Proposed ESB Transmission Access Reforms and Considerations for REZ Design
Introduction
The Energy Security Board’s (ESB) transmission and access reforms and state-led development of renewable energy zones (REZs), represent some of the most ambitious market developments since the National Electricity Market (NEM) was established in the late 1990s. The implementation of both these measures will be progressed in tandem into the late 2020’s and beyond, with states focused on accelerating renewables development and further decarbonisation of the electricity sector as a critical path to meet emissions reduction targets.
States’ development of REZs has occurred in the context of uncertainty regarding a uniform direction on transmission and access issues. Most recently, the failure to obtain consensus on the Australian Energy Market Commission’s (AEMC) Coordination of Generation and Transmission Investment process, and the lengthy options analysis and iteration undertaken by the ESB to date has almost certainly, despite the recent change in Federal Government, made states wary of believing that genuine reform is possible. It is now more important than ever that transformational network development, facilitated by the Australian Energy Market Operator’s (AEMO) Integrated System Plan and state REZs, is accompanied by similarly important uniform regulatory reform. Both measures will be necessary to drive an accelerated and efficient rollout of renewable projects and further decarbonisation of the energy system.
In February this year, Energy Ministers took steps towards a definitive model for access and pricing reform, endorsing the Congestion Relief Market (CRM) and the priority access framework proposed in the ESB’s preferred ‘hybrid model’.[1] While significant design elements still need to be worked through by the ESB, there is now indication that a model amenable to jurisdictions and industry can be implemented.
The ESB’s transmission and access reforms should be largely complementary to REZs, facilitating operational efficiencies and locational signals that REZs alone cannot provide. However, the implementation timing and significant breadth of the ESB’s proposed reforms means they will have implications for REZs established prior to, and following, reform commencement. Given jurisdictions’ apparent intention to provide REZ rights to proponents on a long-term (and certain) basis, it is important that they take a view on not only the commercial and regulatory risks that may arise for REZ proponents by way of the changes proposed by the ESB, but also the opportunities that these potential reforms present for proponent REZ engagement in the near term.
This article explains the ESB and state REZ reforms under development, explores some of their interactions, and discusses some issues that jurisdictions should consider now so as to ensure greater coordination with the potential future market environment. These include:
How proposed changes to operational incentives, and corresponding changes in operational behaviour of energy storage facilities, will impact on the identification of REZ capacity limits, and the types and quantity of access rights that can be allocated to REZ proponents;
How generators located in pre-existing REZs should be integrated into the broader priority access regime to ensure investor certainty (both now and later), and efficient network outcomes; and
How the potential benefits that arise by way of the ESB’s reforms – particularly in relation to priority access rights – can be used now to incentivise engagement by proponents, and reduce taxpayer liability.
ESB and State REZ Reform Progress
On 24 February, Energy Ministers, under the Energy and Climate Change Ministerial Council (ECCMC), requested the ESB work with Senior Officials and stakeholders to develop the voluntary Congestion Relief Market (CRM) and the ‘priority access’ model.[2] The Congestion Management Model (CMM), previously flagged by the ESB as a ‘back-up’ if the cost benefit analysis for the CRM was not positive[3], was ruled out. Cost benefit analysis released by the ESB soon thereafter identified quantified net benefits of $2.1 – $5.9 billion of the ‘hybrid’ model.[4]
The ESB now intends to progress detailed design and consultation on the CRM and priority access model, with the ESB to consult on:
Detailed design during Q2 2023, before recommending a detailed design to Energy Ministers in mid-2023; and
Rule changes in late 2023, before finalising rule amendments by no later than mid-2024.[5]
Earliest implementation of the ESB-led reforms is expected to be 2028 or 2030.[6]
Simultaneously, States are progressing REZs along different timeframes:
NSW is the most advanced of the NEM jurisdictions, with the Central-West Orana (CWO) REZ declared by Order in October 2021, and the Access Scheme Order setting out details of access arrangements made in December 2022.[7] Shortlisting and financial value bids for the CWO REZ were concluded in early 2023.[8] NSW has also made Orders declaring the New England, South West, Hunter-Central Coast and Illawarra REZs.[9] NSW has established AEMO Services and EnergyCo to lead the planning and implementation of NSW REZs.
