Operating Reserves and Ramping Services – Design Choices and Implications
Fast Facts.
The Australian Energy Market Commission (AEMC) recently extended its time to make a draft determination on two rule changes relating to ‘operating reserves’ and ‘ramping services’ (together, reserve services) submitted by Infigen and Delta Electricity respectively. Publication of the draft determination is expected in June 2023 following the extension made in November 2021.
While the AEMC is tasked with progressing these Rule changes, they are aligned with the broader suite of essential system service reforms being progressed under the banner of the Energy Security Board’s (ESB) Post-2025 work program.
The extension will mean the AEMC’s draft determination will be published after the ESB’s final advice to Energy Ministers on a ‘resource adequacy mechanism’ (RAM), and the AEMC’s determination on procurement mechanisms for system security services.
The reforms are focused on addressing emerging system reliability and security concerns arising from a shortfall in system capacity under contingency or uncertain forecast conditions.
Operating reserves are generation capacity available for dispatch at short notice. A new market for reserve services would be separate to the existing energy and frequency control ancillary service (FCAS) markets, and would be expected to supersede the existing reliability and emergency reserve trader (RERT) arrangements through a market-based mechanism.
Given these proposed arrangements would impact both reliability and security settings, the creation of a new market must be weighed against other potential reforms to avoid distorting incentives and intended efficiency outcomes.
The pool of reserve service providers is likely to be influenced by the market design settings: notably the time between procurement of the reserve service and (potential) dispatch; and whether this new market will be co-optimised for dispatch with the energy and FCAS markets.
Background
On 18 March 2020, Infigen submitted a Rule change requesting the implementation of a dynamic operating reserve market (in addition to existing energy and FCAS markets) to provide additional market capacity under conditions of unforeseen material tightening of supply-demand balance.
Delta Electricity submitted a separate Rule change on 4 June 2020 seeking an extension to existing FCAS markets to include raise and lower services over a 30-minute timeframe. This would create an additional FCAS market to the existing 6 second, 60 second and 5 minute arrangements.
The ESB identified operating reserves as an essential system service in its Final 2021 Post-2025 Market Design in July 2021, but deferred additional detailed consideration of this service given the AEMC’s consideration of issues under the two Rule changes.
Consideration of operating reserves is part of a broad suite of Rule change determinations that were due for release in late 2021. These include consideration of primary frequency response, fast frequency response, and efficient management of system strength on the power system.
Key Issues
Reserve services are designed to deal with electricity supply and demand uncertainty associated with increasing levels of variable renewable generation in the National Electricity Market (NEM). As the percentage of variable renewable generation increases (grid scale and behind the meter), supply and demand balances are more difficult to forecast, and require more traditional forms of generation to behave more flexibly (ramp up and down).
Where an energy market generator or demand response provider can be provided with information of a potential tight supply and demand balance (i.e., expected need), the expectation of an associated increase to energy prices should incentivise capacity to become available to the energy market. For example, thermal generation will come online in anticipation of committing capacity into the energy market during high price events. However, if sufficient and timely information is not available to participants, a ‘gap’ may emerge, presenting a risk to system reliability and security.
A reserve service market therefore seeks to incentivise participants to make capacity available (for potential commitment) at times when there may be insufficient expectation of a tight supply – demand balance. This would be dynamic, as opposed to the RERT arrangements which are not dynamic and must remain out of market. A reserve service market would also be different to existing FCAS markets which only have capacity to balance supply and demand in the very short and short terms (i.e., 6 seconds, 30 seconds, 5 minutes).
Given the introduction of a reserve market would seek to mitigate uncertainty in the system, there are a range of other related measures that might be implemented to improve information associated with the supply – demand balance. These include improving forecasts of variable renewable energy output, consumption patterns, and transmission outages.
Accordingly, the AEMC has proposed four high-level models for a reserve service market; which are all consistent with the primary objective of providing a more dynamic market-based alternative to procurement by the Australian Energy Market Operator (AEMO) of out of market capacity.
Key differences across the potential models include:
The time between reserve service procurement and dispatch as energy – this has implications for how accurate reserve service forecast requirements can be, and affect the types of generation that can participate;
Whether to co-optimise the reserve service market with the existing energy and FCAS markets – this will decide whether a service provider can bid into multiple markets simultaneously (with dispatch of services determined by AEMO); or whether a participant will be required to select the market it wishes to participate prior to bid; and
Setting the amount of reserve services to procure – demand for the reserve services will not be based on energy demand, but rather must be ‘constructed’. Choices regarding how the demand for reserve services is generated will have significant implications for incentives and market signals.
The ESB’s work suggests that reserve service providers would be paid for their ability to deliver reserve capacity to the energy market at the request of AEMO, and that providers who have this capacity dispatched will also be paid for energy.
Responses to the option of an operating reserve raised by the ESB’s Post-2025 Consultation Paper have been mixed, with no clear consensus on whether an operating reserve or ramping services are required. Given the suite of reforms on foot, many stakeholders have concerns about the introduction of a new market into what is becoming an increasingly overcrowded ecosystem of potential incentives and markets.
