Hydrogen Part 1: Australia could be a Hydrogen Superpower: Extracts from Australian Energy Market Operator Draft Plan

Draft 2022 Integrated System Plan

Important notice


AEMO publishes the Draft 2022 Integrated System Plan (ISP) pursuant to its functions under section 49(2) of the National Electricity Law (which defines AEMO’s functions as National Transmission Planner) and its supporting functions under the National Electricity Rules.



This Draft 2022 ISP contains data provided by or collected from third parties, and conclusions, opinions, assumptions or forecasts that are based on that data.

AEMO has made every reasonable effort to ensure the quality of the information in this Draft 2022 ISP but cannot guarantee that the information, forecasts and assumptions in it are accurate, complete or appropriate for your circumstances. This Draft 2022 ISP does not include all of the information that an investor, participant or potential participant in the national electricity market might require and does not amount to a recommendation of any investment.

Anyone proposing to use the information in this Draft 2022 ISP should independently verify and check its accuracy, completeness and suitability for purpose, and obtain independent and specific advice from appropriate experts.

The Draft 2022 ISP does not constitute legal or business advice and should not be relied on as a substitute for obtaining detailed advice about the National Electricity Law, the National Electricity Rules, or any other applicable laws, procedures or policies.

AEMO has made every effort to ensure the quality of the information in this Draft 2022 ISP but cannot guarantee its accuracy or completeness. Accordingly, to the maximum extent permitted by law, AEMO and its officers, employees and consultants involved in the preparation of this document:

  • make no representation or warranty, express or implied, as to the currency, accuracy, reliability or completeness of the information in this Draft 2022 ISP; and
  • are not liable (whether by reason of negligence or otherwise) for any statements or representations in this ISP, or any omissions from it, or for any use or reliance on the information in it.


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Invitation to engage


Since 2018, the Integrated System Plan (ISP) has guided industry and government on the best investments to supply affordable and reliable electricity to Australian homes and businesses.

On behalf of AEMO, I am incredibly proud of this Draft 2022 ISP.

It is a ‘whole of system plan’ that offers a roadmap for development in eastern Australia’s electricity system. A roadmap that responds to the latest technology, economic shifts and policy developments.

Read as a whole, it offers a clear view of how we can best respond to challenges that will emerge over the next 30 years.

The draft document calls for significant investment across generation, storage, transmission and system services. A transformation of the National Electricity Market, to provide high reliability at low cost, while meeting the nation’s objective to reduce emissions.

Of course, the final version of the ISP can only do this with constructive and critical input from a wide range of stakeholders.

This draft document is itself the result of consultation over the past year. I would like to thank the ISP Consumer Panel and the many organisations and individuals who have contributed to the consultations that have made this draft what it is today.

As we publish this draft and work in the coming months to finalise the 2022 ISP, we will again rely on your contribution. We have planned public forums during February, and I encourage you to make a written submission. All views will be considered as we prepare the final report.

The consultation process is set out in Part D of this document. We look forward to your feedback and contributions.

Chief Executive OfficerDaniel Westerman




Invitation to engage                                                                                                                            3

Abbreviations                                                                                                                                     6

Acknowledgements                                                                                                                            7

Executive summary                                                                                                                            8

Part A Meeting the ISP’s challenge                                                                                                  17

1.                    The ISP’s purpose and challenge                                                                                           18

1.1               Interpreting the ISP’s prescribed purpose                                                                                   18

1.2               The complex race to net zero emissions                                                                                     21

2.                    Consultative modelling for the ISP                                                                                         24

2.1               Consultations to date                                                                                                                24

2.2               Four scenarios to span a range of plausible futures                                                                     25

2.3               Step Change scenario most likely                                                                                              29

2.4               Modelling of the power system to meet targets                                                                           31

Part B ISP Development Opportunities                                                                                            33

3.                    Renewable energy capacity needed to achieve net zero NEM emissions                               35

3.1               Nearly five times today’s distributed energy resources                                                                 35

3.2               Nine times today’s utility-scale variable renewables                                                                    36

3.3               Renewable energy zones for new VRE                                                                                      38

3.4               Renewable penetration                                                                                                             41

3.5               Curtailment of VRE will sometimes be efficient                                                                            42

4.                    Dispatchable capacity needed to firm the renewable supply                                                  44

4.1               Coal retiring two to three times faster than anticipated                                                                 44

4.2               Treble the capacity of dispatchable storage, hydro and gas-fired generation to firm renewables     46

4.3               Stronger services for power system requirements                                                                       53

Part C The Draft Optimal Development Path                                                                                   55

5.                    The optimal development path                                                                                               56

5.1               The Draft ODP and its benefits                                                                                                  56

5.2               Committed and anticipated network projects                                                                               60

5.3               Actionable ISP projects                                                                                                             61

5.4               Future ISP projects                                                                                                                   70

6.                    Determining the Draft Optimal Development Path                                                                  72

6.1               Step 1: the least-cost path for each scenario – a case of not ‘if’ but ‘when’                                    72

6.2               Designing candidate development paths – to assess risks of investing too early or too late (Step 2)74

6.3               Assess, evaluate and rank candidate development paths (Steps 3-5)                                           75

6.3.1      Approach A – scenario-weighted net market benefits                                                                  76

6.3.2      Approach B – least-worst regrets approach                                                                                78

6.3.3      Insurance value associated with staging HumeLink as an actionable project                                 80

6.3.4      Competition benefits have not influenced the CDP assessments                                                  83

6.4               Testing the robustness of the candidate development paths through sensitivity analysis (Step 6)   84

Part D Advancing the Draft Optimal Development Path                                                                   87

7.                    Significant risks and limitations are being monitored                                                             88

7.1               Risks quantified within the ISP methodology                                                                               88

7.2               Risks to timely implementation of the Draft ODP network projects                                                88

7.3               Additional factors that may be considered in future ISPs                                                              91

8.                    Consultations relating to the Draft ISP                                                                                    93

8.1               Consultation on the Draft ISP                                                                                                     93

8.2               Preparatory activities and REZ design reports                                                                             94

8.3               Call for submissions on non-network options                                                                              96

9.                    Further analysis in preparation for final 2022 ISP                                                                   97

Supporting documents                                                                                                                     99






AC alternating current NER National Electricity Rules
AEMC Australian Energy Market Commission NSCAS network support and control ancillary services
AER Australian Energy Regulator NSG non-scheduled generation
ARENA Australian Renewable Energy Agency NSP network service provider
CCS carbon capture and storage ODP optimal development path
CDP candidate development path OWZ offshore wind zone
DER distributed energy resources PACR Project Assessment Conclusions Report
DNSP distribution network service provider PADR Project Assessment Draft Report
DSP demand-side participatioon PEC Project EnergyConnect
ESB Energy Security Board PFR primary frequency response
EV electric vehicle PV photovoltaic
FCAS frequency control ancillary services QNI Queensland – New South Wales Interconnector
FFR fast frequency response RET Renewable Energy Target
FOM fixed operating and maintenance REZ renewable energy zone
GW gigawatt/s RIT-T Regulatory Investment Test for Transmission
HVDC high voltage direct current SIPS System Integrity Protection Scheme
IASR Inputs, Assumptions and Scenarios Report TNSP transmission network service provider
IBR Inverter-based resources TRET Tasmanian Renewable Energy Target
IIO Infrastructure Investment Opportunities TWh terawatt hour/s
ISP Integrated System Plan V2G Vehicle-to-grid
kW kilowatt/s VNI Victoria – New South Wales Interconnector
MW megawatt/s VPP virtual power plant
NEM National Electricity Market VRE variable renewable energy




Producing a robust Draft ISP is only possible with the extensive involvement of a wide variety of critical energy market stakeholders.

AEMO acknowledges and sincerely thanks the more than 200 individual stakeholders who have actively participated in the process leading up to this publication. Since September 2020, AEMO has received 120 written submissions and held 25 webinars and forums. This formal engagement has been supplemented and enhanced through extensive informal discussions.

The contributions of consumer groups, generators, developers, electricity and gas networks, retailers, advisory firms, academics and environmental groups have each been invaluable throughout this process.

The Australian and State Governments have been generous and rigorous in the input they have provided.

Transmission networks have played an invaluable role, in particular through their participation in the Electricity Joint Planning Committee.

AEMO thanks the many Australian Energy Regulator (AER) Board and staff who have offered AEMO their input and advice on key issues whenever requested.

The ISP Consumer Panel has guided AEMO in a range of areas, not just on issues of content but also on communication and stakeholder engagement. AEMO thanks the Panel Chair, Andrew Nance, and Members for their contribution.

Finally, AEMO acknowledges the immense efforts of our own people to produce the Draft ISP. Staff from across AEMO’s Forecasting Group and System Planning Group, as well as AEMO’s legal, engagement and communications teams, have worked with precision, expertise and dedication to produce the Draft ISP.

AEMO looks forward to further meaningful engagement on the Draft ISP, as we work towards finalising the 2022 ISP.


Executive summary


Australia’s National Electricity Market (NEM) is supporting a once-in-a-century transformation in the way society considers and consumes energy: drawing on electricity in place of much of the oil and gas for industry and homes, replacing legacy assets with low-cost renewables, adding batteries and other new forms of firming capacity, and reconfiguring the grid to support two-way energy flow to new power sources in new locations. It is doing so at world-leading pace, while continuing to provide reliable, secure and affordable electricity to consumers.

Since November 2020, AEMO has engaged comprehensively with energy consumers, policy makers, regulators, industry representatives and other stakeholders to prepare this Draft ISP. Towards the end of that consultation, Australia’s Long Term Emissions Reduction Plan (Australia’s Emissions Reduction Plan) was launched, adding to existing NEM jurisdiction policies to deliver net zero emissions by 2050.

The Draft ISP proposes to support this highly complex, once-in-a-century transformation with a development path that optimises the consumer benefits of affordable, reliable and secure power.

Significant investment in the NEM is needed to:


  • Double the electricity it now delivers, without coal generation, requiring a nine-fold increase in utility-scale variable renewable energy (VRE) capacity, and a five-fold increase in distributed photovoltaics (PV),
  • Treble the firming capacity that can respond to a dispatch signal, including utility-scale batteries, hydro storage, gas generation, and smart behind-the-meter batteries or “virtual power plants” (VPPs),
  • Adapt networks and markets for two-way electricity flow and to provide essential power system services,
  • Efficiently install more than 10,000 km of new transmission as part of the transformation, to connect geographically and technologically diverse, low-cost generation and firming with the consumers who rely on it,
  • Pursue these actionable ISP transmission projects on a pathway that is low cost and low regrets for consumers, with work commencing on their earliest planned schedule, and
  • Manage the supply chain and social licence risks for investments of this scale.

Stakeholder consultation on the Draft ISP including public forums and written submissions will be open until 11 February 2022, following which AEMO will finalise the 2022 ISP by 30 June 2022.


The power system’s transformation is profound

The Draft ISP considers four scenarios that cover a broad range of plausible trends and events in its operating environment through the power system’s transformation. A strong consensus of stakeholder representatives sees the Step Change scenario as being the most likely.

Figure 1 below shows the modelled transformation of the NEM through the Step Change scenario through to 2050.


Figure 1     Forecast NEM capacity to 2050, Step Change scenario, with transmission



The ISP development opportunities that form part of the Draft Optimal Development Path (ODP) will assist the NEM catering for:

  • Double the delivered electricity to approximately 330 terawatt hours (TWh) per year. Today the NEM delivers just under 180 TWh of electricity to industry and homes per year. The NEM would need to nearly double that by 2050 to replace much of the gas and petrol currently consumed in transport, industry, office and domestic use. That growth is needed in addition to the significant ongoing investment by consumers in distributed energy and energy efficiency. The needs of proposed hydrogen production, if supplied from the grid, would be additional to this growth and are explored further in AEMO’s Hydrogen Superpower scenario.
  • Coal retiring two to three times faster than anticipated. Current announcements by thermal plant owners suggest that about 5 gigawatts (GW) of the current 23 GW of coal capacity will withdraw by 2030. However, modelling suggests that 14 GW may do so. Over the past decade, coal-fired generators have withdrawn from the market before their announced dates, and competitive and operational pressures will intensify with the ever-increasing penetration of cheap renewable generation. All brown coal generation and over two-thirds of black coal generation could withdraw by 2032.
  • Nine times the utility-scale VRE capacity. On a per capita basis, Australia added four to five times more VRE than the European Union, the USA or China in 2018-19. The NEM now needs to maintain that record rate every year for the decade to triple VRE capacity by 2030 – then almost double it again by 2040, and again by 2050. Much of this resource will be built in renewable energy zones (REZs) that coordinate network and renewable investment, and foster a more holistic approach to regional employment, economic opportunity and community participation.


