provides additional information on the optimal level of wind development in Tasmania.

This modelling therefore shows that a key source of market benefits of the second interconnector is not its ability to unlock additional renewable development in Tasmania. The second interconnector may increase wind investment in Tasmania (as it does in AEMO’s Base scenario). However, due to a number of factors, the cost savings this investment unlocks are relatively small. This considers only benefits permissible under the RIT-T framework.

5.3 Tasmanian demand reduction The sensitivity of market benefits to a reduction of Tasmanian demand was determined in a scenario with a 40% reduction in Tasmanian annual energy consumption relative to 2016 spread uniformly over the year. Market benefits and net market benefits are shown in Table 17. In this scenario the net benefit is positive indicating that modelled market benefits exceed the cost of building the second interconnector.

Table 17: TasDemand regulated interconnector outcomes (NPV $m) Discount rate = 7% Discount rate = 10% Market benefits 2,017 1,528 Interconnector costs -1,164 -1,104 Net benefit 853 424

Significant reduction of Tasmanian demand acts to increase the market benefits of the interconnector as Tasmanian energy must be able to be exported to the mainland in order to have any value. With low Tasmanian demand, Tasmania has surplus energy and there are several effects that combine to improve the market benefits of the second interconnector.

As Tasmanian demand decreases, the surplus of energy in Tasmania increases. There are several effects that combine to improve the benefits of the second interconnector relative to the Base scenario:

• As Tasmanian demand decreases there are trading intervals where Tasmanian wind and run-of-river generation exceeds demand. In these instances, if that energy cannot be exported, it cannot be saved for the future and so is lost. With the second interconnector, the energy can be dispatched.

• Even in the hydro schemes with long-term storages and hence good ability to move energy around, if Tasmanian demand is low enough and interconnection limited there are trading intervals during which there is too much energy in Tasmania and water from the long-term storages must be spilt to maintain reservoir limits. This is particularly true in wet years but also occurs in dry years with a demand reduction of this size. With the second interconnector, this energy can also be dispatched.

Whereas in the Base scenario market benefits were reduced by the inflexibility of hydro generation to respond to cost variability on the mainland, the lack of flexibility is increasing market benefits in this scenario. If fully unrestricted, all hydro generation could be able to be exported from Tasmania, even in a year of high water inflows. In reality, the seasonality of inflows, the limits on storage size, cascading storages, and non-discretionary output from run-of-river generators means that additional interconnection is required to maintain production volumes.


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In the TasDemand case, there is no difference in renewable investment between the TasDemand Basslink Only and TasDemand Regulated Basslink and 2IC Operation scenarios. The only difference in generator planting is that the second interconnector defers 600 MW of OCGT development in Victoria. A comparison between the components of market benefits from the second interconnector between this scenario and the Base scenario is shown in Table 18.

Table 18: Market benefits by category – Base vs TasDemand scenario (NPV $m – discount rate = 7%) Cost savings in Regulated

Basslink and 2IC Operation relative to Base Case Basslink

Only

Cost savings in TasDemand Regulated Basslink and 2IC

Operation relative to TasDemand Basslink Only

Variable costs 487 1,588 Fixed O&M 36 48 Capital costs 286 381 Total 809 2,017

The large increase in variable cost savings resulting from the second interconnector in the TasDemand scenario is due to the ability to more fully utilise Tasmanian wind and hydro resources. Fixed O&M and capital cost benefits are a result of the deferral of 600 MW of OCGT new capacity in Victoria.

5.4 Low rainfall Section 5.1 showed that variable cost savings attributable to the second interconnector were larger in wet years than in average or dry years of hydro inflows. This is further supported by the low rainfall scenario. In this scenario, the lower frequency of wet years mean that market benefits are lower than in the Base scenario, as shown in Table 19.

Table 19: LowRain vs Base scenario regulated interconnector outcomes (NPV $m) Discount rate = 7% Discount rate = 10%




Cost savings in LowRain


Operation relative to LowRain

Basslink Only




Cost savings in LowRain


Operation relative to LowRain

Basslink Only

Market benefits 809 647 634 379 Interconnector costs -1,164 -1,164 -1,104 -1,104

Net benefit -356 -518 -470 -725 Although lower rainfall reduces the market benefits arising due to fuel and variable operating and maintenance cost savings, there may be significant additional benefit from a Tasmanian energy security perspective. This is discussed in Section 5.5.

5.5 Strong emissions constraint This scenario achieved 45% emissions reduction in 2030 and zero emissions in 2050. The generation development plan provided by AEMO included significant new gas capacity at the tail end of their study period (to 2035–36). In order to meet zero emissions in 2050, this capacity is phased out after AEMO’s study period in addition to other remaining thermal generators. In their place, significant wind, solar, battery and biogas capacity is installed.

Market benefits and net benefits in this scenario are shown in Table 20 and a comparison to Base scenario outcomes in Table 21. Total market benefits and consequently net benefits are $24m higher in the StrongAction scenario (with a 7% discount rate). The market benefit components in


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Table 21 shows variable cost savings are much larger, but this is partly offset by an increase in fixed O&M and capital costs.

The balance between variable and fixed costs differences between these two scenarios is predominantly a result of the generation development plan provided by AEMO. In the inputs applied for the StrongAction scenario, additional renewable generation was built in the NEM. This increases capital costs and reduces variable costs. In the StrongAction scenario, the second interconnector does defer new thermal capacity in Victoria; however the effect of this change on total capital costs is obscured by the difference in renewable generation development. This means that a direct comparison between the components of the market benefits between the StrongAction and the Base scenario is difficult to interpret.

Table 20: StrongAction regulated interconnector outcomes (NPV $m) Discount rate = 7% Discount rate = 10%

Market benefits 833 592 Interconnector costs -1,164 -1,104 Net benefit -331 -512

Table 21: Market benefits by category – Base scenario vs StrongAction (NPV $m – discount rate = 7%)

Cost savings in Regulated Basslink and 2IC Operation

relative to Base Case Basslink Only

Cost savings in StrongAction Regulated Basslink and 2IC

Operation relative to StrongAction Basslink Only

Variable costs 487 1,020 Fixed O&M 36 -149 Capital costs 286 -38 Total market benefits 809 833

In general, our finding is that the impact of the more aggressive emissions abatement trajectory on market benefits is relatively minor. Although brown coal is retired more rapidly, AEMO forecast a corresponding escalation in the amount of battery storage built in Victoria. This means that there is no need for large investments in new thermal capacity until the early 2030s, primarily as a replacement for the Loy Yang power stations. A similar result was observed in the Base scenario. There is therefore no significant improvement in the value provided by the second interconnector in terms of capital deferment. An improvement in this component would have been realised had the second interconnector delayed investment in new thermal capacity much earlier, due to the impact of discounting.

Table 22 shows the components of variable cost saving for the StrongAction scenario. These results are comparable to the Base scenario results presented in Table 10. In the StrongAction scenario, there is significantly more renewable generation on the mainland. However, the ability of the additional interconnection to absorb surplus low cost generation to allow water to be used to offset high cost thermal generation is not significantly different than in the Base scenario. There are two key reasons for this:

• The restricted flexibility of the hydro fleet in Tasmania reduces the ability to manage variability in production costs on the mainland. As the variability between trading intervals of high and low cost generation increases on the mainland, the level of flexibility in the Hydro Tasmania generation fleet starts to limit the ability to extract these benefits. This could be improved through increased flexibility in the Hydro Tasmania generation fleet, such as through the construction of pumped-storage hydro generation, but the cost of this investment would have to be weighed up against the additional benefits.

• The projected development required to meet the target of zero emissions by 2050 results in large investments in battery storage across all regions. Battery storage technology is effectively a competitor to the second interconnector as it fulfils a similar role of helping to manage the variability in production costs over time. In AEMO’s results, there is no significant difference in


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the installed capacity of battery storage in Victoria with the introduction of the second interconnector. This has been maintained in our modelling.

Table 22: Variable cost savings in StrongAction Regulated Basslink and 2IC Operation (discount rate = 7%) Generation reduction

(discounted GWh) Variable cost saving

($m NPV) Average cost $/MWh

TV-CCGT -3,076 -240 78 CCGT -131 -8 58 OCGT and peaking 12,113 1,286 106 Coal -702 -22 32 Renewable -8,667 4 0 Total 1,020

Although the direct impact of the second interconnector on fixed and variable costs is not significantly larger under a more aggressive emissions abatement target, there may be larger benefits relating to technical capabilities, particularly those related to energy security in systems with much less synchronous generation. This is covered in more detail in Section 5.6.

5.6 Discussion of other market benefits and costs There are several sources of additional benefits that may result from the interconnector that are not captured in the market benefits presented in this Report.

5.6.1 Energy security in Tasmania due to interconnector outages Our modelling assumes that Basslink will remain operational without any extended outages over the entire modelling timeframe. Given the recent Basslink outage, there is greater uncertainty regarding the ability of Basslink to operate over this timeframe.

Hydro Tasmania has estimated the cost of the energy supply challenges faced during the period of the Basslink outage (21 December 2015 to 13 June 2016) to be between $140 and $180 million20. This includes reduction in costs relating to unpaid Basslink fees (approximately $8 million per month). Agreements were struck with three major energy users on a voluntary basis. The extent of the value of lost production from the curtailment of approximately 100 MW21 of continuous load and up to 180 MW at times is uncounted. This will have had economic impacts on the workforce and associated communities and revenue for the facilities that reduced load.

As such, the cost to the State of Tasmania due to the loss of the existing Basslink interconnector for a period of almost seven months is unclear. Given the event has happened in the tenth year of operation of the Basslink facility, it may be described as a one-in-ten-year event. Thus in very simplistic terms taking a conservative mid-point of Hydro Tasmania’s cost estimate of $160 million, an additional benefit of the second interconnector could be considered in the range of $16 million per annum.

Further benefits of the second interconnector include reducing the risk that Basslink’s operational life is shorter than expected. Total loss of Basslink with required lead-time for building the second interconnector would result in reliability and security of supply risks, loss of generation and revenue for Hydro Tasmania and other associated uncertainties such as higher electricity supply costs for Tasmania and risks of losing value adding enterprise such as the various smelter and refinery operations.

20

http://www.hydro.com.au/system/files/Energy_Supply_Plan_2016_Final_Summary.pdf 21

Hydro Tasmania Annual Report 2016 (p23) http://www.hydro.com.au/system/files/documents/160201-Hydro-AR-2016-Web-25-10-2016.pdf


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NTNDP resilience benefits

In the NTNDP, AEMO have modelled the impact of a Basslink outage. For Tasmania, they define resilience benefits as the impact of the outage on total generation dispatch inefficiencies throughout the NEM. This is not equivalent to the discussion above which focuses on the impact of the outage in Tasmania, not the impact on mainland generation dispatch. AEMO calculate resilience benefits of $48m. In our discounting terms, this would $94m of market benefits in addition to the benefits modelled in this report, and other associated benefits described in this section.

5.6.2 Frequency Control Ancillary Services (FCAS) The second interconnector could also supply ancillary services to both Tasmania and Victoria in an environment of growing need for FCAS services. This quantity would be equivalent to that available from fully controllable grid connected batteries configured to provide FCAS.

Basslink presently supplies FCAS, within the limits of the Basslink inverter technology and the cable design parameters. The Basslink cable can transmit power and FCAS in each direction and reverse power in accordance with AEMO market settings. Basslink is furthermore equipped with automatic fast acting control systems which detect any frequency difference in the AC systems at the two ends, and act instantly to limit the differences.

Basslink has a cable limitation which requires a short delay of five minutes and a deadzone of 50 MW when reversing power. This also limits the provision of ancillary services to exclude operating in the deadzone. This reduces the overall window within which Basslink can provide FCAS. In contrast, the second interconnector inverter stations and cable would be of the new voltage-source converter (VSC) design using the same technology as large solar, batteries and wind farms, enabling fast FCAS response seamlessly over its entire operating range, both importing and exporting.

The limiting factors for providing ancillary services from the second interconnector include the capacity of the second interconnector, the available spare capacity in the direction of ancillary services support, and the ability of the supporting region to provide the ancillary services without itself breaching security limits. These limitations are equivalent to those of large batteries, which have to account for the state of charge or discharge at all times in determining the available support.

The speed of response of the second interconnector (and Basslink) for providing ancillary services is much faster than that of synchronous fossil-fuelled, hydro and other thermal generators, such as biomass, geothermal and solar thermal types. These cannot respond with ancillary services until their governors react to a frequency change and adjust the level of mechanical power from their turbines. In contrast, the second interconnector would be capable of detecting Rate of Change of Frequency (ROCOF) in a fraction of a second following a disturbance and almost instantly providing full power within the limits of flow of the interconnector and reserve capacity at the other end. Therefore it would provide a one-for-one replacement for existing FCAS categories but at a much faster rate, assisting to contain frequency changes within permissible limits.

The second interconnector has a higher potential to provide FCAS services to Tasmania than the mainland because inertia and spinning capacity is lower in Tasmania. The FCAS services of the second interconnector to Victoria and the mainland should increase over time however, as available mainland FCAS services reduce. This will apply to both inertia and all FCAS categories because as mainland generators retire, the remaining generators will be loaded more fully and thus have reduced spare capacity to provide spinning reserve.

The FCAS benefits of the second interconnector could match the benefits of the equivalent capacity of large batteries, with equivalent value as a proportion of installed MW capacity. The quantification of this benefit has not been attempted, but is of the same scale as that provided by batteries.


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5.6.3 Network Support and Control Ancillary Services (NSCAS) and System Restart Ancillary Services (SRAS)

Depending on location, NSCAS and system restart services are intrinsic features of the second interconnector, unlike Basslink which can provide neither. This again is related to the inverters which are the same technology as that for solar, batteries and the latest inverter connected wind generators.

The VSC inverters can provide reactive power support, equivalent to that of synchronous condensers, up to the design capacity of reactive power, typically half the real MW power capacity, in both directions, absorbing and generating reactive power.

The second interconnector, unlike Basslink, will be able to generate its own AC waveform, and can provide system restart services up to its full capacity to either connected region.

Overall, the ancillary service benefits of the VSC controlled second interconnector would be substantial and could provide all types of FCAS, both positive and negative, NSCAS, and system restart capabilities. VSC HVDC systems can provide full STATCOM functionality to support the AC network at the Tasmanian and Victorian point of common coupling. In addition to the NSCAS functionality VSC can also provide black-start capability by synthesising a balanced set of three-phase voltages much like a STATCOM with the aid of an auxiliary source. We estimate the capital cost of a comparable STATCOM system to provide NSCAS and enhance voltage stability is $50m AUD to $75m.22

5.6.4 Other operational considerations • Our modelling does not consider the impact of the second interconnector on transmission

development across the NEM. The cost of the interconnector assumed in the modelling considers only the direct costs of connecting the second interconnector to the existing transmission network. Similarly, we have not considered the impact of additional renewable generation development on transmission development and connection costs.

• Our modelling has not attempted to quantify competition benefits. Given the long lead-time until the second interconnector is operational and the extended timeframe of the modelling, the competitive dynamics in the wholesale market are highly uncertain. Furthermore, many of the existing coal assets are retired in the early stages of the modelling such that the existing generation portfolios would be very different during the study period. Therefore any assessment of the impact of the interconnector on competition, particularly in the Victorian wholesale market would be highly speculative and heavily dependent on assumptions such as contracting positions and the concentration of ownership in new generation assets. In addition, the development of the interconnector reduces investment in new thermal capacity, which could itself affect competitive dynamics.

• The modelling of hydro generation considers the management of inflows and storages subject to interconnector import and export capacity. This management does not consider risk factors such as interconnector outages, unexpected low rainfall, etc. In reality, this may mean that Hydro Tasmania’s operation must be more conservative without the second interconnector to minimise reliability risks. This conservatism will reduce the effectiveness of generation in Tasmania in reducing variable costs across the NEM. Our modelling incorporates no differences in the behaviour and operating protocol of the Hydro Tasmania portfolio between interconnector scenarios. For example, it may be that Hydro Tasmania could have more aggressive operational targets for reservoir levels when there is the second interconnector to mitigate against risks of unexpected events.

22

http://upcommons.upc.edu/bitstream/handle/2117/77913/Bs_Thesis_Joaquin_Rebled_Lluch.pdf?sequence=1


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6. Results – Merchant interconnector

6.1 Impact of bidding behaviour assumptions Section 3.1.4 details the methodology used to model profit maximising MNSPs. This explanation showed that at times, profit maximising behaviour from MNSPs can result in significant differences in wholesale market prices and interconnector flows when compared to regulated interconnector behaviour. In summary:

• On export from Tasmania, the interconnectors sometimes withhold flow to higher prices. This lowers overall export flow, increases wholesale prices in Victoria and decreases wholesale prices in Tasmania. The interconnectors derive revenue from the price differential between Tasmania and Victoria. In trading intervals where this strategy is used, lower cost Tasmanian gas and hydro generation reduces relative to the regulated option and is replaced by high cost (usually gas) generation on the mainland.