The Victorian Government, via the powers under the National Electricity (Victoria) Act 2005, has already implemented various REZ facilitating projects, including those related to the South West, Murray River and Central North REZs.[10] It is continuing to progress design of the Victorian REZ model, having released a directions paper in February 2021 and preliminary design consultation paper in July 2022.[11] VicGrid has been established to coordinate the planning of the state’s REZs.[12]
Queensland has identified three Queensland REZ (QREZ) regions, and has released a Technical Discussion Paper to progress design of the framework to be implemented via legislation. Currently, it is proposed that QREZ transmission be developed by the jurisdictional transmission network service provider (TNSP) Powerlink.[13] Similar to Victoria, Queensland has initiated early transmission upgrades in some QREZ regions through specific funding allocations[14], with the Clean Energy Finance Corporation (CEFC) also contributing to some southern transmission upgrade projects[15]. The Queensland Government has also recently announced it will deliver the North Queensland Copperstring transmission project that will help facilitate the Northern QREZ.[16] No legislative framework or detailed design has yet been released.
Tasmania has published some principles around REZ development via the release of its Renewable Energy Coordination Framework.[17] This framework sets forth key actions for Government to take in order to coordinate transmission and generation, as well as to incentivise renewables development. Tasmania appointed Renewables, Climate and Future Industries Tasmania (ReCFIT) as the REZ Coordinator in mid-2022.[18] In December 2022, the Tasmanian Government announced the North West REZ would be the first region to be explored in detail for its potential to host the State's first Renewable Energy Zone (REZ).[19]
Uniform Operational reforms: the ESB’s Congestion Relief Market
The ESB transmission and access reforms attempt to address efficiency issues that arise in operational timeframes, and investment timeframes. Operational timeframes relate to the decisions of market participants in real time in response to signals provided by the market.
The ESB’s proposed reform to address current inefficient operational incentives is the CRM. While various forms of the CRM have been proposed[20], the most recent materials provided by the ESB provide a model containing a co-optimised energy market (that establishes access to the regional reference price (RRP)) and a subsequent optimisation market (the CRM) that determines final physical dispatch. [21] The CRM enables participants to engage in mutually beneficial trades that will result in them paying, or receiving additional money, to adjust their physical dispatch upwards or downwards based on the marginal cost of network congestion relief at a particular node (the CRM price).
Participation in the CRM, which would be voluntary, would require participants to submit two sets of bids: initial bids would be in the energy market by reference to the RRP, the second set of bids for the CRM (if not opted out of) would be for adjustment to physical dispatch by reference to a nodal locational marginal price (LMP) (in other words, taking into account of the costs of network congestion at the relevant node).[22] The revenue received by generators comprises the energy market access dispatch ($/MWh) (as is currently the case), plus or minus any incremental adjustments calculated at the CRM price ($/MWh).[23]
Interaction of the CRM and proposed State REZs
The CRM appears to be compatible with all state REZ frameworks. The REZ frameworks currently developed or flagged by states do not attempt to modify the uniform dispatch process operated by AEMO using the NEM Dispatch Engine (NEMDE). As such, it appears the modifications to physical dispatch via the optimisation run under the CRM would apply equally to dispatch for generators within and outside a REZ.
Despite this apparent compatibility, where optimisation of physical dispatch occurs under the CRM, there is a question as to how potential changes in storage charging and discharging patterns will interact with the type and quantity of access rights available to generators within a REZ. Currently, most jurisdictions have indicated they will adopt a ‘physical access rights’ model that operates by identifying a limit on the available aggregate REZ network capacity, and allocating this to generation projects based on expected generation and load profiles. In summary:
NSW has adopted, at least for the Central West Orana REZ, a physical access rights model, which relies on an aggregate maximum capacity cap (and curtailment target), which largely determines access rights available to individual generators.[24]
The Victorian scheme has not yet identified whether it will allocate physical or financial rights (or some combination) to REZ projects (or maintain an open access regime).[25]
Queensland has proposed adopting a physical access right model based on the hosting capacity of the REZ.[26]
Tasmania is not at a stage of indicating a preference for either approach.