  • Nearly five times the distributed PV capacity, and substantial growth in distributed storage. The NEM’s transformation includes the generation and feed-in capability of millions of individual

consumer-owned solar power plants. Today, ~30% of detached homes in the NEM have rooftop PV, their

~15 GW capacity meeting their owners’ energy needs and exporting surplus back into the grid. By 2032, over half of the homes in the NEM will do so, rising to 65% with 69 GW capacity by 2050, with most systems complemented by battery energy storage. Their 90 TWh of electricity will then meet nearly one fifth of the NEM’s total underlying demand.

When successful, the transformation will deliver low-cost renewable electricity with reliability and security, help meet regional and national climate targets, and contribute significantly to regional jobs and economic growth.


Treble the firming capacity as coal retires

As coal withdraws and sun- and wind-dependent generation starts to dominate the NEM, the system must match when and where electricity is generated, with when and where it is needed. To do so, significant investment in the NEM is needed to treble the firming capacity that can respond to a dispatch signal, together with efficient network investment to access this firm capacity.

Currently, the NEM relies on 23 GW of firm capacity from coal, and another 20 GW of dispatchable firming capacity from storage and gas generation. By 2050, without coal, the NEM will require:

  • 45 GW / 620 GWh (gigawatt hours) of storage, in all its forms. The most pressing need in the next decade (beyond what is already committed) is for batteries, hydro or viable alternative storage of up to eight hours’ depth to manage daily variations in the fast-growing solar and wind output. By 2050, the ISP modelling forecasts that VPPs, vehicle-to-grid (V2G services and other emerging technologies will provide approximately 30 GW of dispatchable storage capacity, and utility-scale battery and pumped hydro storage 15 GW (see Figure 1). This balance reinforces the need for close collaboration between AEMO, network service providers (NSPs) and investors to ensure investments work to optimise benefits for consumers. Deeper pumped hydro storages will be vital for seasonal and long duration needs as coal exits the market at scale.
  • 7 GW of existing dispatchable hydro, which relies on natural water inflows rather than other forms of energy to pump water and recharge (and so is not considered ‘storage’).
  • 9 GW of gas-fired generation in total for peak loads and firming. At forecast gas prices, gas-fired generation will play a crucial role as significant coal generation retires. It will complement battery and pumped hydro generation to support periods of peak demand, particularly during long ‘dark and still’ weather periods, as well as provide power system services to provide grid security and stability. The development opportunities are forecast to primarily be for peaking gas generators, with limited opportunities for mid-merit gas plant unless VRE is limited by transmission access. Over time, its emissions will need to be offset, or natural gas will need to be replaced by net-zero carbon fuels such as green hydrogen or biogas.
  • Wholesale demand response and other flexible loads to also help manage peak loads and troughs, reducing reliance on more capital-intensive responses.

All major projects will need careful design to meet environmental, economic and social licence expectations.


Market and technical reforms for system services and two-way electricity flow

Significant market and technical reforms are underway to securely manage the transformation to a low emissions grid:

  • Significant market reforms have already been implemented. AEMO and its industry partners have recently implemented Five Minute Settlement and Wholesale Demand Response in the NEM. These major reforms provide better price signals for fast response and flexible technologies, and enable businesses to provide peak shaving services in the spot energy market.
  • Further significant market reforms are underway. Following Ministerial approval of the Energy Security Board’s (ESB’s) post-2025 reform recommendations, AEMO is working with the Australian Energy Market Commission (AEMC) through rule changes to implement mechanisms for essential system services for the physical power system, and better integration of distributed energy resources (DER). The ESB has also been tasked by Ministers to undertake further policy work on capacity and network congestion for consideration in late 2022. Given the amount of reform underway, AEMO is also working with industry to develop a NEM Regulatory and IT Implementation Roadmap, aiming to reduce reform implementation costs and risks.
  • Collaborative framework for power system requirements. AEMO’s Engineering Framework1 enables industry participants to collaboratively define the operational, technical and engineering requirements for the NEM’s future, and informs the market reforms being undertaken by the ESB. It describes the initial roadmap to inform preparation of the NEM for operation under six identified operational conditions2, including 100% instantaneous penetration of renewable energy by 2025. These actions will be prioritised with industry and integrated into implementation workplans.


Transmission projects add $29 billion in value while enabling the transformation

The new generation and storage opportunities listed above constitute the ISP development opportunities of the draft optimal development path (ODP) to 2050. The Draft ODP then identifies 10,000 km of new transmission to connect these developments and deliver renewable energy to consumers through the NEM. It identifies projects that are actionable now as well as in the future, and is selected from candidates in accordance with the Cost Benefit Analysis Guidelines made by the Australian Energy Regulator (AER), as detailed in AEMO’s ISP Methodology.

The transmission projects within the Draft ODP are forecast to deliver scenario-weighted net market benefits of $29 billion, returning 2.5 times its investment.3 It optimises benefits for all who produce, consume and transport electricity in the market, as well as providing investment certainty and flexibility to reduce NEM emissions faster in the next decade if needed, and time for greater community engagement and supply chain risk management.

The Draft ODP retains that balance and flexibility, while foregoing only $20 million (less than 0.1% of benefits) against the candidate development path (CDP) with the absolute highest net market benefits. This is a



1 See https://aemo.com.au/initiatives/major-programs/engineering-framework.

2 See https://aemo.com.au/newsroom/news-updates/engineering-framework-takes-shape.

3 The network investment identified as actionable in this ISP is ~$12.5 billion in today’s value, and constitutes about 3% of the total spend needed to develop, operate and maintain the generation, storage and future network investments of the NEM to 2050 (in net present value [NPV] terms). Considering all transmission investments (actionable and future), the total transmission capital investment represents about 7% of the total spend (in NPV terms), delivering $29 billion of benefits to consumers.


negligible regret or insurance cost, given that all of the ODP projects are needed – the only question being when. They will all cost-effectively serve the needs of consumers, support Australia’s transition to net zero emissions, and support regional employment and economic growth.

This insurance is provided by staging two transmission projects – the Victoria – New South Wales Interconnector (VNI) West and HumeLink. Both are supported in Australia’s Long Term Emissions Reduction Plan as major projects to transport energy to consumers, including from Snowy 2.0. Staging the projects ensures they can be delivered when needed under all scenarios, with an additional checkpoint before construction to reconfirm that need. In particular, delivery of these projects as early as possible, with early works as the first stage, protects consumers against:

  • the risk of faster than anticipated coal retirements, while giving greater market and price certainty and enhanced power system resilience when they do retire,
  • the risk of project delivery delays. Currently stated lead-times suggest that HumeLink could be paused until after the 2024 ISP and still be delivered just-in-time, in the most likely Step Change scenario. However, any schedule slippage would mean the project is not available when it is most likely to be needed, leading to $200 million regret cost. There only needs to be a 10% possibility of that occurring for HumeLink as an actionable staged project to optimise net market benefits. Since the 2020 ISP, project delays have pushed back the earliest commissioning timing for both VNI West and Marinus Link, and it is foreseeable that HumeLink could face similar delivery risks. Progressing the project now with staging is therefore considered an appropriate low regret action for consumers,
  • the risk that storage of more than 8 hours duration takes longer than expected to materialise. There is a high degree of uncertainty in terms of technology readiness and cost for this type of storage, and more pumped hydro energy storage (additional to Snowy 2.0) may not be able to be delivered in time to cover coal closures if not already well progressed, and
  • the possibility that cost allocation and regulatory arrangements needed to enable Marinus Link are not resolved in a timely manner. Without Marinus Link, the value of having VNI West built by 2031 increases further.

While not valued in the cost benefit analysis under the current regulatory framework, these projects also provide broader benefits including regional economic stimulus, jobs growth and lower emissions.

The early works stage for HumeLink and VNI West may also identify cost savings, reduce cost uncertainties, and provide greater consumer confidence that they will not be over- or under-investing. To ensure benefits are optimised for consumers, further work to drive down costs of these projects should be urgently undertaken as part of these early works.


The draft optimal development path

The Draft ISP identifies the new transmission projects needed to support the transformation, categorised as:


  • committed and anticipated projects already underway,
  • actionable ISP projects, for which work should commence at the earliest planned time, and
  • future ISP projects, for which AEMO may require (in the final 2022 ISP) the transmission network service provider (TNSP) to undertake preparatory works or REZ Design Reports.

These projects are listed in Table 1, and set out visually in Figure 2 below.


Table 1     Network projects in the Draft ODP


Committed and anticipated ISP Projects To be delivered by
VNI SIPS: Victoria – New South Wales Interconnector System Integrity Protection Scheme Summer 2021-224
QNI Minor: Queensland – New South Wales Interconnector Minor upgrade July 2022
Eyre Peninsula Link December 2022
VNI Minor: Victoria – New South Wales Interconnector Minor upgrade September 2023
Northern QREZ Stage 1 November 2023
Project EnergyConnect July 2025
Central West Orana REZ Transmission Link July 2025
Western Victoria Transmission Network Project July 2026
Actionable ISP Projects To be delivered by
New England REZ Transmission Link July 2027
Sydney Ring (Reinforcing Sydney, Newcastle and Wollongong Supply) July 2027
HumeLink, commencing with early works, and then proceeding with implementation so long as the project passes decision rules that demonstrate consumers will continue to benefit from the project. Early works: 2024

Implementation:Target July 2026

Marinus Link Cable 1: July 20275

Cable 2: July 2029

VNI West (via Kerang), commencing with early works, and then proceeding with implementation so long as the project passes decision rules that demonstrate consumers will continue to benefit from the project. Early works: 2026 Implementation: Target July 2031
Future ISP Projects
Interconnector projects: QNI Connect
New South Wales Projects: New England REZ Extension
Queensland Projects: Central to Southern Queensland, Darling Downs REZ Expansion, Gladstone Grid Reinforcement, Far North Queensland REZ Expansion, Facilitating Power to Central Queensland, Facilitating Power out of North Queensland, North Queensland Energy Hub, Far North Queensland REZ Expansion
South Australia Projects: South East South Australia REZ Expansion.
Victoria Projects: South West Victoria REZ Expansion
Additional projects to expand REZs and upgrade flow paths beyond 2040, which are highly uncertain and vary significantly between scenarios.

















4 The VNI SIPS project is expected to be in service at or just after release of this Draft ISP.

5 TasNetworks has now advised that the earliest full commissioning date for the first cable is July 2029 (750 MW, with 250 MW available in 2028) and the second cable in July 2031 (a further 750 MW, with 250 MW available in 2030). These revised dates will be reflected in the final 2022 ISP, but preliminary modelling indicates that it does not materially change the outcomes of the ODP.


Figure 2     Network projects in the optimal development path

 The scenario and cost-benefit analysis methodologies of this Draft ISP take a comprehensive set of transformation risks into account. These risks are incorporated into policy, technology and cost assumptions, and include the risks of coal generation retiring earlier than announced or anticipated.

However, some important considerations may still risk the Draft ODP’s timely implementation:


  • Securing social licence for VRE, storage and transmission. This Draft ISP shows how the NEM can optimise consumer benefits while supporting government policies for emissions reduction and Australia’s new net zero target. However, the land needed for major VRE, storage and transmission projects to realise these goals is unprecedented. Early community engagement will be needed to ensure investments have an appropriate social licence. The new REZ Design Report framework is a start, but proactive engagement and integrated land-use planning is also needed at a jurisdictional level. In some cases, this may lead to alternative developments that reduce the need for new transmission, including batteries,

gas-fired generation and offshore wind developments that connect to the existing network easements.

  • Project sequencing to manage supply chain risks. There is strong industry consensus on the acceleration in global infrastructure and renewable energy investment over the next two decades. This will significantly increase demand for expertise, materials, and equipment, putting pressure on costs and schedules for new NEM generation and transmission projects. Development optimisation through the ISP process alone cannot fully secure the strategic sequencing of projects to manage supply chain risks.