• On import to Tasmania, the interaction between the bidding strategies of the interconnectors and Hydro Tasmania water management was problematic. Large interconnector revenues could be earned by the MNSPs by withdrawing imports when generation in Tasmania was limited due to low storage levels and low wind, leading to very high wholesale prices in Tasmania. In reality, it is likely that Hydro Tasmania would manage their water differently in this situation. Owing to these difficulties, we restricted the interconnectors to bidding $0/MWh as they do when regulated.

6.2 Impact of interconnector ownership structure assumptions If the construction of the second interconnector were merchant, as well as Basslink, there are a number of key assumptions that will determine where benefits will flow. It would be challenging to realise MNSP revenues if the two interconnectors were to compete for wholesale price differential between the two regions. For this reason we have modelled both interconnectors acting co-operatively, such that the bidding of the two interconnectors aims to maximise the total revenue of the interconnectors. There are alternative operational model options such as converting Basslink to a regulated interconnector while operating the second interconnector as an MNSP – these have not been modelled in this Report. The EY financial modelling team considered some alternative options in their analysis to form a view on the ability of the private sector to fund the second interconnector under a range of commercial models, not limited to regulated or MNSP only cases. The results for Base Case 1 (where Basslink and the second interconnector operate as MNSPs) in the EY financial modelling report are directly comparable to the results provided in this Report23.

Another possible ownership structure that could occur is Hydro Tasmania bidding one or both of the MNSPs to maximise total net wholesale revenue, including generator revenue and MNSP revenue. Preliminary modelling showed that in the vast majority of trading intervals under this ownership structure, Hydro Tasmania would not benefit from bidding the MNSPs above $0/MWh – Hydro Tasmania would increase net wholesale revenue by having higher Tasmanian wholesale prices, rather than higher MNSP revenue. There would however be limited trading intervals in which a combined Hydro Tasmania-Basslink-second interconnector portfolio would benefit from bidding both interconnectors at higher prices and benefitting from the resulting higher mainland wholesale prices and reduced export volumes.

The ownership structure we have tested is where Hydro Tasmania continues to bid cost reflectively, i.e. bidding at water value, while the two interconnectors bid as cooperative MNSPs to maximise trading revenue. By bidding Hydro Tasmania generation based on the water value and the H2Opt

23

Noting that the EY financial modelling present NPVs in real June 2016 dollars discounted to 2016 using a 7% or 10% nominal discount rate.


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water plan, Hydro Tasmania is effectively restricted from any use of market power and competing with the MNSP interconnectors. Varying this assumption could lead to very different outcomes.

6.3 Summary of MNSP revenue outcomes The NPV of MNSP revenue for the second interconnector and Basslink are shown in Table 23 and Table 24 show, applying a 7 percent and 10 percent discount rate respectively. As our modelling assumes that the two interconnectors cooperate in their bidding behaviour, the split in MNSP revenue between the two interconnectors is an outcome of the loss equations and MLFs. Relatively minor changes to bidding could materially alter this split.

Table 23: MNSP revenue (NPV $m – discount rate = 7%) Second interconnector Basslink Total

Base 2,110 772 2,881 TasWind 2,244 848 3,092 TasDemand 4,869 2,579 7,448 LowRain 2,014 705 2,720 Oversupplied Base 1,357 420 1,776

Table 24: MNSP revenue (NPV $m – discount rate = 10%)

Second interconnector Basslink Total

Base 1,481 549 2,030 TasWind 1,591 609 2,200 TasDemand 3,453 1,844 5,297 LowRain 1,409 502 1,911 Oversupplied Base 966 304 1,270

The key findings are:

• In almost all scenarios, the total revenue of the two MNSPs is large, and would likely exceed the cost of the second interconnector. However, the costs associated with the Basslink agreement and issues related to cooperative bidding would need to be considered in more detail.

• Due to its lower losses, the majority of MNSP revenue is captured by the second interconnector.

• High levels of wind in Tasmania increase MNSP revenue. Higher levels of wind investment in Tasmania will tend to reduce wholesale prices in Tasmania, as wind bids at low prices. This increases the wholesale price differential between Tasmania and Victoria, particularly in trading intervals of high Tasmanian wind production. This increases MNSP revenues.

• Similarly, a reduction in demand in Tasmania would dramatically reduce water value and therefore the price bid by Hydro Tasmania. This increases the potential price differential between the wholesale price of energy offered in Tasmania relative to wholesale price in Victoria.

• Lower rainfall reduces MNSP revenues slightly relative to the Base scenario. Lower rainfall will tend to increase Tasmanian wholesale prices, and therefore reduce the potential differential between Tasmania and Victoria.

• The Oversupplied Base scenario shows the sensitivity of MNSP viability to wholesale market conditions. In this scenario, additional generation reduces wholesale prices in the mainland such that wholesale prices are below the LRMC of new entrant generation. This results in a large reduction in MNSP revenue for both interconnectors, while export across the interconnectors remains relatively constant.


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• Given the risks associated with MNSP operational models, the higher discount rate may be more appropriate for assessing the viability of the second interconnector.

When compared against interconnector costs, the MNSP revenue outcomes provided above indicate that the merchant operational model could be viable. However, it is important to consider that the ability of the MNSP to capture these revenues is dependent on Hydro Tasmania not changing its bidding behaviour in response to the bidding strategies implemented by the MNSPs. Any competition from Hydro Tasmania (by increasing bid prices) would reduce the revenue that could be captured by the MNSPs.

6.4 Base scenario 6.4.1 Financial outcomes Table 25 and Table 26 show Basslink and second interconnector revenues on an NPV basis of cash flows. Given the significant impact of the second interconnector and interconnector bidding behaviour on the Tasmanian wholesale market, these tables also show the effect of interconnection on Hydro Tasmania’s net wholesale revenue and the total wholesale cost to Tasmanian consumers using the regulated and merchant models. (Note that under the regulated model, the cost to consumers does not include any cost recovery of the second interconnector.) The differences between cash flows under the merchant and regulated options are discussed further in Section 7.

Table 25: Revenue outcomes — Base scenario — Merchant vs regulated (NPV $m – discount rate = 7%)

Merchant Basslink and 2IC Operation relative to Base Case Basslink Only

Regulated Basslink and 2IC Operation relative to Base Case Basslink Only

MNSP revenue – Second interconnector 2,110 - MNSP revenue – Basslink 772 - Increase in Hydro Tasmania wholesale market net revenue

221 6,171

Increase in total wholesale cost to TAS consumers (negative benefit)

-73 3,908

Cost of the second interconnector -1,164 -1,164 Table 26: Revenue outcomes – Base scenario — Merchant vs regulated (NPV $m – discount rate = 10%)

Merchant Basslink and 2IC Operation relative to Base Case Basslink Only

Regulated Basslink and 2IC Operation relative to Base Case Basslink Only


2 4,118


-68 2,676

Cost of the second interconnector -1,104 -1,104 MNSP revenue

For both discount rates applied, the cash flows of the two interconnectors combined exceeds the cost of the second interconnector. In isolation, the second interconnector also has revenue in excess of its cost, noting that the division of the revenue between the two MNSPs here is dependent on their cooperative behaviour.

Whether the additional interconnector operating under the merchant model is viable given the above results will depend on negotiations with the current owners of Basslink. Should the MNSPs compete for revenue, total MNSP revenue would likely be much lower. However, it is unlikely that Basslink would benefit from an arrangement where the revenue was divided according to losses (as it effectively is in the above results) without some form of compensation.


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Financial impact on Tasmanian market participants

The tables also show the total costs and benefits to Tasmanian market participants, i.e. Hydro Tasmania and Tasmanian wholesale energy costs. The relative impact on mainland generation revenue and wholesale market costs will be much smaller. The impact of an additional 600 MW of interconnection in Victoria is much smaller than the impact in Tasmania. Furthermore, the additional interconnection in Victoria defers new capacity such that the resulting wholesale prices in Victoria are not significantly changed.

Due to its Government ownership, the impacts on Hydro Tasmania net wholesale revenue and Tasmanian consumers are strongly related. As such, scenarios that substantially increase Hydro Tasmania’s net wholesale revenue but result in similarly large increases in wholesale market costs will not necessarily disadvantage Tasmanian consumers.

In the Base scenario, these tables show that the two interconnectors operated as MNSPs make substantial returns. The impact on Hydro Tasmania and Tasmanian consumers is relatively minor. In contrast, under a regulated model the increase in Hydro Tasmania net wholesale revenue is very large, although this is partly offset by the increase in costs to Tasmanian consumers.

There are a number of other key findings from the above tables:

• The table shows that the improvement in Hydro Tasmania’s net wholesale revenue due to the second interconnector is larger when the second interconnector is regulated. This indicates that if Hydro Tasmania controlled the interconnectors with the objective of maximising its profitability, bidding behaviour would more closely resemble the regulated outcome, i.e. bidding at $0/MWh.

• Although operating as a regulated interconnector improves Hydro Tasmania net wholesale revenue, it also increases cost to consumers and does not generate market revenue.

6.4.2 Sensitivity to wholesale market conditions The value of the additional interconnector, both in terms of MNSP revenue and the impact on Hydro Tasmanian net wholesale revenue are dependent on wholesale market conditions, particularly in Victoria. There is therefore the potential of significant downside risk on the outcomes presented above should wholesale market prices be more subdued than those modelled.

Market modelling generally involves forecasting scenarios with perfect foresight. In modelling studies, key assumptions such as demand, capital costs, emissions constraints, fuel prices, etc. tend to follow consistent projections rather than moving up and down over time. As such, wholesale market outcomes over the medium- to long-term converge towards equilibrium.

Recent history shows that the impact of unforeseen changes in the pattern of consumption, the introduction and repeal of carbon pricing, the impact of government renewable energy policy have caused wholesale prices to vary over time, and in general have been below the long run marginal cost of new entrant generation.

To illustrate the impact of this downside risk, we have modelled a sensitivity to the Base scenario where the market is consistently oversupplied for the duration of the study. This has been simulated by adding a consistent amount of additional CCGT and OCGT generation to Base Case Basslink Only, Regulated Basslink and 2IC Operation and Merchant Basslink and 2IC Operation. As such, the relative capacity differences between these scenarios have been maintained.

The outcomes from this study are shown in Table 27 and Table 28, noting these results are directly comparable to Table 25 and Table 26 respectively. The downside risk for MNSP revenue is evident in that revenues fall by approximately 40% in a more oversupplied market.


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When compared to Table 25 and Table 26, the tables below also show that the benefits of a regulated interconnector to Hydro Tasmania’s net wholesale revenue (and the opposing impact on Tasmanian consumers) is significantly reduced in this oversupplied scenario.

Table 27: Revenue outcomes – Oversupplied Base scenario – Merchant vs regulated (NPV $m – discount rate = 7%)

Merchant Basslink and 2IC Operation relative to Oversupplied Base Case

Basslink Only

Regulated Basslink and 2IC Operation relative to Oversupplied Base Case

Basslink Only


-1,063 3,366


-757 2,207

Cost of the second interconnector -1,164 -1,164 Table 28: Revenue outcomes – Oversupplied Base scenario – Merchant vs regulated (NPV $m – discount rate = 10%)

Merchant Basslink and 2IC Operation relative to Oversupplied Base Case

Basslink Only

Regulated Basslink and 2IC Operation relative to Oversupplied Base Case

Basslink Only MNSP revenue – Second interconnector 966 - MNSP revenue – Basslink 304 - Increase in Hydro Tasmania wholesale market net revenue

-846 2,255


-495 1,573

Cost of the second interconnector -1,104 -1,104 An assessment of annual MNSP revenue also illustrates this sensitivity to wholesale market conditions. In the Base scenario, the volatility of the Victorian wholesale market escalates during the early 2030s as brown coal generation retires. MNSP profitability is strongly linked to this escalation, as shown in Figure 6.

Figure 6: Annual MNSP revenue – Base scenario


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6.5 Other scenarios 6.5.1 Tasmanian wind generation expansion As described in Section 5.2, it is more reasonable to compare the impact of the second interconnector in the TasWind scenarios with the outcomes from Base Case Basslink Only. Table 29 and Table 30 show the outcomes for TasWind on this basis.

The addition of more wind generation in Tasmania reduces wholesale prices as wind offers its generation at low prices. The MNSPs make the majority of their revenue by exporting low cost energy from Tasmania to the mainland. Therefore, higher levels of wind generation in Tasmania will increase MNSP revenue, as shown in the following tables.

Table 29: Revenue outcomes – TasWind scenario – Merchant vs regulated (NPV $m – discount rate = 7%) TasWind Merchant 2IC

and Basslink Operation relative to Base Case

Basslink Only

TasWind Regulated Basslink and 2IC



-610 5,601


-416 3,693

Cost of the second interconnector -1,164 -1,164 Table 30: Revenue outcomes – TasWind scenario – Merchant vs regulated (NPV $m – discount rate = 10%)

TasWind Merchant 2IC and Basslink Operation relative to Base Case

TasWind Regulated Basslink and 2IC

Operation relative to Base Case


-807 3,537


-350 2,508

Cost of the second interconnector -1,104 -1,104

6.5.2 Tasmanian demand reduction The large reduction in Tasmanian demand forecast in this scenario results in very low water values for Hydro Tasmania, particularly if there is no additional interconnection. This results in very low wholesale market prices in Tasmania.

The second interconnector operating as an MNSP would make very large profits in this scenario, primarily by exporting very low cost energy from Tasmania to the mainland. This is shown in Table 31 and Table 32. The revenues earned by the MNSPs far exceed the cost of the second interconnector. In general, the driver for additional interconnection under both regulated and merchant models is very strong given the demand reduction assumed in this scenario.

Given a substantial reduction in Tasmanian demand, there are many trading intervals where the value of Hydro Tasmania’s water will be very low or near zero, as inflows exceed the ability to export excess generation to mainland. In these trading intervals, the MNSPs can effectively earn near to the wholesale price in Victoria by exporting near zero cost energy from Tasmania. In these trading intervals, Hydro Tasmania’s wholesale revenue would be very low as the MNSPs would be maintaining the wholesale price differential between Tasmania and Victoria.


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Table 31: Revenue outcomes – TasDemand scenario - Merchant vs regulated (NPV $m – discount rate = 7%) TasDemand Merchant

Basslink and 2IC Operation relative to TasDemand Basslink

Only

TasDemand Regulated Basslink and 2IC

Operation relative to TasDemand Basslink

Only

MNSP revenue – Second interconnector 4,869 - MNSP revenue – Basslink 2,579 - Increase in Hydro Tasmania wholesale market net revenue

-961 5,260


-566 2,984

Cost of the second interconnector -1,164 -1,164 Table 32: Revenue outcomes – TasDemand scenario - Merchant vs regulated (NPV $m – discount rate = 10%)

TasDemand Merchant Basslink and 2IC


Only

TasDemand Regulated Basslink and 2IC


Only MNSP revenue – Second interconnector 3,453 - MNSP revenue – Basslink 1,844 - Increase in Hydro Tasmania wholesale market net revenue

-808 3,488


-469 1,959

Cost of the second interconnector -1,104 -1,104 Under the regulated model, Hydro Tasmania’s wholesale market net revenue increases significantly due to the second interconnector. However under the merchant operational model, Hydro Tasmania’s net revenue reduces.

6.5.3 Low rainfall Low rainfall reduces the available water in Hydro Tasmania’s storage. As a result, the value of each unit of water increases. This results in higher prices being bid into the wholesale energy market by Hydro Tasmania. Higher price bid offers by Hydro Tasmania reduce the potential wholesale price differential between Tasmania and Victoria. This results in a reduction in MNSP revenue, as seen in Table 33 and Table 34. Despite the reduction relative to the Base scenario, the second interconnector’s MNSP revenue exceeds its cost.

Table 33: Revenue outcomes – LowRain scenario – Merchant vs regulated (NPV $m – discount rate = 7%) LowRain Merchant

Basslink and 2IC Operation relative to


LowRain Regulated Basslink and 2IC

Operation relative to LowRain Basslink Only


73 5,949


-81 3,885



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Table 34: Revenue outcomes – LowRain scenario – Merchant vs regulated (NPV $m – discount rate = 10%) LowRain Merchant

Basslink and 2IC Operation relative to


LowRain Regulated Basslink and 2IC

Operation relative to LowRain Basslink Only


-134 3,906


-93 2,626


6.6 Impact of the MNSP on NEM market benefits The bidding behaviour of MNSPs in the modelling is entirely based on an assessment of which strategy maximises the total revenue of the two interconnectors. At times, this results in flow outcomes that are not beneficial to the market as a whole, as defined by the market benefits attributable to the second interconnector (calculated in the same way as done for the regulated interconnector in Section 5). This is demonstrated in Table 35 which shows market benefits in each scenario under regulated and merchant interconnector operation. In all scenarios, other than the Tasmanian demand reduction scenario, market benefits are considerably lower than the equivalent regulated scenario due to the impact of profit-maximising MNSP bidding from both the second interconnector and Basslink.