The CRM provides for potential network congestion relief by creating an incentive for storage facilities to charge at times of high congestion. It does this by allowing storage facilities access to the locational marginal price (LMP) at the relevant node, rather than the regional reference price (RRP). All things being equal, the relevant LMP should be lower than the RRP at times of higher congestion.[27] Should the incentive for storage to charge at times of high congestion be ignored when determining the generation and load profiles of projects in the REZ (and thus the access rights that can be offered to generation within the REZ), there is a likelihood that sub-optimal use of REZ network capacity will occur, because forecasts will ignore the ability of storage to relieve some measure of congestion at times of peak network use, and thus free up REZ network capacity to the shared network.
All jurisdictions that have proposed REZ design models have acknowledged, to a greater and lesser extent, the important role that storage technologies can play in REZs, but none have yet proposed a way of utilising storage to facilitate higher REZ output at times of peak demand, or how to allocate REZ access rights that acknowledges this potential opportunity.
Currently NSW does not take into account the charging properties of storage projects as part of setting the aggregate maximum capacity cap for the Central West Orana REZ (see below NSW Case Study: Dealing with Storage in the CWO REZ).
Victoria has explicitly acknowledged that storage can compete with other generation for network access during peak demand periods, and would likely require additional incentives to facilitate charging during periods of peak congestion.[28] Despite these observations, the Victorian arrangements do not currently identify any additional incentives for storage to mitigate congestion.
Queensland, while distinguishing between technology types and flagging a role for storage and load within QLD REZs, has not yet provided a position on how storage would be treated, or whether there would be capacity for storage to mitigate congestion at times of peak demand.[29]
Similarly, the Tasmanian Government has not yet developed a firm position on storage, only noting that the development of REZs in Tasmania seeks coordination between, “transmission, generation, storage and firming infrastructure…”[30]
As noted, the CRM should help address the storage incentive issues, but states should proactively consider – ahead of ESB reforms coming into force – the type and quantity of access rights that will best take advantage of CRM opportunities for storage.
Optionality for financial rights may be an appropriate way to address future operational uncertainty
Where jurisdictions seek to allocate access rights by way of identifying projects’ impact on REZ network physical capacity at any one time, they will require modelling to understand the charging and discharging profile of storage and capacity profile of generation assets. Notwithstanding the difficulty of accurately forecasting storage operation, the opt-out model currently proposed for the CRM may make this forecasting more difficult given that it is conceivable that some storage projects may engage in the CRM and others may not.
This issue could potentially be overcome by allowing some oversubscription of generation capacity into the REZ, while allocating a proportionate quantity of financial rights to this capacity to mitigate against the risk that REZ infrastructure is not used efficiently when storage is able to charge at times of high congestion.
NSW consulted on financial compensation models involving tiered financial rights in earlier iterations of access rights models. These models allowed generators holding the highest form of financial rights (Tier 1) to receive payments from those generators with lesser rights (Tier 2) if the dispatch of Tier 2 generators resulted in the constraining off of Tier 1 rights holders.[31]
Given the uncertainty of the incentives that might be provided to generators and storage via the ESB’s reforms, embedding optionality to provide financial rights or other compensation models may provide for more efficient use of the network at a later time. An important consideration for jurisdictions will be striking the right balance of certainty for potential investors now, versus the potential future benefits.
NSW CASE STUDY: Dealing with Storage in the CWO REZ
While the CWO Position Paper notes that the expected capacity profile for storage projects is to be based on market modelling, current regulation appears to preclude this modelling taking into account the charging characteristics of storage.[32]
Storage projects are not specifically defined in the Access Scheme Order, but are captured under the definition of ‘project’.[33] The definition of ‘aggregate expected capacity profile’[34] explicitly excludes the consideration of electricity consumption within the REZ by any ‘approved project’ which includes any ‘project’ that is, or is to be, located in the CWO REZ.[35] As such, the CWO REZ access arrangements contemplate the treatment of storage as a generator but not as a load.[36]
In addition, the headroom assessment carried out by EnergyCo, to identify whether additional access rights or network capacity is available to existing projects, is based only on ‘maximum capacity’ (of ‘potential future projects’) relative to existing aggregate capacity. Because the definition of ‘maximum capacity’ is related to capacity (in MW) it is doubtful that this would take into account the load characteristics of storage projects.[37]
The inclusion in the NSW CWO REZ design of stand-alone storage as a late design choice may explain why the Access Scheme Order does not accommodate storage in its charging capacity. A more overarching consideration however, is that – absent the CRM reforms - storage is incentivised to discharge at times of high RRP prices in line with other generators, and so is unlikely to offset the use of REZ network capacity during periods of high demand.