Additional factors that may be considered in future ISPs include:


  • Consideration of broader public benefits when selecting the Draft ODP. The AER’s Cost Benefit Analysis Guidelines consider only benefits for those who consume, produce and transport electricity in the NEM. They make it clear that consumers should not have to pay for broader public benefits, even if these benefits may be valued by governments on behalf of the wider community. These benefits include regional economic and jobs growth, the full societal value of emission reductions, and resilience and adaptation for more extreme climate events.
  • Potential need for additional transmission investment in the NEM’s main flow paths. While the Draft ODP identifies the need for significant new transmission, the NEM may require further augmentation of its main transmission flow paths, or potentially new transmission flow paths, to cater for more significant VRE developments by the 2050s. This Draft ISP has started to study these needs – including alternatives to transmission and the use of alternative technologies such as dedicated high voltage direct current (HVDC) ties – but further work would map out the detailed implications beyond the planning horizon.
  • Securing social licence for greater DER integration. The Draft ISP recognises the significant market reforms achieved since the 2020 ISP to support the technical integration of DER and other modern energy resources. While the Draft ISP assumes all DER generation can be exported into the network, there comes a point beyond which some active management is needed to maintain the reliability and security of the whole system. The emergence of VPPs across the NEM is expected to assist in meeting this challenge and provide further benefits for consumers. AEMO is actively collaborating with distribution network service providers (DNSPs) to better understand how developments in the distribution network interact with the transmission network and ultimately support optimisation of benefits for consumers. Full DER integration requires a step change in engagement across the industry to ensure all consumers, retailers, networks and other market participants orchestrate these resources to optimise net benefits and maintain security and reliability.


Invitation for written submissions

Drawing on extensive consultation over the past 18 months, this Draft ISP outlines a whole-of-system plan that provides an integrated roadmap for the efficient development of the NEM to 2050, and in AEMO’s view, balances consumer risks and benefits.

All stakeholders are invited to provide a written submission on any aspect of the Draft ISP, including development path outcomes, and in particular answering the following questions:

  • Do you consider that the Draft ODP appropriately reflects the consumer risk preferences? Is the reasoning for the ODP clear? Are there any other risks that should be quantified?
  • Is the proposed staging for HumeLink and VNI West, with early works as the first stage and then proceeding to implementation subject to conditions, appropriate?
  • Is the proposed treatment of Marinus Link as a single actionable ISP project appropriate?
  • Do you consider that REZ Design Reports are warranted for the indicated REZs?
  • Do you have any feedback on the Addendum to the 2021 Inputs, Assumptions and Scenarios Report


Submissions need not address every question posed and are not limited to them, but should not relate to inputs and assumptions or methodology which have been consulted on separately.

The full extent of stakeholder consultation on the Draft ISP is set out in Table 2.


Table 2     Stakeholder consultation forums and milestones for the Draft ISP


Date Event Purpose
10 Dec 2021 Draft ISP published Provide a basis for consultation on draft outcomes of the ISP modelling and analysis process.
10 Dec 2021 Public Forum 1 Public briefing on and explanation of the Draft ISP, as well as an opportunity for stakeholders to ask initial questions and clarifications.
15 Dec 2021 AEMO Consumer Forum Provide a tailored briefing and opportunity for questions from Consumer Forum attendees.
1 Feb 2022 Public Forum 2 Provide all stakeholders with the opportunity to ask more in-depth and specific questions arising from their consideration of the Draft ISP materials.
4 Feb 2022 Consumer Advocate verbal comment Allow energy consumer advocates to make verbal comments on the Draft ISP, which AEMO will record and consider.
11 Feb 2022 Submissions close Seek written comments on the Draft ISP from all stakeholders.


Part A

Meeting the ISP’s challenge


Australia’s energy sector has now commenced a complex and accelerating transformation, aimed at reducing both the sector’s emissions and its long-term cost. Traditional generators are being replaced by consumer-led DER, utility-scale VRE and new forms of dispatchable resources. The NEM must provide the power system assets and services to ensure these resources are efficient, safe, reliable and secure.

To meet its prescribed purpose, the 2022 ISP6 sets out an optimal development path (ODP) which includes transmission projects and non-network options. It may also include “distribution assets, generation, storage projects or demand-side developments that are consistent with the efficient development of the power system”.7 It guides investors and other decision-makers on the optimal timing and placement of those resources.

The ISP is published every two years as the NEM’s operating environment changes. Over the last four years, the NEM’s transformation has outpaced this cycle. VRE and rooftop PV development is accelerating faster than assumed likely in the previous ISP, and new technology and business models are driving consumer adoption faster than anticipated. This rate of transformation will continue to accelerate, with state and Commonwealth governments announcing significant new policies to support a lower emissions power system.

The accelerating shifts in technologies, behaviours and business models, not to mention the complexity of the system itself, mean a single pre-determined path is not sufficient. This Draft ISP therefore takes a balanced risk-based approach to the NEM’s future development, considering a range of scenarios and risks, and carefully examining the upsides and downsides of key decision points.

AEMO has consulted extensively with stakeholders for this Draft 2022 ISP. In particular, AEMO has worked with all NEM participants to draft and publish the 2021 Inputs, Assumptions and Scenarios Report (IASR)8, the ISP Methodology9 and the 2021 Transmission Cost Report10. These reports have done much of the preparatory heavy-lifting for the Draft ISP, which incorporates their content unless otherwise stated.

This Part A completes that groundwork for the Draft ISP, by setting out:


  • Section 1 – the objective of the 2022 ISP and the challenges it faces, and
  • Section 2 – the extensive consultation undertaken to agree on the scenarios, inputs and assumptions relied on by the ISP.

Given the material investment and policy changes since the 2020 ISP, this Draft ISP also serves as an ISP update of the 2020 ISP. Any feedback loop assessments that may be requested between now and publication of the final ISP in June 2022 then benefit from using the latest inputs, assumptions and ODP. An ISP update accompanies this Draft 2022 ISP, and provides reasons for the update and the specific elements of the 2020 ISP that have been updated.11


6 The term “2022 ISP” refers to both this Draft ISP and the final 2022 ISP due to be published before 30 June 2022.

7 NER 5.10.2

8 See https://aemo.com.au/-/media/files/major-publications/isp/2021/2021-inputs-assumptions-and-scenarios-report.pdf?la=en.

9 See https://aemo.com.au/energy-systems/major-publications/integrated-system-plan-isp/2022-integrated-system-plan-isp/isp-methodology.

10 See https://aemo.com.au/-/media/files/major-publications/isp/2021/transmission-cost-report.pdf?la=en.

11 At https://aemo.com.au/energy-systems/major-publications/integrated-system-plan-isp/2020-integrated-system-plan-isp.


1.           The ISP’s purpose and challenge

The ISP’s prescribed purpose is “… to establish a whole-of-system plan for the efficient development of the power system that achieves power system needs for a planning horizon of at least 20 years for the long-term interests of the consumers of electricity.”12

This section first clarifies each of the underlined phrases in this purpose. It then considers the extent of the challenge this purpose represents, given the inherent and emerging complexities the NEM faces. In particular, AEMO has considered policies for the rapid decarbonisation of the NEM. This transformation must negotiate the complexities of the NEM’s physical operating system, the rising need to secure community support, and the uncertainties of global policies and supply chains.


1.1            Interpreting the ISP’s prescribed purpose


The whole NEM power system, through to 2050

The NEM is an intricate system of systems, which includes regulatory, market, policy and commercial components. At its centre is the power system, an inherently complex machine of transcontinental scale. This system is now experiencing the biggest and fastest transformation since its inception over 100 years ago.

The ISP is a whole-of-system plan to efficiently achieve power system needs through that transformational change, in the long-term interests of electricity consumers. AEMO has extended the ISP’s planning horizon through to 2050, to reflect Australia’s 2050 net zero emissions target.

The ISP takes into account:


  • consumer-led DER investments, storage and generation investments, and demand side responses,
  • the capital and fuel costs of generation, storage, transmission, distribution and DER,
  • State and Commonwealth energy and environmental policies,
  • power system requirements13 that must continue to be satisfied as new technologies are integrated, and
  • the impacts of coupled sectors such as transport, gas and hydrogen.

As a rigorous whole-of-system plan, prepared in collaboration with NEM jurisdictional planners and policy-makers, energy consumers, asset owners and operators, and market bodies, the ISP is the most comprehensive analysis of Australia’s energy future.


Power system requirements

NEM power system requirements are the reliability and security needs for operating a power system within operating limits and in accordance with operating standards. Table 3 summarises the fundamental power system requirements that are considered in the ISP. Primary among these is that the system remains in a


12 NER 5.22.2

13 See https://aemo.com.au/initiatives/major-programs/past-major-programs/future-power-system-security-program/power-system-requirements- paper.


satisfactory operating state through a contingency14 and can be returned to a secure operating state within 30 minutes. Appendix 7 provides detail on the power system security needs as the NEM transforms from a power system dominated by large thermal power stations, to a system that is more decentralised.


Table 3    Power system requirements considered in the ISP


Need Operational requirements considered when developing the ISP
Reliability Resource adequacy and capability

•   There is a sufficient overall portfolio of energy resources to continuously achieve the real- time balancing of supply and demand.

Energy resources provide sufficient supply to match demand from consumers at least 99.998% of the time.
Operating reserves exist to provide the capability to respond to large continuing changes in energy requirements.
Network capability is sufficient to transport energy to consumers.
Security Frequency management and inertia response

•   Ability to maintain system frequency within operating standards.

Frequency remains within operating standards – considering primary frequency response and frequency controls, minimum inertia requirements, and the availability of alternatives; the system is maintained within transient and oscillatory stability limits.
Voltage management and system strength

•   Ability to maintain voltages on the network within acceptable limits.

•   System strength is above minimum levels.

Voltage remains within operating standards, fault levels are below equipment ratings, and system strength/fault levels are maintained above minimum requirements.



Public policies considered

In determining these power system needs, AEMO may consider the current environmental or energy policies of the NEM jurisdictions.15 In this ISP, the following policies are included in its assumptions:

  • Emissions reduction targets. Australia’s 2030 target (to reduce greenhouse gas emissions economy-wide to 26-28% below 2005 levels) is included in forecast assumptions, as well as the Australia-wide net zero emissions target by 2050.
  • Renewable Energy Targets (RETs) for Victoria, Queensland and Tasmania. AEMO applies a linear development trajectory to meet the RET targets, starting from the latest forecasts of existing, committed and anticipated renewable energy. For Victoria, this also includes the development requirements anticipated by the second Victorian Renewable Energy Target (VRET2)16 auction process.
  • Policies affecting REZs and associated transmission. For New South Wales, AEMO applies a generation development trajectory at least as fast as that specified in the Consumer Trustee’s 2021 Infrastructure Investment Opportunities (IIO) Report.17





14 An event affecting the power system which AEMO expects would be likely to involve the failure or removal from operational service of one or more generating units and/or transmission elements.

15 NER 5.22.3(b)

16 Further details available at https://www.energy.vic.gov.au/renewable-energy/vret2.

17 See https://aemo.com.au/-/media/files/about_aemo/aemo-services/iio-report-2021.pdf?la=en.


  • Various DER and energy efficiency policies. AEMO incorporates each of these schemes in its DER uptake and behavioural analysis.18
  • Electric vehicle (EV) policies. The EV policies within NEM jurisdictions are included in electricity demand forecasts and apply them to all scenarios. Slow Change follows the targets, but ultimately falls short in a slower economy.19 Some V2G services are also assumed in all scenarios.
  • Energy efficiency policies. Both Commonwealth and NEM jurisdiction policies are incorporated into electricity demand forecasts for all scenarios. These include building and equipment energy performance standards and ratings, and energy savings or efficiency schemes.


Long-term interests and net market benefits

The ISP must pursue its purpose in the long-term interests of electricity consumers. This is measured primarily by the net market benefits that a development path will bring to those consumers, although AEMO may justify the inclusion of other factors (see Section 7). The extensive classes of market benefits and costs that are included in this calculation are set out in the National Electricity Rules (NER) (rule 5.22.10). As detailed in the ISP Methodology, these market benefits align with the categories in the Regulatory Investment Tests for Transmission (RIT-Ts).

In most cases, assuming an efficient market, the greatest net market benefits will arise from the lowest long-term system costs. Table 4 sets out the classes of market benefits and costs the ISP must consider in terms of operation and capital costs. As perfect foresight of future events is unlikely, these market benefits

include the option value of an asset whose future need or timing may not be certain, but which would be highly desirable in some future scenarios. This option value may be realised by staging a project: starting it now on the information available, with the option to pause development based on the best information available at a later time.

