Submissions to our investigation into intervention mechanisms and system strength in the national electricity market are now available on the AEMC’s website.
Why are we doing this investigation?
System security is becoming an increasingly important issue as the generation mix changes. Services that were once provided as a by-product of the generation of electricity are no longer being provided to the same extent. The level of such things as inertia, frequency control and system strength has been deteriorating. These are the services that keep the system operating within its technical limits. If we don’t have enough of any one of these services, the system can become unstable.
AEMO has a number of ‘safety net’ tools available to it to stop that from happening. One of these tools is to intervene in the market by directing a generator which can provide these security services to come on line. However, once AEMO has intervened in the market, directed generators must be compensated, along with participants who are dispatched differently due to the intervention. Intervening in the market may also have implications for the wholesale price due to the use of “intervention pricing” – a practice designed to minimise market distortion by preserving price signals at the level they would have been but for the intervention.
AEMO is frequently intervening in the South Australian market to ensure one of these security services, system strength, is adequate. Reliance on system strength directions to generators is increasing, with AEMO issuing a system strength direction to a Victorian generator in late 2018 – the first time this has occurred in a region other than South Australia. AEMO’s Integrated System Plan also highlights the emergence of system strength as an issue to be managed across the national electricity market.
Under the National Electricity Rules, there is a framework to maintain sufficient system strength in the power grid. The Commission created this in 2017 to deliver efficient and timely action to ensure system strength is maintained as the generation mix changes. Importantly the system strength framework was intended to address this issue proactively and remove the need for frequent intervention by AEMO. While the ‘safety net’ that the intervention framework provides is important, it was not intended to be used to provide ongoing maintenance of power system security. It is also proving costly.
To address these issues, the Commission is doing do two things as part of this investigation:
- reviewing experience to date with the system strength framework and considering whether changes are warranted so that the provision of system strength is optimally efficient.
- identifying any changes necessary to ensure the interventions and compensation frameworks are not imposing inefficient costs on consumers or creating inefficient operational or investment signals. The Commission also initiated two rule change requests when it released the investigation consultation paper. We will deliver a package of our determinations on the proposed rule changes and also recommendations for changes that may be necessary to address other issues with the interventions framework.
The AEMC has received 21 submissions from a range of stakeholders including consumer representatives, generators, network businesses, industry associations, jurisdictional governments and market bodies. Key issues explored in the submissions are set out below.
System strength framework
The system strength framework places an obligation on a transmission network business to maintain minimum levels of system strength within its region when a shortfall is declared by AEMO. To date, South Australia is the only region in which a shortfall has been declared and ElectraNet has committed to addressing the shortfall by 2020.
The majority of stakeholders support the AEMC revisiting this system strength framework. Several also draw attention to the ‘do no harm’ element of the framework, which requires new connecting generators to remediate their system strength impact. By contrast, one stakeholder urged the Commission to allow the benefits of these relatively new frameworks to be realised before recommending any significant changes.
Stakeholders are divided as to whether the system strength framework should be modified to enable a long-term, centrally planned approach to investment (linked for example to the Integrated System Plan), or whether system strength services should be individually valued and procured through competitive market mechanisms.
Each of the stakeholders who addressed the ‘do no harm’ framework criticised it as a barrier to entry that forces new entrants to invest in costly and inefficient remediation work that can increase operational complexity. These stakeholders consider that, in place of the ‘do no harm’ framework, the impact on system strength of individual connections should be absorbed into the system strength responsibilities of networks who are able to implement more efficient and coordinated solutions.
Intervention pricing and the regional reference node test
Intervention pricing is a practice intended to minimise market distortion when AEMO intervenes in the market. It does this by preserving price signals at the level they would have been at but for the intervention event.
Under the current rules, AEMO applies intervention pricing whenever it activates the RERT. By contrast, when AEMO issues a direction, it has to apply the ‘regional reference node (RRN) test’ to determine whether to apply intervention pricing. Broadly, the objective of the test is to determine whether there is a region-wide scarcity of the service that is the subject of the direction, or whether the problem being fixed is localised. If the problem is region-wide, then it will be important to preserve price signals and the incentive they create for investment. This is the aim of intervention pricing.
AEMO has submitted a rule change request to extend the reach of the RRN test so that it encompasses the RERT as well as directions. This would have the effect of limiting the use of intervention pricing to those instances where the RERT is activated in response to a region-wide rather than localised issue (whereas, at present, intervention pricing is used every time the RERT is activated). This will create consistency between the pricing approach for directions and the RERT. The request also proposes to change the wording of the RRN test to improve clarity.
In response to the consultation paper, five stakeholders supported retaining intervention pricing in its current form while six stakeholders (including AEMO) supported applying intervention pricing only when there is an economic rationale for doing so: that is, where the intervention is to obtain a service that is traded in the market – meaning that there is a relevant price signal to preserve.
Only some stakeholders commented on the proposal to extend the RRN test to encompass the RERT (in addition to directions) but all who did were in favour of this proposed change.
The compensation framework that is triggered when AEMO intervenes in the market
The rules provide for compensation to be paid to directed participants (those who provide services under direction) and affected participants (those who are dispatched differently as a result of the intervention). No compensation is payable to other participants. The cost of compensating directed and affected participants is passed through to consumers.