The ESB is still in the very early stages of developing relevant new markets and is continuing to weigh the benefits and costs of each. The AEMC’s deferral of the operating reserve Rule changes to the middle of 2023 indicates that significant further deliberations on these matters will be required before any firm position can be settled.
It is relevant to note that in late April 2021, the ESB commissioned scenario modelling to help assess whether there was need for greater operating reserves in the system. This was largely inconclusive on the material benefits of a reserve market where the operation of generation and load in the future is uncertain – particularly if markets become more two-sided. The ESB has signalled that the AEMC will conduct further modelling as part of the Rule change process.
Further, AEMO’ s submission seemed to support the valuing of reserve capacity (consistent with that proposed by Infigen) rather than FCAS ramping services (as proposed by Delta) to assist in management of the system. Given the lack of consensus from market participants, it is likely AEMO’s position will carry significant weight.
Our Insights
This Rule change, and the work being done around it, raise two significant issues for industry and for the future development of the market.
The first is that market design is of critical importance for reserve service participation models and needs careful and consultative review before it is settled upon. The time at which reserve services are procured prior to (potential) dispatch as energy, and whether services are co-optimised with other markets, are settings will have significant implications for potential service providers.
Short procurement lead times (e.g., where procurement occurs immediately prior the subsequent dispatch interval) – a feature of the ‘option 1’ in the AEMC’s Directions Paper – will require a reserve service provider to be available to dispatch within 5 minutes of having their availability capacity procured by AEMO. Such lead times may benefit quicker start participants such as batteries, gas peaking plant, and (potentially) demand response providers. This may reduce the pool of potential participants and may, in some part, undermine the intention of the market.
This issue may be mitigated by providing potential service providers with certainty as to when reserve services will be in demand. On face value, this might be far easier than the energy market, because the reserve demand curve is likely to ‘constructed’ based on some combination of forecasting uncertainty and the value of lost load. This may allow for a consistent market signal, providing some measure of reserve market revenue certainty for slower starting generation.
If semi-scheduled generators are able to tailor their output to meet the requirements of a reserve market, the length of the procurement period is also likely to be important for their participation. A shorter procurement period may not provide sufficient time to ramp linearly, whereas a longer period may reduce confidence in ability to dispatch at the required time.
Co-optimisation would require the NEM dispatch engine to look at all bids and offers for energy, FCAS and reserve capacity at the same time in order to maximise efficient resource use. This is the approach taken in most US regions with reserve markets, and is also the market operation philosophy supported by AEMO. The alternative is that procured reserve capacity remains ‘out of market’ with the participant unable to bid the same capacity into either the energy or FCAS markets.
If markets are not co-optimised, participants will be required to do extended due diligence on opportunity cost of offering reserves services, rather than bidding into energy and/or FCAS markets. Again, this may reduce the number of participants who would be willing to engage in the market.
The second major issue is that impacts on the resource adequacy mechanism will need to carefully considered. A reserve services market has linkages with both reliability and security elements of the system; as it seeks to ensure there is sufficient capacity available on an operational timescale to meet demand, as well as manage frequency over a period not covered by the existing FCAS markets.
While these issues are seemingly separate from those being considered by the ESB as part of the resource adequacy mechanism, there will need to be careful consideration of potential interactions of any reserve services market with broader reliability reforms. Of particular interest is the impact on providing an additional potential revenue stream to service providers. The beneficiaries of such revenue are participants who are able to guarantee dispatchable capacity – these are the same market participants who are likely to be the main beneficiaries of a resource adequacy mechanism.
As such:
Additional revenue afforded to existing generators through a reserve services market may incentivise generation that may have otherwise been retired to remain in the market – thus performing part of the ESB’s stated role of the resource adequacy mechanism; and
The price paid for reserve services would be in addition to the energy price received in the event the provider was dispatched in the energy market. This additional revenue stream may provide incentives for investment in generation of the sort that can participate in a reserve service market. Again, this may perform – in part – part of the role of the ESB’s reliability reforms.
It is well understood by the AEMC that any new reserve market should not cost more than the costs of maintaining relevant security and reliability issues under current arrangements. Broadly, the costs of managing the system without adequate reserve services markets are the sum of AEMO directions, instructions, and RERT costs. While RERT costs are costed,[2] the market costs of interventions and directions avoided via a reserve services market are less certain and would need to be considered when assessing the value of the market.
Given the current pace of the energy transition – AEMO’s draft 2022 Integrated System Plan suggests that Step Change is the most likely scenario – consideration needs to be given to reserve design that meets both medium and longer-term system security and reliability requirements as the generation mix rapidly changes.
[1] AEMC, Capacity Commitment Mechanism and Synchronous Service Markets, 9 September
[2] RERT costs were $40.57 million in 2019-20 (AEMC, Annual Market Performance Review, 2020)
For more information, contact Simone Rennie at srennie@renniepartners.com.au
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