All values presented in this report are 30 June 2021 real dollars unless stated otherwise.


Table 4     Optimal net market benefits seen as minimal long-term system costs


Benefit Realised by Identified by Costs avoided
Low operation cost Low marginal cost Cost of fuel, other operating costs, plant maintenance and plant start-up Higher cost
Efficient generation Co-optimising future generation and transmission build (and retirement) timings and calculating the fuel costs associated with this generation mix Greater fuel consumption
Efficient storage and transmission Assessing additional generation costs effectively wasted due to network losses under each alternate development path Network losses
Low capital cost Deferred capital Time value of money Capital expenditure
Optimal investment size Total generation and transmission costs, compared to counterfactual Capital expenditure
Option value Least-regrets modelling Assessing risks and regret of an investment (or lack of) based on an assumed future that does not play out, and the value of staging Lost options/flexibility


18 See Appendix A3 of the Electricity Demand Forecasting Methodology for details of the approach to incorporate DER. Available at https://aemo.com.au/energy-systems/electricity/national-electricity-market-nem/nem-forecasting-and-planning/forecasting-approach.

19 See IASR Section 3.3.5 and CSIRO’s ElectricVehicle Projections 2021 report, at https://aemo.com.au/energy-systems/major-publications/integrated- system-plan-isp/2022-integrated-system-plan-isp/current-inputs-assumptions-and-scenarios.


1.2            The complex race to net zero emissions

The Commonwealth and all state NEM jurisdictions have now confirmed the objective of a net zero emission economy by 2050. Not only is the NEM going through its own decarbonisation, but it is a critical enabler for other sectors to reach their net zero emissions objectives through electrification. As a result, the ISP must help guide the NEM through both the inherent complexities in its physical system, and a rapid doubling of demand to meet the needs of electrification.


The physical system is complex enough

The inherent complexities in operating the NEM’s physical system include:


  • the rapid introduction of increasing levels of consumer-driven DER,
  • uncertainties in the timing of and market response to the retirement of coal generators,
  • satisfying the critical operational needs for the power system with increasingly scarce system services, and
  • uncertain yet intensifying climate change impacts.

The first major complexity is the interaction between DER and utility-scale supply (see Figure 3). As more behind-the-meter PV is installed, and more batteries and EVs charge and discharge, the demand profiles for grid-supplied energy shifts. This in turn influences how generators operate, and increases the value of flexible generation, storage and loads in the power system.


Figure 3     Power system interactions between grid and behind-the-meter energy supply


The second major complexity for the ISP is forecasting when existing black and brown coal plants will reduce generation, temporarily withdraw units from the NEM, or shut down. Owners of coal generators have already either brought forward their announced retirements, or indicated that they would, citing market, financial and operating pressures from the rise in renewable generation. The financial viability of existing thermal generation will become increasingly uncertain, particularly coal-fired generation that is less able to adjust generation levels rapidly in response to changes in market prices. Significant financial decisions to repair and maintain plant may be harder to justify under this uncertainty, potentially resulting in declining plant reliability.

Asset owners make these decisions based on a range of commercial factors, in the context of energy and climate change policies, market arrangements, competing technologies, and social and investor licences. These traditional assets have guided the NEM’s design, construction and operation to date. Their replacement with DER, VRE and alternate dispatchable resources also means a transformational modernisation of the NEM’s operations, including the system services which synchronous generators have traditionally delivered.

As sun, wind and water become the NEM’s primary energy resources, supported by gas, it will become increasingly complex to preserve the resilience of the system against a broad array of extreme weather and climate impacts. System resilience is enhanced through fuel diversity, geographic diversity and strategic redundancy, and with design standards that meet Australia’s expected climate and often high temperatures. Gas-fired generation, potentially fuelled by hydrogen, will play a crucial role as coal generation retires, both to help manage extended periods of low VRE output and to provide power system services to provide grid security and stability (see Section 4.3).


The race to reduce emissions adds to the complexity

The NEM’s operating environment is always subject to an array of economic, trade, security, policy (including on-land gas extraction) and technology environments, as set out in the 2020 ISP. However, the speed and scale of the transformation to a decarbonised NEM poses a unique set of challenges.

So far, the NEM’s transformation has outpaced all expectations. On a per capita basis, Australia added over four times the VRE the European Union did in 2018, and five times in 2019.20 In the last two years, through the pandemic, VRE development accelerated, with 40% more VRE now committed or anticipated to be connected to the grid by 2023-24 than was forecast in the 2020 ISP. By May 2021, a surge of renewable generation set a record, delivering 57% of the total generation in the NEM for one trading interval. That record rose twice in September 2021, first to 59% and then again to 61%. AEMO now forecasts periods of 100% renewable generation in some periods as early as 2025, across the NEM rather than in significant parts of it.21

Modelling for the Draft ISP confirms that this rate of transformation will continue to accelerate (see Part C). The decarbonisation challenge has now been confirmed by the Commonwealth Government’s Australia’s Long-term Emissions Reduction Plan22 (Australia’s Emissions Reduction Plan). Five of this plan’s seven priority technologies depend on a low emission NEM, and three depend on clean hydrogen (see Figure 4).

Two new NEM challenges arising from the pace and scale of transformation require urgent and continuing focus. The first is the need to secure community and land owner support for the large amount of VRE, storage and network development signalled in this plan. While generation, transmission and distribution assets have


20 Blakers et al. ‘Pathway to 100% renewable electricity’, IEEE Journal of Photovoltaics, vol. 9, no. 6, November 2019.

21 Base case for the 2021 Electricity Statement of Opportunities.

22 See https://www.industry.gov.au/sites/default/files/October%202021/document/australias-long-term-emissions-reduction-plan.pdf.


always been a difficult local planning issue, the transformation will require greater local community support for the proposed use of larger amounts of land, potentially including dual-use considerations.

The second is that Australia is not alone in this race to decarbonise. The already heavy investment in global power systems is expected to surge in the wake of COP26.23 This is on top of a long-running and accelerating global boom in infrastructure investment – from a public perspective to catch-up on infrastructure needs, and from an investor perspective as a newly favoured asset class in a low-interest-rate environment. These trends will require continued focus on supply chain reliability, availability of skilled labour, and cost management for power system development in Australia. Some actionable ISP projects have already experienced schedule delays, and such slippages are likely to continue.


Figure 4     Priority technologies in Australia’s Emission Reduction Plan

Source: Australia’s Long-term Emissions Reduction Plan, 2021 (Figure 2.4).


The ISP aims to consider and model these variables and complexities in the most rigorous way possible. The following section sets out how AEMO has consulted with industry to settle on the scenarios upon which that analysis relies.

23 The 26th Conference of the Parties to the UN Framework Convention on Climate Change, Glasgow, November 2021.


2.           Consultative modelling for the ISP

As discussed in Section 1, the challenge for the ISP is to meet power system needs in the long-term interests of the consumers of electricity, responding to government policies for decarbonisation.

This is a complex challenge, to which all NEM participants have risen through the ISP consultation process to date.

This section briefly summarises the modelling process of the ISP to achieve that purpose. It sets out:


  • the extensive industry consultation to date on the ISP methodology, inputs and scenarios,
  • the scenarios developed through that consultation to consider the future possibilities,
  • the selection of Step Change as the scenario that industry stakeholders believe is most likely to play out, and
  • the modelling used to determine how the NEM could optimally meet its electricity demand and emission reduction objectives for consumers.

The results of this modelling are set out in Parts B and C of this Draft ISP.


2.1            Consultations to date

Consultations for the Draft ISP commenced in September 2020. The first phase culminated in the 2021 IASR24 and the ISP Methodology25, published on 30 July 2021. Those reports benefited from the insights of industry and consumer stakeholders, through 88 detailed written submissions, four workshops and numerous stakeholder meetings (see Figure 526). Consultation for potential minor amendments to the ISP Methodology and 2021 IASR relating to competition benefits was held in October.


Figure 5     Parallel ISP consultations 

24 See https://aemo.com.au/-/media/files/major-publications/isp/2021/2021-inputs-assumptions-and-scenarios-report.pdf?la=en.

25 See https://aemo.com.au/energy-systems/major-publications/integrated-system-plan-isp/2022-integrated-system-plan-isp/isp-methodology.

26 A consultation on minor amendments to the ISP Methodology and IASR regarding the inclusion of competition benefits in ISP analysis was launched on 15 October 2021. All material related to that consultation, including the final report, is available at https://aemo.com.au/consultations/current-and-closed-consultations/competition-benefits-in-the-isp


A second phase of engagement was to determine the relative likelihood of the five scenarios identified in the IASR. This process is detailed in Section 2.2 below, and resulted in one scenario being dropped from this ISP analysis and a name change for another, as well as determining the most likely scenario.


ISP Consumer Panel

The five-member ISP Consumer Panel (the Panel) remains highly engaged in all aspects of the ISP process. The Panel delivered its statutory report on the IASR on 30 September 2021, which stated that, in the Panel’s assessment, the evidence and reasons supporting the IASR were sound and the selected scenarios are appropriate.

The Panel also made 23 recommendations related to many aspects of the IASR process and AEMO as an organisation. AEMO is considering, consulting on, and actioning these recommendations through a range of processes, including consultation on the Draft ISP. Full discussion of the Panel’s report and subsequent actions is provided in Appendix 1.


AER transparency reviews

The NER require the AER to review and report on whether AEMO has adequately explained how it has derived key inputs and assumptions at both the IASR development stage and for the Draft ISP.27

On 30 August 2021, the AER published its transparency review of the 2021 IASR (the IASR review report).28 This review report focused on the adequacy of AEMO’s explanation of the inputs and assumptions to be used in the cost benefit analysis to identify the ODP in the Draft 2022 ISP.

The IASR review report concluded that the majority of AEMO’s inputs and assumptions were adequately explained and that AEMO has demonstrated that it has taken into account stakeholder feedback.

In addition to the overall finding, and to promote the transparency of the 2021 IASR, the IASR review report required AEMO to provide further explanation to address specific inputs and assumptions, and to consult on these matters in the Draft 2022 ISP.29

AEMO has published an addendum to the 2021 IASR that provides further explanation on these matters, and welcomes submissions on the content of the addendum and this Draft 2022 ISP by 11 February 2022.30

The AER will undertake the second transparency review of the Draft ISP (an ISP review report) as to whether AEMO has adequately explained how it has derived key inputs and assumptions and how these inputs and assumptions have contributed to the outcomes in the Draft 2022 ISP.31


2.2            Four scenarios to span a range of plausible futures

Five scenarios were developed through industry consultations and published in the IASR. Further consultations determined the Steady Progress scenario to be no longer relevant for this ISP, given Australia’s


27 NER 5.22.9 (IASR review report) and NER 5.22.13 (ISP review report)

28 AER, Transparency Review Integrated System Plan 2022: Final Inputs, Assumptions and Scenarios Report, at https://www.aer.gov.au/networks- pipelines/performance-reporting/transparency-review-of-aemo-2021-inputs-assumptions-and-scenarios-report.

29 Publication of an IASR addendum and consultation in the Draft ISP is required by NER clause 5.22.9(c).

30 AEMO, 2021 Inputs, Assumptions and Scenarios Report: Addendum, at https://aemo.com.au/energy-systems/major-publications/integrated- system-plan-isp/2022-integrated-system-plan-isp/current-inputs-assumptions-and-scenarios.

31 NER clause 5.22.13(a) requires the AER to publish this ISP review report within one month of the publication of the Draft ISP.


commitment to net zero emissions by 2050, and that the Slow Change scenario already tested the impact of slower than anticipated decarbonisation.

The four remaining scenarios span a range of plausible futures with varying rates of decarbonisation, electricity demand, and decentralisation (see Figure 6). The scale of electricity demand is influenced by the extent to which other sectors electrify (for example, the transportation sector via EVs). ‘Decentralisation’ is the extent to which business and household consumers manage their own electricity generation, storage or services, rather than just draw power from the grid. In the case of Hydrogen Superpower, this decentralisation is swamped by the scale of electricity demand needed for a hydrogen export industry.


Figure 6     Scenarios used for the Draft 2022 ISP



The set of scenarios aligns to some degree with those in the 2020 ISP, but has been refined in response to stakeholder feedback and extended to consider greater electrification of other sectors. Since 2019-20, consumer-driven DER has continued to outpace historical forecasts, government policies have supported stronger large-scale renewable energy investments, and some coal retirements have been brought forward.32 From that shared starting point, the scenario trajectories were driven by a range of assumptions, laid out in Figure 7 and discussed in detail in the 2021 IASR.


