feasibility of a second tasmanian interconnector · 2016-09-27 · feasibilit terconnect eport 1...

Feasibility of a second Tasmanian interconnector Preliminary Report The Hon Warwick Smith AM June 2016

1Feasibility of a second Tasmanian interconnector – Preliminary Report

PurposeThe Australian and Tasmanian governments have jointly initiated a feasibility study of Tasmania’s renewable energy resources and the role of a second interconnector for Tasmania. This study is being undertaken by the Hon. Warwick Smith AM LLB, with support from a taskforce led by the Department of Industry, Innovation and Science and including the Department of the Environment, the Treasury and the Australian Energy Market Commission. The taskforce will also be supported by input provided by the Tasmanian Government, the Australian Energy Market Operator and the Clean Energy Finance Corporation. KPMG has assisted the taskforce by providing an independent perspective during the preparation of this Preliminary Report.

The Terms of Reference for this feasibility study are included at Attachment A.

The Australian and Tasmanian governments have requested that a preliminary report is to be provided in June 2016 and the final report is to be completed by the end of 2016. This report is the Preliminary Report from the Hon. Warwick Smith AM LLB in response.

The Hon. Warwick L. Smith AM LLBThe Hon. Warwick Smith AM LLB is Chairman New South Wales & Australian Capital Territory and Senior Managing Director of the Australia New Zealand Banking Group Limited (ANZ Bank); Chairman of the Board - ANZ Bank Greater China, Chairman of the Advisory Board of Australian Capital Equity, holder of interests in Seven Group Holdings, West Australian News, Coates Hire, WesTrac and Caterpillar industrial services and equipment in Western Australia, New South Wales and North East China; Chairman of the Australia–China Council, Global Trustee of the Asia Society; Chairman of the Financial Services Knowledge Hub and Chairman of the Flagship Property Group. He is a Board Director of Seven Group Holdings and Coates Hire. Recently, Mr. Smith completed a review of the Federal Department of Infrastructure and Regional Development and is currently chairing a review of the Federal Department of Finance and a review of the Contestability of Members of Parliamentary Services.

Formerly, he was Chairman of E*TRADE, the Australian Sports Commission and an Executive Director with Macquarie Bank; and a Federal Government Minister with a parliamentary career spanning 15 years. He was also Australia’s first Telecommunications Ombudsman and has received a Centenary Medal and an Order of Australia.

2 Feasibility of a second Tasmanian interconnector – Preliminary Report

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Content contained herein should be attributed as Australian and Tasmanian governments: Feasibility Study of a second Tasmanian interconnector - Preliminary Report.

Disclaimer:

This report has been developed by the Hon. Warwick Smith AM LLB, with support from a taskforce led by the Department of Industry, Innovation and Science and including the Department of the Environment, the Treasury and the Australian Energy Market Commission. The report is also supported by input provided by the Tasmanian Government, the Australian Energy Market Operator and the Clean Energy Finance Corporation. KPMG has also provided an independent perspective during the preparation of this report.

All parties involved have exercised due care and skill in the preparation and compilation of the information and data in this publication. Notwithstanding, the Commonwealth of Australia, its officers, employees, agents or any other party involved in drafting this report disclaim any liability, including liability for negligence, loss howsoever caused, damage, injury, expense or cost incurred by any person as a result of accessing, using or relying upon any of the information or data in this publication to the maximum extent permitted by law. No representation expressed or implied is made as to the currency, accuracy, reliability or completeness of the information contained in this publication. The reader should rely on their own inquiries to independently confirm the information and comment on which they intend to act. This publication does not indicate commitment by the Australian or Tasmanian governments to a particular course of action.


Contents

Introduction ..................................................................................................................5Overview .............................................................................................................................................5Large-scale Tasmanian renewable energy development ....................................................................6Contribution to energy security in the NEM ........................................................................................7Long-term costs and benefits to consumers .......................................................................................9Next steps .........................................................................................................................................11

The National Electricity Market ..................................................................................12Ancillary services ..............................................................................................................................15Interconnectors in the National Electricity Market .............................................................................17Utilisation ..........................................................................................................................................20

The Tasmanian Energy Sector ..................................................................................21Tasmania’s Generation Mix ...............................................................................................................23

Australian Renewable Energy Industry Development ...............................................26Carbon and Renewable Energy Policies ..........................................................................................26

Renewable Energy Growth ...............................................................................................................27

Tasmania’s Renewable Energy Potential ..........................................................................................31

Interconnector Regulatory and Financing Considerations ........................................33Regulatory considerations ................................................................................................................33Unregulated asset .............................................................................................................................34Supporting infrastructure...................................................................................................................34

Planning and Environmental approvals ............................................................................................35Commercial and financing considerations ........................................................................................35

Preliminary Conclusions and Proposed Study Activities ...........................................38Attachment A .............................................................................................................40

Terms of reference – feasibility study of a second interconnector ....................................................40

Attachment B .............................................................................................................41Feasibility Study Key Considerations................................................................................................41

Attachment C .............................................................................................................42State and Territory Climate Policies ..................................................................................................42


AbbreviationsAcronym Full Title

AEMC Australian Energy Market Commission

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

ARENA Australian Renewable Energy Agency

BPL Basslink Pty Ltd

CEC Clean Energy Council

CEFC Clean Energy Finance Corporation

CER Clean Energy Regulator

COAG Council of Australian Governments

DCCEE Department of Climate Change and Energy Efficiency (former)

DIIS Department of Industry, Innovation and Science

ERF Emissions Reduction Fund

FCAS Frequency Control Ancillary Services

GW / GWh Gigawatts / Gigawatt hours

MW Megawatts

NEL National Electricity Law

NEM National Electricity Market

NER National Electricity Rules

NSCAS Network Support and Control Ancillary Services

NSW New South Wales

OTTER Office of the Tasmanian Economic Regulator

PC Productivity Commission

PJ Petajoules

PV Photovoltaic

RET Renewable Energy Target

RIT-T Regulatory Investment Test for Transmission

SRAS System Restart Ancillary Services

SRES Small-scale Renewable Energy Scheme

TGP Tasmanian Gas Pipeline

TJ Terajoules

TVPS Tamar Valley Power Station

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Introduction Australia’s electricity sector is in a period of major and unprecedented transition. Changes are underway which are fundamentally altering the operation of the National Electricity Market (NEM) including an increased shift from fossil fuels to renewable energy, growing decentralisation of the electricity market, roll-out of new technologies and further privatisation of businesses in the NEM.

The potential for Tasmania to support this transition, in addition to the recent unique set of circumstances in the Tasmanian energy market, has led to the Australian and Tasmanian governments requesting a study into the feasibility of a second interconnector from Tasmania to Victoria.

My preliminary conclusion is that, if viable, a second interconnector would support long term energy security in Tasmania, assist in the integration of Tasmanian renewable energy into the NEM, support the operation of the NEM and could open the path way for more than 1,000 megawatts of new renewable energy development in Tasmania.

In summary, my interim recommendations are:

• The Australian and Tasmanian Governments should commit to supporting a second interconnector, subject to my final report demonstrating there is a likely long term benefit to consumers from its development.

• The Clean Energy Finance Corporation should be actively involved in the process from the start, bringing its expertise, analytical and financial capacity to the decision making process.

OverviewTasmania’s renewable energy could play a significant role in the NEM in the future. Tasmania is already a leader in renewable energy generation in Australia, with a long history of its extensive hydro power generation underpinning its electricity sector and the broader Tasmanian economy. Further, Tasmania is blessed with abundant renewable energy resources across a variety of types of renewable power, such as wind, biomass and marine based power, and could continue this leadership role in the future should market conditions be favourable. A second interconnector would play a key role in enabling increased development of these renewable energy resources.

Studies into the feasibility of a second interconnector and the role it could play in supporting development of Tasmanian renewable energy are not new. In 2010-11 the Tasmanian Renewable Energy Industry Development Board (with the support of consultants Marchment Hill), conducted a preliminary examination of this issue and the Tasmanian Government, with the assistance of Hydro Tasmania is currently completing its own assessment.

However, these studies have not fully considered the effects nationally that a second interconnector and associated Tasmanian renewable energy development might have on the remainder of the NEM. The outlook for the NEM means there may be increasing benefits nationally, as well as within Tasmania, from stronger interconnection over the long term. Concerns on Tasmanian energy security1 have also become a more significant issue given the recent interruption to Basslink since 20 December 20152 until 13 June 2016 3 and historically low hydro levels during the spring of 2015.

To assist in determining the business case for a second interconnector, this study will build on previous and current work to add a national focus and perspective, with the aim of addressing the requirements of the Australian and Tasmanian governments for this study, as set out in the Terms of Reference at Attachment A. To ensure this national focus, this study will examine the case for a second interconnector having regard to the existing regulatory frameworks.

There are many challenges for policy makers in efficiently managing the transformation to the electricity market which is currently underway and there may need to be changes in existing market frameworks and regulatory models in the coming years ahead. In order to best support policy makers in this context, it is intended that this study will explore the conditions under which a second interconnector could be feasible. The Clean Energy Finance Corporation can play an important role in this work and any subsequent business case and its financial expertise and resources should be utilised more, bringing its expertise, analytical and financial capacity and resources to the decision making process.

1 An explanation of how the terms “energy security” and “power system security” are used in this report is provided at Box 2.

2 Basslink Pty Ltd (BPL) 2016, Basslink interconnector outage, http://www.basslink.com.au/wp-content/uploads/2015/12/Media-Statement221215-final.pdf

3 BPL 2016, Basslink interconnector outage http://www.basslink.com.au/wp-content/uploads/2016/06/Media-statement-13-June-final1.pdf


This study sees a second interconnector as fundamentally needing to be in the long term interests of electricity consumers. To explore whether this is the case, this study will assess the merits of a second interconnector, considering:

• Its potential role in facilitating the development of large-scale renewable resources in Tasmania.

• Its contribution to energy security in the NEM, including Tasmania.

• The long term costs and benefits to consumers, both in Tasmania and the NEM more broadly.

Through a consideration of these dimensions, this report establishes a framework for the study’s evaluation of the feasibility of a second interconnector (the Final Report), due by the end of 2016.

Large-scale Tasmanian renewable energy development The Australian Government has committed to reduce national greenhouse gas emissions by 26 to 28 per cent below 2005 levels by 2030. Key measures in this regard include its Emissions Reduction Fund (ERF), Safeguard Mechanism and the Renewable Energy Target (RET).

The RET scheme is currently the primary way in which growth in renewable energy is supported in Australia, with associated innovation and early stage deployment of Australian renewable energy technologies supported by the activities of the Clean Energy Finance Corporation (CEFC) and the Australian Renewable Energy Agency (ARENA).

As outlined at Attachment C, there are also various initiatives at the state and territory level designed to promote renewable energy, including:

• A Tasmanian Government commitment to pursue the potential for an additional 10 per cent hydro generation output from its existing hydro asset base.4

• A Victorian Government Renewable Energy Target of 25 per cent renewable energy by 2020 and 40 per cent renewable energy by 2025.5

There are over 12,000 megawatts (MW) of prospective renewable energy generation projects proposed across the NEM to meet current and future policy settings.6 Based on current technology costs, it could be expected that a significant mix of wind energy projects will be developed in the near term, with use of renewable technologies, in particular wind and solar based generation expected to continue to grow in use in the longer term as technology costs decline.

At present there are multiple prospective wind energy generation sites under consideration in Tasmania, with various reports and industry publications suggesting that there is the potential for wind farm sites totalling well over 1,000 MW of generation capacity, mostly to the north-west and north-east of the state.

Whether Tasmanian renewable energy resources are developed will depend on how commercially and technically prospective the renewable resource, generation technology and market settings are and the appetite for such commercial investment. Key potential advantages in favour of developing these resources are linked to existing Tasmanian hydro resources, which can:

• rapidly change output to meeting changing supply and demand;

• provide ancillary services to the market;

• through pumped hydro, potentially offer large scale storage; and

• be combined with generation from wind energy to smooth its intermittent power output.

However, these advantages will need to be considered against various challenges, such as the likely considerable costs of developing supporting infrastructure (including network upgrades and hydro enhancements) in order to use Tasmania’s hydro in this way, whether the timeframes required to develop this infrastructure support electricity market needs and the effects of this change on existing long term contracts to industrial consumers. The full costs and benefits of these options and to what extent renewable projects could proceed with and without a second interconnection will be a key consideration in the final report.