Locational investment signals: REZs and the ESB’s priority access model
REZs go some way to dealing with the lack of locational investment incentives under the current framework. By centrally coordinating generation and transmission development through access schemes, a subset of generators has access to network capacity within a pre-defined geographic area. In theory, this allows the ‘optimal mix’ of generation resources to be assigned to the available REZ transmission capacity, while also offering generators within the REZ an advantage over uncoordinated participants who risk greater congestion uncertainty via open access arrangements.
The congestion risk for generators located in REZs is that, despite holding access rights within the REZ (whether in physical or financial form), network access is cannibalised by projects locating in the same region, but outside the REZ. Were this to occur to a sufficient extent, it would mean that projects located in the REZ would have no advantage in dispatch compared with those located outside the REZ.
The issue of congestion on the shared network has not been explicitly addressed by NSW as part of the CWO REZ design, and to date QLD does not envisage modifying existing regulatory arrangements related to shared network outside the boundaries of the REZ.[38] Victoria has identified that the Victorian Transmission Investment Framework (VTIF) may assess restrictions on physical transfer limits from REZs that arise from the broader network. In turn, the VTIF may outline additional transmission infrastructure outside of REZs needed to support the development of additional hosting capacity[39]; however, there is no indication of how such transmission upgrades would be paid for – and whether such costs could be assigned to REZ users under a causer-pays framework.
ESB reforms – the priority access model
In its broadest form, the priority access model proposed by the ESB involves amending the operation of NEMDE to facilitate energy access by priority (queue preference) at times of tied market bids (e.g. where multiple bids are at the market floor) between generators participating behind the same binding constraints, rather than constraint coefficients[40] which is currently the case.[41] Locational signals are provided by the priority access framework by incentivising generators to locate on areas of the network where they will face lower access risk – either areas of low congestion, or where there are lower numbers of generators with preferential queue positions.
Several details of the priority access model proposed by the ESB are yet to be finalised, and these include the specific form of priority access rights, how the rights are allocated, and the duration of rights. The ESB is considering three broad models in relation to the allocation of priority access rights within a network ‘area’:
A ‘pure’ queuing arrangement that allocates different queue positions to each individual project;
A ‘batching’ model that allocates more than one project to the same queue position (without a predetermined number of ‘tiered’ queue positions), based on time of connection or other characteristics; and
Tiered access that allocates projects to a limited set of queue position groupings based on access characteristics.[42]
One of the most obvious issue with any of these models is that, because of the precedence of queuing rights, less efficient generation may be provided access to the energy market, i.e., a generator with a higher constraint coefficient could be provided access over a generator with a lower one. The ESB notes that the CRM is likely to correct this, but given the opt-out arrangements contemplated for the CRM[43] this requires further resolution, particular in cases where queue priority threatens secure dispatch.[44]
Priority access implications for REZs
For incumbent generators within a REZ, the hierarchy of access to the REZ network (whether physical or financial) is likely to have already been determined through the access rights allocation process carried out by the responsible jurisdictional entity. No jurisdiction currently proposes to guarantee energy market access (i.e., access to the RRP) to generators located in the REZ. As such, it appears that overlaying a priority access regime on current arrangements would be compatible with the REZ frameworks proposed by jurisdictions. However, this does not mean that aligning existing REZ arrangements with a uniform priority access regime will be frictionless as important decisions must be made on how existing projects, both within and outside a REZ, will be grandfathered into the priority access arrangements.
