AEMC Publishes Final Rule Determination on Integrating Energy Storage Systems into the NEM
Fast Facts.
On 2 December 2021, the AEMC published its Final Rule Determination on ‘Integrating Energy Storage Systems into the NEM’.
Rule amendments were initially proposed by AEMO in August 2019. AEMO suggested that these amendments would more efficiently accommodate the growing number of bi-directional network connections, particularly energy storage systems and hybrid facilities.
The rule amendments made by the AEMC will, among other things:
Introduce a new registration category, called the Integrated Resource Provider (IRP), and transfer existing small generation aggregators (SGAs) into this new category;
Introduce a new facility classification, called a bidirectional unit, and require some existing storage facilities to be reclassified;
Provide increased flexibility in scheduling obligations for hybrid and DC-coupled systems; and
Amend the recovery of non-energy costs, to separate energy injections and withdrawals at the connection point.
Some existing participants will be required to transition to the IRP participant category, with some participants having the option to transition to the new IRP category (see below for further information).
The AEMC chose not to change the transmission pricing arrangements, meaning that storage facilities may still be required to pay transmission network charges.
The new rules will commence on 3 June 2024, with various transitional arrangements (see below for further information).
The AEMC has taken care to avoid unintended transition consequences and costs – existing connection agreements, performance standards and service levels should continue to apply, and no registration fees are payable to transition existing registrations.
AEMO and the other market bodies will need to update a large number of existing procedures and guidelines, many of which will be subject to public consultation.
Further registration framework changes are expected to emanate from future Energy Security Board (ESB) reforms.
Background
Aren’t there already large batteries operating in the NEM?
Yes. However, the current National Electricity Rules (NER) predominantly reflect a traditional binary model of generators injecting energy into the network, and customers withdrawing energy from the network. This extends to the reliance on ‘load’ and ‘generating unit’ terminology in the rules.
Energy storage systems are not defined in the NER, and must therefore be registered as two separate facilities (generation and load). As new technologies and business models have emerged, AEMO and other parties have needed to interpret the current rules in order to apply them to these new applications.
In proposing rule changes, AEMO suggested that:
The current rules are unclear and confusing for storage developers, resulting in inefficiency in the registration process;
The treatment of a single storage asset as two components unnecessarily complicates facility operation (e.g., bidding) and market analysis;
Perverse and unintuitive outcomes can arise due to the separate classifications of generation and load (e.g., potential for multiple marginal loss factors, multiple intervention compensation payments, and duplicate technical performance standards);
Storage proponents must negotiate the network charges to apply to their facilities, given that the rules do not specify how these should apply to storage facilities; and
Market processes may not accurately account for technical characteristics of storage systems, particularly storage capacity limits and ramping, with potential implications for power system reliability and security.
AEMO’s proposal also highlighted that hybrid facilities (which may include storage devices co-located with generation) do not always map clearly to the existing categories of scheduled and semi-scheduled generating units, and their associated obligations.
What are non-energy costs and why were they part of this rule change?
Energy settlement is (relatively) easy – pay for energy injections, and charge for energy withdrawals, based on interval meter data, spot prices and loss factors.
However, various other costs need to be recovered from generators or customers, as applicable. These include:
Services that support system security – including frequency control ancillary services (FCAS), network support and control ancillary services (NSCAS) and system restart ancillary services (SRAS);
Compensation costs associated with market and system interventions – including the Reliability and Emergency Reserve Trader (RERT), direction compensation, and compensation payments associated with administered price events; and
Participant fees to fund AEMO’s operation.
These costs are typically allocated to individual participants according to either ‘causer pays’ or ‘beneficiary pays’ principles. The total estimated cost in the 2020-21 financial year is in the order of $500 million[1].
AEMO’s proposal noted that the current rules allocate costs differently for different types of facilities with bidirectional energy flows, particularly grid-scale storage registered in its own right compared with small storage that is registered through a SGA.
Key Issues
Transmission use of system (TUOS) charges
It’s the topic that has dominated much of the reporting on this rule change – the decision to maintain the current arrangements for transmission charging for storage systems, which treat the load side of a storage system the same as other customers. Under these arrangements, storage providers must sign up to either a:
Prescribed transmission service, which has a defined service standard and a regulated price; or
Negotiated transmission service, where the level of service and price are negotiated with the transmission network service provider (TNSP).
Stakeholders advocating for storage systems to be exempt from TUOS charges highlighted the benefits that storage systems provide to the grid, while raising concerns about energy being ‘double-charged’ (once when entering storage and again when being consumed) and about the imbalance of negotiating power between storage proponents and TNSPs.
However, in explaining its decision, the AEMC explained that a broader review is needed to consider how the network charging framework should better account for flexible, price-responsive loads. It stated that it was not mandating that storage systems be subject to TUOS charges, but set out detailed reasons (see below) for why no change is being made at this time.
Another step in overhauling the registration framework
The changes to the registration framework have been informed by related ‘two-sided market’ work by the Energy Security Board (ESB), which is considering comprehensive changes towards a single trader participant category. However, the AEMC has noted that the scope of this rule change was predominantly confined to storage, hybrid and other bi-directional facilities, and opted against requiring all existing participants to transition to a new participant category at this time.
