NEM Post-2025 Market Design: ESB releases Consultation Paper
What you need to know about the September 2020 Consultation Paper and the vision for Australia's National Electricity Market.
What you need to know
- On 7 September, the Energy Security Board released the Consultation Paper for its Post-2025 Market Design workstream.
- Unlike the shorter Directions Paper published in April 2020, the Consultation Paper defines seven challenges facing the National Electricity Market in coming years, sets out the options being considered by the Energy Security Board to meet these challenges, and poses a number of questions to stakeholders.
- The Consultation Paper acts as a blueprint for the consideration of future reforms which are to be implemented in phases and which must dovetail with other reforms currently underway.
What you need to do
- Stakeholders should consider making submissions to the Energy Security Board on the questions raised in the Consultation Paper. Submissions are due by 19 October 2020.
- The Energy Security Board intends to publish options for the market design in late December 2020/early January 2021, and will make recommendations on a future design to the former COAG Energy Council by mid-2021.
Background to the Consultation Paper
The Energy Security Board (ESB) was tasked by the former COAG Energy Council to develop a long-term, fit-for-purpose market design for the National Electricity Market (NEM). This work is intended to address the substantial changes in technology and market conditions since the NEM was first developed in 1998.
In particular, the impending withdrawal of significant quantities of coal-fired capacity, increasing levels of utility-scale variable renewable energy and distributed energy resources (DER), and new technologies such as energy storage systems and electric-vehicles, has led to issues associated with:
- system reliability and security;
- network congestion and access; and
- price signalling.
The ESB considers that the current market design is no longer entirely fit for purpose or able to meet the changing needs of the system or consumers.
On 7 September 2020, the ESB published a Consultation Paper seeking feedback from stakeholders on the seven market design initiatives canvassed in the Directions Paper published in April 2020, being:
A. Resource Adequacy Mechanisms;
B. Aging Thermal Generation Strategy;
C. Essential System Services;
D. Scheduling and Ahead Mechanisms;
E. Two-Sided Markets;
F. Valuing Demand Flexibility and Integrating DER; and
G. Transmission Access and the Coordination of Generation and Transmission.
As a general comment, the Consultation Paper gives some comfort that the regulatory changes required to resolve the challenges facing the NEM are no longer to be considered in isolation as part of individual rule change requests submitted to the Australian Energy Market Commission (AEMC) (though the Consultation Paper does lean on the progression of some of the existing rule change proposals currently before the AEMC). Rather, the changes will be developed as part of a package of reforms ultimately giving effect to an updated vision for the NEM, albeit one which is phased in incrementally (in order to reduce the risk of unintended consequences in the new market design as far as possible).
Helpfully, the Consultation Paper describes the problem that each market design initiative is intended to address, the options considered by the ESB to date, the options that the ESB proposes to focus on moving forward, and the issues on which it is seeking stakeholder feedback. We discuss these in more detail below.
Market Design Initiative A - Resource Adequacy Mechanisms
The current NEM design relies heavily on forecast and actual high prices during particular periods to encourage investment in new generation. However, the ESB has noted that sustained prices at the levels required to encourage investment in new dispatchable generation may be so high that there may be government intervention in the market, which can deter further investment. Other issues include the absence of long duration price signals and the inability to hedge large demand risk.
In our experience, the risk of government intervention is an issue considered by developers, investors and financiers alike. However, almost all of the new dispatchable capacity (batteries and pumped hydro) developed in the NEM in recent years has received some level of government support, such as through Australian Renewable Energy Agency or State government grants. We see other issues which also play a large role in discouraging investment in new dispatchable generation, including:
- lengthy environmental approvals timelines for new dispatchable thermal generation, coupled with high natural gas costs;
- uncertainty as to marginal loss factors;
- increasing numbers and duration of constraints, caused by the current access framework and falling cost of renewables; and
- a regulatory framework that currently does not appropriately recognise the role of energy storage systems (and makes retrofitting energy storage systems to existing plant difficult).
The ESB is seeking feedback on current barriers to investment in dispatchable energy and whether changes to current resource adequacy mechanisms (RAMs) would help remove those barriers. Subject to stakeholder feedback, the ESB plans to further consider:
- implementing an operating reserve mechanism or market;
- expanding the Retailer Reliability Obligation (RRO) or introducing a price for reliability through a decentralised capacity market; and
- making consequential adjustments to the Reliability and Emergency Reserve Trader (RERT) or interim reliability reserve (depending on the other mechanisms introduced).