4 Department of State Growth 2015, Tasmania’s Energy Strategy – Restoring Tasmania’s Energy Advantage, page 29

5 Victorian Premier 2016, Media Release (15 June 2016) Renewable Energy Target to Create Thousands of Jobs, https://www.premier.vic.gov.au/renewable-energy-targets-to-create-thousands-of-jobs/

6 AEMO 2015, Electricity Statement of Opportunities, page 12


Contribution to energy security in the NEMChanging trends in the electricity market are shaking up traditional models of market operation. Market and technological changes are shifting the traditional generation mix and the drivers influencing demand. This has led to unexpectedly flat or declining electricity demand at the national level for six consecutive years to June 2015.7 The demand for new generation technologies, in particular wind and photovoltaic solar power, caused primarily by the Renewable Energy Target (RET), combined with energy efficiency initiatives, has seen an oversupply of generation capacity in the NEM, causing depressed wholesale electricity prices and leading to withdrawals of coal and gas fired generation from the market.

Interconnectors have and will continue to play a vital role in efficiently responding to this transition, by allowing for the efficient trade of power and ancillary services between different regions of the NEM, as well as improving power system security and energy security more generally. For example, the existing Basslink interconnector assisted in avoiding blackouts in Victoria during the June 2012 earthquake when there was an unexpected loss of supply.

The transition currently occurring in the electricity market is not unique to Australia, with policy makers experiencing similar issues overseas. In response to these challenges, a number of international governments are constructing or evaluating additional interconnectors between electricity grids to reduce the costs and mitigate the risks associated with these changes.

A second interconnector, combined with changes to the Tasmanian network and supporting hydro infrastructure, could play a role in supporting energy security in Tasmania and the NEM more broadly. The role greater interconnection could play with regards to energy security is particularly relevant for Tasmania, where the energy generation mix differs materially from other regions in Australia and where constraints are largely based on energy resource availability, unlike the network capacity constraints experienced in the rest of the NEM.

However, it should be noted that the time between approval and a second interconnector commencing operation is estimated at between five to eight years. Given this long lead-time, a second interconnector’s viability can only be considered in the long term – it cannot address the recent energy constraint challenges in Tasmania.

To what extent a second interconnector could contribute to greater NEM energy security more broadly will be examined as part of this study. The recent interruption in the operation of Basslink has highlighted risks to the Tasmanian electricity market from its energy constraints and its reliance on Basslink and will add to the case for redundancy in connection to mainland Australia. Similarly, with associated network and infrastructure upgrades, a second interconnector may enable the large existing hydro capacity in Tasmania to be used to more efficiently manage and support current and expected future market trends, including the retirement of ageing fossil fuel generation and the increased penetration of intermittent and distributed renewable energy generation in the NEM.

7 AER 2015, State of the Energy Market 2015, page 2


Box 1 - Basslink InterruptionOn 20 December 2015, a fault on Basslink, the existing interconnector between Tasmania and Victoria, separated Tasmania from the NEM and it did not return to service until 13 June 2016.8

Electricity supply for Tasmania is predominantly hydro-generated but due to low spring rainfall, Hydro Tasmania’s dam storage levels were at 25 per cent at the time of the interruption 9 Hydro Tasmania’s Tamar Valley gas-fired power generators were returned to service from 20 January 2016, to ensure Tasmania’s demand could be met.10 The recommissioning of the Tamar Valley Power Station (TVPS) was a key component of Tasmania’s response to the Basslink outage. Containerised diesel generators (200 MW11) were also installed to meet Tasmania’s electricity requirements, and Hydro Tasmania entered a series of commercial agreements with Tasmania’s major industrial energy users to enact a series of temporary load reductions.

The shortfall that was being met by Basslink prior to its interruption was increasingly being met by gas generation, diesel and voluntary load reduction during the interruption period, as demonstrated in Figure 1.

Figure 1 – Tasmania’s electricity generation mix, August 2015 to May 201612

8 BPL 2016, Media Statement 13 June 2016 – Basslink has returned to service, http://www.basslink.com.au/wp-content/uploads/2016/06/Media-statement-13-June-final1.pdf

9 Hydro Tasmania 2016, Energy in Storage, http://www.hydro.com.au/water/energy-data

10 Hydro Tasmania 2016, Energy Supply Plan (updated 2 May 2016), Page 8

11 Hydro Tasmania 2016, Installation of temporary diesel generators at Bell Bay, http://www.hydro.com.au/about-us/news/2016-04/installation-temporary-diesel-generators-bell-bay

12 Hydro Tasmania 2016, Energy Supply Plan (updated 2 May 2016), Page 9

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Long-term costs and benefits to consumersThe costs and benefits to electricity consumers in Tasmania and elsewhere in Australia will be a key consideration in the building of a second interconnector. The future benefits to electricity consumers will be multifaceted and may include; lower wholesale prices, greater price stability as well as improved certainty of supply. The effect of a second interconnector on costs will need to be assessed, including consideration of whether a second interconnector would increase or decrease future electricity costs and how such costs would be allocated between electricity consumers. It may also be important to consider how the time profile of both costs and benefits changes over the life of the second interconnector.

Significant investment would be required to finance a second interconnector, with a recent study estimating capital costs around $800 million.13 Whether this estimate is still reasonable will depend on the choice of parameters for this latest study. In this regard Hydro Tasmania has been working with the Tasmanian Government over the past 18 months to develop preferred options and conduct preliminary investigations of the viability of a second interconnector. It is intended that this work will inform this study, in particular in relation to:

• consideration of preferred interconnector locations, siting and sizing;

• preferred technological, technical and operational details for a second interconnector; and

• estimates of likely interconnector construction and development timeframes and costs.

While these details are yet to be finalised, if developed it is likely that a second interconnector would be similar in size to Basslink, so as to support Tasmania’s power system security in the event of the sudden loss of either interconnector, and that the interconnector would be located either in the north-east or north-west of the state, close to Tasmania’s wind energy resources.

This cost would only be one component of the total investment required to ensure the effective utilisation of a second interconnector, with the total costs of associated network and supporting infrastructure upgrades and the associated financing of related renewable energy (mostly wind) proposals also requiring close consideration.

In this regard it is noted that the feasibility of a second interconnector and any associated wind energy development are closely linked, as while an interconnector may enable renewable energy development, conversely generation development will be needed to ensure a second interconnector is sufficiently utilised such that the costs of its development are justified. Should the majority of the more than 1,000 MW of wind energy under consideration in Tasmania be required to be developed to support the case for a second interconnector, this would require significant investment in supporting wind farm development. These linkages will need to be closely explored in this study.

Typically the financing arrangements for major infrastructure assets depend on the associated level of risk of the investment and the certainty of income streams. Risks of a second interconnector would be driven by both the technical challenges in building it, and its role and expected rate of utilisation in the NEM. To inform considerations by any prospective investors in a second interconnector, the final report will consider the risks associated with the investment, and how these could best be managed.

One of the key considerations in the regulatory and financing decisions for a second interconnector is whether it would be built as a regulated asset or market asset. This decision would have a key bearing on the nature of the asset’s income stream, and hence, the associated risks of any project financing.

The test to consider whether an interconnector may be regulated is the Regulatory Investment Test for Transmission (RIT-T), which identifies the most efficient option for transmission investment in the long term interests of consumers.

13 Marchment Hill 2011, RELink Preliminary Proof of Concept, page 5


The process to complete a RIT-T involves extensive stakeholder consultation and consideration of options by the proponent to determine the option with the highest net present value, based on the costs and benefits to electricity market participants.

A regulated interconnector may provide greater certainty on returns to a potential investor than a market interconnector, as the amount of revenue would be set on a fixed basis every year by the Australian Energy Regulator (AER) in accordance with the prudent and efficient costs of the asset. For market (unregulated) interconnectors, no RIT-T assessment is required; however revenues must be recovered from the electricity spot market, ancillary services markets or through concurrently providing other services.

The interaction of a second interconnector with Basslink will be significant both for the feasibility of a second interconnector and the ongoing viability of Basslink itself. Accordingly, this study will also consider Basslink’s ongoing role and potential interactions with a second interconnector.

Other considerations for investors include (but are not limited to); development, construction and technology risks, government support for the project, associated network augmentation and support costs, operational risk, possible future policy uncertainty, and any relevant interdependencies such as associated renewable energy development in Tasmania.

The various alternatives for financing and operating a second interconnector will require careful examination. Each approach comes with different risks, and potentially differences in the revenue payment profiles and payment durations. There may also be financing structures that could combine both a regulated and a market component. The sources of financing for a second interconnector and the sensitivities of potential financiers will need to be considered further but capital could potentially come from a number of sources including the CEFC, export credit agencies, project finance banks and infrastructure equity and debt funds.

Further consideration of possible investment models and their financial impacts will be detailed in the final report. This will also outline other regulatory considerations, such as the planning and environmental approvals likely to be required for a second interconnector.


Next stepsContained through this report are second interconnector considerations – indicators of where further thinking is required. These boxes signpost where the final report will need to focus in its assessment of the feasibility of a second interconnector. For ease of reference these questions have been collated at the end of this report at Attachment B.

These are complex issues and the expertise lies with no one body. To support this study a taskforce has been established comprising staff from Department of Industry, Innovation and Science, the Department of the Environment, the Australian Energy Market Commission and the Treasury. The taskforce will also be supported by input provided by the Tasmanian Government, the Australian Energy Market Operator (AEMO) and the Clean Energy Finance Corporation. Over the period ahead it is proposed that this taskforce will:

• develop credible future scenarios of how a second Interconnector might be developed; and

• undertake detailed modelling of these future scenarios, to understand underlying electricity market dynamics and to support exploration of associated regulatory, financial and business models.

In particular, based on the preferred options for the interconnector presented by Hydro Tasmania, it is proposed that the AEMO will undertake power system modelling to determine the likely market and network dynamics of each of these options in light of the expected future growth of the NEM. This would then form the basis of financial modelling, which would be developed with input from the CEFC, to assist in understanding potential investor considerations and financial structures, as well as financing considerations for related potential wind energy project investment.

Close collaboration is also expected with the Tasmanian Energy Security Taskforce, chaired by Mr Geoff Willis, to support its efforts to undertake a future energy security risk assessment for Tasmania and to report back to the Tasmanian Government with recommended actions to help manage future energy security risks.

Consultation to support this study will occur in a targeted manner, but all interested parties can participate. Submissions can be made to [email protected], and these will all be considered when developing the final report, due to the Australian and Tasmanian governments by the end of 2016.

mailto:[email protected]


The National Electricity Market Australia has one of the world’s longest alternating current systems, stretching from Port Douglas in Queensland to Port Lincoln in South Australia and across Bass Strait to Tasmania – a distance of around 5,000 kilometres as shown in Figure 2. This power system is known as the National Electricity Market (NEM).

Figure 2 – The National Electricity Market14

14 AER, 2015 State of the Energy Market, page 28


The NEM promotes efficient generation by allowing trade in electricity among Queensland, New South Wales (including the Australian Capital Territory), Victoria, South Australia and Tasmania – these different regions are linked by transmission interconnectors which allow trade to occur. Trade enhances energy security by allowing the regions to draw on a wider pool of reserves to manage system constraints and outages.

The NEM is governed by a set of national institutions established by the Council of Australian Governments (COAG) under the Australian Energy Market Agreement. The NEM’s governance structure is clearly separated between the market and system operations, economic regulation and compliance monitoring and rule-making. These are managed by the Australian Energy Market Operator (AEMO), the Australian Energy Regulator (AER) and the Australian Energy Market Commission (AEMC) respectively. State and territory governments have retained some responsibilities relating to the energy market, such as reliability standards, land use planning and safety regulation. The National Electricity Rules (NER) govern the operation of the NEM. The Rules have the force of law, and are made under the National Electricity Law (NEL). Most decisions in the electricity market are made with regard to the National Electricity Objective set out in the NEL:

‘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 –

(a) price, quality, safety, reliability and security of supply of electricity; and

(b) the reliability, safety and security of the national electricity system.

The NEM is a wholesale commodity exchange which facilitates the exchange of electricity between generators and retailers. As electricity cannot be stored easily, the market works as a ‘pool’, or spot market, where power supply and demand is matched instantaneously in real time through a centrally coordinated dispatch process.

Figure 3 depicts how the NEM functions, both as a physical and financial market. “Dispatchable” electricity generators (those which can increase or decrease their output in response to instructions by AEMO), offer to supply the market with specified amounts of electricity at specified prices for set time periods, and can re-submit the offered amounts at any time.

From all the bids offered, AEMO decides which electricity generators will be deployed to produce electricity, with the cheapest dispatchable generator put into operation first, being mindful of the physical and technical limitations of certain generators, including the speed at which a generator can change its output in response to market changes (known as ramping capability). Electricity production is matched as closely as possible to electricity consumption, with spare generating capacity kept in reserve. Electricity production is also subject to transmission limitations to ensure that the network is not overloaded.