If a ‘unique’ queuing number for individual generators is adopted for allocation of priority access rights, jurisdictions will need to carefully consider the order of priority between all generators in the REZ. Because REZ project deployment appears likely to take place by tender batches, there will need to be a way of assigning priority between generators in the same ‘batch’. One way of doing so would be by time of first generation – this could be used by jurisdictions, in advance of any ESB reforms coming into force, as a carrot to project proponents to incentivise moving quickly to production. Alternatively, prospective queuing rights could be auctioned as part of the tender processes taking place to provide REZ schemes additional funds to make good on government commitments.
Possibly more problematic is defining the ideal queuing position of generators within REZs relative to generators outside the REZ. This issue will need to be dealt with regardless of the priority access allocation model adopted in the ESB’s final design. In order to induce REZ engagement, jurisdictions may be tempted to assign generators within the REZ priority over those outside a REZ, regardless of generator incumbency status. Depending on arrangements, this optionality could be built into ESB rule changes, or jurisdictions could derogate to ‘artificially’ modify the queueing positions assigned under uniform rules. The adoption of such an approach could have a general chilling effect on investment, as developers become wary of having investments outside of REZs becoming unprofitable after ESB reform commencement. It also risks reducing dispatch efficiency if in-REZ generators are – for a common constraint – provided energy market access in preference to out-of-REZ generators, even though dispatch of out-of-REZ generators may be more efficient.
To avoid these issues, jurisdictions should emphasise coordinating the sizing of REZ capacity (and intended generation profile) with the REZ network assets, shared network assets, and existing generation.
In this way, generation within the REZ could be queued behind incumbent generation, without fear of significant impediment to energy market access for REZ generators. This would also allow efficient utilisation of network capacity surrounding the REZ following the award of REZ capacity to proponents.[45] In addition, this approach provides for an orderly transition despite different expiry dates for REZ access rights and the priority access rights under the ESB reforms. Providing transparency of approach by jurisdictions as REZs are developed in the near term will be critical to ensuring the market understands the intended arrangements once ESB reforms come into effect.
Conclusion
There is no doubt that a number of further issues will come to light as the detailed design of the CRM and priority access model progresses. Despite the ESB not expecting commencement of these reforms until close to 2030, it will be crucial that jurisdictions take a proactive role in providing the market with clear insight into how significant REZ alignment issues will be dealt with. Failure to do so risks not only the future of efficient REZ development, and corresponding renewables development, but also the success of the ESB’s long-awaited reforms.
Rennie helps organisations navigate and optimise the transition to a net zero, sustainable future.
If you would like support navigating the ESB’s transmission and access reforms, or jurisdictional REZ frameworks, please feel free to get in touch with David Northcott, Senior Manager at Rennie at dnorthcott@renniepartners.com.au
[1] Energy and Climate Change Ministerial Council, Meeting Communique, Friday 24 February 2023
[2] Energy and Climate Change Ministerial Council, Meeting Communique, Friday 24 February 2023
[3] ESB, Transmission access reform Directions paper, November 2022, p 11
[4] ESB, Transmission access reform, Cost benefit analysis, February 2023
[5] ESB, project update – transmission access reform, p 7
[6] ESB, Transmission access reform, Cost benefit analysis, February 2023, p 30
[7] NSW Government Gazette, Renewable Energy Zone (Central-West Orana) Access Scheme Order 2022
[8] AEMO Services, Media Release ‘Consumer Trustee shortlists high-quality projects in Roadmap inaugural tender’, January 2023
[9]NSW Government Gazette (no. 643), Renewable Energy Zone (New England) Order 2021, 10 December 2021; NSW Government Gazette (no. 515), Renewable Energy Zone (South West) Order 2022, 4 November 2022; NSW Government Gazette (no. 569), Renewable Energy Zone (Hunter-Central Coast) Order 2022, 9 December 2022; NSW Government Gazette (no. 98), Renewable Energy Zone (Illawarra) Order 2021, 27 February 2023