Operating reserve mechanism
The ESB has proposed that a central body would determine the principles to be used by the Australian Energy Market Operator (AEMO) to periodically determine operating reserve demand curves. Operating reserves would be offered as a service in the NEM, and dispatch would be co-optimised with the energy market by the National Electricity Market Dispatch Engine (NEMDE).
The ESB considers that this mechanism will attract significant administrative overheads, but will only lead to incremental improvements to the current incentives for investment in dispatchable plant. It would also only be developed in conjunction with the market design initiative for essential system services.
Expansion of RRO or decentralised capacity market
The ESB has proposed that it will consider modifying the RRO by potentially:
- removing the T-1 trigger so that the obligation to hold qualifying contracts applies in all regions and during all periods;
- tightening the measure of firmness of qualifying contracts;
- improving enforcement of the RRO prior to T-1; or
- increasing the penalties payable by non-compliant retailers.
In our experience, offtake agreements in the market for new dispatchable plant (such as energy storage systems) have already started to include features specifically designed to assist the offtaker to use the contract as part of its compliance with the RRO. However, these clauses have tended to be quite general and still give the service operator wide operational discretion (eg in relation to periods of planned maintenance). Any tightening of the RRO requirements may mean that the drafting of these agreements needs to be revisited to ensure the contract remains valuable to offtakers from a compliance perspective.
Alternatively to adopting an enhanced RRO, the ESB will consider introducing a decentralised capacity market, which would place obligations on retailers to procure central capacity (either in physically-backed contracts or financially-backed contracts). This would appear to operate in a similar way to the existing RRO.
Importantly, the ESB has noted that introduction of a decentralised capacity market would "usually" lead to the spot market price cap being reduced, as the high pricing offered under the current caps would no longer be required to signal that investment in new dispatchable capacity is required. This may affect the price of derivatives offered in the market and/or the profitability of peaking plant (eg gas peakers), which we expect to be increasingly called on to provide firming services to renewable generation. It will be important for any decrease in the market price cap to take account of the possibility of rendering peaking plant unprofitable which could reduce their incentive to firm the grid.
RERT or interim reliability reserve measures
If the ESB introduces additional resource capacity mechanisms such as an operating reserve mechanism, it will also review the current reliability "backstops" in the market.
Significantly, the ESB has also noted suggestions from some stakeholders that it should consider how resource adequacy in the NEM could be adjusted or implemented to reflect the priorities and preferences of individual NEM jurisdictions. Such a change would depart from the current uniform approach to the design of the NEM and could increase government intervention risk for market participants.
Market Design Initiative B - Aging Thermal Generation Strategy
The NEM currently relies on large thermal plants (predominately coal-fired plants) to maintain reliability, security and affordability. However, over 15GW of large thermal plants are expected to exit the NEM in the next 20 years and are expected to be replaced with between 26GW and 50 GW of renewable plants, and 6GW and 19GW of firming resources. It is important to ensure that appropriate quantities of replacement generation are operational in time given the "lumpy" nature of the exit of thermal capacity.
Despite the three year notice of closure rules introduced in early 2019 (which were expanded to 42 months in mid-2019), the ESB considers that uncertainty still remains about the timing of exit of thermal capacity. This uncertainty may deter investment (or encourage inefficient investment in maintaining ageing plant) or further government intervention if prices rise in response to exiting plant.
Current measures to deal with these issues include:
- notice of closure requirements;
- the RRO;
- the Integrated System Plan (ISP);
- the Electricity Statement of Opportunities (ESOO);
- the Transparency of New Projects Rule made by the AEMC in late 2019;
- the Projected Assessment of System Adequacy processes (ST-PASA and MT-PASA); and
- the RERT.
The ESB intends to consider whether these mechanisms create any residual reliability and security risks that may be addressed by regulatory change.
Market Design Initiative C - Essential System Services
The increase of renewable energy in the NEM has resulted in falling levels of inertia, system strength and frequency control (which are traditionally provided by large synchronous generators, which are predominantly thermal generators). This has led to more frequent interventions in the market by AEMO, such as by issuing directions to market participants. Some mechanisms have already been introduced to respond to these issues – such as new system strength rules in 2017 and new primary frequency response rules made in early 2020 (though these sunset after three years).