Table 35: NEM market benefits (NPV $m, excluding IC cost) Merchant - 7%

discount rate Regulated - 7% discount rate

Merchant - 10% discount rate

Regulated - 10% discount rate

Base 183 809 48 634 TasWind -57 522 -169 257 TasDemand 1,996 2,017 1,508 1,528 LowRain 491 647 250 379 Oversupplied Base 126 679 8 400

By operating as an MNSP, the market benefits of the second interconnector reduce substantially relative to operating as a regulated interconnector. There are many trading intervals where the interconnectors withhold exports, adding to their revenue but not reducing variable costs to the extent that they could have if export capacity was not withheld. In other words, the profit-maximising behaviour of the MNSPs negates many of the instances where interconnection results in cost savings.

Under a regulated model, the interconnectors effectively export energy from the lower priced region to the higher priced region until either wholesale price differentials are entirely due to losses, or the interconnectors are constrained from increasing export (due to either interconnector limits or transmissions constraint equations). Given that prices are strongly related to the marginal cost of production, this regulated operation will generally result in the interconnectors providing the maximum possible market benefit in terms of total market costs.

Under a merchant model, the incentives to bid the interconnectors differently on export to increase profit can negate the impact of the second interconnector in reducing generation costs. A key source of revenue under the merchant model is exporting to Victoria in periods of high Victorian prices. These periods also coincide with high marginal costs of production in Victoria. Under a regulated model, the interconnectors would likely export at maximum capacity during such periods, reducing the dispatch of high cost generation to the maximum extent. However under the merchant model, it may be that larger market profits for the interconnector result from withholding export supply (i.e. a price-volume trade-off), reducing the benefit of additional interconnection on NEM generation costs. In our modelling, this can means that hydro generation uses water in other periods


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where the cost of generation being offset is much lower, or reduces the dispatch of gas generation in Tasmania.

In contrast to all other scenarios, in the TasDemand scenario market benefits are not negatively impacted by the profit maximising behaviour of the second interconnector. In general this is because the market benefits of the second interconnector in the TasDemand scenario result primarily from the capacity to export excess energy from Tasmania that would otherwise have been wasted (spilt or curtailed). This benefit is more easily captured in comparison with the benefits that result from shifting generation to use energy more effectively (a key driver of benefits in other scenarios).

The market benefits in the Oversupplied Base scenario are similar to the Base scenario for the regulated second interconnector. They reduce by less than 4% due to the capacity oversupply. This outcome stands in contrast to the interconnector revenue outcomes for the second interconnector operating as an MNSP shown in Section 6.4.2, where capacity oversupply represents a large downside risk.

6.7 Relationship to EY financial modelling The bulk of the market modelling presented in this Report examines the merits of the second interconnector if it is regulated. These outcomes are focused on the NEM-wide market benefits the interconnector would provide (such as lower production costs or deferred capital costs). These outcomes are based on the interconnector bidding at zero.

For the MNSP option, we consider the market revenues that might be expected to flow to the owner of the second interconnector, and also the financial impact on other relevant parties in Tasmania: Basslink, Hydro Tasmania and energy consumers in Tasmania. The impact of the second interconnector on these parties is heavily dependent on the arbitrage opportunities to be exploited and the operating behaviour of the second interconnector. Although market benefits may result from the operation of the MNSP, these benefits do not form the basis of the viability of the asset, as the second interconnector asset owner is unable to capture these benefits as project revenues. Rather, the viability of the MNSP will be formed by an expectation of revenues derived from arbitrage benefits between Tasmania and Victoria with appropriate consideration of the range of market and regulatory risks associated with the asset.

EY were also engaged to provide commercial and financial advice in respect to the assessment of commercial models for the second interconnector, ranging from fully regulated to fully merchant options.

The financial modelling relies on the same underlying data as the market modelling for the MNSP option. The financial modelling however examines the merits of the second interconnector by examining the private benefits that it would provide under an MNSP commercial model (i.e. those that can be captured by and accrue to the owner of the asset). Under the regulated model, those private benefits are somewhat divorced from the operation of the asset and the market benefits it delivers because private benefits flow indirectly through the regulated returns as determined by the AER.

The financial analysis of the regulated interconnector is based on the assumption that the asset can meet the RIT-T – the analysis in this Report considers under what conditions this assumption is likely to be true. Under the MNSP model, however, those private benefits are largely a function of the owner’s ability to exploit arbitrage opportunities, and are therefore strongly dependent on wholesale market conditions. Furthermore, the private benefits depend on the extent to which the owner of the second interconnector can capture these when there is another interconnector (and associated commercial arrangements) that influence the extent to which deriving an acceptable commercial return is possible.

As a result, while the result of the financial modelling relies on the underlying market modelling data, it illustrates financial outcomes under a range of operating models not directly considered in the market modelling presented in this Report. The market modelling is best used to form a view on


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the merits of having the second interconnector. The financial modelling is best used to form a view on under what commercial model a private party might be willing to fund the second interconnector.

The operating assumptions of Basslink and the second interconnector in the MNSP Base scenario market modelling presented in this Report is similar to the operating assumptions of the two interconnectors in the financial modelling Base Case 1 scenario. Alternative operating models such as converting Basslink to a regulated interconnector while operating the second interconnector as an MNSP have not been modelled in dispatch modelling. The EY financial modelling team considered these alternative options in their analysis to form a view on the ability of the private sector to fund the second interconnector under range of commercial models, not limited to regulated or MNSP only cases. Simplifying assumptions were made to illustrate the potential financial impacts and ability of the private sector to fund the second interconnector for the range of commercial models. Where these commercial model alternatives are worthy of further investigation, additional electricity market modelling of these alternatives at the next phase of project development is suggested.


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7. Financial impact of the second interconnector on Tasmanian market participants

The second interconnector and its bidding behaviour (and Basslink’s) have a significant effect on the Tasmanian wholesale market. A regulated interconnector effectively bids at $0/MWh. The impacts of the bidding behaviour of a regulated and merchant interconnector on Tasmanian and Victorian prices in described in Section 3.1.4 and Section 3.1.5 respectively.

Given the significant impact of the second interconnector and interconnector bidding behaviour on the Tasmanian wholesale market, we provide in Table 36 and Table 37 a summary of the impact of the second interconnector on wholesale revenues for Hydro Tasmania and wholesale costs for Tasmanian consumers respectively. This is provided for both the regulated and merchant operational models. Note that under the regulated model, the cost to consumers does not include any cost recovery of the second interconnector.

Table 36: Impact on Hydro Tasmania net wholesale revenue (NPV $m) Merchant - 7%

discount rate Regulated - 7% discount rate



Base 221 6,171 2 4,118 TasWind -610 5,601 -807 3,537 TasDemand -961 5,260 -808 3,488 LowRain 73 5,949 -134 3,906 Oversupplied Base -1,063 3,366 -846 2,255

Table 37: Impact on wholesale cost of supplying Tasmanian demand (NPV $m)





Base -73 3,908 -68 2,676 TasWind -416 3,693 -350 2,508 TasDemand -566 2,984 -469 1,959 LowRain -81 3,885 -93 2,626 Oversupplied Base -757 2,207 -495 1,573

Compared to the regulated model, the merchant model has a much smaller impact on Hydro Tasmania and Tasmanian consumers. Under the regulated model, the second interconnector bids its capacity at $0/MWh which acts to increase Tasmanian wholesale prices, resulting in significant increases in both Hydro Tasmania generator revenue and Tasmanian wholesale costs. It should be noted that given the government ownership of Hydro Tasmania, the impact on Tasmanian consumers of the second interconnector operating as a regulated asset could be shared differently between the Hydro Tasmania and Tasmanian consumers.

Under the merchant model, the second interconnector does not affect Tasmanian wholesale prices to the same extent as the regulated model as the two interconnectors bid to maintain the price differential between Tasmanian and Victorian wholesale prices. These differentials are the main source of MNSP revenue.

The outcomes show that if the second interconnector were constructed and operated under a regulated model, it is likely that much of the benefit would flow to Hydro Tasmania, primarily through higher wholesale prices in Tasmania. Wholesale prices would increase due to the ability to maintain the connection to Victorian wholesale prices at times of high demand and through the increase in water value that would affect Hydro Tasmania’s bidding behaviour. In simple terms, greater access to the Victorian market increases the value of water in Hydro Tasmania’s storage, and this translates to Hydro Tasmania selling energy at higher wholesale prices. There would also be a significant increase in costs to Tasmanian energy consumers.


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The outcomes in Table 37 indicate that a regulated interconnector is significantly more costly to Tasmanian consumers than a merchant interconnector due its effect in raising Tasmanian wholesale prices. However, if there was a transfer of revenue between Hydro Tasmanian and Tasmanian consumers, the impact on consumers could be reduced. Note again though that the calculated cost to consumers does not include any cost recovery of the second interconnector.

All outcomes are dependent on assumptions about future behaviours and operational arrangements. They are particularly dependent on bidding behaviours and the reactions of Hydro Tasmania and other market participants to the presence of the second interconnector. Alternative arrangements where Hydro Tasmania has input to the bidding of the interconnectors could cause the merchant outcomes to be more similar to the regulated outcomes.


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Base scenario regulated interconnector outcomes

In the body of the Report, we discuss a scenario Regulated Basslink and 2IC Operation. In this scenario, the generation development plan is based on the Base Case Basslink Only generation development plan. We maintained the same wind, solar and CCGT development plan as in Base Case Basslink Only but deferred 450 MW OCGT installation in Victoria in Regulated Basslink and 2IC Operation relative to Base Case Basslink Only such that a similar level of USE was achieved.

We were also provided a generation development plan by AEMO with Basslink and a second interconnector (scenario B). In this plan, wind and solar development is an output of AEMO’s modelling. The outcome is additional wind and solar capacity in the early study years (at additional capital cost). The consequence of this is that the scenario slightly overachieves on the emissions constraint. This Appendix presents market benefits for this alternative scenario.

We have not presented this modelling as the main Regulated Basslink and 2IC Operation result as it is not consistent with the generation development plan used by AEMO in the NTNDP and the sources of market benefits attributable to the second interconnector are obscured by the differences in renewables planting between the Basslink only and second interconnector case. In addition, the early installation of additional renewable capacity is that the scenario overachieves on the emissions constraint; these emissions reductions are not valued. In contrast, emissions in the Regulated Basslink and 2IC Operation scenario are similar to Base Case Basslink Only.

The cost savings due to the construction of the second interconnector in both the Regulated Basslink and 2IC Operation scenario and alternative version are provided in Table 38 for a 7% and 10% discount rate. The overall market benefits of the second interconnector are similar in two simulations: $809m vs $739m. However, the split of benefit components is very different.

In the alternative scenario, the savings in variable costs are significant – this is partly due to the impact of the second interconnector on Hydro Tasmania dispatch but also due to the increased investment in renewable generation in the NEM. This comes at higher capital and fixed O&M costs.

The components of market benefits in Regulated Basslink and 2IC Operation are easier to interpret as direct impacts of the second interconnector.

Table 38: Base scenario market benefits by category (NPV $m) 7% discount rate 10% discount rate




Cost savings in Alternative Regulated






Cost savings in Alternative Regulated



Variable costs 487 1,454 377 1,028 Fixed O&M 36 -281 22 -180 Capital costs 286 -433 236 -403 Total market benefits 809 739 634 445

There are two key insights from the analysis of the Regulated Basslink and 2IC Operation scenario and alternative version:

• In the Alternative case, there is 1,100 MW of new wind constructed in Tasmania relative existing capacity. This is lower than the 1,200 MW of wind built in the TasWind scenario. A comparison between these results shows that the TasWind scenario delivers lower market benefits. This


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supports the view of both EY and AEMO that the development of 1,200 MW of new wind is not beneficial, even with a second interconnector.

• In AEMO’s Base case modelling, the development of the second interconnector results in an additional 365 MW of wind in Tasmania. This suggests there may be market benefits associated with additional wind generation in Tasmania enabled by the second interconnector. This is not captured in our Alternative Regulated Basslink and 2IC Operation scenario presented in this Appendix as the potential benefits of additional wind are outweighed by the costs imposed by building significantly more renewable generation across the NEM. Market benefits of additional Tasmanian wind has also not been captured in the Regulated Basslink and 2IC Operation scenario presented in this Report as Tasmanian wind capacity is the same as Base Case Basslink Only. A scenario may exist where the second interconnector enables the development of some additional wind capacity in Tasmania and results in additional NEM-wide market benefits.


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List of acronyms

Acronym Expanded name AEMO Australian Energy Market Operator AER Australian Energy Regulator FCAS Frequency control ancillary services LRMC Long-run marginal cost MLF Marginal loss factor MNSP Market Network Service Provider NEM National Electricity Market NPV Net present value NSCAS Network support and control ancillary services NTNDP National Transmission Network Development Plan O&M Operations and maintenance POE Probability of exceedance ROCOF Rate of change of frequency SRAS System restart ancillary services SRMC Short-run marginal cost TI Trading interval TV CCGT Tamar Valley CCGT VSC Voltage source converter WACC Weighted average cost of capital

EY | Assurance | Tax | Transactions | Advisory About EY EY is a global leader in assurance, tax, transaction and advisory services. The insights and quality services we deliver help build trust and confidence in the capital markets and in economies the world over. We develop outstanding leaders who team to deliver on our promises to all of our stakeholders. In so doing, we play a critical role in building a better working world for our people, for our clients and for our communities. EY refers to the global organisation and may refer to one or more of the member firms of Ernst & Young Global Limited, each of which is a separate legal entity. Ernst & Young Global Limited, a UK company limited by guarantee, does not provide services to clients. For more information about our organisation, please visit ey.com. © 2017 Ernst & Young, Australia. All Rights Reserved. ey.com/au

Appendix E 191

Appendix E: Ernst & Young Report: Financial and Commercial Analysis—Second Tasmanian InterconnectorEY report: Financial and Commercial Analysis—Second Tasmanian Interconnector, 22 December 2016.

Financial and Commercial Analysis – Second Tasmanian Interconnector

Department of the Environment and Energy 22 December 2016

1

NOTICE

Ernst & Young (“EY or “we”) was engaged on the instructions of the Department of Industry, Innovation and Science1 (“the Department”) on behalf of the Tasmanian Energy Taskforce to undertake commercial and financial analysis in relation to a second, Tasmanian energy interconnector in accordance with our contract dated 21 September 2016.

The results of Ernst & Young’s work, including the assumptions and qualifications made in preparing the report, are set out in Ernst & Young's report dated 22 December 2016 ("Report"). The Report should be read in its entirety including the applicable scope of the work and any limitations. A reference to the Report includes any part of the Report. No further work has been undertaken by Ernst & Young since the date of the Report to update it.

Ernst & Young has prepared the Report for the benefit of the State and Federal Governments, and has considered only the interests of the potential viability of a second cross interconnector between Tasmania and Victoria. Ernst & Young has not been engaged to act, and has not acted, as advisor to any other party. Accordingly, Ernst & Young makes no representations as to the appropriateness, accuracy or completeness of the Report for any other party's purposes.

No reliance may be placed upon the Report or any of its contents by any recipient of the Report for any purpose and any party receiving a copy of the Report must make and rely on their own enquiries in relation to the issues to which the Report relates, the contents of the Report and all matters arising from or relating to or in any way connected with the Report or its contents.

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1 The energy function from the Department of Industry, Innovation and Science has been transferred to the Department of the Environment and Energy. For the avoidance of doubt, EY has used the original engagement department for this notice.

2

Department of the Environment and Energy Canberra, ACT, 2600

22 December 2016

Financial and Commercial Analysis –Second Tasmanian Interconnector – Draft Report

To Whom it may concern, In accordance with work order dated 21 September 2016, pursuant to agreement with the Tasmanian Energy Taskforce to undertake commercial and financial analysis in relation to a second, Tasmanian energy interconnector (“Agreement”), Ernst & Young (“we” or “EY”) has been engaged by the Department of Industry, Innovation and Science (“you”, “the Department” or the “Client”) on behalf of the Tasmanian Energy Taskforce to provide financial and commercial analysis in relation to the suitable commercial and delivery models (the “Services”) in relation to a proposed second Tasmanian interconnector (the "Project"). The enclosed report (the “Report”) sets out the outcomes of our work. You should read the Report in its entirety. A reference to the report includes any part of the Report. Purpose of our Report and restrictions on its use

Please refer to a copy of the Agreement for the restrictions relating to the use of our Report. We understand that the deliverable by EY will be used for the purpose of assisting the Department in its investigation into the relative merits of a proposed second Tasmania to Victoria interconnector, and in particular the potential commercial and delivery model(s) in which a proposed interconnector could operate, should a decision be made to proceed to delivery of the project (the “Purpose”). This Report was prepared on the specific instructions of the Department solely for the Purpose and should not be used or relied upon for any other purpose. This Report and its contents may not be quoted, referred to or shown to any other parties except as provided in the Agreement. We accept no responsibility or liability to any person other than to the Department or to such party to whom we have agreed in writing to accept a duty of care in respect of this Report, and accordingly if such other persons choose to rely upon any of the contents of this Report they do so at their own risk. Third parties seeking a copy of this Report will require permission from EY, and will be required to sign an access letter in the format agreed to between EY and the Department.