Diverse future demand scenarios

The scenario broad descriptions are:


  • Slow Change – Challenging economic environment following the COVID-19 pandemic, with greater risk of industrial load closures, and slower net zero emissions action. Consumers continue to manage



32 See 2021 IASR, at https://aemo.com.au/energy-systems/major-publications/integrated-system-plan-isp/2022-integrated-system-plan-isp/current- inputs-assumptions-and-scenarios.


their energy needs through DER, particularly distributed PV. However, Slow Change would not reach the decarbonisation objectives of Australia’s Emissions Reduction Plan.

  • Progressive Change – Pursuing an economy-wide net zero emissions 2050 target progressively, ratcheting up emissions reduction goals over time. Progressive Change (previously Net Zero 205033) delivers the decarbonisation objectives of Australia’s Emissions Reduction Plan, with a progressive build up of momentum ending with deep cuts in emissions across the economy from the 2040s. The 2020s would continue the current impressive trends of the NEM’s emission reductions, assisted by government policies, consumer DER investment, corporate emission abatement, and technology cost reductions. The 2030s would see commercially viable alternatives to emissions-intensive heavy industry emerge after a decade or longer of research and development, paving the way for stronger economy-wide decarbonisation and industrial electrification in the 2040s, and nearly doubling the total capacity of the NEM. EVs become more prevalent over time and consumers gradually switch to using electricity to heat their homes and businesses. Some domestic hydrogen production supports the transport sector and as a blended pipeline gas, with some industrial applications after 2045.
  • Step Change – Rapid consumer-led transformation of the energy sector and co-ordinated economy-wide action. Step Change moves much faster initially to fulfilling Australia’s net zero policy commitments that would further help to limit global temperature rise to below 2° compared to pre-industrial levels. Rather than building momentum as Progressive Change does, Step Change sees a consistently fast-paced transition from fossil fuel to renewable energy in the NEM. On top of the Progressive Change assumptions, there is also a step change in global policy commitments, supported by rapidly falling costs of energy production, including consumer devices. Increased digitalisation helps both demand management and grid flexibility, and energy efficiency is as important as electrification. By 2050, most consumers rely on electricity for heating and transport, and the global manufacture of internal-combustion vehicles has all but ceased. Some domestic hydrogen production supports the transport sector and as a blended pipeline gas, with some industrial applications after 2040.
  • Hydrogen Superpower – strong global action and significant technological breakthroughs. While the two previous scenarios assume the same doubling of demand for electricity to support industry decarbonisation, Hydrogen Superpower nearly quadruples NEM energy consumption to support a hydrogen export industry. The technology transforms transport and domestic manufacturing, and renewable energy exports become a significant Australian export, retaining Australia’s place as a global energy resource. As well, households with gas connections progressively switch to a hydrogen-gas blend, before appliance upgrades achieve 100% hydrogen use.



33 Renamed from ‘Net Zero 2050’ to avoid confusion with any NEM jurisdiction or national plan.


Figure 7     Scenario input assumptions

Emissions reduction targets and trajectories for the scenarios

Included in these assumptions are carbon budgets for the electricity sector itself – that is, the NEM’s contribution to reducing Australia’s emissions to net zero by 2050. Figure 8 below sets out the emission reduction trajectory for the electricity sector in each scenario. While each gets to net zero by 2050, each takes a very different path. Progressive Change gets there ‘just in time’, while Step Change and Hydrogen Superpower move faster to approach or reach net zero by 2035. Slow Change sees reductions in emissions early due to assumed load closures, but abatement then slows considerably in the second and third decade.

To determine these carbon budgets, AEMO and its consultants (CSIRO and ClimateWorks) considered four means (or “pillars”) by which to decarbonise the economy. The decarbonisation of the NEM is a key pillar, which influences, and is influenced by, shifts in the other three pillars:

  • Electricity sector decarbonisation, being the speed at which the carbon intensity of electricity generation approaches zero.
  • Fuel switching from fossil fuels to zero or near-zero emissions alternatives, including electrification. By 2050, at least 150 TWh of new consumption is forecast from the switching of other energy sources to electricity, almost doubling today’s delivered consumption of just under 180 TWh per year. Transport, heating, cooking, hot water and almost all transport and industrial processes are able to be electrified. As some electrification is more expensive than others, the level increases over time in all scenarios as emission targets tighten and/or technology breakthroughs reduce the cost of fuel-switching.

As the price of EVs falls, for example, their share of the total vehicle fleet is expected to increase, rising in Step Change to 58% by 2040. This would account for approximately 37 TWh of electricity demand, with a demand profile that would ideally provide a sponge for solar supply, but may exacerbate peak demands without proper infrastructure and consumer incentives to charge outside those periods.

  • Energy efficiency through improved energy productivity and waste reduction.


  • Carbon offsets through non-energy emission reductions and sequestration, with technology-based carbon sequestration likely accounting for 3 to 10% of all sequestered carbon (depending on the scenario).


Figure 8     NEM carbon budgets and the resulting emission trajectories


Financial year ending


2.3            Step Change scenario most likely

Step Change is considered by energy industry stakeholders to be the most likely scenario to play out, ahead of the Progressive Change scenario. This was the conclusion of a careful process through which AEMO twice convened a panel of Australian energy market experts representing all stakeholder groups, with an intervening round of public consultation:

  • First panel considers two scenarios equally likely. The panel of experts representing government, market bodies, generators, consumer and network service providers first met on 5 October 2021. They deliberated using a Delphi Technique, which allowed them to maintain their anonymity, rate the scenarios using web-based software, offer written reasons for those ratings, and consider the responses of others to revise their ratings if appropriate.

In this first forum, Step Change and Progressive Change each earned over one-third of participant votes. Another 30% of votes was split between Hydrogen Superpower and Steady Progress, with very few votes expecting Slow Change to play out.

  • Public forum tests the panel findings. AEMO then held a public forum on 22 October 2021, in which the first Panel views were published, in aggregate and by stakeholder sub-groups. Those attending were asked whether they had any concerns about the use of the Panel’s weightings, and importantly, about the approach AEMO should follow to update the scenario weightings if the Commonwealth Government committed to net-zero emissions economy-wide by 2050 (which it subsequently did). Written comments on all three issues were also invited. Stakeholders considered that if commitments were made that invalidated the Steady Progress scenario, reconvening the Delphi Panel to reconsider their weightings was most appropriate (see Appendix 1).


  • Second panel prefers Step Change. The same experts from the first panel were invited back to repeat the Delphi process on 16 November 2021. In this second sitting, the same Delphi Technique was deployed, with the same question being asked of the Panel. In addition, Panel members were asked whether it was appropriate to discard the Steady Progress scenario and focus ISP modelling efforts on the remaining four scenarios; approximately 80% of panellists agreed that this was an appropriate action considering Australia’s Emissions Reduction Plan. In considering the remaining four scenarios, the panellists concluded that the Step Change scenario was the clear ‘most likely’ scenario, securing approximately half of all votes, followed by Progressive Change and then Hydrogen Superpower. Again Slow Change received very few votes. The increased weighting for Step Change reflected the Panel’s view that the economy may exceed the ambition of Australia’s Emissions Reduction Plan, and do so faster than currently envisaged.

The following comments, made by participants during the second Delphi Panel, illustrate this point:

–          Step change is most likely as the will to change is clear. International pressure to decarbonise will continue to increase, the step change scenario could roll out faster than the ISP scenario timing (Network participant).

–          I think domestic politics will aim for net zero scenario but global politics and global technology change will drag us towards Step change with slightly higher probability (Government participant).

–          I expect a significant increase in policy ambition within the next 5 years (other).

–          I think there will be significant international pressure to achieve the Paris goal of <2 degrees. The only two scenarios that achieve this are Step change and Hydrogen superpower (network).

–          Globally the financial, policy and political momentum to reduce emissions is now unstoppable



–          Most industries are looking to achieve significant decarbonisation and looking to electricity for this, biasing [the likelihood of] the step change (consumer).


Figure 9     Voting in second Delphi panel


2.4            Modelling of the power system to meet targets

All scenarios and potential power system investments have been analysed through an integrated suite of forecasting and planning models and assessments, to determine which investments would form the optimal development path. It is an iterative approach, where the outputs of each process determine or refine inputs into others. An overview of the integrated suite is shown in Figure 10.


Figure 10   Overview of ISP modelling methodology



  • The fixed and modelled inputs are the inputs, assumptions and scenarios published in the IASR. Significant changes to the 2020 ISP are noted in the IASR, and include:

–          The updated GenCost 2020-21 report34 confirms that the costs of inverter-based resources (IBR) like wind, solar (utility-scale and rooftop) and batteries are expected to keep falling, while costs for mature technologies such as coal, gas and hydro generation (pumped storage and conventional) remain flat. That said, larger gas peaking plant recently preferred by the market have a 35% lower capital cost than the smaller sized options considered in the 2020 ISP, and have been included as options this time round.

–          Multisectoral modelling identified a strong opportunity for the NEM to support emissions reduction across Australia’s economy through electrification, and produced carbon budgets where applicable to achieve each scenarios’ decarbonisation intent (see Section 2.2).

–          AEMO has also invested heavily in improving the accuracy and transparency of transmission costs used for the 2022 ISP, following feedback from stakeholders on the 2020 ISP. The resulting 2021



34 CSIRO. GenCost 2020-21, at https://www.csiro.au/-/media/EF/Files/GenCost2020-21_FinalReport.pdf.


Transmission Cost Report35 and associated public database are world-leading initiatives in transparency for regulated transmission builds.

–          DER, particularly distributed PV systems, have continued to grow strongly since the 2020 ISP’s release, despite the economic and social challenges associated with COVID-19. AEMO’s updated DER forecasts for the 2022 ISP forecasts continued strong growth for distributed PV, noticeably higher than previously applied.

  • The capacity outlook model projects the generation, transmission and dispatch outcomes in each scenario, seeking to optimise capital and operational costs.
  • The time-sequential model then optimises electricity dispatch for every hourly or half-hourly interval.
  • The engineering assessment tests and validates the capacity outlook and time-sequential outcomes using power system security assessments to ensure that investments are aligned and robust.
  • The gas supply model may then validate any assumptions on gas pipeline and field developments.
  • Finally, the cost-benefit analyses test each individual scenario and development plan, to determine the ODP and test its robustness (see Part C).

The results of this modelling process are given in Part B (ISP Development Opportunities) and Part C (the Optimal Development Path) below.

35 AEMO. 2021 Transmission Cost Report, at https://aemo.com.au/en/consultations/current-and-closed-consultations/transmission-costs-for-the- 2022-integrated-system-plan.


Part B

ISP Development Opportunities


AEMO has comprehensively modelled each of the scenarios introduced in Part A, in line with the ISP Methodology and in consultation with NEM stakeholders.

The ISP has found that the NEM must triple its overall generation and storage capacity if it is to meet the economy’s electricity needs in the most likely scenario. Today, NEM installed capacity of nearly 60 GW delivers just under 180 TWh of electricity to industry and homes per year. In Step Change, utility-scale generation and storage capacity would need to grow to 170 GW and deliver almost 400 TWh per year by 2050 to cater for existing loads and replace the gas and petrol currently consumed by much of our transport, industry, office and domestic use. That growth is needed despite significant investment by consumers in distributed energy and energy efficiency. The needs of any hydrogen production would be additional to this growth and result in an eight-fold increase in capacity being required to meet the assumed scale of opportunity in Hydrogen Superpower.

This Part B details how the NEM is forecast to deliver those needs.


  • Section 3 – Conversion to renewable generation. The ISP forecasts that VRE capacity will increase nine-fold by 2050, from 15 GW currently to nearly 140 GW in Step Change. That is over a doubling of capacity every decade. Additionally, distributed PV is forecast to increase from 15 GW to nearly 70 GW over the same period.
  • Section 4 – Storage and services to support renewable generation. To firm that VRE and DER,

60 GW firm dispatchable generation (30 GW utility-scale) and additional power system security services will be needed.

These resources are the ISP development opportunities that form part of the ISP’s ODP (see Figure 11). The other part of the ODP, the actionable and future ISP projects, are set out in Part C.