The ESB has indicated a preference for essential system services to be procured in a spot market where permitted by the system and/or technology (for example, some elements of system strength services do not currently appear capable of being procured in a real-time spot market). We expect that the introduction of market mechanisms (rather than centralised mechanisms) will be welcomed by market participants.
The ESB has proposed to develop a roadmap of procurement and scheduling options for essential system services, covering:
- the introduction of an operating reserve procured by a spot market with a demand curve framework (as discussed in relation to Market Design Initiative A above;
- developing arrangements to incentivise primary frequency response (which will apply after the sunset date of the current rules in 2023);
- supporting the provision of faster frequency response (with a potential for co-optimisation with the energy market and formulation within a demand curve framework);
- supporting ahead-scheduling and co-ordination of the provision of inertia and system strength alongside new procurement arrangements (such as provision by Network Service Providers, bilateral contracts and generator performance standards, or through a power system security ancillary services mechanism which has been proposed by some stakeholders); and
- a spot market for inertia (in the post-2025 NEM), with co-optimisation with the frequency control and operating reserve markets.
Market Design Initiative D – Scheduling and Ahead Mechanisms
As both the demand and supply side of the NEM transition to a large and more complex mix of resources, the complexity to efficiently schedule resources and make operational decisions (eg charging or discharging decisions for energy storage systems, or commitment decisions for slow-start generators) increases.
Currently, energy market participants manage dispatch uncertainties in a decentralised manner (such as through the use of derivatives). The ESB has considered the benefits of establishing additional markets to reduce pre-dispatch uncertainty and to co-optimise the delivery of energy and essential services.
We expect that additional transparency and information in the pre-dispatch period will be welcomed by market participants, and in particular, useful to energy storage system operators who will be able to better use this information to make charging, state of charge, and discharging decisions.
The ESB is considering the implementation of a Unit Commitment for Security (UCS). A UCS is a tool that would provide AEMO with the means of identifying (up to 40 hours ahead of pre-dispatch) reliability and security shortfalls. It would achieve this by automatically conducting an assessment of the latest unit commitment schedule at regular intervals during pre-dispatch and determine shortfalls. It will let AEMO then schedule non-market system security contracts (either held by AEMO or a Network Service Provider), and support the identification of the need to trigger last resort intervention mechanisms (such as issuing directions or activating the RERT) in a more transparent and efficient manner.
The ESB is also considering developing:
- a voluntary ahead market to facilitate trading and scheduling of essential system services (but not energy) ahead of real-time – as described in the ESB's March 2020 paper on system services and ahead markets; and
- a voluntary integrated ahead market incorporating energy trading and the co-optimisation of energy and system services in the ahead market design.
The introduction of voluntary ahead markets would be a significant change to the operation of dispatch in the NEM, but are increasingly common around the world and can offer valuable improvements to scheduling decisions.
Market Design Initiative E - Two-Sided Markets
The current NEM framework is undoubtedly focused on the supply side of the market, making it difficult for consumers to be incentivised to reduce or shift the timing of their demand (however, new wholesale demand response rules and other distributed resource trials (eg AEMO's virtual power plant demonstrations) will begin to change this dial).
As technology advances, and the flexibility of demand side resources becomes more accessible, the NEM can transition towards a market with both an active demand and supply side. This is a longer-term aspect of the Consultation Paper, stretching beyond a five year timeframe.
In the:
- short term, the ESB is considering opportunities for consumers to participate in the market through an improved aggregator framework, and improving opportunities to better integrate storage devices (such as through the bi-directional resource provider rule change currently before the AEMC);
- medium term, the ESB will explore ways to simplify the registration and classification processes in Chapter 2 of the National Electricity Rules, as well as the scheduling, dispatch and forecasting frameworks; and
- long-term, the ESB will consider removing the distinction between generators only supplying electricity and consumers only demanding electricity (which underpins much of the current market framework), and transitioning to a market where material quantities of supply and demand response participate in central dispatch.
Many of these changes will be welcomed by market participants exploring new and innovative business models. In our experience, the current rules around aggregation and the divide between the binary concepts of generation and load at a connection point (leading to binary registration and classification outcomes) act as a real restriction on some behind-the-meter supply and hybrid facility business models.