Some generation with variable fuel sources (such as wind and large scale solar energy), which are unable to increase their generation output in response to instructions by AEMO, are subject to semidispatch market arrangements, whereby they can be directed by AEMO to decrease, but not increase, their output in response to network demands and constraints. In this way, NEM operation is designed to meet electricity demand (consumption) in the most cost-efficient way.

In calculating spot prices, AEMO must account for any limits on the inter-regional flow of electricity. When an interconnector’s capacity is reached, AEMO may need to schedule a more expensive generator to meet electricity demand within the region, even if lower priced generation is available in other regions.15

Maintaining power system security is crucial (refer to Box 2). AEMO deems the NEM is secure when all equipment is operating within safe loading levels and will not revert to an unsatisfactory operating state in the event of a single credible contingency (that is an event affecting the system which is likely to involve the failure or removal from service of one or more generating units and/or transmission elements). Secure operation depends on the combined effect of controllable plant, ancillary services, and the underlying technical characteristics of the power system plant and equipment.



Box 2 – Security definitions Energy security has varying meanings and can be used interchangably depending on the context and contemporary concerns. This report references the Australian government definition of energy security, as the adequate, reliable and competitive supply of energy where:

• adequacy is the provision of sufficient energy to support economic and social activity.

• reliability is the provision of energy with minimal disruptions to supply.

• competitiveness is the provision of energy at an affordable price.16

Where this report refers to power system security it is in regards to the definition as set out in the National Electricity Law to mean the safe scheduling and dispatch, and operation and control, of the national electricity system. AEMO is responsible for managing power system security in the NEM.

Figure 3 – How the NEM works17

16 Department of Industry, Innovation and Science 2016, Energy Security, http://industry.gov.au/Energy/EnergySecurity/Pages/default.aspx

17 AEMO 2015, Fact Sheet – the National Electricity Market, http://www.aemo.com.au/~/media/Files/About%20the%20industry/Fact%20sheets/AEMO_FactSheet_NationalElectricityMarket_2015_new.ashx, page 3

The Physical Supply System ‘The Grid’The transmission and distribution networks deliver electricity from power stations anywhere in the system to homes and business 24/7.

HOW THE NEM WORKS FLUCTUATING PRICES

The NEMThe NEM is a wholesale electricity market in which generators sell electricity and retailers buy it to on-sell to consumers. There are over 100 generators and retailers participating in the market, so it’s highly competitive and therefore an efficient way of maintaining relatively competitive electricity prices in the wholesale market.

All electricity sales are traded through the NEM. It is a wholesale market and prices fluctuate in response to supply and demand at any point in time.

THE NEM, THE GRID AND THE FINANCIAL MARKET

WORK TOGETHER

The Financial MarketThe financial market sits alongside the NEM and involves retailers and generators entering into hedging contracts to buy and sell electricity. These contracts set an agreed price for the electricity and help to manage the risk of price volatility.

NEM Market PriceThe price of electricity in the NEM is based on:

1. O�ers by generators to supply electricity to the market at particular volumes and prices at set times.

2. Demand at any given time.

Financial Market PriceTo manage price volatility, retailers and generators often enter into hedging contracts to fix the price for future electricity sales.

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Ancillary services Ancillary services are used by AEMO to manage the power system safely, securely and reliably. Ancillary services maintain key technical characteristics of the system, including standards for frequency, voltage, network loading and system re-start processes.18

All NEM ancillary services can be grouped under one of the following three major categories:

1. Frequency Control Ancillary Services (FCAS); to maintain the frequency on the electricity system close to fifty cycles per second (50 hertz).

2. Network Support & Control Ancillary Services (NSCAS); to control the voltage and power flow through the network.

3. System Restart Ancillary Services (SRAS); reserved for situations which there has been a complete or partial system black out and the electricity system must be restarted.19

Only the FCAS is a market service, whereas NSCAS and SRAS are contracted services. The FCAS market provides for eight different services to manage frequency control across different time periods. Ancillary services costs in the NEM are dependent upon the amount, urgency and time the service is required. Ancillary services are paid for by either generators or consumers. Ultimately, the consumer pays for the stable functioning of the network as these costs flow through the system.

Many participants in these ancillary markets are dispatchable and synchronous (able to generate or absorb reactive power as needed to support voltage control) forms of generation (such as coal fired power and hydroelectricity) which can respond relatively quickly to network requirements as needed. These generators provide the required frequency control and regulation to maintain secure operation of the power system and contribute to ride-through of power system disturbances via fast acting voltage control, inertia and fast acting frequency control capability when connected, regardless of output levels.20 Reducing conventional synchronous generation reduces frequency and voltage control capability and increases the complexity of managing power system security.21

Wind (in particular full converter-based turbines) and photovoltaic (PV) solar generation technologies are non-synchronous and provide ancillary services at a low level, or not at all.

Recent reduction in conventional synchronous generation in the NEM, due to the retirement of ageing fossil fuel generation and the introduction of renewable energy, has given rise to concerns about the ability of the market to efficiently respond to large swings in wind and PV generation output. Concerns have also been raised about how ancillary services for frequency control may be efficiently provided in the future.

One scenario relevant to this study is the possible closure of fossil fuel generation assets in Victoria, in particular in the Latrobe Valley. The Latrobe Valley in Victoria is responsible for 85 per cent of the state’s power generation22 and is home to around 6,000 MW of brown coal generation plant, including the Hazelwood, Yallourn and Loy Yang A and B brown coal fired power stations.

Should these generation assets close, and be replaced by intermittent generation, careful consideration will be needed of how to efficiently maintain power system security. One option may be through the provision of such services from Tasmania’s significant hydro resources, and a second interconnector, supported by strategically located reactive power plant.

18 AEMO 2016, Ancillary Services, http://www.aemo.com.au/Electricity/Market-Operations/Ancillary-Services

19 AEMO 2015, Guide to Ancillary Services in the National Electricity Market, page 4

20 AEMO and Electranet 2014, Renewable Energy integration in South Australia, page 7

21 AEMO and Electranet 2014, Renewable Energy integration in South Australia, page 7

22 LaTrobe City Council 2012, Transition to a Low Carbon Community, http://www.latrobe.vic.gov.au/Business_and_Investment/Transition_to_a_Low_Carbon_Economy


The NEM is changing

The NEM is currently undergoing substantial and sustained transformation, with market and technological changes shifting the traditional generation mix. This is providing opportunities and challenges for decision makers and is a key distinction with earlier studies into a second interconnector.

Various drivers influencing demand, including increasing network prices, increased use of decentralised and non-dispatched generation sources (such as rooftop PV) and increased uptake of energy efficiency measures, have led to flat or declining electricity demand for six consecutive years to June 2015.23 While this trend has recently been changing (AEMO forecasts an average annual growth rate of 1.8 per cent over the next three years24), low rates of growth in demand are likely into the foreseeable future.

Concurrently, the demand for new generation technologies has seen an oversupply of generation capacity in the market, causing depressed wholesale electricity prices and leading to the withdrawal of some generation. Since 2011-12, there has been over 4,500 MW of generation capacity withdrawn from the market - nearly all of which has been either coal fired or otherwise combined cycle gas turbine plant. In contrast, of the 2,500 MW of new generation technology added over the same time, most new generation has been either wind generation (61 per cent), gas fired generation in Victoria, or large scale solar plant in NSW.25 As noted above, the replacement of synchronous generation capacity with non-synchronous generation capacity has a material impact on grid stability.

Therefore there is an increasing role for interconnectors to play in maintaining power system security as the share of electricity generation coming from renewable energy sources grows, as demonstrated in the case study in Box 3. To what extent a second interconnector will contribute to greater NEM energy security more broadly will be examined as part of this study.

Box 3 – South Australia in the NEM

Wind energy development in the NEM has been highly concentrated in South Australia. The State had a total registered wind generation capacity of approximately 1,475 MW in 201526, supplying around 33 per cent of South Australia’s total generation output, compared with an average 4.9 per cent output in total across the NEM.

Due to the intermittent nature of wind, there is potential for sudden variations in generator output from wind farms. This variability in wind generation means the residual demand must be met by more responsive non-wind generators in South Australia, or by changes in power flow on the Heywood interconnector with Victoria.

When levels of wind penetration are high, frequency control and network support services can be sourced from Victoria to maintain power system security. And at times of high operational demand in South Australia, reliable supply depends on the contribution from wind generation and imports.

With Alinta Energy’s withdrawal of the Northern and Playford coal-fired power stations in early 2016, ancillary services provided by the Northern power station will need to be sourced from elsewhere.

As wind energy continues to be developed in South Australia, it will rely heavily on interconnection for reliable and secure power supply in the future. The upgrade of the Heywood interconnector will further increase import and export flow capacity. However, should an outage on the Heywood interconnector cause South Australia to temporarily separate from the NEM, the ability to maintain a secure operating state based on local generation sources may prove challenging.

As the penetration of intermittent renewable energy generation in the South Australian electricity grid continues to rise, options will need to be considered as to how to efficiently meet supply. In its 2016/17 budget the South Australian government has committed $500,000 towards a feasibility study to investigate the development of additional interconnection with the eastern states of Australia.27


24 AEMO 2015, National Electricity Forecasting Report Update, December 2015, page 7



27 Premier of South Australia media release, June 2016: http://www.premier.sa.gov.au/index.php/jay-weatherill-news-releases/697-state-budget-2016-17-study-into-new-interconnector


Interconnectors in the National Electricity Market The high-voltage transmission lines that transport electricity between adjacent NEM regions are called interconnectors. Interconnectors are used to import electricity into a region when demand is higher than can be met by local generators, or when the price of electricity in an adjoining region is low enough to displace local supply.

Queensland, New South Wales (which includes the Australian Capital Territory), Victoria, South Australia and Tasmania are linked by transmission interconnectors which are listed at Table 1.

Interconnectors Location Regulated Asset

Nominal capacity28 Owner

Terranora (Directlink)

QLD-NSW Yes NSW to QLD, 107 MW

QLD to NSW, 210 MW

Energy Infrastructure Investments (Marubeni 50%, Osaka Gas 30%, APA Group 20%

Murraylink VIC-SA Yes VIC – SA, 220 MW

SA – VIC, 200 MW

Energy Infrastructure Investments (Marubeni 50%, Osaka Gas 30%, APA Group 20%

Basslink VIC-TAS No TAS – VIC, 594 MW

VIC – TAS, 478 MW

Publicly listed Keppel Infrastructure Trust

Heywood VIC-SA Yes VIC – SA, 650 MW

SA – VIC, 650 MW

ElectraNet

QNI QLD-NSW Yes NSW to QLD, 300-600 MW

QLD to NSW, 1078 MW

Operated by Transgrid (privatised in December 2015) and Powerlink (QLD state owned)

NSW-VIC NSW-VIC Yes VIC to NSW, 700-1600MW

NSW to VIC, 400-1350MW

Transgrid/SP Ausnet

Table 1: National Electricity Market Interconnectors 29

At present, regulated interconnectors operate between all adjacent regions of the NEM, except Tasmania (Figure 4). Basslink, which connects Victoria and Tasmania and began operations in 2006, is not regulated. Further details about regulated and unregulated interconnectors are in the Interconnector Regulation and Financing chapter of this report. Basslink assigned its rights to inter-regional revenues to the Tasmanian generator, Hydro Tasmania, for 25 years (with an option to extend for a further 15 years) under the Basslink Services Agreement in exchange of an annuity style payment.

Two other unregulated interconnectors - Directlink (now called Terranora) and Murraylink — began operations in 2000 and 2002, respectively, and subsequently converted to become regulated interconnectors.30

28 Nominal is defined as the optimal capacity for a particular interconnector. The nominal capacity can be affected by adjacent transmission capability, peak loads, nearby generator outputs and availability of load or generation for control schemes and actual interconnector capacity may differ.

29 AER 2015, State of the Energy Market 2015, page 68 and AEMO 2015, Interconnector Capabilities

30 Productivity Commission (PC) 2013, Electricity Network Regulatory Frameworks- Inquiry Report Volume 2, page 734


Figure 4 – Interconnectors in the NEM31

Interconnectors enhance competition by allowing generators in a greater range of locations to compete to supply regions of the NEM, as well as improving power system security and energy security more generally. Regional circumstances – such as available generation, the cost of generation and levels of demand – determine if they are net importers or exporters of electricity.

In this regard the physical and technical capabilities of interconnectors set the upper limits on interregional trade. For example, Basslink has a technical temperature operating range of 360c at the Tasmanian end to 460c at the Victorian end, due to the physical properties of the interconnector at the points of network connection.