Figure 11   Development opportunities to 2050 in Step Change, and compared to total capacity required in

Progressive Change and Hydrogen Superpower



3.           Renewable energy capacity needed to achieve net zero NEM emissions

The shift to renewables is already accelerating. On a per capita basis, Australia added over four to five times the solar and wind generation of any of the European Union, the USA, Japan or China in 2018-1936, building to today’s 15 GW of VRE. Records for instantaneous renewable generation penetration (including hydro generation and distributed PV) were broken time and again in 2021.

However, the pace is forecast to accelerate further. Since the 2020 ISP, NEM jurisdictions and the Commonwealth Government have strengthened their emission reduction targets and industry has committed to the electrification of Australia’s economy. Their confidence is rising in the viability of electric alternatives in transportation, manufacturing and mining. At the same time, coal-fired generation is withdrawing faster than anticipated, so that investment in utility-scale generation and storage must accelerate to replace it.

This Section 3 details the renewable energy development opportunities needed to help double the NEM’s operational consumption by 2050 to meet decarbonisation objectives of other sectors, while simultaneously replacing coal-fired generation. In Step Change:

  • DER will deliver about 30% of renewable capacity, with 54 GW of new capacity needed to increase the current 15 GW capacity nearly five-fold to 69 GW.
  • VRE will deliver about 70% of renewable capacity, with over 120 GW of new capacity needed to increase the current 15 GW capacity over nine-fold to nearly 140 GW, to meet renewable energy policies and provide electricity consumers with the lowest-cost generation supply.
  • This VRE capacity is best developed in REZs that coordinate network and renewable investment and foster a more holistic approach to regional employment, economic opportunity and community participation.
  • The renewable share of total annual generation will rise from approximately 28% in 2020-21 to 79% by 2030, to 96% by 2040, and to 97% by 2050.
  • Some curtailment of installed VRE generation may be expected, as it is not economically efficient to further expand the transmission system or build even more storage to enable delivery of all available electrons at all locations at all times (see Section 3.5 for more about curtailment).

This rate of conversion to renewable capacity is fast in both historical and global terms. However, it is far from a stretch target when Australia’s uniquely rich renewable resource is considered. If Australia chose to become a renewable energy powerhouse and capture, store and export that renewable energy in the form of hydrogen, the NEM could require eight times its current capacity.


3.1            Nearly five times today’s distributed energy resources

DER describes consumer-owned devices that, as individual units, can generate or store electricity or have the ‘smarts’ to actively manage energy demand. This includes small-scale embedded generation such as

36 Blakers A et al, “Pathway to 100% Renewable Energy”, IEEE Journal of Photovoltaics, Volume: 9, Issue 6, November. 2019.


residential and commercial rooftop PV systems (less than 100 kilowatts [kW]), PV non-scheduled generation (NSG, up to 30 MW), distributed battery storage, VPPs and EVs.

By 2050, over 65% of detached homes are projected to have rooftop PV in Step Change, with most systems coupled with a battery, meeting these households’ own energy needs and exporting surplus back into the grid. In the most likely scenario, total distributed PV capacity (including rooftop PV and PV NSG) would reach

69 GW, up from 15 GW today. These distributed systems would produce approximately 90 GWh of electricity, enough to meet about a fifth of the NEM’s total underlying demand.

Behind-the-meter domestic and commercial batteries are expected to grow strongly in the late 2020s and early 2030s, as costs decline. EVs are also expected to surge in the 2030s, driven by falling costs, greater model choice and more charging infrastructure. By 2050, between 50% (Progressive Change) and 60% (Step Change) of all vehicles are expected to be battery EVs.

The growth in distributed PV is radically influencing the NEM operational demand profile, with maximum demand now occurring near sunset in most regions, and minimum demand rapidly declining. New sources of dispatchable capacity and critical system services will be required to complement these new resources (see Section 4). The impact of other emerging forms of DER such as EVs will depend on how well the interface with the energy system is planned.

Full DER integration requires a step change in engagement across the industry to ensure all consumers, retailers, networks and other market participants orchestrate these resources to optimise net benefits and maintain security and reliability (see Section 7.2).


3.2            Nine times today’s utility-scale variable renewables

The ISP forecasts the need for ~122 GW of additional VRE by 2050 in Step Change, to meet demand as coal-fired generation withdraws (see Section 5.1). This means maintaining the current record rate of VRE development every year for the decade to treble the existing 15 GW of VRE by 2030 – and then double that capacity by 2040, and again by 2050.

In Hydrogen Superpower, the scale of development can only be described as monumental. To enable Australia to become a renewable energy superpower as assumed in this scenario, the NEM would need approximately 256 GW of wind and approximately 300 GW of solar – 37 times its current capacity of VRE. This would expand the total generation capacity of the NEM 10-fold (rather than over three-fold for the more likely Step Change and Progressive Change scenarios).

Australia has long been in the top five of energy exporting nations. It is now in the very fortunate position of being able to remain an energy superpower, if it chooses, but in entirely new forms of energy.


A mix of solar and wind is required

Both wind and solar VRE is needed for the efficient transformation of the NEM, as they offer complementary daily and seasonal profiles. Taking distributed PV into account, wind and solar will have almost equal shares of NEM generation by 2050.

However, investments in utility-scale wind and solar are forecast to take different paths (see Figure 12 and Figure 13). In the next decade, more wind capacity than solar is efficient to develop to complement the strong uptake of distributed PV. By 2030, wind would represent approximately 80% of all utility-scale VRE installed beyond existing, committed and anticipated projects in Step Change. Utility-scale solar will accelerate again


once there is enough storage and network investment (see Section 5). Although utility-scale solar is relatively low-cost, it needs more storage to time-shift its midday generation peaks to the morning and evening demand peaks, particularly given the abundance of distributed PV generation. By 2050, it is projected to make up 50% of newly installed VRE capacity in Step Change.

Geographical as well as technical diversity across the NEM will help reduce the need for firming and dispatchable resources. The geographic spread of REZs provides that diversity (see Section 3.3).

Offshore wind has great potential due to resource quality, possible lower social licence hurdles, and proximity to strong transmission, but the economics are not yet proven. It is therefore not currently projected to play a large role in the future energy mix at current forecasts of future costs, unless land use considerations limit onshore development. Further cost reductions could see offshore wind feature more prominently in future ISPs.


Figure 12   Growth and share of utility-scale solar and wind capacity, all scenarios


3.3            Renewable energy zones for new VRE

Much of the VRE will be built in REZs that coordinate network and renewable investment and foster a more holistic approach to regional employment, economic opportunity and community participation.

Located in areas with strong community support, quality renewable resources and network with existing or committed spare capacity and system strength, REZs can materially reduce costs and risks for VRE investors, ultimately for the benefit of consumers, by:

  • reducing transmission and connection costs and risks,
  • sharing costs and risks across multiple connecting parties,
  • co-locating and optimising system support infrastructure and weather observation stations, and
  • promoting regional expertise and employment at scale.

The ISP seeks to co-optimise these REZs with potential network investments. The modelling considers how new and existing transmission and the emerging REZs can be a critical enabler for economy-wide emissions reductions. If well planned and supported by appropriate social licence, REZs can improve grid reliability and security, minimise community, environmental and aesthetic impacts, adhere to relevant design standards and regulatory requirements, and offer flexibility and expandability to address the future needs of the power system.

There is already approximately 15 GW of utility-scale VRE installed in the NEM, and approximately another 5 GW is expected to be operational over the next few years, as either committed or anticipated projects.37

While some developments may connect efficiently to existing transmission capacity, many will need strong technical coordination for their connection, and also to engage effectively with local communities, build social licence, and strengthen resource and employment supply chains. The new REZ Design Report process38 has been introduced for that purpose, and is detailed in Section 9.2.

Appendix 3 details each of the 39 REZs, including four offshore wind zones (OWZs), considered in the ISP. In Step Change, the following development is projected above what is already existing, committed or anticipated in each region over the next 10 to 20 years:

  • 38 GW new VRE in New South Wales by 2050. The Central-West Orana REZ would install 3 GW by 2026-27, increasing to 5 GW by 2030 and 10 GW by 2040. The New England REZ would start behind Central-West Orana, but would also install 5 GW by 2030 and 10 GW by 2040. This development is consistent with the minimum development requirements of the New South Wales Roadmap to deliver at least 33,600 GWh p.a.by the end of 2029, as outlined in the 2021 IIO Report39.
  • 47 GW new VRE in Queensland by 2050. Darling Downs, Far North Queensland, North Queensland Clean Energy Hub, Isaac and Fitzroy REZs would all take advantage of spare network capacity to together install approximately 7.2 GW by 2030. Following that, Darling Downs and Fitzroy would see greater development to add more than 4–6 GW each between 2030 and 2040.




37 Data is as of July 2021, AEMO Generation Information Page, at https://www.aemo.com.au/energy-systems/electricity/nationalelectricity-market- nem/nem-forecasting-and-planning/forecasting-and-planning-data/generation-information. Definitions of committed and anticipated are included in each Generation Information update.

38 See NER 5.24

39 At https://aemo.com.au/about/aemo-services/aemo-services-as-the-consumer-trustee.


  • 15 GW new VRE in South Australia by 2050, taking advantage of the Project EnergyConnect inter-connector. REZs with high wind quality would see the earliest development: South East South

Australia with an additional 1 GW by 2030 and 2 GW by 2040, and Mid-North South Australia installing

1.5 GW between 2027 and 2035, reaching 2.5 GW by 2040.

  • 2.5 GW new wind in Tasmania by 2050, provided Marinus Link is built. Of that, approximately 1.5 GW is projected to be installed in the Central Highlands REZ, and 1 GW in the North West Tasmania REZ. No further VRE capacity is forecast and, without significant cost reductions, there is no offshore wind projected in any scenario.
  • 23 GW new VRE in Victoria by 2050, with only 3 GW above what is already existing, committed or anticipated forecast to be required by 2030, in the South West Victoria and Gippsland REZs utilising the existing spare network. Without significant cost reductions, no offshore wind development is projected in Victoria in any scenario.




Part B ISP Development Opportunities




Figure 14   REZ development in the Step Change scenario – 2029-30 (left) and 2049-50 (right)





3.4            Renewable penetration

The NEM is continuing its transformation to world-leading levels of renewable energy output, measured as a percentage of annual generation as well as instantaneously, period by period. Figure 15 presents the level of renewable energy as a proportion of annual generation by scenario to 2049-50. In Step Change, the renewable share of total annual generation will rise from approximately 28% in 2020-21 to 79% by 2030, to 96% by 2040, and to 97% by 2050. In the 2020s alone, half of all NEM generation will switch to renewables.


Figure 15   Evolution of the annual share of total generation from renewable sources for each least-cost development path


Increasingly, AEMO must engineer the power system to operate securely through periods of 100% instantaneous penetration of renewable generation. Based on resource potential in the most likely Step Change scenario, the ISP projects that those periods may commence by 2025, in periods of low demand, and then become more frequent. At times the renewable penetration will exceed the instantaneous demand for electricity from consumers, with storage helping absorb the excess.

By the mid-2040s, electricity supply is expected to be generated almost exclusively from renewable resources, with energy storages helping manage their seasonality and intermittency, and peaking gas generation providing firming support. By 2040, 100% instantaneous renewable penetration is projected to be achieved 36% of the time and 65% by 2050 (see Figure 16), unless constrained due to system security or other operability constraints in the network.


Figure 16   NEM annual share of renewable generation and instantaneous penetration, 2025-2050


3.5            Curtailment of VRE will sometimes be efficient

The ISP modelling confirms that, rather than build network and storage to capture every last watt of energy, it is sometimes more efficient to curtail or ‘waste’ some generation. This may occur when there are system security or other operability constraints in the network, or there is simply over-abundant renewable energy available.

Assuming new transmission infrastructure is developed in accordance with this ISP’s ODP, most of the curtailment identified in the ISP modelling will be at times when utility-scale wind and solar become direct competitors for dispatch, rather than pricing out fossil fuel generation. At these times there is simply not enough operational demand to utilise all available renewable resources. Adding more storage to soak up the surplus supply is unlikely to be economically efficient because, with so much annual renewable generation, there is little marginal value in shifting VRE to other times in the day, month or year.

Curtailment is strongly correlated with daylight hours and therefore solar output, with only a small proportion of curtailment projected to occur at night. Curtailment also occurs most frequently during spring and summer months as solar irradiation improves. This indicates that, based on future technology cost estimates, installing sufficient VRE to meet the energy needs of winter and accepting some curtailment in summer is likely to be a more efficient outcome than the alternative of building less utility-scale solar but more seasonal storage.