The ESB has sought feedback on consumer protections that it will need to consider in its framework for a two-sided market. On 20 April 2020, the ESB published a Discussion Paper proposing a two-sided market that would:
- allow end-users to either directly participate in responding to pricing where they have the technology or allow end-users to participate indirectly through a trader where they do not have the technology to directly participate;
- allow for DER to supply to the market (either directly or indirectly); and
- replace the current use of real-time supply and demand forecasts with ahead of time bids and prices where prices and volumes would be determined multiple trading intervals ahead of real-time. Therefore, where users do not want to pay a certain price at a certain time, they would not consume energy.
Market Design Initiative F – Valuing Demand Flexibility and Integrating DER
The capacity of DER in the NEM is rapidly increasing at both a household and grid scale level. The ESB has recognised that integrating DER into the overall system, and having regulatory arrangements in place that will accommodate this, has the potential to deliver lower prices, improved reliability (and other essential system services) and low emissions electricity to consumers.
The Consultation Paper sets out a number of key issues to enabling the co-ordination of DER integration with the other market design initiatives, including:
- the technical capabilities of DER and whether this reduces the need for other essential system services;
- determining the extent to which consumers are willing to participate in the market, including considering implementing cost-reflective tariffs;
- an expansion and standardisation of IT and communications infrastructure to manage data, physical and financial flows (overlayed with cybersecurity protections);
- the ability for aggregators and other DER providers to access multiple revenue streams (ie value stacking) in order to offer value to consumers;
- balancing ease of participation in the market and AEMO's requirements for system operation; and
- whether there should be local settlement of transactions outside of wholesale markets (eg distribution level markets such as local energy trading or nested wholesale markets).
In our experience, consumers are willing to engage with the provision of DER if it is flexible, easy to understand, and meets their particular pricing or environmental, social or governance requirements (such as carbon offsets). Complex requirements (such as the establishment of embedded networks at sites involving third parties, the requirement to amend connection agreements to permit export to the grid, and the requirement to manually apply to AEMO for an exemption from the obligation to register as a Generator) can act as a significant deterrent to the aggregation model and integration of DER.
The ESB has asked for feedback on how best to integrate DER into the market design. The ESB will further consider:
- the development of a DER integration workplan that sets out regulatory and technical arrangements for DER to effectively integrate into the NER;
- current market participant categories (including aggregators) and the extent to which these need to be adapted to facilitate the participation of new market participants;
- developing participation requirements, compliance and enforcement arrangements making it simple for DER to provide services into all markets (and simple for DER owners); and
- developing overarching market design options which enable value-stacking, and exploring the need for full integration into the market.
Design Initiative G - Transmission Access and the Coordination of Generation and Transmission (COGATI)
The challenges facing the capacity of the transmission network in light of increasing numbers of renewables projects connecting to the fringes of the grid have been well documented. This has also been felt by existing generators through falling marginal loss factors and an increasing number of constraints on the network. The COGATI reforms proposed by the AEMC are now being considered as part of the ESB's post-2025 market design work.
The Consultation Paper notes that the basic model proposed by the AEMC has remained the same for some time: locational marginal pricing will be introduced, and participants will be able to purchase financial transmission rights (FTRs) (sold via a competitive auction process) which pay out on the difference between the regional reference price and the locational marginal price.
The ESB has referred to the separate technical paper published by the AEMC on 7 September 2020 (available here) which describes the current proposed design in more detail. Significantly for existing generators, it is proposed that FTRs consistent with almost all of the transmission capacity will be provided to existing and committed generators at the commencement of the reforms (and only a very small proportion of available FTRs will be sold via auction). Over five years, the proportion of free FTRs will decrease and the proportion available for auction will increase.
The ESB has also noted a potential future evolution of the access arrangements as a way to encourage investors to fund incremental development of the shared transmission networks (in exchange for a firm right over the additional transfer capacity constructed). This could be useful to investors seeking to establish new renewable energy zones or could complement the COGATI regime. In many ways, this model is a return to the previous practice (before the solar boom which commenced in the mid-2010s) whereby new generators funded an augmentation of the transmission network if there was insufficient capacity for their generation. We expect that the implementation of this model will be appreciated by investors by giving them additional flexibility to hedge against constraint risks.
Next steps
The ESB is seeking feedback on the issues raised in the Consultation Paper by 19 October 2020.
It intends to publish options for the market design in late December 2020/January 2021, and will give its final recommendations to the former COAG Energy Council on the post-2025 market design in mid-2021.
Authors: Paul Newman, Partner; Tristan Shepherd, Senior Associate; Ainsley Masek, Lawyer, Allison Boland, Lawyer.
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