Additionally, the amount of power that can practically be transported by electricity interconnectors is linked to the capacity of the power lines connected to it. In effect, the maximum amount of power an interconnector can transport is irrelevant if the capacity of the lines immediately connected to the interconnector or else deeper in the electricity network constrain the amount of power available to the interconnector when needed.32

As shown in Figure 5, Queensland and Victoria typically export electricity while New South Wales (NSW) and South Australia are typically importers.

31 AEMO 2010, An Introduction to Australia’s National Electricity Market, page 15

32 PC 2013, Electricity Network Regulatory Frameworks – Inquiry Report Volume 2, page 657


Figure 5 – Annual interregional trade as a percentage of regional energy consumption33

Tasmania’s trade position fluctuates depending on the market and weather conditions. The introduction of the carbon price in July 2012 enhanced the competitive advantage of hydro generation compared with Victoria’s brown fired coal generation. This resulted in Tasmania becoming a major net exporter and, in 2013-14. Tasmania recorded the highest ratio of exports of any region since the NEM’s commencement. The abolition of the carbon price reduced the incentive to generate hydro at high levels, following which Tasmania started importing again from Victoria.34

33 AER 2015, Annual interregional trade as a percentage of regional energy consumption, http://www.aer.gov.au/wholesale-markets/wholesale-statistics/annual- interregional-trade-as-a-percentage-of-regional-energy-consumption


-40

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UtilisationFigure 6 shows Basslink’s transfer flows during 2015 calendar year. It can be noted that there was a large bias toward import into Tasmania in 2015 in response to low rainfall and to recover water storage following exports in 2013-14, with flows at the transfer limit for significant periods.

Figure 6 – Basslink flows in 2015 calendar year (MW), positive means flow from Tas-Vic, negative means flows from Vic-Tas35

Interconnectors have a crucial role in the provision of adequate supply - for example, the presence of the Basslink interconnector assisted in avoiding blackouts in Victoria during the June 2012 earthquake36 by providing additional power to Victoria following the unexpected loss of nearly 2,000 MW of generation, and provided Tasmania with adequate supply from Victorian generation when drought conditions limited hydro generation.37

Interconnector technology has changed since Basslink was constructed. Voltage Source Converter technology is now able to allow for large power transfers and high direct current voltage. Interconnectors using this technology will be able to have an increased role in providing various additional ancillary service support, such as voltage control. The technology used on Basslink is able to provide frequency control, however has some technology limitations in its capacity to provide power balance and Network Support and Control Ancillary Services to support the NEM.Second interconnector considerations

Second interconnector considerations • A second interconnector, powered by Tasmanian hydro generation (which has excellent ramping capability) could

support increased penetration of intermittent renewables and the efficient servicing of NEM peak demand growth through improved ramping capability in the Victorian market.

• The second interconnector could also help to provide ancillary services (such as inertia, frequency and voltage support services), to replace those that would be lost if brown coal generation in Victoria is retired.

• The extent to which hydro can play a role in both providing peak demand to Victorian market and meeting existing commitments to Tasmania’s industrial load will need careful consideration.

To what extent would a second interconnector address long term NEM energy security?

How might a second interconnector support the electricity industry in the future?

35 Aggregated data provided by AEMO

36 On 19 June 2012, the NEM was affected when a magnitude 5.4 earthquake struck Gippsland, Victoria at a shallow depth of 9.9km. The earthquake resulted in the tripping of five major generating units with a total of 1,955 MW and 400MW of load in across the NEM. The power system was restored to a secure operating state 58 minutes after the initial event occurred, see: http://www.aemo.com.au/Electricity/Resources/Reports-and-Documents/~/link.aspx?_id=FAEFAD9BF568444E91261194F0E5E32D&_z=z

37 PC 2013, Electricity Network Regulatory Frameworks – Inquiry Report Volume 2, page 659


The Tasmanian Energy Sector Tasmania’s economy is in a period of recovery after several years of weak economic activity, with expected economic growth of 2.5 per cent in 2015-1638 and continued growth above the long-term trend of 2 per cent in 2016-17.39 Business confidence is high, household spending is strong, the tourism industry is buoyant and international exports have returned to growth, following an extended period of subdued growth.

Despite the positive economic indicators, the Tasmanian economy is small, relying heavily on broader factors in the Australian and international economies. Tasmania’s population of 515,700 (2.2 per cent of Australia’s population)40 is expected to grow at 0.6 per cent in 2016-17, lower than the national average.41 The unemployment rate in Tasmania stood at 6.6 per cent in April 2016, compared to the Australian average of 5.7 per cent.42 GST Revenue is the largest single source of revenue for Tasmania, representing 41.3 per cent of total General Government sector revenue in 2016-17.43

In the long run, Tasmania’s low population growth rate constrains its economic performance relative to Australia as a whole. In the absence of strong population growth, it is important that the state continues to pursue other means of stimulating growth in the economy, including through investment in the industrial sector.

Energy has traditionally played a key role in the Tasmanian industrial sector, reflective of the successful implementation of the hydro-industrialisation policies of earlier Tasmanian Governments during the mid to later part of last century. Electricity intensive major industrial facilities now dominate the sector, which consumes a much larger proportion of overall state energy consumption relative to the rest of Australia. This energy is mostly in the form of electricity, which represented 42 PJ of Tasmania’s overall energy consumption of 108 PJ in 2013-14.44 This means electricity represents nearly 40 per cent of total energy consumed in Tasmania in 2013-14, compared to an Australian average of approximately 15 per cent.45 Tasmanian energy consumption by fuel type is shown in Figure 7.

Figure 7 – Tasmanian energy consumption by fuel type, 2013-1446

38 Tasmanian Department of Treasury and Finance 2016, The Budget – Budget Paper No 1, page 23


40 Tasmanian Department of Treasury and Finance 2016, Population (ABS Cat No 3101.0), https://www.treasury.tas.gov.au/domino/dtf/dtf.nsf/LookupFiles/Population.pdf/$file/Population.pdf, page 2


42 Tasmanian Department of Treasury and Finance 2016, Labour Force (ABS Cat No 6202.0), https://www.treasury.tas.gov.au/domino/dtf/dtf.nsf/LookupFiles/Labour-Force.pdf/$file/Labour-Force.pdf , page 1


44 DIIS 2015, Australian Energy Statistics 2015 (Table C), http://www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Australian-energy-statistics.aspx

45 Department of Industry, Innovation and Science (DIIS) 2015, Australian Energy Statistics 2015 (Table D), http://www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Australian-energy-statistics.aspx

46 DIIS 2015, Australian Energy Statistics 2015 (Table D), http://www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Australian-energy-statistics.aspx

39%

7%

37%

6%

11%

Electricity

Coal

Liquid fuels

Wood

Natural gas


Electricity consumption in Tasmania is dominated by four large major industrial facilities which, combined, represent more than half of Tasmania’s electricity requirements. These facilities, which require a constant supply of electricity to be viable, include:

• Bell Bay Aluminium (aluminium smelter). This facility is the largest single electricity consumer in the state, accounting for around 25 per cent of electricity consumption47

• Tasmanian Electro Metallurgical Company (manganese smelter)

• Nyrstar (zinc smelter)

• Norske Skog (paper manufacturer)

The remainder of Tasmanian demand is from commercial and residential consumers. Residential electricity consumption is high in comparison to other states and territories, due to a combination of a cold climate, relatively low penetration of natural gas, and relatively inefficient housing and building stock. This results in a relatively high electrical heating demand, and peak domestic electricity consumption is in winter. Electricity demand in Tasmania declined from 10,115 GWh to 9,752 GWh between 2010-11 and 2014-15.48 AEMO forecasts that peak (winter) demand in Tasmania will be flat and that there will be a further slight decline in the state’s overall electricity consumption between 2015-16 and 2024-25.49

Residential electricity prices are projected to increase by an average of 1.9 per cent each year from 2015 to June 2018.50 This is largely due to increasing competitive market costs, regulated network costs, and rising environmental policy costs. Regulated network costs contribute approximately 59 per cent to Tasmanian’s electricity bills.51

Tasmania’s generation and retail sectors are open to competition, while transmission and distribution services are provided by a government owned utility.52 Key industry participants include:

• Hydro Tasmania – the major electricity generator (Tasmanian Government owned);

• TasNetworks – provides regulated transmission and distribution services (Tasmanian Government owned);

• Basslink Pty Ltd – owns and operates the Bass Strait interconnector and is classified as a transmission network service provider under the NEM (privately owned);

• Aurora Energy – the major electricity retailer and the only retailer required to supply electricity to small consumers at regulated prices (Tasmanian Government owned); and

• ERM Power Retail Pty Ltd and Progressive Green Pty Ltd – provide retail services to Tasmanian commercial and industrial sector (privately owned), but not residential customers.

Basslink Facts • Commissioned in April 2006 at a total cost of $874 million, Basslink runs between George Town in Tasmania

and Loy Yang in Victoria.53 Basslink is the world’s second longest subsea electricity interconnector. Basslink has a nominal capacity to export 594 MW from Tasmania to Victoria, and import 478 MW.54 Basslink can export up to 630 MW from Tasmania to Victoria for limited periods.55

47 DIIS 2016, estimate based on internal data

48 Office of the Tasmanian Economic Regulator (OTTER) 2015, Energy in Tasmania – Performance Report 2014-15, page 9

49 AEMO 2015, Update – National Electricity Forecasting Report December 2015, pages 6-7

50 AEMC 2015, Residential Electricity Price Trends – Tasmania fact pack and media release, http://www.aemc.gov.au/Markets-Reviews-Advice/2015-Residential-Electricity-Price-Trends/Final/State-and-territory-fact-pack/Tasmania-fact-pack-and-media-release.aspx

51 AEMC 2015, Residential Electricity Price Trends – Tasmania fact pack and media release, http://www.aemc.gov.au/Markets-Reviews-Advice/2015-Residential-Electricity-Price-Trends/Final/State-and-territory-fact-pack/Tasmania-fact-pack-and-media-release.aspx

52 Effective retail competition in the small consumer market has not yet established in Tasmania, as indicated in the AEMC’s 2015 Retail Competition Review.

53 Electricity Supply Industry Expert Panel 2012, An Independent Review of the Tasmanian Electricity Supply Industry – Final Report Volume II March 2012, http://www.electricity.dpac.tas.gov.au/__data/assets/pdf_file/0007/160585/Final_Report_Volume_II.pdf, page 33.

54 AEMO 2015, Interconnector Capabilities for the national electricity market, page 9

55 OTTER 2015, Energy in Tasmania – Performance Report 2014-15, http://www.energyregulator.tas.gov.au/domino/otter.nsf/LookupFiles/Energy_in_Tasmania_-_Performance_Report_2014-15.pdf/$file/Energy_in_Tasmania_-_Performance_Report_2014-15.pdf, page 68


Tasmania’s Generation MixTasmania’s energy security challenges are uniquely different to the rest of the NEM, where the predominance of fossil fuel generation and the availability of fuel means that electricity demand is largely constrained by the capacity of generators and the network to generate and deliver power as required. As a result, the NEM can be capacity constrained however is not typically constrained by resource availability. Tasmania’s ability to produce electricity from its hydro system (which is able to rapidly change output in response the demand fluctuations) means that it is generally not constrained by generation capability, however may be constrained by network capability and over time it is limited by the availability of water. Thus, Tasmania has mostly energy constraint challenges rather than capacity constraints.56

As demonstrated in Table 2, in 2014-15, around 99 per cent of total electricity generation in Tasmania was from renewable sources. This is the highest penetration of renewable energy generation among all Australian states and territories. Tasmania’s energy generation is underpinned by hydropower, which represented around 89 per cent of total electricity output in 2015. Wind power provided the second largest contribution to electricity generation, providing an estimated 10 per cent of the state’s output in 2015. Other sources of generation include small-scale solar, natural gas, oil products and biomass. An overview of Tasmania’s generation and transmission system is at Figure 8.

Figure 8 – Transmission infrastructure for the NEM – location of Tasmanian power stations57

Hydro Tasmania operates 30 hydropower stations in Tasmania with a total generation capacity of 2281 MW,58 using six major water catchments and 55 major dams.59 This represents around 29 per cent of all of Australia’s existing hydro capacity.60 Heavy reliance on hydro generation leaves Tasmania exposed to the risk of variations in rainfall. This risk is mitigated to an extent by Hydro Tasmania’s significant water storage capability, which supports its generation capacity. The Tasmanian government has committed to pursue a potential 10 per cent additional hydro generation output from its existing asset base.61 This is expected to be achieved through enhancements to its existing generation assets.