By 2050, the proportion of curtailed generation in Step Change increases to approximately 20% of total available VRE output in aggregate (assuming some new transmission): see Figure 17. At these levels, market reform will be needed to maintain incentives for investors to develop the optimal VRE capacity. The market reforms presently being developed by the ESB40, including capacity mechanisms and increased market transparency, will be important enablers to support the continued transition to deliver the outcomes forecast by this Draft ISP.




40 ESB post-2025 market reform recommendations, available at https://esb-post2025-market-design.aemc.gov.au/delivering-post-2025-reforms.


Variable renewable energy (TWh)


4.           Dispatchable capacity needed to firm the renewable supply

Section 3 detailed the renewable resources that will be needed to meet consumer demand efficiently as coal generation retires, at the same time as industry and households switch to electricity from petrol and gas-fired power.

This transformation poses significant operability challenges to retain the levels of reliability and security that consumers rightly expect from their power system. Significant investment in the NEM is needed to treble the firming capacity that can respond to a dispatch signals, along with efficient network investment. Wholesale demand response and other flexible loads will also help manage peak loads and troughs, and reduce reliance on more capital-intensive responses.

The ISP seeks to find the most cost-efficient balance between investment in network transmission (see Part C) and in dispatchable capacity to complement renewable generation development. The less transmission capacity there is, the more dispatchable capacity is needed, and vice versa.

This Section 4 details the development opportunities in the NEM to meet those challenges, as part of the ODP. It discusses the following projected shifts:

  • the withdrawal of 23 GW of coal capacity, 14 GW of it by 2030 in the Step Change scenario,
  • 45 GW of new battery and hydro storage (distributed and utility-scale), able to respond to a dispatch signal to help firm the renewables,
  • a total of 9 GW of gas-fired generation for peak loads and firming, particularly during long ‘dark and still’ weather periods, with the need to offset emissions,
  • the increased value of wholesale demand response and other flexible loads to take advantage of renewable energy oversupply, and minimise disruption during undersupply,
  • the increased need for network to shift electricity from where it is produced to where it is needed, maximise the value of geographic diversity and efficiently share resources across the NEM, and
  • the increased need to strengthen power system services as the system rapidly approaches 100% instantaneous penetration of renewables.

The detailed analysis underpinning this section is set out in Appendix 4 (System Operability).


4.1            Coal retiring two to three times faster than anticipated

Current announcements by thermal plant owners suggest 5.4 GW of the current 23 GW of coal capacity will withdraw by 2030, but the modelling suggests 14 GW is likely to withdraw by then in Step Change.

The sector is undergoing a more rapid change than has been previously expected. Owners of coal generators have already either brought forward their announced retirements, or indicated they would.41 Their decisions


41 Yallourn Power Station (by four years, to 2028), Eraring Power Station (one unit by two years, to 2030, another by one year, to 2031), Mt Piper power station (by two years, to 2040). Mothballing of one unit of Torrens Island B Power Station for three years from October 2021. Early closure of both the Loy Yang A and B power stations increasingly likely. See AGL’s media release https://www.agl.com.au/about-agl/media-centre/asx- and-media-releases/ 2021/july/agl-to-mothball-one-unit-at-torrens-b-in-south-australia?zcf97o=vlx3ap, https://www.afr.com/policy/energy-and- climate/alinta-concedes-coal-plant-may-shut-15-years-early-20211012-p58z8x.


remain necessarily uncertain, as they grapple with operating dynamics in the face of cheap renewable generation, their own competitive strategies, plant conditions, regulatory and remediation costs, and the wishes of local communities (to either close or remain open). Given these uncertainties, the effective coordination of closures will be extremely challenging, and prudent planning takes into consideration the potential impacts of less coordinated closures on consumers.


14 GW of coal forecast to withdraw by 2030, but uncertainty expected

The currently announced closure timings suggest that only 5 GW of the current 23 GW of coal capacity will withdraw by 2030. The Draft ISP forecasts faster withdrawals across all scenarios:

  • In Step Change, modelling indicates 14 GW of coal generation is likely to withdraw by 2030 to meet tighter carbon budgets for the sector. All coal capacity could close as early as 2040.
  • In Progressive Change, modelling indicates 8 GW of coal generation is likely to withdraw by 2030. From then, competitive operating conditions drive regular withdrawals slightly earlier than currently reported by participants, until 2 GW capacity remains, then representing only 2% of the total generation capacity.
  • In Hydrogen Superpower, modelling indicates 20 GW of the current 23 GW of installed capacity is likely to withdraw by 2030, in response to the ambitious decarbonisation objectives, and all coal (as well as

mid-merit gas) would retire by 2050. This is in spite of the increase in demand for electricity for hydrogen production.

  • In Slow Change, modelling indicates that 10 GW of coal generation is likely to withdraw by 2030, even more than in Progressive Change. This is because lower loads and the same investment in VRE to meet renewable energy policies result in lower daytime residual demand (operational demand met by generators other than VRE), and so less need for dispatchable coal. By 2050, only 2 GW of coal capacity is expected to remain operational (as forecast in Progressive Change).

These retirements are shown in Figure 18 below. The retiring coal will require significant scale and diversity of storages and other dispatchable generation to firm VRE (see Section 5.2 below).


Figure 18   Forecast coal retirements, all scenarios versus announced retirements


Of the coal types, higher emission brown coal generation may be retired ahead of black coal generation to help meet the faster emission reduction ambitions of Step Change and Hydrogen Superpower. However, the pathway to a zero-coal grid would likely progressively retire power stations across more than one region at a time so closures can be managed reliably and securely. Figure 19 sets out that modelled pathway for Step Change, highlighting an earlier and diverse retirement schedule than present announcements would suggest.


Figure 19   Forecast coal retirements, Step Change technology and regional outlook


4.2            Treble the capacity of dispatchable storage, hydro and gas-fired generation to firm renewables

Approximately 45 GW / 620 GWh of dispatchable storage capacity, 7 GW of existing dispatchable hydro and 9 GW of gas-fired generation is required by 2050, to efficiently operate and firm VRE.

By 2050, the most likely Step Change scenario would call for over 60 GW of firming capacity that can respond to a dispatch signal, including utility-scale batteries, hydro storage, gas-fired generation, smart behind-the-meter batteries or VPPs and (potentially) V2G services from EVs. The willingness of consumers to lower their consumption during high price periods (referred to as demand-side participation, or DSP) will also have an important role to maintain reliability and avoid involuntary load shedding. While the system today has approximately 43 GW of firming capacity, 23 GW of this is coal capacity. As this coal retires, it needs to be replaced with new low-emission firming alternatives. New utility-scale battery and pumped hydro storage, located at appropriate parts of the network, will both enable more effective dispatch of clean electricity on demand, and provide critical system security services.

This Section 4.2 considers how:


  • the NEM’s daily operational demand pattern is forecast to change as distributed storage helps soak up excess distributed PV during the day, and reduce peak demands in the evening,
  • different storage depths are needed to manage this intra-day pattern, as well as match supply and demand between days and between season, with high levels of consumer engagement needed to coordinate DER storages, and


  • gas-fired generation will help manage extended periods of low VRE output and peak demands, and also deliver power system services to provide grid security and stability as coal retires.


The average daily operational demand pattern will flatten over time

Energy consumption behaviours will continue to change, driven by continued DER uptake, improving energy efficiency and increasing electrification. As it does, the time-of-day operational demand will change shape, with a gradual flattening of the peaks and troughs. Figure 20 shows the outcomes in Step Change, normalised to remove the effects of rising energy consumption.


Figure 20   NEM normalised average time of day operational demand, Step Change


Figure 20 demonstrates a number of underlying trends in consumer demand occurring over the next 30 years:


  • Daytime minimum demand will initially be driven lower with continued uptake of distributed PV, but then be driven up by the electrification of other sectors and the opportunities for customer battery systems to charge during periods of excess solar generation.
  • Evening peak demand will flatten as distributed storages use the energy absorbed from distributed PV during the day and discharge this during the evenings.
  • EV charging during the day will further improve the operability of the power system. EV charging in the evening will add to system peaks and so to system costs, so charging infrastructure and tariff design to encourage daytime charging would benefit consumers.

Additional insights on consumer demand (not captured in Figure 20) include:

  • Flexible demand response will be used to flatten the shape of operational demand, helping to reduce the need for new firming capacity42.

42 To enable the scale of demand response potential assumed in later years in some scenarios, market reforms such as those reported on in Section 4.3, may be necessary, as well as acceptance from consumers.


  • Operational electricity consumption will increase during winter more than summer, as electrification of heating loads in particular introduces new load, and shorter winter days reduce the output from distributed PV systems.
  • Maximum demand in winter is still forecast to be lower than in summer in most regions, however the NEM-wide maximum daily operational consumption is projected to occur in winter, representing a shift from historical trends.
  • In the later years, hydrogen production may provide new, flexible load. Electrolyser facilities will operate strongly during periods of excess supply such as during the day where solar production is strongest.


A range of firm, dispatchable resources needed to firm VRE

Figure 21 shows how the different forms of dispatchable capacity interact to deliver electricity to consumers across New South Wales, Victoria, South Australia and Tasmania through a forecast winter week in 2039, using a historically observed set of weather conditions. Queensland consumers are excluded to showcase the dynamics in the other regions more easily, but Queensland generation is available to be imported.

In this sample winter week, weather conditions are calm, cloudy and cool, leading to higher heating loads in the southern regions and limited renewable energy availability. Above 0 on the Y-axis is generation consumed, and below 0 is excess generation stored.

Figure 21 demonstrates why the ISP calls for technological and geographic diversity in the ISP development opportunities, supported by transmission capacity to share resources. In the illustrated week, Queensland and northern New South Wales wind offered reasonable generation, unlike the becalmed sites across the southern mainland and Tasmania. Inland locations for utility-scale PV are less likely to be shaded by cloud than the distributed PV in coastal cities.


Figure 21   A week’s dispatch outcomes across the NEM (excluding Queensland), Step Change, 2039

The most severe renewable energy shortfall runs from Sunday to Tuesday, when there is very little wind generation and greater reliance is placed on gas and hydro generation. In support, transmission enables sharing of available firm resources, including surplus renewable energy from Queensland. Storages play a pivotal role. On Friday to Sunday, they absorb abundant renewable energy, particularly during the day when


excess solar generation is available. They then play a strong firming role during the three days of low renewable energy – even discharging throughout Monday night.

Through this modelled week and from season to season, the NEM will draw on a range of different storage types and depths: see the box below. These uses are described through the rest of this section.


Medium utility-scale storage needed over the next decade

Figure 22 shows the forecast need for each of the storage types through the Step Change scenario. The most obvious feature on the left-hand chart is the projected growth of coordinated DER (see next section) and other distributed storage. However, the most pressing utility-scale need in the next decade (beyond what is already committed) is for storage of 4 to 12 hours duration to manage daily variations in solar and wind output and meet consumer demand as coal capacity declines. This is visible in the left-hand figure, with most utility-scale storage (aqua-coloured bands) shown at medium depth.

This need for medium-depth storage includes the 2 GW of storage that can be dispatched for at least eight hours, needed by the end of 2029 to help meet the objectives of the New South Wales Roadmap. The 2021 IIO Report43 recognises the supply chain and other issues that may delay delivery of these projects, and allows for contingencies. This delivery risk is not inherently captured in the modelling of the Draft ISP, but is qualitatively considered when selecting the Draft ODP (see Section 6.3.3).

As demonstrated in the right-hand figure, Snowy 2.0 provides much of the necessary additional storage depth to 2030, although additional storage depth is needed in the 2030s and 2040s.

43 At https://aemo.com.au/about/aemo-services/aemo-services-as-the-consumer-trustee.


Figure 22   Forecast of MW storage capacity (left) and energy storage capacity (right), Step Change



As shown in Figure 22, distributed storages including coordinated VPPs are forecast to represent almost three-quarters of dispatchable capacity in Step Change by 2050. The forecast strong uptake of distributed battery storage over the next decade reduces the need for shallow storage at utility scale44. This distributed storage will work in tandem with the daily solar PV generation cycle to smooth out much of the daily curve for NEM operational demand, and reduce the need for traditional generation and firming sources such as coal and gas.


Daily demand and PV supply cycles

The complementary daily profiles for electricity demand and solar PV generation create a great opportunity for coordinated DER storages to shift energy from day to evening and night.

