Wholesale market access for unscheduled BESS
I submit to our AI overlords.
If you know anything about batteries in the NEM, you’ll know that there’s a stack of services that batteries can provide, and that big prizes go to the person who can optimise the operation of the BESS against all the available value streams. Wholesale (a.k.a. spot) market arbitrage is just one service in the stack, but is arguably the most profitable and the most crucial to get right. In this post, we’ll explain the regulatory arrangements that underpin how an unscheduled BESS operator can access the spot market.
For the purposes of this post, we will focus on sites that are operating in the wholesale market in real time with no mention of derivatives or Power Purchase Agreements (PPA). Most sophisticated operators are combining PPAs and derivatives with real-time merchant operation to maximise returns. Such concepts will be covered in subsequent posts (or not at all, God, we’re so busy you know?).
As with all other posts referencing the National Electricity Rules (NER) and volatile commodity markets, this post is for general interest/education only and does not constitute legal or financial advice.
The boring stuff
The NER requires any battery connected to the NEM, regardless of size or location (i.e. behind or ‘in front of’ the meter), to be either registered or exempt from registration. AEMO, through its Registration information resources and guidelines, decides who is required to be registered and who is exempt. The current guidelines state that a person who owns, operates or controls a battery system with a nameplate rating <5MW is automatically exempt from the obligation to register as an Integrated Resource Provider (IRP, a relatively new term introduced to describe parties who own/operate/control bi-directional resources, i.e. batteries). Further, the asset will be unscheduled, i.e. not part of central dispatch.
As mentioned in our post on Scheduled Lite, we use the term ‘unscheduled’ to refer to Distributed Energy Resources (DERs) such as batteries that are neither Registered nor Scheduled.
This outcome (i.e. being unregistered and unscheduled) is desirable for many small asset operators. This is because the implementation costs, technical challenges, compliance obligations, and potential penalties of the registration and scheduling frameworks outweigh any benefits. As a result, the NEM has a whole bunch of generating and battery systems with nameplate ratings <5 MW, many of which are at Commercial & Industrial (C&I) sites.
Wow, that’s exciting. But if I’m not participating in central dispatch, how do I get spot revenue with my BESS?
There are three main ways to do this under the current rules and market arrangements, via three different market participants - the retailer, Small Resource Aggregator, and Demand Response Service Provider.
“It is worth remembering that having an active market-exposed BESS means you live and die by the decisions you make with your BESS. You receive money for exporting during high price periods/importing during negative price periods, and you owe money for importing during periods when the price settles >$0/MWh. If you get the formula wrong, things can go South very quickly.”
Overview of typical participant relationships for unscheduled BESS sites. The C&I Load may or may not feature in such sites.
Via a retailer
Retailers (officially Market Customers, under the NER) buy electricity directly from the spot market, and on-sell it to end users like you and me. They have discretion in how much, if any, spot price volatility (i.e. spread) they pass through to their customers. Some retailers will offer a fixed price per kWh, based on expectations of future market volatility and the costs of hedging, among other things. Others will pass on the spot price in part or in full, which creates an incentive for the customer to change how and when it uses electricity to keep costs low. However, many energy users find it hard to reap the potential rewards of spot price exposure because they struggle to change their consumption patterns in a volatile five-minute market. Further, many spot exposed customers (and retailers!) got burnt in the market crisis of 2022, which saw sustained periods of extremely high spot prices. This is where onsite flexibility (e.g. through use of batteries) can help. With a right-sized battery and effective forecasting of load and spot price, the customer can carry on business as usual, while the battery’s optimisation engine manages the battery’s activity to minimise or maximise the site’s net grid consumption based on the spot price.
To access spot market value via the retailer, all the customer needs is a retail contract with some element of spot price exposure. The retailer may optimise the battery themselves, offer spot price signalling to drive the customer’s chosen third party optimiser, or leave the customer’s destiny completely in their hands (often through partnership with a third party optimiser). Whichever way, all being well, the benefits of wholesale market access under this option will be seen on the customer’s retail bill. Retailers will often package the rewards of spot exposure as “revenue” to the customer, but ultimately it’s a cost saving against the counterfactual, i.e. the amount of electricity the site would have drawn from the grid if it hadn’t responded to price.
Some retailers are also interested in signing contracts for the output of a behind-the-meter BESS (or combined PV + BESS), because the dispatchable nature of this system makes it very attractive to them. This is an emerging model but we believe it will grow significantly over the years to come,
Where unscheduled batteries are not co-located with load, it is not common for the parent connection point to be controlled by a retailer. These sites often opt to go with our next category.
2. Via a Small Resource Aggregator
Many years ago, some energy services companies (ESCOs) were looking to monetise the value of <5MW behind-the-meter generators. We won’t tell you who, but SOME companies were doing it.
I think you might know them very well.