Tasmania has world class wind energy resources, with many areas of the state experiencing strong and consistent wind speeds. Tasmania currently has several wind farms, with a total generation capacity of 310 MW.62 The largest wind farms are Woolnorth Bluff Point Wind Farm (65 MW), Woolnorth Studland Bay Wind Farm (75 MW) and Mussleroe Wind Farm (168 MW) all of which are managed and operated by Woolnorth Wind Farm Holdings - a joint venture between Hydro Tasmania and Chinese renewable energy business Shenhua Clean Energy Holdings Pty Ltd.63

56 Electricity Supply Industry Expert Panel 2011, Tasmania’s Energy Sector – An Overview, http://www.dpac.tas.gov.au/__data/assets/pdf_file/0017/141803/Tasmania_s_Energy_Sector_-_an_Overview.PDF, page 38

57 AEMO 2015, NEM Regional Boundaries Map, http://www.aemo.com.au/Electricity/Planning/Related-Information/Maps-and-Diagrams


59 Hydro-Electric Corporation 2016, How we produce hydropower, http://www.hydro.com.au/energy

60 Geoscience Australia 2014, Australian Energy Resource Assessment, page 230

61 Tasmanian Department of State Growth 2015, Tasmania’s Energy Strategy – Restoring Tasmania’s Energy Advantage, page 29

62 Clean Energy Council (CEC) 2016, Clean Energy Australia Report 2015, page 54

63 Hydro-Electric Corporation 2016, Wind Power, http://www.hydro.com.au/energy/our-power-stations/wind-power

WesleyVale

Waddamana

Ulverstone

Tribunna

Smithton

Sheffield Scottsdale

St Leonards

St Marys

Sorell

Savage River

Rosebery

RokebyRisdon

Railton

Queenstown

Que

Port Latta

Palmerston

Norwood

Newton

New Norfolk

Mowbray

Mornington

Lindisfarne

Knights RoadKingston

Kermandie

Huon River

Hampshire

Hadspen

Farrell

Emu Bay

Electrona

Devonport

Derwent Bridge

Derby

Creek RoadChapel Street

Castle Forbes Bay

Burnie

Bridgewater

Boyer

Avoca

Arthurs Lake

Yadnarie

Wudinna

Woomera

WhyallaTerminal

Whyalla Central

WaterlooEast

Waterloo

Tungkillo

TemplersTemplers West

Tailem Bend

StonyPoint

South East

Snowtown

Robertstown

Red Hill

PortPirie

Port Lincoln

Pimba

ParaRoseworthy

Olympic Dam West Olympic Dam North

North West Bend

Neuroodla

Mt Gunson

Mt Gambier

Mt. Barker SouthMt. BarkerMorphett Vale East

Monash

Mokota

Mobilong

Millbrook

Middleback

Mayura

Mannum

LeighCreek SouthLeighCreekCoalfield

Keith

Kincraig

Kadina East

Hummocks

Happy Valley

Dorrien

Davenport

Dalrymple

Cultana

Clements Gap

Clare North

Cherry Gardens

Bungama

Brinkworth

Blyth West

Blanche

Berri

Belalie

Baroota

Angas Creek

Adrossan West

4

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Geelong

Fosterville

Elaine

Dederang

Cranbourne

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APD

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Williamsdale

Wellington TownWellington

Waratah West

Hawks Nest

Wagga 330

Wagga 132 Wagga North

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Tumut

Tuggerah

Tomago

Terranora

Temora

Tenterfield

Taree

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Sydney South

Sydney East

Sydney North

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Steeple Flat

Singleton

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Regentville

Raleigh

Queanbeyan

Port Macquarie

Parkes

Panorama

Orange North

Nyngan

Newcastle

Nevertire

Narromine

Narrabri

Nambucca

Muswellbrook

Murrumburrah

Munyang

Munmorah

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Jindera

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Holroyd

Hillston

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CapitalCanberra

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Brandy Hill

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Wycarbah

Boyne Island

Wotonga

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Woleebee Creek

Woolaga

Wandoan South

Western Downs

Warwick

Wandoo

Turkinje

Tully

Traveston

Townsville South

Townsville ZincTownsville East

Teebar Creek

TangkamTorrington

Halys

Stanthorpe

Ruby

Ross

Rolleston

Rockhampton

Raglan

Proserpine

PostmansRidge

Port Douglas

Pioneer Valley

Peak Downs

Pandoin

Palmwoods

Oonie

Norwich Park

Nth Goonyella

Newlands

Stony Creek

Nebo

McLaren

MoranbahMoranbah South

Murarrie

Mungar

Moura

Maryborough

Mudgeeraba

Mt England

Molendinar

Mindi

Middle Ridge

Memooloo

Mackay PortsLouisa Creek

Loganlea

Lilyvale

Larcom Ck

Kumbarilla Park

King Creek

Kilkivan

Kidston

Kemmis

Kamerunga

Isis

Innisfail

Ingham South

Gympie

Gregory

Greenbank

Grantleigh

Goonyella Riverside

Gin Gin

Gladstone Sth

Georgetown

Gatton BlackwallRocklea

Abermain

Garbutt

El Arish

Edmonton

Eagle Downs

Dysart

Dingo Duaringa

Dan Gleeson

Dalby

Copabella

CooroyCooran

Columboola

Collinsville

Bowen North

Strathmore

Condabri South

Condabri North

Condabri Central

Clermont

Clare South

Chalumbin

Cardwell

Calliope River

Cairns

BurtonDowns

Bundaberg

Broadsound

Bollingbroke

Clayton

Chinchilla

Wurdong

Calvale

Bulli Creek

BouldercombeBlackwater

Bluff

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Belmont

Baralaba

Aramara

Alligator Creek

Alan Sheriff

Blackstone

Lockrose

Wilmont

Tribute

John Butters

Trevallyn

Tods Corner

Lake Echo

Bell BayTamar Valley

Studland Bay

RowallanReecePoatina

Paloona

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Devils Gate

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Oaklands Hills

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West Kiewa

Jeeralang

Hazelwood

Bogong

Dartmouth

McKay Creek

EildonChallicum Hills

Bald Hills

Anglesea

Bairnsdale

Woodlawn

Warragamba

Wallerawang

Vales Point

Uranquinty

UpperTumut

LowerTumut

Taralga

Tallawarra

Royalla

Nyngan

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Jindabyne

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Wivenhoe

Tarong Nth.

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Stanwell

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Mackay

Kogan Ck

Invicta Mill

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Natural gas is also available for both commercial and domestic consumption in Tasmania. The Tasmanian Gas Pipeline (TPG) is a natural gas transmission pipeline from Longford in Victoria to Bell Bay, Tasmania was completed in 2003, allowing the importation of natural gas from Victoria. The TGP consists of a mainline that links Longford in Victoria with Bell Bay, Rosevale and Springfield near Launceston, and Bridgewater near Hobart in Tasmania. There is also a lateral pipeline that connects with the mainline at Rosevale and extends northwest to Devonport, Burnie and Port Latta.64

The TGP supplies gas to the Tasmanian Gas Network – which runs past 46,500 commercial and residential consumers,65 the Tamar Valley gas fired power station, the Rio Tinto Alcan Bell Bay aluminium smelter and the Australian Bulk Minerals’ iron ore processing facility at Port Latta. Gas is sourced from the Victorian offshore Gippsland Basin gas fields.

The TGP remains an uncovered pipeline under the National Gas Law and is therefore not subject to regulation under the National Gas Rules.

The TGP capacity is 129 terajoules (TJ) per day but it has been underutilised. In 2014-15 it was reportedly operating at less than 20 per cent capacity due to low demand from the Tamar Valley Power Station (TVPS).66 Figure 9 demonstrates the TGP flows since June 2007 and the increase in gas imports in January 2016 to supply the Tamar Valley gas fired power station as a result of Basslink’s interruption.

Figure 9 - Tasmanian Gas Pipeline historical daily flows June 2007 to June 2016 (TJ)67

64 AEMC 2016, TAS: Tasmanian Gas Pipeline, http://www.aemc.gov.au/Energy-Rules/National-gas-rules/Gas-scheme-register/TAS-Tasmanian-Gas-Pipeline

65 OTTER 2015, Energy in Tasmania – Performance Report 2014-15, page 132


67 AEMO 2016, Natural Gas Services Bulletin Board, https://gbb.aemo.com.au/Reports/Actual%20Flow.aspx

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The TGP also offers surplus linepack capacity (essentially an ability to increase the gas pressure and hence the amount of gas in the pipeline) as storage to the Victorian Declared Transmission System. Enhanced storage facility will allow for increased injections into the Victorian system from 2016 when needed. The TGP supplies the gas-fired TVPS, which is owned by Hydro Tasmania and is the state’s only major thermal generator. The TVPS consists of open cycle gas turbines with a capacity of 178 MW and a combined cycle gas turbine with a capacity of 209 MW.68 Tasmanian electricity generation and demand for the previous three years is summarised in Table 2.

2012-13 2013-14 2014-15

Total electricity demand (GWh) 9,763 9,795 9,752

Total electricity generated (GWh) 12,786 13,813 9,083

Hydro generation (GWh) 10,627 11,925 8,167

Wind generation (GWh) 463 996 898

Gas generation (GWh) 1,696 893 18

Basslink imports (GWh) 255 20 2203

Basslink exports (GWh) -2419 -3113 -772

Table 2 – Total Tasmanian electricity generation by source (GWh), 2012-13 to 2014-15. 69

Second interconnector considerations • There is the potential for a second interconnector to help to ensure supply in Tasmania but it is not a solution to

Tasmania’s energy constraint challenges in the short term. Other options, such as diversification of Tasmania’s generation mix and energy efficiency may need to be adopted.

To what extent could a second interconnector address Tasmania’s long-term energy constraint challenges?


69 OTTER, Energy in Tasmania – Performance Reports (various) and data provided by OTTER (Does not include solar generation data)


Australian Renewable Energy Industry Development

Carbon and Renewable Energy PoliciesAcross all Australian governments, there is a broad range of policies and measures in place which encourage renewable energy development as a means to achieve various climate change, sustainability and renewable energy industry development objectives.

As noted in the introduction, the Australian Government has a suite of measures in place to achieve its commitment to reduce national greenhouse gas emissions by 26 to 28 per cent below 2005 levels by 2030, with key measures in this regard including the Emissions Reduction Fund (ERF), Safeguard Mechanism and the Renewable Energy Target (RET).

Central to Australia’s carbon emission reduction efforts is the ERF, which provides $2.55 billion for the purchase of Australian Carbon Credit units through a series of reverse auctions. The fund includes an additional ‘safeguard’ mechanism to ensure large emitters (over 100,000 tonnes CO2-e p.a.) do not increase emissions above a baseline (historical max emissions between 2009-10 – 2013-14). Of note, this safeguard works differently for the electricity sector, where a baseline will apply across the electricity sector as a whole, with individual baselines to apply to facilities in the event that the sectoral-baseline is exceeded.

The RET scheme is the primary way in which renewable energy is supported in Australia. The scheme comprises two components, namely:

• A Large Scale Renewable Energy Target, which encourages investment in large scale renewable energy generators to achieve 33,000 GWh of additional renewable energy generation by 2020; and

• A Small Scale renewable energy scheme (SRES), which supports small-scale installations like household solar panels and solar hot water systems.70

Operation of the RET is supported by the activities of the CEFC and the Australian Renewable Energy Agency (ARENA), which have been established with mandates which collectively include support for research, development, commercialisation and deployment of clean energy technologies in Australia.

The Australian Government has also committed to a target of improving Australia’s energy productivity by 40 per cent between 2015 and 2030, which is to largely be met through the COAG Energy Council’s National Energy Productivity Plan. The Plan aims to achieve this target through measures designed to enable more productive consumer choices and energy services.

As outlined in Attachment C, each state and territory government is implementing measures to achieve carbon emissions reduction, energy productivity or increased renewable energy development. In Tasmania and Victoria, key government initiatives include:

• A Tasmanian Government emissions reduction target of 60 per cent below 1990 levels by 2050.71

• A Tasmanian Government commitment to pursue the potential for additional 10 per cent hydro generation output from its existing hydro asset base.72

• A Victorian Government announcement of a series of five year interim targets with the goal of achieving the overall target of net zero carbon emissions by 2050.73

• A Victorian Government Renewable Energy Target of 25 per cent renewable energy by 2020 and 40 per cent by 2025.74

70 Clean Energy Regulator (CER) 2015, About the Renewable Energy Target, http://www.cleanenergyregulator.gov.au/RET/About-the-Renewable-Energy-Target

71 Tasmanian Department of Premier and Cabinet 2016, Embracing the climate challenge: Tasmanian’s draft climate change action plan 2016-2021, page 8

72 Tasmanian Department of Premier and Cabinet 2016, Embracing the climate challenge: Tasmanian’s draft climate change action plan 2016-2021, page 19

73 Victorian Department of Environment, Land, Planning and Water 2016, Climate Change, http://www.delwp.vic.gov.au/environment-and-wildlife/climate-change

74 Victorian Premier 2016, Media Release (15 June 2016) Renewable Energy Target to Create Thousands of Jobs, https://www.premier.vic.gov.au/renewable-energy-targets-to-create-thousands-of-jobs/


Second interconnector considerations • Across all Australian governments, there is a broad range of policies and measures in place to encourage

renewable energy development, as a means to achieve various climate change, sustainability and renewable energy industry development objectives (see Attachment C).