Nature and scope of our work

The scope of our work, including the basis and limitations, are detailed in our Agreement and in this Report. Our work commenced on 21 September 2016 and was completed on 22 December 2016. Therefore, our Report does not take account of events or circumstances arising after 22 December 2016 and we have no responsibility to update the Report for such events or circumstances.

Ernst & Young 8 Exhibition Street Melbourne VIC 3000 Australia GPO Box 67 Melbourne VIC 3001

Tel: +61 3 9288 8000 Fax: +61 3 8650 7777 ey.com/au

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Limitations

The outputs and advice provided within the report considers a number of combinations of input assumptions relating to future conditions, which may not necessarily represent actual or most likely future conditions. Additionally, the modelling outputs that have been utilised within this report are sourced from work conducted separately by EY and can be found within the “Market dispatch cost benefit modelling of a second Bass Strait Interconnector – Report” which is also subject to similar restrictions in use and limitations. The outputs inherently requires assumptions about future behaviours and market interactions, which may result in forecasts that deviate from future conditions. There will usually be differences between estimated and actual results, because events and circumstances frequently do not occur as expected, and those differences may be material. We take no responsibility for the achievement of projected outcomes, if any. We highlight that our analysis and Report do not constitute investment advice or a recommendation to you on a future course of action. We provide no assurance that the scenarios we have modelled will be accepted by any relevant authority or third party. Our conclusions are based, in part, on the assumptions stated and on information provided by the Department during the course of the engagement. The commercial and financial analysis are contingent on the collection of assumptions as agreed with the Department and no consideration of other market events, announcements or other changing circumstances are reflected in this Report. Neither Ernst & Young nor any member or employee thereof undertakes responsibility in any way whatsoever to any person in respect of errors in this Report arising from incorrect information provided by the Department. In the preparation of this Report we have considered and relied upon information from a range of sources believed after due enquiry to be reliable and accurate. We have no reason to believe that any information supplied to us, or obtained from public sources, was false or that any material information has been withheld from us. We do not imply and it should not be construed that we have verified any of the information provided to us, or that our enquiries could have identified any matter that a more extensive examination might disclose. However, we have evaluated the information provided to us by the Department as well as other parties through enquiry, analysis and review and nothing has come to our attention to indicate the information provided was materially misstated or would not afford reasonable grounds upon which to base our Report. This letter should be read in conjunction with our Report, which is attached. Thank you for the opportunity to work on this project for you. Should you wish to discuss any aspect of this Report, please do not hesitate to contact Craig Mickle via email at [email protected]. Yours sincerely

Craig Mickle Partner

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Table of contents 1. Executive Summary ................................................................................................... 1

1.1 Key findings ........................................................................................................ 2 1.2 Detailed findings .................................................................................................. 3 1.3 Relationship to the EY Market Dispatch Cost Benefit Modelling ................................ 7

2. Background ............................................................................................................... 9 2.1 Overview ............................................................................................................. 9 2.2 Basslink .............................................................................................................. 9 2.3 Scope of Work ................................................................................................... 10 2.4 Approach to Assessment .................................................................................... 10 2.5 Structure of this report ...................................................................................... 11

3. Commercial Analysis ................................................................................................ 12 3.1 Overview of Commercial Model analysis ............................................................... 12 3.2 Qualitative and Quantitative Analysis................................................................... 14 3.3 Detailed results – Base Case ................................................................................ 19 3.4 Detailed results – Alternative Cases ..................................................................... 23 3.5 Detailed results – Hybrid models .......................................................................... 29 3.6 Conclusion – Commercial Analysis ....................................................................... 31

4. Procurement Models ................................................................................................ 33 4.1 Procurement considerations ............................................................................... 33 4.2 Ownership structure – 1 Owner vs 2 Owner .......................................................... 33 4.3 Procurement Model Options................................................................................ 34 4.4 Procurement Summary ...................................................................................... 35

5. Validation ............................................................................................................... 36 5.1 Market Sounding Participants ............................................................................. 36 5.2 Case Study Validation ........................................................................................ 37

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1. Executive Summary

In April 2016, the Australian and Tasmanian governments established a joint feasibility study (the Study) into whether a second Tasmanian interconnector could improve Tasmania’s energy security and facilitate large scale renewable energy investment. The Study is investigating the benefits of a second high voltage direct current (HVDC) interconnector (the Project, 2IC), construction of which would increase transfer capacity of electricity between Tasmania and Victoria.

EY have been engaged to undertake two separate tasks, firstly, market modelling to evaluate the costs and benefits of a second interconnector (“Market dispatch cost benefit modelling of a second Bass Strait interconnector Report – 22nd December 2016”) and secondly, to provide Commercial and Financial analysis in respect of the second interconnector (“this Report” or “Financial and Commercial Analysis – Second Tasmanian Interconnector – 22nd December 2016”). This Report provides the findings that result from our analysis in respect to the assessment of commercial models for the second interconnector, ranging from fully regulated to fully merchant options. The report “Market dispatch cost benefit modelling of a second Bass Strait interconnector” presents the market modelling assessment of the merits of a second interconnector. The market modelling (“Market cost benefit modelling of a second Bass Strait interconnector Report – 22nd December 2016”) is best used to form a view on the merits of having a second interconnector. The commercial and financial analysis (Financial and Commercial Analysis – Second Tasmanian Interconnector – 22nd December 2016”) is best used to form a view on whether a private party might be willing to fund a second interconnector.

The purpose of this Report is to consider and analyse the commercial and financial impact of various options to deliver the second interconnector. The analysis is a desktop study and preliminary in nature, consistent with the conceptual stage of the Project’s development. A range of hypothetical commercial operating models have been assessed on a qualitative and quantitative basis to capture the full scope of potential options. The commercial operating models considered range from fully regulated, partly regulated, fully market and partly market exposed. For the purposes of the analysis, it is assumed that the 2IC (and Basslink where relevant) could attain the relevant status and, if required, existing commercial arrangements could be modified.

A second interconnector could be developed under the following models:

► A regulated transmission asset with the contribution of costs evaluated under a RIT-T type process, with revenues determined through the Australian Energy Regulator (AER)’s typical process

► A Market Network Service Provider (“MNSP or merchant interconnector”), whereby all revenues are determined by the ability of the operators to profit from arbitrage opportunities that exist between Tasmania and Victoria. The profit, and ultimately the viability of the interconnector, is the responsibility of the operator

This Report also considers variations of these commercial models, such as Basslink operating as an MNSP with the 2IC operating as a regulated asset and vice versa. With MNSP interconnectors being exposed to considerable revenue volatility that could negatively impact commercial viability, the report also considers two hybrid models. The partially regulated and partially merchant models involve some risk sharing between governments, consumers and the private sector in order to improve the viability of the Project:

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► Partially Regulated Assets – defined as assets that earn a fixed return with revenues over and above the viability line shared between the owner of the interconnector and the Government. These are becoming increasingly popular in Europe and are typically called Cap and Collar or Cap and Floor Models.

► Partially Merchant Assets – defined as assets that operate outside of regulation, i.e. the interconnectors generate their own revenue stream, but still requires some form of government assistance in order to support the viability of the commercial model.

Please note all prices in this report refer to real June 2016 dollars unless otherwise labelled. The net present values are discounted to 2016-17.

1.1 Key findings Assessing the commercial structures that may be used to develop the Project raises substantial commercial complexities due to the interactions that the operation of the assets would have on each other.2 This means that the second interconnector cannot be viewed in isolation of Basslink.

These complexities are not limited to either a merchant or regulated approach. A more merchant approach to the development of the Project exacerbates these complexities because of the implications for the existing owners of Basslink, and those that derive value from its use. A more regulated approach to the development of the Project reduces these complexities, but does not remove them entirely, as any inconsistency in the status of the two interconnector’s risks creating material distortions.

These complexities mean that:

► A merchant 2IC is unlikely to be commercially viable without harmonizing the commercial arrangements in regard to Basslink and providing some level of funding support. The model is therefore likely to favour joint ownership;

► A regulated 2IC is likely to be commercially viable, assuming it could attain that status, but would also require some harmonization of the commercial arrangements in regard to Basslink. Regulation could however achieve that this without joint ownership.

The advantages of the regulated approach should, however, not be surprising given that the Project is being driven primarily by objectives that are broader than the commercial opportunities for arbitrage. In determining the appropriate commercial and delivery model for a second interconnector, clear consideration needs to be given to the reasons for its development, as that will have the greatest bearing on the most appropriate delivery model.

2 We have not had access to the BSA between BassLink and HydroTas as part of this work and are only aware of its broad commercial terms. We also do not have visibility of the restrictions on HydroTas’s bidding behaviour. We understand, however, that Basslink in essence currently operates as a quasi-regulated asset (i.e. bids in at zero and HydroTas’s bidding behaviour is constrained).

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1.2 Detailed findings Table 1 contains a summary of the various models assessed, with some initial commentary on their commercial viability.

Table 1: Model Summary

Commercial Model Key Features Viability Base Case – 134. ► Basslink – MNSP

► 2IC - MNSP

1. Basslink operates as a pure

MNSP (no availability charge is earnt)

2. 2IC enters the market as an MNSP asset

3. Unless there is a single owner for both interconnectors would compete for flow to ensure efficient use of the assets

► Model only likely to be practical in scenarios where HydroTas can participate as owner, who would then be incentivised to ensure its viability

► Some form of guaranteed revenues likely to be required as the market risks are considered too great for typical investors

Base Case – 2. ► Basslink – MNSP

► 2IC - MNSP

1. Basslink remains a MNSP whilst earning an availability charge (mimics current operations)

2. 2IC enters the market as an MNSP

3. Commercial restrictions in the Basslink Services Agreement between HydroTas and Basslink Pty Ltd (BPL) limit 2IC operating as overflow cable only (only utilised when Basslink is at capacity)

► Similar to above, models are only viable with ongoing revenue support

► No true MNSP’s are currently operating in the Australian landscape

Alternative Case 1. ► Basslink – MNSP

► 2IC – Regulated

1. Basslink remains MNSP (with availability charge)

2. 2IC meets RIT-T to become a regulated asset

3. 2ICs’ regulated revenue determined by Regulator

► Model provides support for 2IC at the expense of Basslink

► Pure MNSP operations for Basslink would negatively impact its viability (currently earns an availability charge)

Alternative Case 2. ► Basslink –

Regulated

► 2IC – MNSP

1. Basslink becomes a regulated

asset with regulated revenues 2. 2IC to operate a MNSP

► Similarly to Alternative Case 2, Basslink regulation will further support its operations

► 2IC would not be viable without HydroTas’s support

Alternative Case 3. ► Basslink –

Regulated


1. Basslink becomes a regulated asset with regulated revenues

2. 2IC regulated, revenue determined by Regulator

► Regulated models provide some level of surety in regards to revenue which will support the viability and delivery of a second interconnector

3 In the market modelling report, this is the “MNSP Base Case” 4 In the market modelling report, this is similar to the operational assumptions of Base Case unregulated interconnector. Importantly, the market modelling assumes that both interconnectors act co-operatively such that the bidding of the two interconnectors maximizes the total revenue of the interconnectors. However, from a commercial perspective, this would only be the case where the interconnector is owned by the same owner. Further, this Report does not include consideration any of the market benefits, as these are unable to be captured by the asset owner to generate commercial returns. See Section 1.3 for discussion of the relationship to the market modelling

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Hybrid Case 1. ► Basslink –

Partially Unregulated

► 2IC – Partially Unregulated

1. Both Interconnectors are partially unregulated (MNSP), with an availability charge

2. Government provides partial upfront grant, lowering capital costs and therefore ongoing impact on consumers.

► As this model is in essence an MNSP structure with some level of government support in the form of grants, the revenue required to remain viable would be lower than pure MNSP options

► Still requires the support of HydroTas to remain viable

Hybrid Case 2. ► Basslink –

Partially Regulated

► 2IC – Partially Regulated

1. Both Interconnectors are partially regulated

2. Both Interconnectors are supported by a partial transmission charge (Floor)

3. Both Interconnectors earn 25% of the arbitrage revenues

► Partially regulated models have the potential to provide some regulated revenues and exposure to market risks

► Model would be appealing to investors, though none are in operation in Australia and would require government policy shift

Finding 1: Basslink must be considered in the delivery of 2IC.

► Both Basslink and 2IC connect Tasmania to the rest of the NEM, which creates the potential for competing bidding behavior between the two links in an unconstrained market.

► 2IC can operate with reduced transmission losses, which means it can bid more competitively than Basslink, in an unconstrained world.

► The position and approach adopted by Hydro Tasmania (HydroTas) in its bidding behavior would be crucial.

This means that the optimal commercial model for the 2IC to be procured may not produce the optimal outcome overall for other key stakeholders.

Finding 2: Commercial structures and operational assumptions that impact bidding behavior are critical to the delivery models assessment.

► The BSA sets out the commercial arrangements between Basslink and HydroTas. We understand that the commercial structure consists of an availability charge for capacity, plus a variable payment linked to electricity flows.

► In the event that the majority of flows are transmitted through 2IC, Basslink would still be paid its availability payment at a minimum subject to maintaining minimum availability requirements, but may not receive its variable payments.

► To the extent that competition restrictions exist in the BSA (for example Basslink has dispatch priority over 2IC), this may materially impact the ability of 2IC to generate revenue to cover its capital repayments.

Finding 3: Commercial models which expose the asset owners to revenue risk have the potential to impact the ongoing commercial viability of Basslink and 2IC

► Operating model options that have both links acting as MNSPs and separate ownership, expose the asset owners to considerable revenue and asset stranding risk. Without operational restrictions, sub-optimal market outcomes may eventuate:

o Either very low competitive pricing which creates financial stress for the asset owners; or

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o Pricing is maintained at artificially high levels due to the pricing power a duopoly might possess.

► MNSP models actively encourage profit maximisation at the expense of the other interconnector. With the new interconnector able to deliver lower transmission losses, though newer design capability and improved technology, the newer interconnector could garner a majority of the energy flows, which will further isolate Basslink’s ability to generate a rate of return that would support its ongoing operation and viability.

► MNSP models with a high degree of revenue risk expose asset owners to significant volatility in forecast revenue. For an interconnector which captures benefits from the price differential between Tasmania and Victoria, this revenue is expected to be challenging for financiers to forecast and ultimately raise debt against.

► MNSP options are expected to attract a risk premium by financiers to compensate for this risk, and result in much lower gearing (the proportion of debt to debt plus equity) compared to models with more stable and secure cashflows.

► The bidding behaviour (and strong market position) of HydroTas may impact the ability of financiers to take a long term view on the ability to secure revenues to repay investors.

Finding 4: A form of the regulated asset model for 2IC could be expected to minimize financing costs and creates more options for how the Project can operate alongside Basslink

Regardless of whether Basslink remains a MNSP, or is regulated, delivery of 2IC under a regulated asset model is likely to have advantages because:

► This would reflect the underlying reasons why the 2IC would be built (i.e. not to provide additional capacity that can pay for itself by operating as an MNSP in the short term). It would also reflect the difficulties that the MNSP model has previously encountered in Australia.

► Fully regulated models for 2IC and Basslink on balance offer the greatest level of benefits to electricity consumers and also to the owners of the interconnectors. It would however impact negatively on private generators, which may expose consumers to higher costs over the longer term.

► It effectively encourages the higher utilisation of the second interconnector as it will benefit from reduced transmission losses being newer technology and design which could undermine the viability of Basslink (if it remains a MNSP), whilst simultaneously impacting the energy security benefits of dual interconnectors.

► Enables a broader range of benefits to be delivered to consumers through regulated asset framework and can be structured so government and other beneficiaries can contribute funding to the link.

► Regulated assets owner takes the risk on changes of regulated returns made by the AER on a five (or more) year basis.

However, under this model, regulation would be required to provide the incentives to encourage efficient maintenance of the assets.

Finding 5: There may be potential to refine the regulated asset model to enable other beneficiaries of the Project to contribute to the funding of the Project

► Government may consider funding a proportion of the capital costs through providing an upfront grant to the Project delivery company. We expect that this would reduce the Regulated Asset Base (RAB) that the regulated return would be based upon and mean that taxpayers rather than electricity consumers bear part of the cost.

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► A cap and floor model, similar to what has been implemented by Ofgem in the UK could also provide incentives for efficiency.

► Further investigation would need to be undertaken into variants of regulation that could meet these objectives.

Finding 6: While revenue modelling indicates that a fully merchant MNSP model has the potential to be feasible, the risk premium for the transfer of revenue risk is unlikely to be considered feasible by the financing market

► Indicative modelling of MNSP revenues show considerably higher net present values than its regulated counterparts, over the project life for 2IC.