In Figure 23 below, the red line represents grid demand without the impact of coordinated DER storage. The yellow shape represents excess PV generation through the daylight hours, which is sent into this distributed storage. After 4:00 pm, the evening peak can then draw on that stored energy. The black line represents the resultant grid demand after taking into account the charging and discharging of coordinated DER storage.

Without that storage, there would be greater need for traditional hydro and gas-fired generators, as well as utility-scale shallow storage, to meet higher peaks of demand.

44 If distributed storage uptake is slower than assumed, more utility-scale shallow storage would be needed instead.


Figure 23   Average time of day profile – impact of co-ordinated distributed storage, Step Change

Need for high levels of engagement to coordinate DER storages

The effectiveness of this DER storage depends on it being well coordinated, for example through VPPs. Increasingly active management of consumer devices (through smart, cloud-connected and rule-based devices) will reduce the scale of utility-scale investment needed to maintain the reliability and security of the system. This in turn depends on greater consumer adoption of those smart technologies, with support of retailers, networks and other market participants. This need is further discussed in Section 7.3.


Deep storage to manage seasonal variability

Deeper storage (and traditional hydro generation) will be vital to manage seasonal, and long duration variations in renewable resource availability. Figure 24 shows two aspects of this seasonal cycle that will heavily influence NEM planning and operation.


Figure 24   Daily energy stored in deeper storages and traditional hydro reservoirs over a year


First, the relatively strong spring water inflows (from snow melt) enables traditional deep storages to discharge over the summer. Then, as early as 2030, additional VRE means that less discharge is required over


summer45, allowing the stored energy to be held over to autumn where solar generation is lower, and then into winter to meet heating needs as gas appliances are increasingly converted to electricity.


Peaking gas generation needed to balance VRE variability

Gas-fired generation will play a crucial role as significant coal generation retires, both to help manage extended periods of low VRE output and to provide power system services to provide grid security and stability (see Section 4.3).

The development opportunities for gas-fired generation are forecast to primarily be for peaking gas generators, to provide firming. With the cost of VRE declining rapidly in the ISP assumptions, limited opportunities exist for expansion of mid-merit gas plant, unless VRE is limited by transmission access.

In a high renewable penetration grid, the exposure to low VRE availability conditions, and other conditions that provide operability challenges, will likely increase. Gas-fired generation and storage will play an important role in these conditions. Figure 25 shows four additional examples of a week’s variable conditions in 2035. It demonstrates the complementary role that storage, hydro and gas generation will need to play to efficiently operate beside renewable generation.


Figure 25   Indicative generation mix in the NEM, Step Change, 2035


The figure demonstrates four conditions:


  • Low renewable output and high demand (top left): the system relies more on hydro, and gas, complemented in the evening peak by shallow storage (including VPP) charged from distributed PV and utility-scale solar during the day. Existing mid-merit gas generators assist through the night, with peaking gas generators needed in the evening and occasionally the morning peaks.




45 Although minimum releases for environmental or irrigation purposes at still observed.


  • High renewable output and high demand (top right): gas is needed to meet the demand peaks just after sunset, and to keep going through the night to cover wind variability.
  • Low renewable output and low demand (bottom left): gas is needed through the night, particularly during winter, when solar output is lower.
  • High renewable output and low demand (bottom right): With VRE output well in excess of total demand, gas generation is barely needed. Deeper storages fill their reservoirs from the excess energy.

The role of gas as an on-demand fuel source for extended operating periods could also be met by alternative technologies such as hydrogen turbines, or potentially greater investment in long-duration storages. However, under current assumptions, gas remains the most cost effective solution, complementing storages, to firm renewables.


4.3            Stronger services for power system requirements

Just as the NEM’s generation and dispatchable resources are transforming, so too will the manner in which the power system services needed to keep the NEM secure and reliable are provided. For example, with fewer synchronous generating units, there are fewer sources of system strength, dynamic reactive support, inertia, primary frequency response and frequency control ancillary services that these units have traditionally provided. Likewise, there are fewer options for black restart services and sources.

There are several actions being taken to ensure these system services support the NEM as it decarbonises and decentralises as projected in this ISP.

  • AEMO’s annual System Security Reports46 assess the current and five years’ projected needs for system strength, inertia and network support and control ancillary services (NSCAS) in the NEM, and declares any shortfalls. The assessments are based on the modelling in this Draft ISP, and demonstrate the growing and accelerating need for system services as the system transforms.
  • AEMO’s Engineering Framework47 enables industry participants to collaboratively define the operational, technical and engineering requirements for the NEM’s future, and informs the market reforms being undertaken by the ESB. It describes the initial roadmap to inform preparation of the NEM for operation under six identified operational conditions48, including 100% instantaneous penetration of renewable energy by 2025. These actions will be prioritised with industry and integrated into implementation workplans.
  • Advanced inverters with grid-forming capabilities and suitable design, placed at strategic sites in the NEM, have the potential to provide a range of future power system requirements. Advanced inverters are not yet demonstrated at the necessary scale to completely replace the services currently provided by synchronous generation in the NEM, and focused engineering is urgently needed to address the remaining issues and realise their promise. To this end, the Australian Renewable Energy Agency (ARENA) is currently exploring the viability of further funding to rapidly prove up the capability of advanced inverters at scale, and hosted a webinar on Monday, 8 November 2021 to gain insight on the





46 At https://www.aemo.com.au/energy-systems/electricity/national-electricity-market-nem/nem-forecasting-and-planning/planning-for-operability.

47 At https://aemo.com.au/initiatives/major-programs/engineering-framework.

48 See https://aemo.com.au/newsroom/news-updates/engineering-framework-takes-shape.


ability to accelerate advanced inverter capabilities on battery projects and address the associated barriers.

These technical requirements are complemented by numerous regulatory and market reforms underway for essential system services, which are vital to enable participants to invest in and operate infrastructure that will provide system services in addition to energy. The market reforms already implemented or in advanced stages include:

  • Five Minute Settlement and Wholesale Demand Response to provide better price signals for fast response and flexible technologies, and enable businesses to provide peak shaving services in the spot energy market.
  • The ESB’s post-2025 reform recommendations. Following Ministerial approval of these recommendations, AEMO is working with the AEMC through the rule change process to implement mechanisms for essential system services for the physical power system, and better integration of DER. The ESB has also been tasked by Ministers to undertake further policy work on capacity and network congestion mechanisms for consideration in late 2022. Given the amount of reform underway, AEMO is also working with industry to develop a NEM Regulatory and IT Implementation Roadmap, aiming to reduce reform implementation costs and risks.
  • Fast frequency response (FFR) market for ancillary services, designed to provide faster frequency control services. AEMO is required to design and put in place these market arrangements by October 2023.49
  • Efficient management of system strength, to address the urgent need to make it simpler, faster and more predictable for new generation, renewables in particular, to connect to the grid while keeping supply as secure as possible.
  • Primary frequency response (PFR) incentives. A Rule change consultation by the AEMC is currently underway50, to examine arrangements supporting the control of power system frequency and to incentivise plant behaviour with the aim of reducing overall consumer costs.


49 AEMC Fast Frequency Response market ancillary service, at https://www.aemc.gov.au/rule-changes/fast-frequency-response-market-ancillary- service.

50 See https://www.aemc.gov.au/rule-changes/primary-frequency-response-incentive-arrangements.


71 See https://aemo.com.au/consultations/current-and-closed-consultations/2022-isp-consultation-non-network-options-supply-sydney-newcastle- wollongong.

72 At https://www.legislation.nsw.gov.au/view/html/inforce/current/act-2020-044.


9.   Further analysis in preparation for final 2022 ISP

AEMO will be conducting additional analysis between draft and final 2022 ISP to further validate the analysis and help decision makers and industry better understand:

  • the distributional effects of the ODP,
  • the impact of changes in marginal loss factors on REZs, and
  • climate scenarios and extreme weather case studies.


Distributional effects of the ODP

The distribution of benefits of the ODP is unlikely to be uniform to all consumers in all regions. AEMO identified in the ISP Methodology that detailed short-term modelling would be deployed to evaluate these effects, including consumer bill impacts and transmission network charges. This analysis will be conducted for the final ISP, in accordance with the AER’s CBA Guidelines73.


Impacts of changes in marginal loss factors on REZ

Network losses occur as power flows through transmission lines and transformers. In the NEM, losses are financially represented through marginal loss factors (MLFs). A renewable generator’s revenue is directly scaled by its MLF. Increasing the amount of VRE connected in remote REZs will typically increase losses and decrease local MLFs.

AEMO is aware of the potential impact of REZ design on MLFs and so on the financeability of individual investments. Renewable energy investors may tolerate a relatively low MLF if the project is likely to have low network congestion or high resource quality. In the final ISP, AEMO will aim to provide information on risks relating to MLFs alongside other key REZ investment metrics such as network congestion and resource quality and consider whether future changes in MLFs are likely to materially influence the choice of REZ developments in the ODP.


Climate scenarios and extreme weather case studies

Australian energy consumers have historically enjoyed the benefits of resilient energy systems, but a renewed focus on resilience is needed to maintain these benefits as the climate changes and the energy system transforms. These two shifts, in combination, have the potential to significantly decrease energy system resilience and increase the likelihood of undesirable outcomes. The vulnerabilities, in particular extreme weather events, are recognised as material risks to individual assets and the integrated energy system.

Where possible, AEMO has considered these vulnerabilities in the Draft ODP, aiming to maximise energy system resilience through good system planning and design. Despite these efforts, limitations in climate, energy system and cost benefit modelling mean that many of these risks are excluded from primary ODP decision-making.



73 At https://www.aer.gov.au/system/files/AER%20-%20Cost%20benefit%20analysis%20guidelines%20-%2025%20August%202020.pdf.


To ensure these risks are fully understood, AEMO will develop a small selection of compound extreme event case studies for the final 2022 ISP. Building on AEMO’s work with the Bureau of Meteorology and CSIRO74, these case studies will demonstrate energy system and societal outcomes that could plausibly occur in response to events such as:

  • coincident heatwaves and bushfires, impacting consumer demand and power system capability,
  • extreme wind or solar droughts, possibly resulting in extremely low energy availability,
  • extreme storm or cyclone risks, that have the potential to damage generation and transmission infrastructure, and
  • other multiple or non-credible contingencies, impacting key inter- or intra-regional transmission availability.

These case studies will demonstrate whether some CDPs are more resilient to extreme weather events than others, and identify risk mitigation strategies aligned with AEMO’s Engineering Framework75. Where opportunities are identified through these case studies that enhance energy system resilience in the long-term interests of consumers, AEMO may consider these opportunities within, or in addition to the Draft ODP.




































74 See https://www.climatechangeinaustralia.gov.au/en/projects/esci/esci-case-studies/case-study-extremes/.

75 See https://aemo.com.au/en/initiatives/major-programs/engineering-framework.


Supporting documents


Draft ISP Appendices and web assets are available on AEMO’s website at https://aemo.com.au/consultations/current-and-closed-consultations/2022-draft-isp-consultation.


Draft ISP Appendices
  • Appendix 1 Stakeholder engagement                       see Section 2
  • Appendix 2 ISP development opportunities               see Section 3 and Section 4
  • Appendix 3 Renewable energy zones                       see Section 3.3
  • Appendix 4 System operability                                 see Section 4
  • Appendix 5 Network investments                             see Section 5
  • Appendix 6 Cost benefit analysis                             see Section 6
  • Appendix 7 Power system security                           see Section 4.3


Draft ISP web assets
  • Chart data
  • Generation outlook



Information relating to inputs, assumptions and scenarios is available at: https://aemo.com.au/energy- systems/major-publications/integrated-system-plan-isp/2022-integrated-system-plan-isp/current-inputs- assumptions-and-scenarios.

  • 2021 Inputs, Assumptions and Scenarios Report (IASR)
  • IASR Addendum
  • IASR Workbook


Non-network consultations

AEMO has issued a call for submissions on non-network options for the two new actionable ISP projects:


  • New England REZ Transmission Link76, and
  • Reinforcing Sydney, Newcastle and Wollongong Supply77.






76 See https://aemo.com.au/consultations/current-and-closed-consultations/2022-isp-consultation-non-network-options-new-england-rez-link.

77 See https://aemo.com.au/consultations/current-and-closed-consultations/2022-isp-consultation-non-network-options-supply-sydney-newcastle- wollongong.

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