[10] Victorian Government Gazette, National Electricity (Victoria) Act 2005: First REZ Stage 1 Projects Ministerial Order, 3 August 2021; Victorian Government Gazette, National Electricity (Victoria) Act 2005: Third Stage 1 Projects Ministerial Order, 14 October 2021; Victorian Government Gazette, National Electricity (Victoria) Act 2005: Fourth Stage 1 Projects Ministerial Order, 26 October 2021;
[11] Victorian Department of Environment, land, Water and Planning, Victorian Renewable Energy Zones Development Plan Directions Paper, February 2021; Victorian Department of Environment, land, Water and Planning, Victorian Transmission Investment Framework, Preliminary Design, July 2022
[12] https://www.energy.vic.gov.au/renewable-energy/renewable-energy-zones
[13] Queensland Department of Energy and Public Works, Consultation on the model for QREZ design and access, November 2021
[14] Queensland Government, Queensland SuperGrid Infrastructure Blueprint, September 2022, p 28
[15] CEFC, ‘Powerlink infrastructure future proofing Qld REZ’, August 2022 (https://www.cefc.com.au/where-we-invest/case-studies/powerlink-infrastructure-future-proofing-qld-rez/)
[16] Queensland Government, Media Release: Palaszczuk Government to own and deliver Copperstring 2.0, 7 March 2023
[17] May 2022
[18] Tasmanian Government, Media Release ‘Tasmania's Renewables Energy Future’, 22 June 2022
[19] https://www.premier.tas.gov.au/site_resources_2015/additional_releases/big-step-towards-tasmanias-first-renewable-energy-zone
[20] See Edify Energy, Submission Post 2025 Market Design Options, Consultation Response - Transmission and Access reform, 9 June 2021; MarketWise (prepared for the CEC), The Modified Congestion Relief Market model, 10 June 2022
[21] ESB, Transmission and Access Reform Consultation Paper, November 2022, p. 38
[22] ESB, Transmission and Access Reform Consultation Paper, November 2022, p. 38
[23] ESB, Congestion management technical working group, Working paper for the congestion relief market, 21 July 2022. Note this ignores transmission losses.
[24] See NSW case study below
[25] Victorian Transmission Investment Framework Preliminary Design Consultation Paper, p 6
[26] Queensland Department of Energy and Public Works, Consultation on the model for QREZ design and access, November 2021, p 15
[27] See Congestion management technical working group, Working paper for the congestion relief market, 21 July 2022, section 5
[28] Victorian Department of Environment, Land, Water and Planning, Victorian Transmission Investment Framework Preliminary Design Consultation Paper, p 47; Baringa, Options Paper: Access for Victorian REZs, March 2022, p 34
[29] Queensland Government, Technical discussion paper on QREZ design and access, November 2021, p 11
[30] Renewables, Climate and Future Industries Tasmania, Renewable Energy Coordination Framework, May 2022, p 11
[31] Department of Planning, Industry and Environment, Renewable Energy Zones - Access Scheme, March 2021
[32] CWO REZ Access Rights and Scheme Design: Positions Paper, p 11
[33] Project means generation or storage plant or a co-located hybrid infrastructure project
[34] In summary, this is the capacity profile of all projects in the REZ, minus the electricity consumption profile of load
[35] The definition of ‘approved project’ relies on the definition of ‘eligible project’.
[36] Renewable Energy Zone (Central-West Orana) Access Scheme Order 2022, subclause 5(3)
[37] The build up of the aggregate expected capacity profiles of individual projects is based on projects’ ‘generation profile’ – see clause 8 of the Renewable Energy Zone (Central-West Orana) Access Scheme Order 2022
[38] Queensland Department of Energy and Public Works, Consultation on the model for QREZ design and access, November 2021, p
[39] Victorian Transmission Investment Framework Preliminary Design Consultation Paper, p 6, 32
[40] Contribution factor of a generator to the relevant constraint
[41] ESB, Transmission and Access Reform Consultation Paper, November 2022, p. 42
[42] ESB, Transmission and Access Reform Consultation Paper, November 2022, pp 69 - 72
[43] ESB, Transmission and Access Reform Consultation Paper, November 2022, p. 67
[44] ESB, Transmission and Access Reform Consultation Paper, November 2022, p. 69
[45] As a further preventative measure jurisdictions may wish to consider making participating in the CRM mandatory for REZ generation projects.