► MNSP models with a high degree of revenue risk expose asset owners to significant volatility in forecast revenue. For an interconnector which captures benefits from the price differential between Tasmania and Victoria, this revenue is expected to be challenging for financiers to forecast and ultimately raise debt against.

► The cost of equity finance for a fully unregulated link likely to be high (15-20+%) given high volatility of cash flows.

► Currently Basslink is the only MNSP in Australia. DirectLink and MurrayLink interconnectors were constructed as MNSPs with merchant revenue exposure, but subsequently applied to the AER to receive regulated status as ‘competing’ regulated interconnects were built or expanded.

► Market sounding of financiers and energy asset owners confirms this finding.

Finding 7: The introduction of 2IC may impact the commercial viability of Basslink, which may require the asset owners to consider their options in relation to the commercial model and ownership structure

The EY electricity market modelling report indicates that Basslink is forecast to be impacted with the introduction of 2IC. The reduced profitability of Basslink may result in the asset owners:

► Considering applying to the AER for regulated asset status

► Considering a sales process for the asset

► Seeking to renegotiate terms with HydroTas

► If it is assumed that Government does not have any levers to compel Basslink to become regulated or modify its commercial model, this would represent a key risk to the delivery of 2IC.

Finding 8: A single owner for 2IC and Basslink is preferred on balance, unless both assets are regulated

► Under the MNSP model a single owner is likely to be the only viable model. This is also likely to be true if only one asset is regulated unless other constraints are imposed

► Separate asset owners is only likely to be viable if both assets are regulated

Finding 9: An initial assessment indicates limited ability for a MNSP to capture revenue benefits other than the difference in pool prices

► There is currently limited scope for third party revenues from other renewable energy generators.

► Whilst there are strong wind sites in Tasmania which may result in differences in capacity factors between new Tasmanian wind farms (when compared to the marginal project in Victoria), the additional transmission costs associated with paying to reserve

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capacity to supply power to the mainland (e.g. under a Power Purchase Agreement) is unlikely to make these projects feasible.

Finding 10: Procurement model analysis indicate a contestable regulated model (applied for projects with significant capital costs) would enable competitive bids for construction, operations and ownership of the asset

► The regulated asset model is market tested, and competitive for transmission assets.

► It could be expected to deliver the Project at a low cost of capital.

► We understand that only 3 HVDC suppliers are capable to meet the technical specifications globally, which may impact the competitiveness of the procurement.

► The existing DNSP arrangements in Tasmania and Victoria would be expected to continue for the procurement of requirement network connection infrastructure for new generation and connection to the existing grid.

Finding 11: Where a MNSP with a capacity charge is preferred, a Build Own Operate Transfer (“BOOT”) delivery model represents a viable delivery model

► BOOT transfers majority of construction, maintenance, operations and ownership to the private sector.

► Bidders would compete on what their minimum availability charge is to deliver and operate the asset over the project life.

► Maintains strong incentives for the asset owner to ensure the asset is available and maintain and maintain and operate the asset to reduce transmission losses.

1.3 Relationship to the EY Market Dispatch Cost Benefit Modelling

EY have been engaged to undertake market modelling (“Market cost benefit modelling of a second Bass Strait interconnector – 22nd December 2016”) and to provide commercial and financial analysis in respect of the second interconnector.

This Report provides commercial and financial insights in respect to the assessment of commercial operating models for the second interconnector, ranging from fully regulated to fully merchant options. This Report considers these alternative options in our analysis to form a view on the ability of the private sector to fund the second interconnector under a range of commercial models, not limited to regulated or MNSP only cases.

The market modelling report (“Market cost benefit modelling of a second Bass Strait interconnector Report – 22nd December 2016”) presents the market modelling outcomes of the merits of a second interconnector under fully regulated and MNSP cases only. This report (“Commercial and Financial Analysis – Second Tasmanian Interconnector – 22nd December 2016”), takes the outcomes and data from the market modelling MNSP case only and applies the data in alternative ways in order to consider the range of commercial operating models that may deliver a second interconnector (please see Section 3 for greater detail).

The market modelling under the regulated asset case examine the merits of a second interconnector largely by examining the NEM wide market benefits it would provide (such as lower production costs or deferred capital costs). The modelling conducted as part of the “Market cost benefit modelling of a second Bass Strait interconnector Report – 22nd December 2016” is intended to consider the potential for the second interconnector to be classified as a regulated asset by meeting the requirements of the Regulatory Investment Test for Transmission (RIT-T).

For the MNSP option, the electricity market modelling report considers the market revenues that might be expected to flow to the owner of the second interconnector, and also the financial

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impact on other relevant parties in Tasmania: Basslink, Hydro Tasmania and energy consumers in Tasmania. The impact of a second interconnector on these parties is heavily dependent on the arbitrage opportunities to be exploited and the operating behaviour of the second interconnector. Although market benefits may result from the operation of the MNSP, these benefits do not form the basis of the viability of the asset, as the second interconnector asset owner is unable to capture these benefits as project revenues. Rather, the viability of the MNSP is formed by an expectation of revenues derived from arbitrage benefits between Tasmania and Victoria with appropriate consideration of the range of market and regulatory risks associated with the asset. The choice of whether one is superior to the other is a function of a broader view about the risks associated with wholesale market exposure and the viability of having competition in the provision of interconnectors. This Report does not consider the financial impact of the range of operating models explored on other market participants such as Hydro Tasmania (HydroTas) and Tasmanian electricity consumers. This Report uses the same underlying data as the market modelling for the MNSP cases. The financial modelling however examines the merits of a second interconnector separately from any market benefits, and as such attempts to determine the private benefits it would provide (i.e. those that can be captured by and accrue to the owner of the asset). Under the regulated model, those private benefits are largely divorced from the operation of the asset and the market benefits it delivers because private benefits flow indirectly through the regulated returns as determined by the Australian Energy Regulator. Under the pure merchant model, however, those private benefits are largely a function of the owner’s ability to exploit arbitrage, and are therefore largely dependent on wholesale market conditions. Furthermore, the private benefits depend on the extent to which to the owner of the second interconnector can capture these when there is another interconnector (and associated commercial arrangements) that influence the extent to which this possible.

The operating assumptions of Basslink and the second interconnector in the MNSP Base case provided as part of the Market Modelling (see “Market cost benefit modelling of a second Bass Strait interconnector Report – 22nd December 2016”) is similar to the operating assumptions of the two interconnectors in the commercial and financial analysis Base Case 1 scenario. Alternative operating models such as converting Basslink to a regulated interconnector while operating the second interconnector as an MNSP have not been modelled in the market modelling. This Report considers these alternative options in our analysis to form a view on the ability of the private sector to fund the second interconnector under a range of commercial models, not limited to regulated or MNSP only cases. Simplifying assumptions were made to illustrate the potential financial impacts and ability of the private sector to fund the second interconnector for the range of commercial models. Where these commercial model alternatives are worthy of further investigation, additional electricity market modelling of these alternatives at the next phase of project development is suggested.

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2. Background

2.1 Overview In April 2016, the Australian and Tasmanian governments established a joint feasibility study (the Study) into whether a second Tasmanian interconnector could improve Tasmania’s energy security and facilitate renewable energy investment. The Study is investigating the benefits of a second high voltage direct current (HVDC) interconnector (the Project, 2IC), construction of which would increase transfer capacity of electricity between Tasmania and Victoria.

2.2 Basslink Basslink is the incumbent Tasmania to Victoria high-voltage transmission line (interconnector) that operates between George Town in Tasmania and Loy Yang in the Latrobe Valley area in Victoria. It was commissioned in early 2006 after Tasmania joined the NEM. It is owned by the publicly listed Keppel Infrastructure Trust (SGX: A7RU), and is the only unregulated interconnector in the NEM. Basslink is the world’s second longest subsea electricity interconnector, with a nominal capacity to export 594 MW from Tasmania to Victoria, and import 478 MW. It cost $874 million.

When the development of Basslink was endorsed by the then Labor Government in 1998, they set out several goals and strategic objectives for the construction of the interconnector including:

► Improve the security of electricity supply and reduce the exposure to drought conditions in Tasmania;

► Provide Tasmania with access to electricity prices determined competitively in the NEM; and

► Provide a means by which electricity generated in Tasmania can be sold into the NEM and provide a new source of peak generating capacity in the NEM.

Basslink generates revenue in a similar way to generators in the NEM; by bidding into the spot market its capacity to deliver energy, with the returns determined by the price difference and the energy flows between Victoria and Tasmania. In 2002, HydroTas signed the Basslink Services Agreement (BSA), in effect agreeing to lease the cable over 25 years and pay a facility fee. The BSA is for an operational period of 25 years, with an option to extend the term for a further 15 years.

The BSA allows the owners of Basslink to swap that market-based revenue for an agreed fixed facility fee, plus performance-related payments. The agreement also gives HydroTas the rights to control the way in which Basslink bids its interconnector capacity, either flowing in or flowing out of Tasmania. Graph 1 is indicative of how Basslink is supported by the availability payment vs. the potential return that could be generated through pricing differential.

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Graph 1: Basslink Revenue Stream

2.3 Scope of Work The report that follows cover four (4) main topic areas to assist in making a determination on the preferred commercial operating model(s) and procurement model(s) that could best support delivery of the Project. The four (4) areas of focus are as follows:

► Assess the range of Revenue/ Business Models via a qualitative assessment and consideration based on the operating models already in existence in the electricity markets (Regulated, Non-Regulated, and/ or combinations of both)

► Run a series financial analyses on each of the model(s) determined above o Assess the financial viability of each model(s)

► Determine the range of delivery models available o Assess the suitability of each model(s) to deliver a second interconnector

► Validate findings through market soundings.

The report is intended to be utilised in the financial and commercial sections of the final feasibility Study report being prepared by the Tasmanian Energy Taskforce.

The Report uses the price forecasts for MNSPs from the EY electricity market modelling in this report to inform the quantum of arbitrage benefits may be able to capture by the asset owner of 2IC.

2.4 Approach to Assessment The report follows the four (4) steps that are outlined below in Figure 1. It follows a structured process on each of the three (3) key work streams to enable Step 4 (listed below) to occur. This approach is based upon Infrastructure Australia’s National Infrastructure Procurement Guidelines.

Figure 1: 4 Steps to determine the Procurement Model.

0

50

100

150

200

250

20162018202020222024202620282030203220342036203820402042204420462048205020522054205620582060206220642066

$ milli

ons

BassLink BassLink MNSP revenues

STEP 1: Data Gathering

STEP 2: Operational

Model Analysis

STEP 4: Validation

STEP 3: Delivery Model

Analysis

Objectives Risks Unique project

Characteristics Agency & Market

capability

Consider the suitability of Regulated Models MNSP Models Hybrid Models

What precedent exists for the project?

What does the market think?

Which model best achieves the requirements and objectives whilst reducing risk?

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The focus of each of the four steps of our approach are discussed below in greater detail.

The Report considers:

► Commercial operating models (e.g. Fully regulated, partly regulated, fully market and partly market exposed) “the Commercial Operating Models”

► Procurement models (e.g. Design & Construct, Build Own Operate Maintain, State build then transfer to private sector upon operations). These procurement models also include a range of private and public sector funding options “the Procurement Models”

► Underlying operational scenarios which will draw on the market modelling work stream (e.g. growth in Tasmanian wind energy generation, Victorian coal fired generator retirement), and which may materially impact on the revenue profile of the asset, particularly over the longer term.

The report enabled each of these combinations (Figure 2) to be assessed against the revenue scenarios from the EY electricity market modelling report in a bespoke financial model, in order to generate a range of quantitative outcomes that inform the financial and commercial outcomes.

Figure 2: Procurement Models and Commercial Models combinations that are possible outcomes for the Project.

2.5 Structure of this report This report is structured as follows:

► Section 3: undertakes the qualitative and quantitative analysis of the commercial operating models considered in this Report

► Section 4: undertakes a qualitative analysis of the delivery model and ownership options available

► Section 5: validates the preliminary findings of sections 3 & 4, summarising the key findings of the market sounding exercise and outlines case studies for the delivery of interconnectors

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3. Commercial Analysis

3.1 Overview of Commercial Model analysis This section:

► Identifies a range commercial models available to the Project ► Undertakes a qualitative assessment of the potential feasibility of these options. Under

each option, the commercial structure that may make each option feasible from a financing perspective is undertaken taking into consideration keys risks, and revenue

► Undertakes a series of qualitative financial analyses on each of the identified commercial models in order to create a holistic overview of the options available to government to pursue the development of a second interconnector

► Assumes that Basslink and 2IC are able to meet the RIT-T.

3.1.1 Commercial Model Options Table 2 summarises the key features of commercial models under which the two interconnectors could potentially operate and variation between them. These commercial models are assessed against a fixed criteria that will help to determine the most appropriate operating model.

Table 2: Commercial Model Variations

Commercial Model Key Features Base Case – 1. ► Basslink – MNSP

► 2IC - MNSP

► Basslink operates as a pure MNSP (no availability charge is earnt)

► 2IC enters the market as an MNSP asset ► Unless there is a single owner for both interconnectors

would compete for flow to ensure efficient use of the assets Base Case – 2. ► Basslink – MNSP

► 2IC - MNSP

► Basslink remains a MNSP whilst earning an availability charge (mimics current operations)

► 2IC enters the market as an MNSP ► Commercial restrictions in the Basslink Services Agreement

between HydroTas and Basslink Pty Ltd (BPL) limit 2IC operating as overflow cable only (only utilised when Basslink is at capacity)

Alternative Case 1. ► Basslink – MNSP


► Basslink remains MNSP (with availability charge) ► 2IC meets RIT-T to become a regulated asset ► 2ICs’ regulated revenue determined by Regulator

Alternative Case 2. ► Basslink – Regulated

► 2IC – MNSP

► Basslink becomes a regulated asset with regulated revenues

► 2IC to operate a MNSP

Alternative Case 3. ► Basslink – Regulated

► IC – Regulated

► Basslink becomes a regulated asset with regulated revenues

► 2IC regulated, revenue determined by Regulator

Hybrid Case 1. ► Basslink – Partially

Unregulated

► IC – Partially Unregulated

► Both Interconnectors are partially unregulated (MNSP), with an availability charge

► Government provides partial upfront grant, lowering capital costs and therefore ongoing impact on consumers.

Hybrid Case 2. ► Basslink – Partially Regulated

► 2IC – Partially Regulated

► Both Interconnectors are partially regulated ► Both Interconnectors are supported by a partial

transmission charge (Floor) ► Both Interconnectors earn 25% of the arbitrage revenues

13

3.1.2 Qualitative Criteria Table 3 includes the six main assessment criteria that have been used to assess the various business models listed in Table 2. It includes a summary explanation of its importance and the critical issues that need to be addressed.

Table 3: Assessment Criteria

Criteria Explanation Importance Rationale for weighting Operational

Risk Transfer

Which business model provides the greatest level of effective risk transfer of second interconnector?

High

The ability to appropriately manage and transfer risk to the private sector is a key differentiator between the models.

It is of high importance due to demand and price risks of the asset, and technology and construction risk of delivering an undersea cable

Operational Utilisation/ Incentives

Which business model(s) encourage the greatest level of interconnector utilisation/ operational efficiency?

Medium

The ability to ensure a high level of utilisation/ encourage the efficient use of the interconnector is deemed as medium importance.

Energy Security

Do any of the potential business models improve or hinder the energy security benefits that an additional interconnector could provide?

Medium

An operational second interconnector is important factor in ensuring energy security for Tasmania and therefore has a medium rating. With dual interconnectors potentially available should 2IC be developed, it has slightly lower importance than if it was a stand alone connection.

Financial

Financing Costs

Which business model offers the lowest financing costs? Low

The cost of financing in relation to other criterion is of less importance than the ability to actually secure funding.

Suitability for Funding

Which business model is bankable? Medium

The ability for the commercial model to be bankable is of medium importance in a high level assessment. The models need to be able to support debt funding in the absence of investor appetite for pure market risk.

Market Appetite

Is there market appetite for the business model? High

The commercial model selection will ultimately determine both the type of investor and appetite for the asset in the long run. In the absence of full government funding, this is a critical criteria which justifies its high rating.

14

A short overview of the assessment scoring can be seen below.

Assessment Scoring:

To facilitate the qualitative assessment of the options against each criterion, the following rating system was adopted:

Table 4 – Options Assessment Scoring

Each score and rank is then be weighted by multiplying the ‘Assessment Score’ by the ‘Importance’ rating. The importance rating attracts the following weightings: High = 3, Medium = 2 and Low = 1.

The assessment criterion above was selected and weightings agreed in conjunction with the Department. The assessment criteria are representative of the key considerations that need to be addressed when assessing the benefits and risks of possible commercial and delivery models.

Throughout the financial analysis and market sounding process, the calculations and feedback tended to ultimately focus on which model would provide the most bankable revenue profile, whilst still providing an avenue to attract the required level of funding to deliver the 2IC.