Existing participants need to be aware of the following arrangements:
SGAs will become IRPs on 3 June 2024, but an ‘early implementation period’ will commence on 31 March 2023, in which SGAs will be permitted to provide ancillary services and consider aggregated dispatch conformance arrangements.
An existing participant with:
scheduled load and generation at the same facility; or
scheduled load, where the participant is not a Market Customer,
must apply to AEMO to register as an IRP within three months, and be approved within six months, after rule commencement. It must also reassess the classification(s) for its facility, which may include transitioning to the new bidirectional unit classification.
Other existing Market Generators whose facilities meet the definition of an integrated resource system will be able to transition to become an IRP by applying within six months after rule commencement.
No fees will be payable for any of the registration transitions described above.
Existing storage facilities:
Will retain dual classifications of scheduled generating unit and scheduled load where the facility cannot linearly transition through the zero point (e.g. where there is a dead band); or
Must otherwise be reclassified as scheduled bidirectional units.
From now until 3 June 2024, a participant that registers and classifies a facility that is, or will be, an integrated resource system will have its application(s) assessed under both the current and new rules, to facilitate a transition into the new registration/classification classes on the effective date.
New options for energy dispatch
Hybrid facilities (comprised of two or more scheduled or semi-scheduled resources) are currently required to be classified at the unit level, with each scheduled or semi-scheduled unit receiving its own dispatch instructions that must be met.
Hybrid facilities will continue to be classified at the unit level under the new rules. However, the new rules allow for conformance with dispatch instructions to be assessed in aggregate, where AEMO considers that this will not impact upon power system security. Operators of hybrid facilities need to be aware that:
Arrangements for aggregate dispatch conformance will commence early, from 31 March 2023;
AEMO must develop a power system operating procedure that explains how it will determine whether and when aggregate dispatch conformance is permissible; and
Permission may be situational, with AEMO specifying within a dispatch instruction where unit-level dispatch conformance is required to support power system security, overriding any aggregate dispatch conformance arrangements.
Our Insights
The TUOS debate will continue, but the AEMC has set a high bar for change
As noted above, the AEMC explained that a broad review is needed to consider the network pricing model for flexible loads that can respond to dynamic price signals and can be controlled to support the management of network congestion (including storage systems and hydrogen electrolysis).
The AEMC also indicated that it expects to receive one or more follow-up rule change requests to review the applicability of TUOS charges to storage facilities. It has committed to prioritise any such rule change request in the 2022-23 financial year.
The final determination provides some markers for how the AEMC will assess any subsequent rule change. In it, the AEMC stated that it is not wedded to a view that storage facilities must pay network charges. However, the final determination flagged that:
Rules should be technology-neutral, rather than being specific to storage systems;
Network charges should be cost-reflective in order to avoid cross-subsidies;
Network pricing arrangements should provide locational signals and incentivise efficient operation;
There should be a level playing field for storage facilities connected at either the transmission or distribution levels; and
Assessment of a rule change will need to consider potential interaction with other reforms, including:
The ESB’s proposed Congestion Management Model, which incorporates the development of Renewable Energy Zones; and
The AER’s review of transmission ring-fencing guidelines, which is scheduled to commence in 2022.
In summary, the AEMC has set the bar high for a subsequent rule change and has highlighted complex interrelationships with other major reforms. Don’t bank on any change happening quickly.
Non-energy cost recovery changes will create ‘losers’, but will be more equitable
Unsurprisingly, the changes to the allocation of non-energy costs will result in some participants paying more and some paying less.
Each non-energy cost is generally considered to be ‘caused’ by either:
Customers, in which case the cost is allocated according to each customer’s share of total consumption; or
Generators, in which case the cost is allocated according to each generator’s share of total generation.
Under the current rules, a Market Customer with large amounts of small exempt generating units (e.g., rooftop PV) will have its total consumption reduced by the generated energy for the purpose of allocating non-energy costs, but its contribution to ‘causing’ that cost is unchanged. This results in a lower cost allocation to that Market Customer than a true application of the ‘causer pays’ principle. Similar outcomes can arise for Market Generators who consume energy in some intervals.
Participants who are ‘losers’ under these changes have arguably benefitted from shortcomings in the existing rules and should have little cause to feel aggrieved by the changes.
More registration changes to come
As noted earlier, the ‘two-sided market’ work by the ESB is considering comprehensive changes to the registration framework, transitioning all market participants into a single trader participant category. While the current changes do not require a transition for existing Market Generators and Market Customers with more traditional facility configurations, the IRP registration category has been established so that it could be the single participant category in future.
From the effective date, an IRP can do anything that Market Customers and Market Generators can do today. Consequently, we see no reason at this stage why anyone would register in the old categories once the new rules have commenced in 2024.
Any participant or developer seeking to register a storage or hybrid facility between now and the effective date should familiarise themselves with the new arrangements, due to the dual registration assessment process (against both current and new rules) that will apply in this period.
[1] Information consolidated from AEMO Quarterly Energy Dynamics Q3 2021 (see Figure 46) and the 2021-22 AEMO Budget and Fees (taken by adding the revenue requirements for the various NEM electricity functions.
For more information, contact Simone Rennie at srennie@renniepartners.com.au
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