These were mostly backup generators, so technically capable of supplying electricity but really just collecting dust. The idea was to use the generator to take the site off grid when spot prices were high – a form of demand response. What followed was [insert dull regulatory process here], and out came the Small Generator Aggregator (SGA) framework. This framework enabled exempt generators (i.e., <5MW nameplate) to earn spot revenue when they ran. Bloody brilliant. The only issue was that each participating generating unit had to have its own connection point for settlement purposes. This was fine, except that most behind-the-meter generators were co-located with load. The solution found by those ESCOs was to set the sites up as embedded networks, with the existing grid connection point turned into a parent connection point, and a new child connection point established in front of the generator. All that was needed then was for the energy service company to register as an SGA, then sit back and wait for some spot price volatility.
When batteries became a thing, participants questioned whether they too could join the SGA framework. The answer was yes. Several rule changes later, batteries are now defined as bi-directional units in the NER, and SGAs have been rebranded to Small Resource Aggregators (SRAs), recognising the use of assets with two-way electricity flows.
To access the spot market via this option, the customer needs to strike a commercial agreement with an SRA covering, among other things, how spot market revenue will be shared between the two parties. SRAs are typically demand flexibility aggregators who also manage the process of setting up the embedded network and running the asset when price conditions are favourable (i.e. a sik spread). The customer continues to hold a contract with its retailer, covering the supply of energy at the parent connection point. Use of the embedded network framework also leads to some fancy metering shenanigans to reconcile activity of the child meters with the parent meter. It’s boring, but it’s part of our lives.
1,001 MW in our portfolio
The key difference between this arrangement and the one described above is the direct accrual of spot market revenue at the source of generation (to the SRA and not the retailer).
Arguably, the embedded network framework was not designed to be used in this way, but for the most part it delivers the desired outcome. However, its use here does lead to some operational, financial, and regulatory burdens for those using it. Fortunately, as set out further below, the implementation of the Flexible trading relationships rule change will simplify some regulatory and operational aspects of this model.
3. Via a Demand Response Service Provider
The final pathway to wholesale market access for users in this category is the Wholesale Demand Response Mechanism (WDRM), with a Demand Response Service Provider (DRSP). Through this mechanism, the DRSP accesses the spot market directly as a Scheduled participant, so some of the benefits of being unscheduled are lost. However, market participants who have thrived in the unscheduled segment have started building portfolios in the WDRM.
The WDRM is complex and warrants its own separate post, which is coming soon you lucky devils.
What does flexible trading have to do with this?
In August 2024 the AEMC made a rule on the Unlocking CER benefits through flexible trading rule change. You may have also heard this being called “flexible trading relationships” or “multiple FRMPs” (Financially Responsible Market Participants, a fancy term for the throat AEMO chokes if they want money from a particular connection point) – an idea that has been around for many years now. The rule, which comes into effect in November 2026, removes a fundamental premise of the original NEM design – that there can only be one financially responsible market participant (FRMP) per connection point.
No decapitation plz
At its core, the rule change allows large customers (think C&I energy users) to:
set up additional connection points on their site (called secondary settlement points), behind the grid connection point; and
contract with a different market participant at those secondary settlement points (i.e. no requirement for the FRMP at the primary connection point to also be the FRMP at the secondary settlement point).
The AEMC envisions that the rule change will drive innovation and competition by allowing large customers to separate their flexible and non-flexible assets on site, and contract with a third party to optimise the operation of their flexible assets in the energy and FCAS markets.
You may be thinking that this arrangement sounds an awful lot like option 2 above. That’s because it is. While the rule does away with the fiddly embedded network framework, the outcome is largely the same. The customer continues to hold a contract with a retailer at the grid connection point, and contracts separately with another party at the secondary settlement point to manage the operation of its BESS / generator / flexible load in response to energy prices. Any wholesale market revenue earned by the operation of the flexible assets accrues to the market participant at the secondary settlement point, who then decides how to share that value with the customer.
A key difference is that it no longer involves the embedded network framework, which regulators have acknowledged was never designed for this purpose in the first place.
Nevertheless, this decision demonstrates a willingness by the AEMC to amend the rules to pave the way for new products, services and service providers, and to reduce regulatory burden wherever possible. And that’s not boring at all.
So what should I do?
If you’re a BESS project developer/operator/investor, the market participants with whom you must engage to successfully build out your portfolio will vary based on:
the energisation date for your project(s);
the technical configuration you are using; and
the contractual details behind your interaction with the wholesale market.
It is rare for any BESS owner-operator to try to do all of the above by themselves, so good project partners are essential. The information here will hopefully help you choose your partners well. You will probably then prepare your in-house capabilities and contract out the things you don’t want to do yourself, and line up your essential market relationships based on your target project energisation dates and the implementation time frames outlined above.
If you’re unsure about your policy position versus the above, then it is always worth seeking legal advice from specialist energy law firms.
Thanks for reading all of this. At the very least, we hope that the post has been useful and informative for you, and has served to remove some of the confusion you will undoubtedly have been facing if you’ve had to grapple with these concepts over the last 2-3 years.
You will hopefully have learned more from this post for free than you would have from people you paid to know the source material behind it. If we’ve helped you learn what’s important to you without being bamboozled through jargon into buying something you don’t need, then it has been well worth writing 🌶️
God speed!
We’re on a mission to democratise this sh*t