3.2 Qualitative and Quantitative Analysis 3.2.1 Quantitative Assumptions and financial modelling approach EY developed a cashflow model to enable the quantitative assessment of the commercial models. In the first instance, for the MNSP models the projected electricity flow profiles (provided as part of the Market Dispatch Cost Benefit Modelling), are utilised to determine a revenue profile for each of the MNSP models. Secondly, the capital costs and ongoing operating costs then flow through the financial model to calculate the likely profitability and free cash flows. This enables a determination of the value of the 2IC generated cash flows has to potential investors. Thirdly, the cash flows are then assessed against some high level project financing criteria (internally generated internal rates of return, debt service coverage ratios, positive Net Present Values) in order to quantify the ability of each MNSP model to attract or sustain investment.

In regards to the regulated models, we have modelled a high level regulated asset financial model structure to calculate the future cost impacts. The regulated models are not reliant upon market generated revenues for their viability, therefore the financial model considers the costs of delivering the project (capital costs, ongoing operating costs, required investment returns) to calculate the ongoing annual payment that would be required to sustain the 2IC. These are the quasi cash flows the project could theoretically generate under a regulated environment, which have value to investors, and in a similar manner to the MNSP models, are then assessed against the high level project financing criteria (internally generated internal rates of return, debt service coverage ratios, positive Net Present Values) to determine their attractiveness to investors.

Rating Number Description 3 Option is extremely effective in satisfying the requirements of the

criterion. 2 Option is effective in satisfying the requirements of the criterion. 1 Option just satisfies the requirements of the criterion. 0 Option is ineffective in satisfying the requirements of the criterion. -1 Option is extremely ineffective in satisfying the requirements of the

criterion.

15

Table 5 contains the operating assumptions that were used within the quantitative analysis.5

Please note, the report is not assessing the suitability of these assumptions as they have been either provided by third parties (Tasmanian Energy Taskforce) or are indicative of typical market financing terms that EY, in its experience, deem suitable for this type of analysis. All assumptions should not be relied upon outside of this report and would need to be independently verified in a competitive process. EY takes no responsibility to the accuracy of these figures.

Financial revenue and cost outcomes in the Report are in 2016 dollars unless otherwise labelled.

Table 5: Assessment Criteria

Assumption Input

2IC Capital Cost A$930 million (June 2015 $)

2IC Operating Costs A$16.7 million annually (June 2015 $)

2IC Construction Period 6 Years beginning 2020

2IC Operational State Date 2026

Inflation (CPI) 2.0% p.a.

Cost of Equity Funding 15.0% p.a. (post tax nominal)

Cost of Debt Funding 5.03% p.a. (post tax nominal)

Capital Structure (Gearing) 75% debt ; 25% equity

Loan Term 20 Years

Debt Service Coverage Ratio (“DSCR Target”) >1.5x

Discounting base date The net present values are discounted back to 2016 terms.6

Discount rates Two scenarios are presented: 7% nominal and 10% nominal discount rates7

Source: Tasmanian Energy Taskforce, EY assumptions.

5 It should be noted that the same cost of capital assumptions are used for all commercial models. This is a major simplifying assumption (given they entail different risks) but ensures consistency with the market modelling. The implications of weakening that assumption is discussed when presenting the results. 6 The electricity market modelling report discounts its real prices forecasts to 2026/27 terms 7 The electricity market modelling report applies 7% and 10% real discount rates to real cashflows, where this Report converts revenues and cost to nominal terms, and applies nominal discount rates

16

3.2.

2 Q

ualit

ativ

e Su

mm

ary

Ta

ble

6 sh

ows

that

the

resu

lts o

f the

qua

litat

ive

com

mer

cial

mod

els

asse

ssm

ent.

The

MN

SP s

cena

rio

(Bas

e Ca

se 1

) gen

erat

es th

e gr

eate

st r

isk

tran

sfer

and

ut

iliza

tion,

thou

gh th

is c

omes

at t

he e

xpen

se o

f fun

ding

sui

tabi

lity,

whe

reas

the

dual

reg

ulat

ed s

cena

rio

(Alt

erna

tive

Cas

e 3)

off

ers

the

grea

test

sui

tabi

lity

for

fund

ing,

thou

gh th

is c

omes

at t

he e

xpen

se o

f ris

k tr

ansf

er a

nd u

tilis

atio

n of

the

seco

nd in

terc

onne

ctor

.

Tabl

e 6:

Qua

litat

ive

Scor

e Su

mm

ary

Cri

teri

a Im

port

ance

B

ase

Cas

e 189

B

ase

Cas

e 2

Alt

. Cas

e 1

Alt

. Cas

e 2

Alt

. Cas

e 3

Hyb

rid

Cas

e 1

Hyb

rid

Cas

e 2

Bot

h M

NSP

’s

Bot

h M

NSP

’s –

C

omm

erci

al

Res

tric

tion

s on

2I

C

Bas

slin

k M

NSP

, 2I

C R

egul

ated

Bas

slin

k R

egul

ated

, 2IC

M

NSP

B

oth

Reg

ulat

ed

Par

tial

ly M

NSP

P

arti

ally

R

egul

ated

Ris

k Tr

ansf

er

Hig

h

Ope

ratio

nal

Util

isat

ion

Med

ium

Ener

gy S

ecur

ity

Med

ium

Suita

bilit

y fo

r Fu

ndin

g

Low

Fina

ncin

g Co

sts

Med

ium

Mar

ket A

ppet

ite

Hig

h

Scor

e 10

8

12

7 12

8

14

Wei

ghte

d Sc

ore

23

19

24

24

24

16

29

The

Hyb

rid

Case

2 m

odel

ran

ks h

ighe

st a

s it

take

s th

e be

st p

arts

of t

he r

egul

ated

mod

el (a

min

imum

tran

smis

sion

cha

rge

to s

uppo

rt fu

ndin

g), w

hils

t tr

ansf

erri

ng s

ome

MN

SP r

even

ue r

isk

expo

sure

to in

cent

ivis

e as

set u

tilis

atio

n an

d en

able

hig

her

inve

stor

ret

urns

. The

abi

lity

of th

is m

odel

to g

ener

ate

furt

her

retu

rns

(ove

r an

d ab

ove

the

tran

smis

sion

cha

rge)

pro

vide

s an

add

ition

al b

enef

it of

ince

ntiv

isin

g as

set o

wne

rs to

ens

ure

the

link

is u

tilis

ed, a

s th

ey a

re a

ble

to

shar

e a

port

ion

of th

e ar

bitr

age

reve

nues

that

they

oth

erw

ise

wou

ldn’

t in

a tr

aditi

onal

reg

ulat

ed m

odel

.

8 In

the

mar

ket m

odel

ling

repo

rt, t

his

is k

now

n as

the

“MN

SP B

ase

Case

” 9 In

the

mar

ket m

odel

ling

repo

rt, t

his

is s

imila

r to

the

oper

atio

nal a

ssum

ptio

ns o

f MN

SP B

ase

Case

. Im

port

antly

, the

mar

ket m

odel

ling

assu

mes

that

bot

h in

terc

onne

ctor

s ac

t co-

oper

ativ

ely

such

that

th

e bi

ddin

g of

the

two

inte

rcon

nect

ors

max

imiz

es th

e to

tal r

even

ue o

f the

inte

rcon

nect

ors.

How

ever

, fro

m a

com

mer

cial

per

spec

tive,

this

wou

ld o

nly

be th

e ca

se w

here

the

inte

rcon

nect

or is

ow

ned

by

the

sam

e ow

ner.

Fur

ther

, thi

s R

epor

t doe

s no

t inc

lude

con

side

ratio

n an

y of

the

mar

ket b

enef

its, a

s th

ese

are

unab

le to

be

capt

ured

by

the

asse

t ow

ner

to g

ener

ate

com

mer

cial

ret

urns

. Se

e Se

ctio

n 1.

3 fo

r di

scus

sion

of t

he r

elat

ions

hip

to th

e m

arke

t mod

ellin

g

17

3.2.

3 Q

uant

itat

ive

Sum

mar

y –

40 Y

ears

Ta

ble

7 be

low

hig

hlig

hts

both

the

prof

itabi

lity

of e

ach

com

mer

cial

mod

el o

ver

40 y

ears

. It i

s im

port

ant t

o no

te th

at th

e m

odel

led

outc

omes

are

bas

ed u

pon

hypo

thet

ical

mar

ket s

cena

rios

that

wer

e pr

oduc

ed b

y th

e EY

ele

ctri

city

mar

ket m

odel

ling

team

on

beha

lf of

the

Tasm

ania

n Ta

skfo

rce.

T

able

7: M

odel

led

Scen

ario

Sum

mar

y –

40 y

ears

Th

e ne

t pre

sent

val

ues

are

disc

ount

ed t

o 20

16 te

rms

usin

g no

min

al p

ost t

ax d

isco

unt r

ates

of 7

% an

d 10

% re

spec

tive

ly. N

ote

that

for

Base

Cas

e 1,

the

NPV

of I

nter

conn

ecto

r R

even

ues

are

diff

eren

t to

MN

SP B

ase

Case

1 in

th

e el

ectr

icity

mar

ket m

odel

ing

due

to d

iffer

ent d

isco

unt r

ate

assu

mpt

ions

as

set o

ut in

Tab

le 4

. The

diff

eren

ces

in a

ssum

ptio

ns a

re a

ppro

pria

te a

s th

e di

scou

ntin

g is

und

erta

ken

for

diff

eren

t pur

pose

s, a

nd v

aria

nces

hav

e be

en r

econ

cile

d.

Inve

stor

Sui

tabi

lity

Sum

mar

y

Scen

ario

(NP

V 2

016

term

s)

Bas

e C

ase

1 B

ase

Cas

e 2

Alt

erna

tive

Cas

e 1

Alt

erna

tive

Cas

e 2

Alt

erna

tive

Cas

e 3

Hyb

rid

Cas

e 1

Hyb

rid

Cas

e 2

Des

crip

tion

B

oth

MN

SP’s

Bot

h M

NSP

’s –

C

omm

erci

al

Res

tric

tion

s on

2I

C

Bas

slin

k M

NSP

, 2I

C R

egul

ated

Bas

slin

k R

egul

ated

, 2IC

M

NSP

B

oth

Reg

ulat

ed

Par

tial

ly M

NSP

P

arti

ally

R

egul

ated

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

7%

($m

) – 2

IC

1,66

2 59

8 1,

152

1,66

2 1,

152

662

1,31

4

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

7%

($m

) – B

assl

ink

598

1,01

3 1,

013

791

791

- -

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

10%

($m

) – 2

IC

827

304

619

827

619

353

695

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

10%

($m

) – B

assl

ink

304

515

515

407

407

- -

Proj

ect I

RR

12.7

% 3.

9%

9.9%

12

.7%

9.9%

9.

9%

11.2

%

Equi

ty IR

R 18

.2%

1.7%

15

.0%

18.2

% 15

.0%

15.0

% 18

.1%

Cash

flow

suf

ficie

nt to

sup

port

deb

t re

paym

ents

Y

es

No

Yes

Y

es

Yes

Y

es

Yes

2IC

finan

ceab

le

No

No

Yes

N

o Y

es

No

Yes

Not

es

Mar

ket r

even

ues

are

seen

as

“ris

ky”

and

unlik

ely

to b

e ab

le to

be

fully

tr

ansf

erre

d to

the

priv

ate

sect

or. W

ill

be d

iffic

ult t

o fin

ance

as

pure

M

NSP

with

out

pric

e su

ppor

t.

Sim

ilar

to B

ase

Case

1, M

NSP

ba

sed

reve

nues

ar

e un

likel

y to

at

trac

t fun

ding

due

to

the

risk

ines

s of

ca

sh fl

ows.

Poo

r ut

ilisa

tion

of 2

IC,

and

cons

eque

ntia

l lo

w r

etur

ns.

As

2IC

wou

ld h

ave

the

bene

fit o

f re

gula

ted

reve

nues

, will

in

crea

se th

e lik

elih

ood

of

attr

actin

g fu

ndin

g to

del

iver

the

proj

ect a

t a lo

w

cost

of c

apita

l.

Sim

ilar

to B

ase

Case

1, M

NSP

ba

sed

reve

nues

ar

e un

likel

y to

at

trac

t rea

sona

ble

fund

ing

leve

ls d

ue

to th

e ri

skin

ess

of

cash

flow

s.

As

2IC

wou

ld h

ave

the

bene

fit o

f re

gula

ted

reve

nues

, will

in

crea

se th

e lik

elih

ood

of

attr

actin

g fu

ndin

g to

del

iver

the

proj

ect a

t a lo

w

cost

of c

apita

l

Sim

ilar

to B

ase

Case

1, M

NSP

ba

sed

reve

nues

ar

e un

likel

y to

at

trac

t rea

sona

ble

fund

ing

due

to th

e ri

skin

ess

of c

ash

flow

s.

As

2IC

wou

ld h

ave

the

bene

fit o

f re

gula

ted,

or

min

imum

cas

h flo

w

paym

ents

, will

in

crea

se th

e lik

elih

ood

of

attr

actin

g fu

ndin

g to

del

iver

the

proj

ect

18

3.2.

4 Q

uant

itat

ive

Out

puts

Sum

mar

y –

50 Y

ears

Ta

ble

8 co

ntai

ns th

e sa

me

scen

ario

s an

d ou

tput

s as

the

sum

mar

y ta

ble

abov

e, w

ith a

djus

tmen

ts m

ade

to c

onsi

der

the

outp

uts

over

a 5

0 ye

ar o

pera

tiona

l pe

riod

.

Tabl

e 8:

Mod

elle

d Sc

enar

io S

umm

ary

– 50

Yea

r

Inve

stor

Sui

tabi

lity

Sum

mar

y

Scen

ario

B

ase

Cas

e 1

Bas

e C

ase

2 A

lter

nati

ve C

ase

1 A

lter

nati

ve C

ase

2 A

lter

nati

ve C

ase

3 H

ybri

d C

ase

1 H

ybri

d C

ase

2

Des

crip

tion

B

oth

MN

SP’s

Bot

h M

NSP

’s –

C

omm

erci

al

Res

tric

tion

s on

2I

C

Bas

slin

k M

NSP

, 2I

C R

egul

ated

Bas

slin

k R

egul

ated

, 2IC

M

NSP

B

oth

Reg

ulat

ed

Par

tial

ly M

NSP

P

arti

ally

R

egul

ated

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

7%

($m

) – 2

IC

1,74

5 61

6 1,

211

1,74

5 1,

211

697

1,38

0

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

7%

($m

) – B

assl

ink

616

1,07

3 1,

073

843

843

- -

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

10

($m

) – 2

IC**

84

5 30

8 63

5 84

5 63

5 36

3 71

2

NPV

(201

6) o

f Int

erco

nnec

tor

Rev

enue

s @

10

($m

) – B

assl

ink

308

528

528

418

418

- -

Proj

ect I

RR

12.7

% 4.

0%

10.0

% 12

.7%

10.0

% 10

.0%

11.3

%

Equi

ty IR

R 18

.0%

2.1%

15

.0%

18.0

% 15

.0%

15.0

% 18

.1%

Cash

flow

suf

ficie

nt to

sup

port

deb

t re

paym

ents

Y

es

No

Yes

Y

es

Yes

Y

es

Yes

2IC

fina

ncea

ble

No

No

Yes

N

o Y

es

No

Yes

Not

es

Mar

ket

Rev

enue

s ar

e se

en a

s “r

isky

” an

d un

likel

y to

be

abl

e to

be

fully

tr

ansf

erre

d to

th

e pr

ivat

e se

ctor

. Will

be

diff

icul

t to

finan

ce a

s pu

re

MN

SP w

ithou

t pr

ice

supp

ort.

Sim

ilar

to B

ase

Case

1, M

NSP

ba

sed

reve

nues

are

un

likel

y to

att

ract

fu

ndin

g du

e to

the

risk

ines

s of

cas

h flo

ws.

Poo

r ut

ilisa

tion

of 2

IC,

and

cons

eque

ntia

l lo

w r

etur

ns

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3.3 Detailed results – Base Case 3.3.1 Base Case 1 – Both MNSP’s - Qualitative To consider Base Case 1 from a qualitative perspective, the operating assumptions for each commercial model is compared against the criteria, to provide the key takeaways provided in Table 9. Table 9: Key Takeaways – Base Case 1

Criteria Key Takeaway Rating

Risk Transfer ► MNSP assets provide the greatest transfer of risk from

the interconnectors, particularly for demand and price risks.

Operational Utilisation

► Both interconnectors will be encouraged to operate at the highest level of utilisation as they are directly competing against each other for energy flows, unless they are operated by the same asset owner.

Energy Security

► Whilst dual interconnectors offer greater energy security, this is offset by the potential impacts on viability as both interconnects compete for flow, forcing down profitability and sustainability.

Suitability of Funding

► With limited capability to accurately forecast future wholesale energy prices there is no guarantee that the price differential will be great enough to profit from the arbitrage and underpin revenues that support funding.