• There may be some potential for renewable energy development in Tasmania to be complementary to Victoria’s plans to expand its renewable energy growth.

What role could Tasmanian renewable energy play in meeting the Australian Government’s climate change commitments?

Renewable Energy GrowthCurrent and previous government initiatives have stimulated significant growth in renewable energy in recent times, particularly in wind energy, from a base in the year 2000 consisting nearly entirely of hydro generation capacity. Across the NEM, wind generators accounted for 6.6 per cent of generation capacity and generated 4.9 per cent of total output in 2014-15.75

Solar power has seen significant growth recently, largely due to environmental policies such as state and territory government feed in tariffs and the RET. Almost 1.5 million households have installed small-scale solar PV systems, and total installed capacity in the NEM reached 3,700 MW in 2014-15, equivalent to 8 per cent of installed generation capacity and 2.7 per cent of NEM electricity requirements.76

Large scale solar generation has been slower to develop across Australia, due to having relatively higher costs than wind energy. However, costs are rapidly decreasing, and some large scale plants have either recently been developed or are currently under development, with support from the ARENA and the CEFC. The current mix of generation in the NEM can be seen in Figure 10. Small scale rooftop PV is treated as negative demand in the NEM, so generation from this source is not captured in the Figure 10 and Table 3 below.

Figure 10 – National Electricity Market generation capacity by region and fuel source, 30 June 201577

75 AER 2015, State of the Energy Market Report, page 29

76 AER 2015, State of the Energy Market Report, page 30

77 AER 2015, State of the Energy Market Report; page 29 (Figures based on AER and AEMO data)

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Development of wind, solar and other new renewable technologies is set to rapidly continue through until 2020. The Clean Energy Council (CEC) has recently determined that over 6,000 MW of renewable energy generation capacity is required by 2020 to meet remaining RET liabilities.78 Prospects for further growth in renewable energy generation, after the 2020 large scale RET is met, largely depend on future policy settings and electricity market conditions.

There is no shortage of prospective renewable energy generation projects proposed across the NEM to meet the RET and other renewable energy development incentives. In its 2015 Electricity Statement of Opportunities, AEMO notes it is tracking 21,689 MW of proposed new large scale generation capacity, including 55.4 per cent (12,021 MW) wind, 27.9 per cent (6,040 MW) gas, 9.2 per cent (2,000 MW) coal, 1.3 per cent (287 MW) solar, 3.1 per cent hydro projects and 3.1 per cent of other forms of generation. A breakdown of this proposed generation by state is included in Table 3.

State Coal Open cycle gas turbine

Closed cycle gas turbine

Solar Wind Water Biomass Geo-thermal Other Total

TAS - - - - 329 302 - - - 631

VIC - 1150 500 60 2765 34 - - - 4509

NSW/ACT

2000 1050 75 107 4636 - 8 - - 7876

QLD - 2545 - 70 1328 330 8 - 150 4431

SA - 570 150 50 2963 - - 510 - 4243

Table 3 – Summary of AEMO SOO 2015 data of proposed large-scale new generation capacity (MW) by state79

Which of these, and any other potential renewable energy generation projects, will be developed to meet remaining RET liabilities is unknown, noting not all of these projects will be commercially viable or otherwise able to attract sufficient investor interest to proceed. Based on current technology costs, it is expected that a significant mix of wind energy projects will be developed, along with a smaller proportion of other renewable energy technologies.

Over the longer term wind and solar energy are expected to have an increasingly significant role in the electricity market. As outlined in Figure 11, cost projections expect wind and solar technologies to be among the cheapest forms of generation in the NEM by 2050.80 However, Australia has diverse and plentiful forms of renewable and other generation technologies which may also play an important role, depending on how technology costs evolve.

78 CEC 2016, Progress and Status of the Renewable Energy Target, page 2

79 AEMO 2015, Electricity Statement of Opportunities, aggregated data

80 Bureau of Resources and Energy Economics 2013, Australian Energy Technology Assessment Update, page 61


Figure 11 – Expected Levelised Cost of Electricity from different generation technologies in NSW in 2050, using AETA 2013 Model Technologies, with carbon price set to zero81

Where in Australia renewable energy generation is deployed in the future will depend largely on the available resources and the costs of delivering this power to market. In 2012, AEMO was tasked by the former Department of Climate Change and Energy Efficiency (DCCEE) to undertake a study which explores two future scenarios featuring a NEM fuelled entirely by renewable resources, as a means of contributing to the broader understanding of renewable energy. While the study outcomes are highly dependent on the underlying assumptions and constraints underpinning the study (and so could change significantly depending on how the market actually develops), they present an early consideration of how renewable energy growth could occur in the future.

81 Bureau of Resources and Energy Economics 2013, Australian Energy Technology Assessment Update, page 56


Based on the analysis by AEMO in the 100 per cent renewable energy study, Figure 12 shows regions of the NEM where various types of renewable energy technology development are more likely to occur, based on the strength of available resource and consideration of issues that might limit access to those resources.

Figure 12 – AEMO modelling of possible long term Australian renewable energy development locations, based on renewable resource82

In its study AEMO also identifies where significant amounts of generation would likely be connected to the existing grid to service the major load centres in the NEM, as displayed in Figure 13.

Figure 13 – AEMO high level analysis of likely transmission options to deliver 100 per cent renewable energy83

The final long term locations and mix of renewable energy generation is unknown. Ultimately, the mix will depend on a complex range of factors affecting the relative competitiveness of specific sites including; resource quality, electricity market conditions, policy settings and relevant state planning processes.

82 AEMO 2013, 100 per cent Renewables study Modelling outcomes, page 19

83 AEMO 2013, 100 per cent Renewables study Modelling outcomes, page 20


Tasmania’s Renewable Energy PotentialThe strength of Tasmania’s renewable energy resources is well recognised. Tasmania is a leader in renewable energy generation within Australia, and has significant potential for large scale renewable energy generation into the future, particularly with regard to generation based on wind, hydro, biomass and (depending on future technical and commercially viability) marine energy sources.

Development of hydro generation in Tasmania is fairly mature and there are limited prospects for the development of new generation assets. However, an additional 10 per cent generation output could be achieved through enhancements to existing generation assets.

Similar to other regions of Australia, over the last five years there has been a relatively high uptake of residential rooftop PV across Tasmania, driven by falling PV costs, large increases in electricity prices and government subsidies. However, growth in rates of solar PV installation has declined recently, possibly as a result of lower feed-in-tariffs and reduced subsidies available through the SRES. Installation of PV is predicted to remain constant as PV costs continue to fall.84

There is now 91 MW of domestic solar capacity85 across Tasmania, with growth in the domestic market forecast to continue to around 300 MW in 2024.86 Despite this strong small-scale market growth, it is questionable whether large scale solar will be competitive in Tasmania, due to the relatively stronger levels of solar irradiance experienced in other regions in the NEM.

Biomass is a small but growing area of renewable energy development for Tasmania particularly following recent changes to allow native wood waste from approved sources as an eligible renewable energy source under the RET. The Tasmanian Government is currently supporting investigations into how to take advantage of Tasmania’s forest, cropping and weed residues. There are also excellent wave resources along the west Tasmanian coastline, and some tidal resources in the Bass Strait to the north east of the state, as well as some geothermal potential in the north east corner of the state. The extent to which these resources are developed will depend on technology advancements, the feasibility of using the resource and cost reductions for these generation sources.

Second interconnector considerations • Network augmentation and other supporting infrastructure will need to be built to enable the efficient delivery of

power from Tasmanian renewable projects to a second interconnector and to fully take advantage of the benefits that Tasmania’s hydro resource could offer.

• Consideration will be needed of how to attract sufficient investment to enable all this infrastructure to proceed.

What supporting infrastructure is required to maximise the benefits from Tasmanian renewable energy and how might it be financed?

At present there are multiple prospective wind energy generation sites under consideration in Tasmania. Various media reports and industry publications suggest that there is the potential for wind farm sites totalling well over 1,000 MW of generation capacity under consideration, mostly in the north west and north east areas of the state. An advantage of these locations is that many of these sites are likely to be in locations with low populations and so may avoid local community objections.


85 CEC 2015, Clean Energy Australia Report 2015, page 26

86 Tasmanian Department of State Growth 2015, Tasmania’s Energy Strategy – Restoring Tasmania’s Energy Advantage, page 8


Whether these resources are developed will depend on the business case for doing so and the appetite for such commercial investment. There are numerous factors that drive the cost component of the business case, however a key component would include the ability for Tasmanian generation to rapidly dispatch power and provide ancillary services to the market, particularly at times of peak demand. Tasmania has some natural advantages in this regard – in particular:

• the breadth and strength of its renewable energy resources, noting the significant water storage capacity of its hydroelectric system and its strong and consistent wind regimes; and

• the responsiveness of its existing generation fleet, noting the output of hydro generation is generally able to be rapidly changed in response to demand or intermittent renewable generation (such as wind power) fluctuations.

With associated infrastructure upgrades, there may be opportunity for the output from Tasmania’s large hydro generation capacity to be combined with its intermittent renewable energy sources to provide constant and smoothed power output to service demand. Further, and particularly with increased development of Tasmanian water reservoirs and pumped hydro systems, hydro capacity may be able to also offer the potential for large scale energy storage, which could be used to store excess wind energy. This possibility will need to be balanced against factors such as the concentration of intermittent energy sources in a single, small geographical area, which will increase the need for strong networks and ancillary services to support the loss of the natural benefit provided through diversity in geographical spread.

These prospects may present attractive opportunities for the Tasmanian renewable energy industry in the future. However, any advantages would need to be considered against various challenges. There would need to be significant expenditure to develop these wind farm projects, supporting infrastructure such as associated network upgrades and development of further interconnection, in both the Tasmanian and Victorian markets, as well as associated enhancement and development of Tasmania’s hydro generation assets to realise these opportunities. The case for this expenditure has not yet been made. The costs and benefits of these options and to what extent renewable projects could proceed without a second interconnector will be a key consideration in the final report.

Second interconnector considerations • Tasmania has an abundance of renewable energy resources and has significant potential for large scale renewable

energy generation into the future, particularly with wind and hydro generation.

To what extent would a second interconnector facilitate renewable energy growth in Tasmania?

How do the prospects for Tasmanian renewable energy compare to other regions in the NEM?


Interconnector Regulatory and Financing Considerations

Regulatory considerationsUnder the energy regulatory framework there will be different consequences depending on whether a new interconnector is built as an unregulated asset or as a regulated asset.

Other than Basslink, all interconnectors in Australia are currently regulated, though two were originally unregulated and then converted to being regulated.

Key consequences of an interconnector being regulated or unregulated include:

• whether the regulatory test for transmission (RIT-T) must be met; and

• whether revenues of the interconnector are set annually by the AER.

Whether an interconnector is regulated or unregulated, it will still need to be registered with AEMO.

Regulated asset and the RIT-T

The key test when considering whether an interconnector may be regulated is the Regulatory Investment Test for Transmission (RIT-T). This test identifies the most efficient option for transmission investment. Given that it generally directs investment in the long term interests of consumers, it aligns with the overall aims of the regulatory framework, as set out in the National Electricity Objective. It provides a transparent and consistent approach to transmission investment that considers investments on a NEM-wide basis.

The RIT-T is a framework set out in the National Electricity Rules and administered by the AER. It must be applied by the proponents of all new transmission augmentations (including interconnectors) greater than $5 million in estimated cost.

The purpose of the RIT-T is to identify the option for investment that maximises the present value of net economic benefit to those who produce, consume and transport electricity in the NEM.87 It is applied as a cost-benefit analysis of credible options in which only the costs and benefits to the electricity market and its participants – as opposed to costs and benefits more broadly - may be taken into account. Credible options cover a range of technically feasible solutions which could address the need for transmission investment. In the case of the second interconnector, this could include a range of different technical designs and capacity options.