Figure 1 - Treatment of different market participants under the existing interventions framework
Directed participant compensation
Currently, generators who are directed to provide energy or frequency control ancillary services (FCAS) are compensated based on the 90th percentile price. The consultation paper explored whether the current framework is creating inefficient incentives for generators to withdraw from the market if they think they can earn more under direction, which could then increase costs to consumers.
The paper considered whether an alternative approach warrants consideration. For example, the compensation methodology created for market suspension events could provide the basis for an alternative approach under which compensation would be a function of the costs incurred by the directed generator, rather than a percentile price reflecting the generation mix in the region at the time.
Two stakeholders supported retaining the 90th percentile price approach while four supported the cost based approach and a further four suggested the issue warrants further consideration.
Affected participant compensation
‘Affected participants’ are entitled to receive compensation from AEMO if they are dispatched less as a result of an intervention or may be liable to repay money to AEMO if they are dispatched more.
The consultation paper noted that, unlike affected participants following an intervention, no compensation is payable if dispatch targets change as a result of constraints being imposed by AEMO’s dispatch engine, NEMDE. The paper considered whether affected participant compensation should be retained, or whether it should only apply in certain circumstances (e.g. reliability events as distinct from security events).
Of the stakeholders who commented on this issue, six supported the retention of affected participant compensation in its current form. They stressed the importance of putting participants in the position they would have been in but for the intervention.
Three stakeholders supported limiting the circumstances in which affected participant compensation is paid. Of these three, two suggested that affected participant compensation should only be paid during reliability events but not during system security events. This would reduce inconsistency between the outcomes flowing from constraints and interventions, and reduce costs to consumers.
At present, the National Electricity Rules include a $5,000 threshold which limits the payment of compensation both to and by affected participants and limits the payment of compensation to directed participants in the event they claim additional compensation. AEMO has submitted a rule change request which seeks to change the threshold so it applies per intervention event, rather than per trading interval. Of the seven stakeholders who commented on this issue, all supported the proposal to apply this threshold on a per event basis, rather than per trading interval.
Other issues related to the efficient operation of the interventions framework
Hierarchy of intervention mechanisms
The National Electricity Rules create a two tier hierarchy under which, in times of ‘supply scarcity’, AEMO is to use its reasonable endeavours to activate the reliability and emergency reserve trader (RERT) in preference to issuing directions or instructions. The consultation paper considered whether this hierarchy should remain as is or be modified – for example by having regard for a cost minimisation principle. Four stakeholders expressed support for the current hierarchy while ten (including AEMO) expressed support for a least cost principle.
RERT triggering the market price cap
The consultation paper explored whether, instead of the current approach of using intervention pricing, the spot price should be set to the market price cap (MPC) when the RERT is activated. This option had been raised by two stakeholders in submissions to the Reliability Frameworks Review, and by a report on intervention pricing commissioned by AEMO.
Of the six stakeholders who commented on this issue, only one supported the proposal to replace the current approach (applying intervention pricing when the RERT is activated) with the approach of setting the spot price to the MPC. This was supported on the basis that doing so would provide a clear investment signal to generators and would thus lower costs to consumers in the longer term.
AEMO’s submission notes that, broadly, the purpose of the RERT is to provide additional reserves to the market and thus it is not activated exclusively in scenarios where a supply shortfall (load shedding) would have occurred and the price would have been set to the MPC.
Others note that setting the spot price to the MPC when the RERT is activated is only likely to result in higher costs to consumers – including because the price would likely be at the MPC for longer than strictly necessary due to issues such as minimum RERT run times. This would increase the risk of tripping the cumulative price threshold, as happened in January this year, which would then mute the desired scarcity signal.
Stakeholders also noted that setting the spot price to the MPC when the RERT is activated would strip the RERT of a significant aspect of its purpose, which is to minimise financial impact due to load shedding, which results in the spot price being set to the MPC.
Mandatory restrictions framework
The paper examined the ‘mandatory restrictions’ framework in the National Electricity Rules and considered whether this framework ought to be retained and, if so, whether it should be modified in any way.
Mandatory restrictions are a market intervention mechanism whereby demand restrictions are imposed by a jurisdictional government (under state legislation) in anticipation of, for example, significant supply shortfalls. If this occurs, the rules set out a process of capacity contracting and pricing which is designed to integrate restrictions into the market to ensure delivery of a reliable and secure supply. This contracting and pricing process was included in the National Electricity Rules in 2001 but has never been used.
Three stakeholders considered this framework should be retained in its current form while two supported its removal and three suggested further consideration should be given to modifying the framework.
Several stakeholders called for greater transparency in relation to the use of intervention mechanisms and the payment of compensation to directed and affected participants. Many noted with concern the time lag between the occurrence of intervention events and the publication of AEMO reports.
The AEMC plans to publish draft determinations for the two AEMO rule change requests on 15 August 2019, together with a report dealing with the other intervention-related matters discussed in the consultation paper. Final rule determinations would then be published in November.
A separate report regarding system strength issues will be published later in 2019.
For more contact:
AEMC Executive General Manager, Suzanne Falvi (02) 8296 7883
AEMC Director, Sebastien Henry (02) 8296 7833
Media: Prudence Anderson, Communication Director, 0404 821 935 or (02) 8296 7817