Financing Costs

► As financing is so heavily reliant upon arbitrage which will be an unreliable cash flow, financiers will see this commercial model as presenting them with the highest levels of risk and therefore pricing will represent the riskiness of the investment.

Market Appetite ► Without reliable market data, revenue remains

relatively uncertain which will impact investor confidence and finance ability.

In Base Case 1 both interconnectors operate as MNSP’s (no availability charges or other forms of revenue support) that are attempting to profit from any price differential that may exist on either side of the interconnector in order to generate their revenue. This model encourages the high utilisation of the interconnectors (as flow equals the potential ability to generate returns) though reliability of funding needs to be addressed. The financeability of this commercial model is the key limitation. As MNSP generated revenues are forecast to be highly volatile and reliant upon the electricity generator (HydroTas) to help ensure there are price differentials to take advantage of, this model is expected to struggle to attract reasonable levels of funding and is not regarded as a viable commercial model. The revenue impact and uncertainty of MNSP operating models is illustrated in sensitivity analysis of the second interconnector revenues when the mainland market is oversupplied. The electricity market modelling report (section 6.2.2) estimates that revenue falls by approximately 40% in an oversupplied market compared to MNSP Base Case 1. This outcome has a material impact on commercial viability.

20

3.3.2 Base Case 1 – Quantitative Analysis Graph 2 below shows annual revenue for 2IC and Basslink, with the 2IC being a newly designed interconnector, in a market environment where 2IC competes against Basslink for energy flows. Due to the lower loss factors of 2IC, 2IC would garner a significant portion of the potential revenue that could be earned through arbitrage, which is consistent with the qualitative assessment.

Graph 2: Revenue scenarios under Base Case 1 – MNSP’s

3.3.3 Key Modelling Results Table 10 below shows that based upon the assumptions used in the modelling, that the outcomes generated are indicative of a project with strong financial metrics. The NPV’s are high, the Project and Equity IRR’s are also high. When considering the figures in isolation, it would seemingly support a high gearing ratio (Debt to Equity), all of which are attractive to investors.

Table 10: Financial modelling results for the MNSP Commercial Model

Whilst this commercial model seemingly provides all the required outcomes of a fundable project, when overlaid with the issues raised in the qualitative assessment, namely, the unreliability of market generated cash flows, along with the encouraged interconnector competition, this model is actually unlikely to be fundable, nor desirable by energy infrastructure investors. This is further evidenced by the fact that no true MNSP interconnectors are in operation in Australia.

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Base Case 1 – Dual MNSP

Scenario Outputs

40y operations 50y operations

MNSP NPV (2016) @7% ($m)

2IC 1,662 1,745

Basslink 598 616

MNSP NPV (2016) @10% ($m)

2IC 827 845

Basslink 304 308

Other 2IC financial metrics

Project IRR 12.7% 12.7%

Equity IRR 18.2% 18.0%

Debt Fundable Yes Yes

Financeable No No

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We note the market modelling assumes that both interconnectors act co-operatively such that the bidding of the two interconnectors maximizes the total revenue of the interconnectors. However, from a commercial perspective, this would only be the case where the interconnector is owned by the same owner. The financial outcomes above reflect MNSP outcomes where both assets are owned by single party. We note that electricity market modelling suggests if Hydro Tasmania was the owner of its current assets and the two interconnectors and bid to maximize its total wholesale revenue, in most trading intervals it would derive maximum benefit from being able to export energy (i.e. bidding close to zero).

3.3.4 Base Case 2 – Both MNSP’s – Commercial Restrictions on 2IC -Quantitative Base Case 2 varies slightly operationally from Base Case 1 in one key area, specifically, putting a constraint on the second interconnector’s ability to access energy flows. This model is assumed to have a commercial restriction in place in the Basslink BSA that ensures Basslink receives a majority of flow from HydroTas, with the second interconnector operating as a pure MNSP.

Table 11: Key Takeaways – Base Case 2


Risk Transfer

► MNSP assets provide the greatest transfer of risk from the interconnectors, particularly for demand and price risks.

► Ongoing support and partial risk transfer to underwrite the revenues required to service any form of financing.


► 2IC will operate essentially as an overflow cable only as it’s no longer in competition for the initial 500MW which is the capped capacity of Basslink in this modelling.

Energy Security

► Model restricts the capability of 2IC to support itself if overflows are limited which could negatively impact energy security, as its viability is critical to keeping the asset operational.

Suitability of Funding ► Funding will be difficult to secure unless guarantees for a

minimum flow level is achieved which could support funding.

Financing Costs ► Expect financing costs (if funding can be supported) to be

expensive if no availability payment is made.

Market Appetite

► Guarantees would need to be provided at least for “minimum” flow access to ensure some level of revenue can be generated if the intent is to encourage non-government funding sources.

► In order for this model to be viable, HydroTas would need to have greater capacity to operate the interconnector (as a participating owner).

► Alternatively HydroTas would need to enter into offtake contracts with the interconnector owner to ensure they have consistent access to electricity flows at discounts to the prevailing market prices in order to generate revenues.

►

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In a similar outcome to Base Case 1, all the scores with the exception of Risk Transfer are low. In a commercial model that is unable to provide some certainty of revenues or support for flows through the 2IC, this model is unlikely to attract sufficient funding from investors to meet capital repayments. Any form of commercial restriction on 2IC from accessing a fair amount of flow from HydroTas significantly impacts its profitability. This model also limits the efficient use of 2IC (as there is no incentive for Basslink to change its operating efficiencies to better utilize 2IC).

3.3.5 Base Case 2 – Quantitative Analysis With Base Case 2 placing commercial restrictions on the availability of energy flows for the second interconnector, Basslink is now the major beneficiary of the arbitrage revenue (Graph 3) able to be generated in this scenario. Whilst 2IC would typically garner a majority of the flow due to its ability to provide lower losses to HydroTas, this benefit is not able to be realised.

Graph 3: Revenue scenarios under Base Case 2 – Commercial Restrictions

3.3.6 Key Modelling Results Similarly to the previous case Table 12 below contains the outputs generated from the financial analysis. The NPV for 2IC is less than Base Case 1, and the project and equity IRR would not meet most investors’ minimum criteria. This is compounded by the fact that this model is not able to support a significant level of gearing that would be required to deliver the second interconnector.

Table 12: Financial modelling results for the Base Case 2 - Commercial Restrictions

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Scenario Outputs


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2IC 598 616

Basslink 1,013 1,073

MNSP NPV (2016) @10% ($m)

2IC 304 308

Basslink 515 528




Debt Fundable No No

Financeable No No

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If the second interconnector is unable to garner a fair portion of energy transfers from HydroTas, it will be severely restricted in its ability to generate revenue. The “riskiness” of the revenue profile, means like Base Case 1, this model is unlikely to be financeable.

3.4 Detailed results – Alternative Cases 3.4.1 Alternative Case 1 – Basslink MNSP, 2IC Regulated - Qualitative Alternative Case 1 is a commercial model where Basslink remains an MNSP (and earning an availability charge), and the second interconnector enters the market as a regulated asset. This model assumes no commercial restrictions are in place and that the assets will be utilised by HydroTas as they are required.

Table 13: Key Takeaways – Alternative Case 1


Risk Transfer ► Third party revenue risk not transferred to the private

sector asset owner of 2IC.


► 2IC is only seeking to earn a return on its capital invested and cover operating costs, meaning it could potentially offer lower access costs to the NEM, increase operational utilisation and ensure minimal costs are passed on to electricity consumers as they don’t pay an arbitrage premium.

► However, asset owners are not financially incentivised to optimally maintain and operate the infrastructure (other than through the regulated asset’s minimum requirements).

Energy Security

► Dual interconnectors will increase energy security for Tasmanians purely through the addition of a secondary line that can operate viably as a backup should one or the other line be unavailable.

Suitability of Funding ► Increases the level of funding suitability through reliable cash flows to service investor funding

Financing Costs ► With 2IC having reliable and consistent cash flows then

financing costs would be expected to be competitive with other recent regulated asset sales processes.

Market Appetite

► From a pure investment perspective, if guarantees can’t be provided on returns generated through arbitrage that could consistently be exploited, then a regulated scenario will drive market appetite as investors will have greater insight into the expected returns which will increase the desire for the asset.

► The inability of the model to support adequate gearing levels and provide minimum market returns for investors, coupled with the fact that revenue is still generated via arbitrage opportunities (and therefore out of the control of the interconnector owner), also means this model is unlikely to be commercially viable.

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This model has considerable advantages over the pure MNSP models previously assessed due to the increased financeability of regulated revenues, which could lead to improved outcomes in relation to the bankability of this model as this offers a considerably lower risk profile for investors.

3.4.2 Alternative Case 1 – Quantitative Analysis The cashflow profile of this model visually is different from the previous models. As can be seen Graph 4 below, Basslink’s revenues are directly linked to its ability to generate returns via arbitrage opportunities which is evidenced by the volatile line, whilst 2IC earns a consistent regulated return, hence almost no variation in the revenue profile.

Graph 4: Alternative case 1 – Basslink MNSP, 2IC Regulated.

3.4.3 Key Modelling Results When considering this model with the Base Case options, the outputs in Table 14 indicate that whilst the NPV’s may be somewhat lower, they are still strong outcomes, enhanced by the ability of this commercial model to generate equity IRR’s of approximately 10% (expected to be sufficient for a regulated asset) and is capable of supporting a high gearing ratio. This model is supported by regulated revenues for 2IC (limited only to what is required to repay debt, cover operating costs and applicable depreciation).

Table 14: Financial modelling results for Alternative case 1 – Basslink MNSP, 2IC Regulated

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Scenario Outputs


MNSP / regulated NPV (2016) @7% ($m)

2IC 1,152 1,211

Basslink 1,013 1,073


2IC 619 635

Basslink 515 528





Financeable Yes Yes

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This commercial model provides superior outcomes for 2IC when considering the benefits of regulation on the projects ability to support debt and deliver long term viability. For 2IC, this model would likely be financeable by both debt and equity investors.

3.4.4 Alternative Case 2 – Basslink Regulated, 2IC MNSP - Qualitative Alternative Case 2 is a variation on the Alternative Case 1.



Risk Transfer

► Delivers a greater level of risk transfer over the Alternative Case 1, though with Basslink becoming regulated, there needs to be comfort that this is a sustainable outcome for 2IC to ensure its viability given the transfer of demand and pricing risk and enable effective risk transfer.

Operational Utilisation ► Encourages greater competition that will benefit energy consumers at the expense of profits for the interconnectors.

Energy Security ► With 2IC being MNSP, the commercial viability risks increase

which could negatively impact energy security should the asset be vulnerable to failure through limited revenues.

Suitability of Funding ► With cash flows from the 2IC being directly impacted by the

ability of the asset to generate revenue through arbitrage (needs to compete with Basslink’s to impact on pricing to secure flow), reliability of cash flows becomes a concern.

Financing Costs ► As the asset is subject to inconsistent cash flows being

generated, expected riskiness will increase and therefore this is expected to be represented in an increase in funding costs.

Market Appetite ► With limited certainty into the expected cash flows of the

asset and no firm guarantee of energy flows along the link, the market will have less appetite for this structure.

In this model, Basslink would operate as a regulated asset (earns a regulated transmission charge), whereas 2IC would operate as a pure MNSP. The model assumes no restrictions of flows between either of the interconnectors, as 2IC is expected to compete against the regulated Basslink for flows. This model encourages 2IC to bid, at a minimum, the same equivalent value that it would cost HydroTas to use Basslink.

As previously explored in prior models, with 2IC expected to generate revenues from market arbitrage opportunities and the high levels of risk associated with that revenue profile, it scores low in regards to the finance criteria and therefore is an assessed as an unsuitable model to support the delivery of a second interconnector.

► The biggest issue this model faces is it exposes BassLink to market generated returns which will ultimately impact its ability to generate market linked returns above the availability charge.

► BassLink would need to be able to enter into offtake contracts in order to ensure access to electricity flow and provide a consistent revenue stream.

► With HydroTas being responsible for ensuring base load domestic supply to Tasmania first and foremost, MNSP’s are unlikely to be commercially viable due to their inability to control demand flow from HydroTas.

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3.4.5 Alternative Case 2 – Quantitative Analysis In a similar structure to the Alternative Case 1, though in this instance revenue for Basslink is regulated, whilst 2IC operates as an MNSP. In Graph 5 below, it should be clear that Basslink’s revenues are relatively consistent, with 2IC being directly exposed to market generated returns, which on face value look considerably higher than a regulated return.

Graph 5: Alternative case 2 – Basslink Regulated, 2IC MNSP.

3.4.6 Key Modelling Results The key outputs in Table 16 are similar to the outcomes generated in Base Case 1, specifically when looking at the NPV’s, Project and Equity IRR’s. This commercial model could also theoretically support high gearing levels, though as 2IC is back to generating arbitrage revenues.

Table 16: Financial modelling results for the MNSP Commercial Model

Similarly to Base Case 1, this commercial model provides a significant NPV along with strong project and equity IRR’s. As 2IC’s revenue is again MNSP based, due to the riskiness of cash flows, this model is unlikely to be financeable.

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Alternative Case 2 – Basslink Regulated, 2IC MNSP

Scenario Outputs



2IC 1,662 1,745

Basslink 791 843


2IC 827 845

Basslink 407 418





Financeable No No

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3.4.7 Alternative Case 3 – Both Regulated - Quantitative The next case considered is a scenario where both Basslink and the second interconnector are operating in regulated commercial models.



Risk Transfer ► Limited revenue risk transfer to asset owners (as

above) as both assets are regulated and not exposed to demand and price risks.


► HydroTas would be free to operate both links as they wish with limited commercial implications.

► However, asset owners are not financially incentivised to optimally maintain and operate the infrastructure (other than through the regulated asset’s minimum requirements).

Energy Security

► Regulated revenues for both interconnectors improves energy security for Tasmania as regulation will underpin the viability of both interconnects, meaning the likelihood of both assets being unavailable would be low.

Suitability of Funding

► Regulated returns on the 2IC will provide a higher level of funding when compared to MNSP’s as cash flows are pre-determined and could be more easily financed.

Financing Costs

► With 2IC having reliable cash flows, as long as they can comfortably meet funding covenants then financing costs would be expected to be competitive with other forms of funding.

Market Appetite

► For 2IC to have meet the RIT-T requirements, the asset will be generating a return to cover funding, returns on funding and operating costs, meaning an increased interest in the assets.

In this instance, neither Basslink nor the second interconnector have viability concerns at the same level as MNSP models as their revenues are determined by the regulator. From a financing perspective, this commercial model structure meets the requirements that most investors would be looking for, namely low risk, bankable revenue profiles, though the tradeoff is risk transfer and utilisation are relatively low.

► Though in a similar outcome to Base Case 1 (high NPV’s), this model still relies upon HydroTas supporting the 2IC by providing access to electricity flows at a discount to the prevailing markets at the time in order for the interconnector to generate revenue.

► Without some form of offtake agreement (from HydroTas) or HydroTas participating in some form of ownership structure in 2IC to support it commercially, this model is unlikely to be commercially viable due to the inability of 2IC to generate consistent returns to repay lenders.

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3.4.8 Alternative Case 3 – Qualitative Analysis At the opposite end of risk transfer spectrum to the Base Case options, this commercial model option provides an ongoing regulated return for both Basslink and 2IC. As Graph 6 shows the revenue lines for both interconnectors are stable, only increasing overtime in line with any inflationary impacts.

Graph 6: Alternative case 3 – Basslink and 2IC Regulated.

3.4.9 Key Modelling Results Table 18 shows that this commercial model provides improved outcomes in most areas, though as expected the NPV’s and Project IRR’s are not as strong as you would expect to see in outright MNSP operations. The significant benefit of this model though is the regulated revenues that could support the ongoing viability of the interconnectors.

Table 18: Financial modelling results Basslink and 2IC Regulated.

The dual regulated commercial model is able to support a level of funding, and internal rates of return that will attract investors to support the development of a second interconnector. For 2IC, this model would likely be financeable by both debt and equity investors at a relatively low cost of capital.

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Scenario Outputs


Regulated NPV (2016) @7% ($m)

2IC 1,152 1,211

Basslink 791 843

Regulated NPV (2016) @10% ($m)

2IC 619 635

Basslink 407 418





Financeable Yes Yes

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3.5 Detailed results – Hybrid models 3.5.1 Hybrid Model 1 - Partially Merchant Commercial Model In contrast to the partially regulated model, a partially merchant model functions in a fundamentally different way. The regulated version attempts to create additional value for investors by creating a floor and providing the opportunity to share in some upside, whereas the merchant version is designed to lower the level of return required to remain viable through some form of government assistance. For example, a government grant towards the capital costs required to deliver a second interconnector, instantly lowers the level of revenues that would need to be generated by the interconnector in order to sustain the viability of this model.