Benefits must be determined by comparing the value of the base case against a number of modelled scenarios of future supply and demand. Benefits that must be taken into account include differences in fuel costs as a result of changes in generator dispatch, changes in costs for third parties (such as timing of new plant), competition benefits, differences in the timing of transmission investment, and changes in voluntary load curtailment. Other benefits agreed to by the AER may also be taken into account.

The costs to be taken into account in the RIT-T include the costs of construction, ongoing operation and maintenance costs and the costs of complying with laws and regulations. Any other costs that are determined to be relevant by the proponent, and agreed to by the AER, may also be included.

The RIT-T process involves extensive stakeholder consultation. Once the investment proponent has identified the option with the highest Net Present Value (NPV) according to the RIT-T, it may ask the AER for a determination to confirm this.88

An interconnector that is regulated will have its revenue determined by the AER. The AER sets revenues on an annual basis and these revenues are then recovered from electricity consumers. This annual revenue is based on the size of the approved asset base for the interconnector and its prudent and efficient costs. The consumers from whom the revenue would be recovered would be those in the state or territory connected by the interconnector. In this case, Tasmanian and Victorian electricity consumers would pay via the network charges in their electricity bills. The proportion of costs recovered from consumers of each state or territory will be linked to the proportion of time that the flows are towards that region.

87 National Electricity Rules, clause 5.16.1(b)

88 National Electricity Rules, clause 5.16.6(a)


Unregulated assetNo RIT-T assessment is required for an interconnector to operate in the NEM as an unregulated asset. A key consequence of being unregulated is that the revenues of the interconnector would not be set by the AER. Instead, the interconnector would earn revenues by participating in the electricity spot market, ancillary services markets or through concurrently providing other services.

It is possible for an interconnector that is initially unregulated to subsequently be converted to regulated status. This is subject to AER approval. In the past when the AER has made such decisions it has applied the equivalent of the RIT-T.

Murraylink (South Australia – Victoria) and Directlink (NSW – Queensland) were initially unregulated interconnectors, but have subsequently obtained approval to convert to regulated status.

The differences between a regulated and market interconnector are summarised in Table 4 below.

Regulated Interconnector Market Interconnector

• Must pass the RIT-T.

• AER will determine efficient cost of the interconnector.

• Costs recovered over the economic life of the asset.

• Costs recovered from consumers through regulated network charges (a component of electricity bills).

• Sharing of costs across consumers in different jurisdictions is determined under the regulatory rules.

• Greater regulatory risk (described further below).

• Not subject to AER regulation or the RIT-T.

• Participates in the wholesale electricity market (earning revenue buying electricity and selling electricity) or provides ancillary services.

• Could be underwritten by a contract under which wholesale market revenues are exchanged for a fixed revenue stream, and contract determines cost recovery including timing and which jurisdiction the costs are recovered from.

• Could be funded by a range of bodies including governments, private investors and the CEFC.

• Greater credit risk.

Table 4 – Differences between a regulated and market interconnector

Second interconnector considerations • A key consideration for the regulatory arrangements and financing decisions for a second interconnector

is whether it is a regulated or market (unregulated) interconnector.

Is a second interconnector in the long term interest of consumers and how would its costs and benefits be assessed under the RIT-T?

Supporting infrastructureIn addition to the infrastructure that forms part of the interconnector itself, additional infrastructure may be needed to support the interconnector. This may include strengthening the network belonging to TasNetworks near where it meets the interconnector. Further, if the interconnector is designed to facilitate the development of renewable energy in Tasmania, there may also need to be strengthening of the existing network near where the renewable energy is located, or connections from the new generators to the transmission network. In addition, there will likely need to be some investment at the connection point to the Victorian network.

Some of this additional infrastructure may be regulated where it passes the RIT-T and forms part of the shared network. In this case any costs would be subject to AER revenue determinations and may be passed on to consumers in network charges.

On the other hand, some parts of new connections will be funded by the connecting party, that is, the new renewable energy generator.

Consideration will need to be given to how this additional infrastructure is to be financed.


While outside the scope of NEM regulatory arrangements, a second interconnector may require changes to Hydro Tasmania’s water infrastructure and the way this is managed. How this infrastructure is developed and how water flows are managed will determine what generation capacity is available to the interconnector and at what times. This will be relevant to investors financing new investment.

Second interconnector considerations • Augmentation of networks in Tasmania and Victoria and other infrastructure build will need to occur to enable the

efficient delivery of power between Tasmania and Victoria.

What supporting infrastructure is required and how might it be financed?

Planning and Environmental approvalsRequirements for planning and environmental approvals will be discussed in the final report.

Commercial and financing considerationsSignificant investment would be required to finance a second interconnector, with a recent study estimating capital costs of around $800 million.89 Consideration will need to be given to the key risks facing an investor and how these could be managed to provide sufficient long term certainty to attract investment. Given the life of an interconnector could be around 40 years, net present values and therefore project viability will be sensitive to the cost of financing.

These considerations will impact the models under which financing could occur and the overall outcomes for consumers of electricity.

In addition, consideration should also be given to the approach to financing any supporting infrastructure necessary for a second interconnector to operate.

Regulated versus Unregulated

One of the most important factors bearing on risks a for investors is the certainty of future revenues associated with the investment. If the second interconnector were regulated, as described above, its revenues would be set by the AER and fixed annually, regardless of flows or the spot prices in Tasmania and Victoria. From a timing point of view, these revenues would allow investors to recover the regulatory value of the asset over its life. This could, other things being equal, provide greater certainty for investors on returns than if the interconnector was unregulated. Some risks would remain however. These would include risks around the revenue the AER would set, and in particular:

• What the AER would set as the regulatory asset base for the interconnector

• What rate of return the AER would apply to that asset base and how the AER would approach changing the rate of return at each determination

• How the AER would set performance and quality incentives and what risks would this mean for the revenues

• What risks the AER would allow to be passed through to consumers, and what risks would remain for investors

• The risk of the AER’s approach to revenue determinations changing during the economic life of the interconnector.

For a market interconnector, revenues would be more variable, without additional commercial arrangements, and would largely depend on the spot price of electricity in Victoria and Tasmania and the flows across the interconnector. Other sources of revenue could include capacity payments (similar to the Basslink services agreement) participation in ancillary services markets, or concurrently providing other services such as telecommunications.

The different levels of risk inherent in regulated and unregulated assets would affect financing options for a second interconnector. Higher risk projects generally translate into lower gearing levels (proportion of debt to equity) and investors seeking higher equity returns. Conversely, for lower risk projects, higher gearing levels and a lower cost of capital would likely be available.

89 Marchment Hill 2011, RELink Preliminary Proof of Concept, page 5


Interaction with Basslink

There would be an interaction between a second interconnector – whether regulated or unregulated – and the existing Basslink interconnector. A new interconnector could impact Basslink through increased transmission flows between Victoria and Tasmania, which could change the relative spot prices between these jurisdictions. If having a second interconnector were to affect the way Hydro Tasmania managed its water resources, this could also have a bearing on Basslink.

Basslink will therefore need to be considered in any assessment of feasibility of a second interconnector. The role of Hydro Tasmania in respect of a second interconnector will also need to be considered, including whether it would be appropriate for Hydro Tasmania to continue to have trading rights with respect to Basslink if a second interconnector is built. While Basslink is currently unregulated, the possibility exists for it to convert to regulated status, as occurred with Murraylink and Directlink. This would change the way it is operated and its impact on a second interconnector.

Other considerations

By comparison to augmentations of an existing transmission network, investors are likely to perceive higher levels of risk in a greenfield development such as a new second interconnector. The risk appetite of financiers is likely to be influenced by the recent Basslink interruption and by the large (greater than 50per cent) cost overruns that occurred during the construction and commissioning of Basslink. Also, the uncertainty of future revenues, noting the potential for any changes to government climate change policies to affect electricity flows, revenues and the role of a second interconnector, is likely to be a significant consideration.

Other considerations relevant to investors include:

• The level of development, construction and technology risk;

• Whether governments would provide guarantees, as occurred with the Basslink project;

• If the feasibility of a new interconnector were to be based in part on the development of new renewable energy projects in Tasmania, how long that development will take;

• Commonwealth and state level carbon policies: what the implications are for renewable energy development in Tasmania or Victoria or more broadly, whether these policies encourage the closure of generation in those states, and what the effects may be on the supply-demand balance;

• Who would bear the costs of any consequential network augmentations within Tasmania and Victoria.

Commercial models for operating and financing a new interconnector will need to be developed. Many of these are dependent on the role of third parties, including governments, Hydro Tasmania, and renewable energy developers. In general, these models for operating and financing a second interconnector are distinguished by the way they allocate risk across different public and private stakeholders.

As described above, the consequences for financing and financing models will be very different depending on whether the second interconnector is regulated or unregulated and whether future revenues are underwritten by a stable, creditworthy counterparty. Possible commercial operating models include:

1. Fully regulated - As described above, this is where the asset is entirely regulated and revenues are fixed by the AER and recovered from electricity consumers through network charges;

2. Partly regulated – It may be possible to develop a model where the interconnector is primarily regulated (earning some regulated revenue), but there are external sources of funding/revenue that cover some of the costs;

3. Fully market – In this case the investment would be entirely financed by the private sector and there are no regulated revenues. Whether this is possible will depend on future cash flows and the overall level of risk; and

4. Partly market – There would be no regulated revenues, but a government entity would bear a share of the risk. For example, an arrangement similar to that for Basslink could be put in place, where a government body such as Hydro Tasmania pays the interconnector a facility fee in return for the interconnector’s market revenues and the rights to trade its capacity. Alternatively, the operator could receive an agreed tariff from a government body for electricity dispatched. In addition, government guarantees could be provided.


Under most of these models, if the feasibility is focussed on renewable energy the developers of renewable energy projects could contribute to financing the interconnector. A simple model for achieving this could be to charge renewable energy projects, such as wind farms, for connecting to the interconnector. This would mean that the interconnector would need to link to viable locations for renewable energy.

Second interconnector considerationsHow would a second interconnector interact with Basslink?

Are there any other benefits or costs to electricity consumers (eg lower wholesale prices or improved price stability) and how should these be considered?

Availability of financing

Each of the commercial models outlined above will result in different financing approaches and this will impact the availability of financing for the project. Significantly, financing for interconnectors is available, with numerous examples of private finance being utilised for funding offshore interconnectors and transmission assets. This indicates that financiers can be satisfied with many of the risks associated with these projects, including design, construction and operating risks.

The sources of financing for a second interconnector and the sensitivities of potential financiers will need to be considered further but capital could potentially come from a number of sources including the CEFC, export credit agencies, project finance banks and infrastructure equity and debt funds. In this regard it is noted that the feasibility of a second interconnector and any associated wind energy development are closely linked, as while an interconnector may enable renewable energy development, conversely generation development will be needed to ensure a second interconnector is sufficiently utilised such that the costs of its development are justified.

Should the majority of the more than 1,000 MW of wind energy under consideration in Tasmania be required to be developed to support the case for a second interconnector, this would require significant supporting wind farm investment. These linkages will need to be more closely explored in this study.

Second interconnector considerations • The various alternatives for financing and operating a second interconnector will require careful examination.

Each approach comes with different risks, and potentially differences in the revenue payment profiles and payment durations.

What are the appropriate financing and commercial operating models for a second interconnector and what risks and revenues do they present to investors?


Preliminary Conclusions and Proposed Study Activities As can be seen from the discussion in this study, Australia’s electricity market is in a period of significant and unprecedented change. This is prompted by a diverse set of policy and market factors which will cause both material changes in the generation mix in the NEM, and an increased focus on power system security as the growth in renewable energy use continues to rise. In addition, a unique set of circumstances has impacted electricity supply in Tasmania and prompted urgent consideration of energy security for Tasmania.

I am of the view that the timing is right for consideration of a second interconnector and that this feasibility study is expedited, as outlined in the Terms of Reference. It is timely to consider the feasibility of a second interconnector and how to best develop and use Tasmania’s large scale renewable energy resources, as a means of best supporting a rapidly changing electricity market. I am highly supportive of the efforts of the Australian and Tasmanian governments in having commissioned the consideration of the feasibility of a second interconnector at this time.

On initial review, there is opportunity for Tasmania and for the NEM from the development of a second interconnector, including the possibility of capitalising on Tasmanian renewable energy resources and helping support broader market changes in the NEM. Similarly, the recent outage of Basslink highlights the important role that a second interconnector could play in managing Tasmania’s energy resource constraints.