Graph 7: Partially Merchant Commercial Model – Reduction in Transmission Charge

3.5.2 Key Modelling Results When compared to the partially regulated model results above, Table 19 highlights that the NPV’s, project and equity IRR’s in this model are lower. On face value the model can also sustain high levels of gearing, though this imposes a higher cost on consumers as the interconnector is still operating in profit maximizing mode. As we discuss above, models that ultimately requires market generated returns to recover capital is unlikely to be viable and fundable.

Table 19: Financial Modeling Results - Partially Merchant

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Partially Merchant Model

Scenario Outputs


2IC – NPV(2016) @7% ($m) 662 697

2IC - NPV (2016) @10% ($m) 353 363




Financeable No No

► The dual regulated commercial model is able to support a level of funding, and internal rates of return that will attract investors to support the development of a second interconnector.

► This model does not address the higher loss factors that Basslink suffers from and may ultimately lead to reduced operational viability as HydroTas by default would want to select the second interconnector for transmission due to lower losses.

► Depending on total flows across both interconnectors may force Basslink to operate as an overflow cable only.

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3.5.3 Hybrid Model 2 - Partially Regulated Commercial Model A partially regulated commercial model is one in which at a minimum, the asset is able to generate a regulated return in order to cover debt, operating and associated deprecation costs that to underpin the viability of the interconnector, whilst still offering the owner of the interconnector an ability to generate some market returns, though the partial sharing of any arbitrage revenue that could be realised.

These commercial models are increasingly popular in Europe and are known as Cap and Floor Models. They earn revenue through the payment of a capacity charge, which is set at a minimum amount of revenue that the interconnector can earn. This means that, if an interconnector does not receive enough revenue from its own operations, its revenue will be ‘topped up’ to the floor level.

The top up payment, in this instance would come from HydroTas, which in turn will recover that sum from transmission charges applied to all users of the NEM. This model also passes on the viability of the interconnector to consumers, who are essentially underwriting the revenue risk to pay for the investment. In circumstances where the interconnector’s revenue exceeds a pre-determined cap, the interconnector will transfer the excess revenue to HydroTas, which in turn will reduce the transmission charges for consumers.

Graph 8: Partially Regulated Commercial Model – Capped Upside (25%)

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Regulated revenue 2IC partially regulated 40y operating period

► The interesting take away from this model, is that in a market that could consistently return strong market driven revenues, this would offer considerable appeal over a pure MNSP commercial model by covering the asset owners repayment of capital.

► As the asset would still operates as a MNSP, this model is unlikely to be funded without considerable revenue generation support from HydroTas.

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3.5.4 Key Modelling Results When considering Table 20 against the variations of the models already analysed above, it should be clear as to the benefits this type of model provides.

Table 20: Financial Modeling Results - Partially Regulated

With the benefit of “minimum” ongoing payments due to the floor function of this model, it would likely attract funding should this type of commercial structure become available in Australia.

3.6 Conclusion – Commercial Analysis In a simplistic view, it would easy to take the key outputs from the qualitative and quantitative analysis and draw conclusions that MNSP scenarios are profitable and would encourage the highest level of investor interest, whilst regulated assets may offer lower costs to consumers and are potentially more suitable to debt funding. The reality is that determining the appropriate commercial model is considerably more difficult.

With MNSP’s (at a high level) offering greater levels of returns, the level of market exposed risk is considerable. To generate their revenue the interconnect would need to rely upon HydroTas making electricity available to the interconnector at a level that is consistently lower than mainland prices so that the asset owner can profit off the price differential to sustain the connection or generate substantial revenues through ancillary services.

The fact that the price differential is very difficult to forecast outright, and that HydroTas is not operating with the profitability of the interconnector in mind, mean the potential revenue streams are highly volatile and difficult to predict.

On the other hand, regulated models by nature are considerably more fundable than MNSP’s purely due to their revenue profile being pre-determined through regulation. Whilst regulating assets provide cost of funding benefits when compared to MNSP’s, they may not always encourage the most efficient use of the assets, nor generate the levels of returns that some investors may require due to the reduction in risk profiles.

Partially Regulated Model

Scenario Outputs


2IC – NPV(2016) @7% ($m) 1,314 1,380

2IC - NPV (2016) @10% ($m) 695 712




Financeable Yes Yes

► The benefits of this model comes in the form of capped higher returns for investors over a traditional regulated model, which will encourage greater investment, whilst providing lower costs to consumers as they are only exposed to a capped upside rather than what may otherwise could occur under MNSP type models.

► For this model to be considered in the Australian context, it would require a significant policy shift to supporting this type of commercial structure, though it does offer improved viability over MNSP models and increased attractiveness for investors over a pure regulated model.

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The key to the selection of the preferred commercial model is directly related to the outcome that government is seeking in relation to the second interconnector. If the overarching goal is to ensure energy security and to open further renewable generation options within Tasmania then forms of regulated models should support this goal as they can operate without the need to be in profit maximizing mode as their return is already determined.

Alternatively, if the goal is to deliver a second interconnector that encourages the greatest level of third party investment in a competitive environment with little concern given to their viability or risk profiles, then MNSP models that offer exposure for asset owners to generate greater returns than regulated models would be preferred, assuming that these revenue streams are consistently available and are attractive for investors considering their risk profile.

In light of these two extremes, the advantages of the hybrid models, and in particular the partially regulated model, looks to offer the benefits of regulation for investors (i.e. lower risk profiles) whilst offering some of the MNSP benefits (i.e. efficient asset operation and potential to share in increased revenues). As with all options, the pros and cons of the range of commercial models are considerable and cannot be considered in isolation.

The analysis indicates that for a second interconnector to be delivered in the current environment, it will more than likely, at least initially need to be supported by some level of regulated return or availability type charge, similar to Basslink or the Cap and Floor models in operation in Europe, in order to attract funding and provide a viable commercial model.

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4. Procurement Models

4.1 Procurement considerations This section focuses on the range of procurement model options for 2IC. Figure 3 below identifies the considerations which need to be addressed prior to any procurement model decisions. As can be seen, operating models (Section 4) are typically the starting point, before considering the impact of ownership structure which then help form the decision process around procurement model choices. Figure 3: Decision flow

4.2 Ownership structure – 1 Owner vs 2 Owner As section 4 considers the range of commercial models, the next steps in the process is to overlay those decisions with the impact that the ownership structure may have on procurement options. Table 21 contains the range of ownership structures available depending on the number of potential asset owners of both interconnectors.

Table 21: Ownership structures

In broad terms, under a one-owner model, interface risks are reduced, commercial complexity is reduced and the flexibility and adaptability in how the asset is operated is increased given the single-ownership and governance structure.

Ownership Ownership structures

One Owner (Basslink and 2IC) State-owned (S) Existing operator (E) New Operator (N)

Two Owners (Basslink / 2IC) S / E E / S S / N N / S E / N N / E

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In addition, by controlling both Basslink and 2IC, loss-minimising operational practices can be undertaken by the owner to improve the utilization of both assets in an efficient manner which may also deliver improved energy security outcomes.

The market modelling under Base Case 1 where both assets are MNSPs assumes that both interconnectors act co-operatively such that the bidding of the two interconnectors maximizes the total revenue of the interconnectors. However, from a commercial perspective, this would only be the case where the interconnector is owned by the same owner. Operating model options that have both links exposed to revenue risks (MNSP’s) and have separate ownership structures may impact the commercial viability of the assets. Without regulatory restrictions, sub-optimal market outcomes may eventuate such as:

► Low competitive pricing which creates financial stress for the asset owners ► Pricing is maintained at artificially high levels due to the pricing power of the duopoly

Conversely, under a two-owner model, benefits may include increased price competitiveness, increased opportunity for innovation as well as a diversification of risk through separated ownership and governance structures.

With Basslink being a privately owned MNSP, the Government presumably has minimal levers to compel Basslink to become a regulated asset or consider a change to its commercial model. This represents a key risk to the delivery of 2IC. It is also important to consider that an option to extend the BSA in 2031 for another 15 years exists, though it is unknown at this stage if that option will be executed.

Should Basslink find itself in a less than ideal operating scenario, the options available include:

► Considering applying to the AER for regulated asset status ► Considering a sales process for the asset ► Seeking to renegotiate terms with HydroTas

4.3 Procurement Model Options Table 22 below sets out the key procurement models available for this type of asset. In undertaking this assessment, each model has been evaluated against their ability to meet the project objectives. There are a variety of revenue models which might influence the desirability of each approach. The potential delivery models for 2IC, and their relative advantages and disadvantages include: Table 22: Procurement model options

Procurement Method Description Advantages Disadvantages

Design & Construct (D&C) and transfer to private sector

Under a D&C and transfer approach, Government would procure the design and construction of 2IC with the D&C provider transferring ownership back to Government / current operator following completion.

► Price certainty and value for money (depending on structure of commercial models)

► Time (to market and to completion)

► Risk management

► Flexibility to change

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Procurement Method Description Advantages Disadvantages

Design, Build and Maintain (“DBM”)

Under a design, build and maintain model, Government would contract a private entity to design, build and maintain the asset, with operational responsibilities retained by Government.


► Risk management

► Price certainty and value for money


PPP / Build Own Operate Transfer (BOOT)

Under a PPP / BOOT model, a private operator would be contracted to design, build, operate and maintain 2IC, with Government providing revenue to the operator under an availability payment

► Risk management ► Price certainty and value for

money



4.4 Procurement Summary A contestable regulated model (applied for projects with significant capital costs) is likely to enable competitive bids for construction, operations and ownership of the asset

► The regulated asset model is market tested, and competitive for transmission assets ► It could be expected to be delivered with relatively a low cost of capital ► With only 3 HVDC suppliers capable of meeting the technical specifications globally,

concern needs to be given to the impact this may have on the competitiveness of the procurement model

► The existing DNSP arrangements in Tasmania and Victoria would be expected to continue for the procurement of required network connection infrastructure for new generation and connection to the existing grid

Should an MNSP commercial model with a capacity charge be the preferred choice, a Build Own Operate Transfer (“BOOT”) delivery model should deliver an optimal outcome

► BOOT transfers majority of construction, maintenance, operations and ownership to the private sector.

► Bidders would compete on what their minimum Capacity Charge is to deliver and operate the asset over the project life

► Maintains strong incentives for the asset owner to ensure the asset is available and maintain and maintain and operate the asset to reduce transmission losses.

► Much like the commercial model analysis, procurement decisions cannot be

considered in isolation. Ideal procurement outcomes are a derivative of both the government’s goals and objectives of the second interconnector.

► This analysis also highlights the importance of the level of the need to consider the implication of the one vs. two ownership structure may also have on the procurement and long term viability of two interconnectors.

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5. Validation

5.1 Market Sounding Participants As part of this report, EY undertook a series of market soundings in order to validate the key outcomes for each series of analysis on the various commercial models contained in section 3.

The various market participants included were:

► HydroTas

► Clean Energy Finance Corporation

► APA Group

► Macquarie Bank

► AusNet Services

► HRL Morrison.

Each participant provided considerable insights into the commercial models, which are summarized in the following sections. The views expressed below are EY’s key takeaways from those discussions and it should not be concluded that they reflect the views on any particular party consulted with.

A widely held view was that clarity in relation to the key objectives for considering a 2IC is a critical prerequisite to making an assessment on the appropriate commercial delivery model. Some provided insights (and expressed strong views in both directions) into why a second interconnect might be required and whether there may be other ways of meeting those objectives. Our focus is however on how the Project might be best delivered, if a decision was taken to proceed with it.

5.1.1 MNSP Validation In line with the outcomes of the analysis in section 3, the general feedback from the market participants was that whilst HydroTas continues to operate outside of the ownership structure of the interconnector in Tasmania, MNSP type models (and their variations) are unlikely to be commercially viable.

The market traditionally aims to seek out investment opportunities that contain a risk profile that can be managed in order to generate revenues. As HydroTas isn’t currently operating (nor is it envisaged that this will change) with the viability of the interconnector in mind, for outright asset investors this presents too greater risk. Market participants are unable to manage their market exposure as HydroTas dictates the access to flow and the price that interconnectors must pay.

HydroTas would need to shift its operating position in order to be able to provide greater opportunity for the 2IC interconnector owner to share some of the arbitrage revenue (preferably through an offtake contact with the asset owners) which enables consistent revenue generation to be achieved, underpinning the investment and viability of a second interconnector.

5.1.2 Regulated Validation In a similar outcome to the conclusions from section 3, the market participants were in general agreement that when compared to the alternative market exposed commercial models, some form of regulated model structures, or alternatively models that also include minimum payments (transmission charges, availability fees or floor supports) that ensure the ongoing viability of the interconnector are significant risk exposure improvements over outright MNSPs.

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The market was quick to point out that the current RIT-T is a challenging test to be met and that 2IC may have trouble meeting the requirements to become regulated. It was the markets’ suggestion that alternatively, should the interconnect not meet the regulation test, then “quasi” regulation in the form of ongoing payments (much like Basslink’s availability charge or the Cap and Floor Model in operation in Europe) could be viable variations to consider.

Given the choice between an MNSP model that has terms dictated by HydroTas versus a regulated commercial model that has an almost guaranteed revenue stream, it was clear that the market believed that in the current environment, regulated structures would provide superior outcomes, if the objective is to deliver a second interconnector.

It was also noted, however, that a considerable re-working of the regulatory arrangements might be required if the second interconnect was to achieve regulated status.

5.2 Case Study Validation 5.2.1 Terranora Case Study Terranora (formerly known as Directlink) is an electricity network asset that spans 63km between Mullumbimby and Bungalora in New South Wales. The interconnector was constructed with the aim of addressing the power shortage in South Queensland, and surplus capacities in New South Wales.

The interconnector has a nominal capacity of 180MW and is owned by a joint venture (JV) between Emmlink Pty Ltd (a wholly owned subsidiary of Country Energy) and HQI Australia Ltd Partnership. The asset was commissioned in December 1999 and started operations in April 2000. At a construction cost of US$70 million, Directlink was the first time that transmission systems of New South Wales and Queensland were linked.

Directlink was originally built to operate as an MNSP market network, trading between the NSW and Queensland region. This meant that the asset earned its revenues based on the spot price differential between the New South Wales and Queensland electricity regions.

However in early 2004, the JV submitted an application to the AER requesting to convert the asset from a market network service to a regulated network service. This stance was taken as the MNSP operation was proving to be unprofitable as the asset was consistently underperforming due to operational issues. In order to support the NEM and provide greater surety in regards to its viability, DirectLink applied to achieve regulated status.

Following the decision to reclassify the asset as a prescribed transmission service (and thereby receiving regulated revenue), the AER determined the Regulatory Asset Base and Maximum Allowed Revenues for the nominal 10 year period.

5.2.2 Murraylink Case Study Murraylink is an interconnector that provides a corridor for the flow of electricity between the South Australian and Victorian regions of the NEM. The interconnector covers 176 km from Red Cliffs in Victoria to Berri in South Australia and has a limit of 200MW capacity. The interconnector is the world’s longest underground power transmission system and cost in excess of $175 million.

The asset was commissioned in 2002 by Murraylink Transmission (TransÉnergie Australia), a subsidiary of TransÉnergie (the transmission division of Hydro-Québec, Canada). It is now owned by Energy Infrastructure Investments consortium and operated by the APA Group. In early

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2013, the Murraylink applied to be treated as regulated asset and agreed adopt 5 year regulatory control period (commencing 1 July 2013 and concluding 30 June 2018).

In a similar vein to Directlink, Murraylink was having considerable issues remaining viable operating as an MNSP and therefore sought to become regulated. Whilst there was considerable concern within government at the time as they “believed the asset owners were prepared to take market risk and therefore should not be supported by the South Australian consumers” the regulator believed that the considerable benefits offered by the interconnector to the overall NEM was worth supporting via regulation.

5.2.3 International Precedents In order to support the ongoing development of electricity interconnectors in the United Kingdom (UK) and mainland Europe, a commercial model is emerging that is designed to underpin the viability of interconnects. In a joint project between National Grid Plc and Elia Group (Belgian) called the Nemo Link, subsea and underground cables are being connected to each country, allowing the flow of electricity between them to occur as demand requires.

In order to ensure the viability of the interconnectors and guarantee security of electricity supply, the interconnectors are being delivered using Cap and Floor commercial models. The floor is the minimum amount of revenue that an electricity interconnector can earn. If an interconnector does not earn enough revenue from its operations, its revenue will be topped up to a minimum ‘floor’ payment (funds transferred from the system operator, which is then recovered from transmission charges applied to all users of the electricity transmission system).

The cap is the maximum amount of revenue for an electricity interconnector. Should an interconnector’s revenue exceed the cap, the interconnector then transfer’s excess revenues back to the system operator, which is used to reduce transmission charges. The cap on revenues provides benefits in return for their exposure in managing the floor price. For the interconnectors, it supports an investment route to underpin viability.

Figure 4: NEMO Link Project: European Cap and Floor Interconnectors

The cap and floor model is designed to encourage greater investment into electricity interconnectors as they are structured to strike a balance between commercial incentives and risk mitigation to enable predictable revenue streams to support development.

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