My preliminary conclusion is that, if viable, a second interconnector would support long term energy security in Tasmania, assist in the integration of Tasmanian renewable energy into the NEM, support the operation of the NEM and could open the path way for more than 1,000 megawatts of new renewable energy development in Tasmania.

Given these opportunities, one of my interim recommendations is that the Australian and Tasmanian Governments should commit to supporting a second interconnector, subject to my final report demonstrating there is a likely long term benefit to consumers from its development.

In making this judgement I acknowledge that there are a complex set of benefits, challenges and risks that are in play. These will need to be closely considered to better understand the prospects for, and interplay between, the case for proceeding with developing a second interconnector and the development of the Tasmanian renewable energy industry, compared to other options for how the NEM might evolve.

Over the next six months my taskforce and I will work closely with the Australian and Tasmanian Governments, AEMO and the CEFC in order to develop credible future scenarios of how a second interconnector might be developed. Detailed modelling will be undertaken of these future scenarios to understand underlying electricity market dynamics and to support exploration of associated regulatory, financial and business models.

Based on this work, my taskforce and I will then assess the feasibility of a second interconnector through the dimensions of:

• Its potential role in facilitating the potential development of large-scale renewable resources in Tasmania

• Its contribution to energy security in the NEM, including Tasmania; and

• The long- term costs and benefits to consumers, both in Tasmania and the NEM more broadly,

with the aim of addressing the requirements of the Australian and Tasmanian governments for this study, as set out in the Terms of Reference.

I will also examine the related parallel case for how to best use and develop Tasmania’s large scale renewable energy resources, considering both the case for this investment with and without a second interconnector in place.

As noted earlier in this report, the feasibility of a second interconnector and any associated renewable energy development are closely linked. Investment in a second interconnector will likely be contingent upon extensive investment in supporting renewable energy development, which in turn will be dependent on the interconnector proceeding. These linkages will need to be closely explored, in particular to better understand likely sources of financing and the sensitivities of potential financiers.

I expect that input and feedback from the CEFC will be invaluable as I develop this aspect of the report. More generally, the CEFC can play an important role both in this work and any related business cases for the interconnector, associated renewable energy investment and for any supporting hydro related investment and I am of the view its financial expertise and resources should be utilised more.


There are close links between this study and other complementary reviews underway, including the activities of the Tasmanian Energy Security Taskforce and work underway by the Tasmanian Government in conjunction with Hydro Tasmania to consider the feasibility of a second interconnector.

My work will be complementary to, however distinct from, these efforts, through the national perspective I intend to bring to my analysis. In order to best coordinate and leverage related efforts, I will work closely with the Tasmanian Energy Security Taskforce to integrate, where appropriate, key work streams of mutual interest and will draw on the work of Hydro Tasmania in informing my final report.

In alignment with the work of the Tasmanian Energy Security Taskforce, and as requested, I will provide my final report to the Australian and Tasmanian Governments in December 2016. While this will be soon after the Tasmanian Energy Security Taskforce completes its interim report in November 2016, I am confident that the study’s findings and recommendations will be highly valuable as a key input to the Taskforce as it considers its final report, which is due to the Tasmanian Government around the end of May 2017.


Attachment A

Terms of reference – feasibility study of a second interconnectorThe Australian and Tasmanian governments will conduct a feasibility study into whether a second interconnector could improve Tasmania’s energy security and facilitate renewable energy investment.

The study will:

1. Analyse the extent to which a second 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.


Attachment B

Feasibility Study Key Considerations

NEM energy security: • To what extent would a second interconnector address long term NEM energy security challenges?

• How might a second interconnector support the electricity industry in the future?

• To what extent could a second interconnector address Tasmania’s long-term energy constraint challenges?

Tasmanian Large Scale Renewables Development: • What role could Tasmanian renewable energy play in meeting the Australian Government’s climate change

commitments?

• What supporting infrastructure is required to maximise the benefits from Tasmanian renewable energy and how might it be financed?

• To what extent would a second interconnector facilitate renewable energy growth in Tasmania?

• How do the prospects for Tasmanian renewable energy compare to other regions in the NEM?

Long-term costs and benefits to consumers in Tasmania and the NEM more broadly: • Is a second interconnector in the long term interest of consumers and how would its costs and benefits be assessed

under the RIT-T?

• What supporting infrastructure is required and how might it be financed?

• How would a second interconnector interact with Basslink?

• Are there any other benefits or costs to electricity consumers (e.g. lower wholesale prices or improved price stability) and how should these be considered?

• What are the appropriate financing and commercial operating models for a second interconnector and what risks and revenues do they present to investors?


Attachment C

State and Territory Climate Policies 90

Key Targets Electricity/Energy Policies

Federal91 • Emissions reduction target of 5 per cent below 2000 levels by 2020.

• Renewable Energy Target of 33,000 GWh by 2020

• Emissions reduction target of 26-28 per cent below 2005 levels by 2030.

• Emission Reduction Fund (ERF); $2.55 billion for purchase of Australian Carbon Credit Units.

• Additional ‘safeguard’ mechanism under ERF to ensure large emitters (over 100,000 tonnes CO2-e p.a.) do not increase emissions above baseline (historical max emissions between 2009-10 and 2013-14).

• Electricity sector is treated differently: a baseline will apply across the electricity sector as a whole, with individual baselines to apply to facilities in the event that the sectoral-baseline is exceeded.

• RET met by legislating proportion of electricity each retailer must deliver from renewable sources.

• National Energy Productivity Plan to improve Australia’s energy productivity by 40 per cent between 2015 and 2030.

Australian Capital Territory92

• Emissions reduction target of 40 per cent below 1990 levels by 2020.

• Emissions reduction target of 80 per cent below 1990 levels by 2050.

• Zero net greenhouse gas emissions by 2050.

• Renewable energy target of 100 per cent by 2020.

• Renewable energy target to be achieved by a staged, reverse-auction process to provide renewable electricity at lowest cost. A feed-in tariff is levied on electricity users to meet difference between renewable energy producers’ LCOE and wholesale electricity price. Large-scale generation certificates obtained from renewable energy projects can be voluntarily retired to ensure additionality of renewable generation above the national RET. Reducing residential and non-residential sector emissions through approaches such as the Energy Efficiency Improvement Scheme; potential regulation around water heaters and home appliances; community engagement aimed at behaviour change.

• $12 million committed to a Renewable Energy Innovation Fund.

90 Table is not an exhaustive list of measures

91 Department of the Environment, 2016, Australia’s 2030 climate change target, https://www.environment.gov.au/climate-change/publications/factsheet-australias-2030-climate-change-target Department of the Environment, 2016, The Renewable Energy Target Scheme, https://www.environment.gov.au/climate-change/renewable-energy-target-scheme; Department of the Environment, 2016, Emissions Reduction Fund, https://www.environment.gov.au/climate-change/emissions-reduction-fund COAG Energy Council 2015, National Energy Productivity Plan,https://scer.govspace.gov.au/workstreams/energy-market-reform/national-energy-productivity-plan/

92 ACT Environment and Planning Directorate, 2016 Emissions and Mitigation, http://www.environment.act.gov.au/cc/what-government-is-doing/emissions-and-mitigation; ACT Environment and Sustainable Development Directorate, AP2- A new climate change strategy and action plan for the ACT, pg. vii http://www.environment.act.gov.au/__data/assets/pdf_file/0006/581136/AP2_Sept12_PRINT_NO_CROPS_SML.pdf; ACT Environment and Planning Directorate, 2016, Renewable energy industry development, http://www.environment.act.gov.au/energy/growth-in-the-clean-economy/local-investment



New South Wales93 • Renewable energy target of 20 per cent by 2020 (in support of, not additional to, national RET).

• Energy Savings Scheme; mandatory obligation on scheme participants (e.g. electricity retailers) to obtain and surrender energy savings certificates.

• Attract investment, build community support and grow expertise in renewable energy as outlined in the Renewable Energy Action Plan. Includes 24 actions to support renewable energy investment.

Northern Territory94 • No target renewable energy policy. • $55 million Solar Energy Transformation Program project aims to transform the delivery of electricity in remote off-grid communities throughout the Northern Territory.

Queensland95 • Renewable Energy Expert Panel to assess and establish a pathway to a renewable energy target of 50 per cent by 2030.

• Solar future plan target of 1 million rooftop PVs by 2020.

• Supporting up to 60 MW of large-scale solar power generation through a renewable energy reverse auction.

South Australia96 • Emissions reduction target of 60 per cent below 1990 levels by 2050.

• Additional goal of net zero emissions by 2050.

• Renewable energy target of 50 per cent by 2025.

• Adelaide to be the world’s first carbon neutral city.

• Retailer Energy Efficiency Scheme (REES); establishes energy efficiency and audit targets to be met by electricity and gas retailers. The 2017 target is to save 2.3 PJ of energy through efficiency measures.

• $10 billion investment in low carbon technologies by 2025.

• Advocate for stronger climate action nationally, including a carbon price and evolution of the GreenPower scheme.

• Building Innovation Fund to encourage new low carbon and energy efficient designs.

Tasmania97 • Emissions reduction target of 60 per cent below 1990 levels by 2050.

• Pursue potential for 10 per cent additional hydro output from existing hydro asset base.

• Advance the case for commercial development of biofuels in Tasmania.

• Tasmanian Energy Strategy- 2015 Restoring Tasmania’s Energy Advantage including actions related to renewable energy, energy efficiency and electric vehicles.

93 NSW Department of Environment and Heritage, NSW Government action on climate change, http://www.climatechange.environment.nsw.gov.au/About-climate-change-in-NSW/NSW-Government-action-on-climate-change/; NSW Department of Environment and Heritage 2013,NSW Energy Saving Scheme http://www.ess.nsw.gov.au/Home ; NSW Trade and Investment 2013, NSW Renewable Energy Action Plan; http://www.resourcesandenergy.nsw.gov.au/__data/assets/pdf_file/0010/475318/nsw-renewable-energy-action-plan.pdf

94 ARENA 2014, Northern Territory Solar Energy Transformation Program, http://arena.gov.au/project/northern-territory-solar-energy-transformation-program/

95 Queensland Department of Environment and Heritage Protection 2016, Advancing Climate Change Action, http://www.ehp.qld.gov.au/assets/documents/climate/advancing-climate-action.pdf

96 South Australia Government Climate Change Strategy 2015-2050 Towards a low carbon economy, pages 10,15; South, Retailer Energy Efficiency Scheme, https://www.sa.gov.au/topics/water-energy-and-environment/energy/rebates-concessions-and-incentives/retailer-energy-efficiency-scheme-rees#title3; Retail Energy Efficiency Scheme Final Decisions on thresholds and targets https://www.sa.gov.au/__data/assets/pdf_file/0007/134989/REES-final-decisions-on-thresholds-and-targets.pdf

97 Tasmanian Department of Premier and Cabinet 2016, Embracing the climate challenge: Tasmanian’s draft climate change action plan 2016-2021, pages 8,19; Tasmanian Department of State Growth 2015, Tasmania’s Energy Strategy – Restoring Tasmania’s Energy Advantage, page 29


98 Victorian Premier 2016, Media Release (15 June 2016) Renewable Energy Target to Create Thousands of Jobs, http://www.premier.vic.gov.au/renewable-energy-targets-to-create-thousands-of-jobs/ Victorian Department of Environment, Land, Water and Planning, Climate change and Victoria, http://www.climatechange.vic.gov.au/action/leadership-and-governance; Victorian Premier 2016, Targets to achieve Victoria’s Energy Efficient Future, http://www.premier.vic.gov.au/targets-to-achieve-victorias-energy-efficient-future/ Victorian Department of Economic Development, Jobs, Transport and Resources 2015, Victoria’s Renewable Energy Roadmap, page 5

99 Western Australian Department of Environment Regulation, Low Emissions Energy Development Fund projects, https://www.der.wa.gov.au/our-work/programs/65-leed-fund-projects


Victoria98 • Renewable Energy Target of 25 per cent by 2020 and 40 per cent by 2025.

• A target of net zero greenhouse gas emissions by 2050.

• Victorian Energy Efficiency Target (VEET): mandatory obligation on large energy retailers to surrender a specified number of energy efficiency certificates every year. Energy savings equivalent to 6.5 MtCO2-e avoided emissions by 2020.

• A Victorian Government $20 million for New Energy Jobs Fund to support community groups and business developing renewable energy projects.

• Victorian Government activities to reduce regulatory barriers, provide information and help facilitate renewable energy projects

Western Australia99 • No specific policy or target but supports the national targets.

• Low Emissions Energy Development Fund to provide assistance for demonstration and commercialisation of innovative low emission energy technologies.

Feasibility of a second Tasmanian interconnector – Preliminary Report