The history of demand-side participation in the NEM
The NEM was conceived as a two‑sided market, but for many years, demand-side participation fell far short of that vision. Regulatory changes have progressively enabled customer‑sited assets to provide, and earn revenue for, four key flexibility services. Today, large customers have real opportunities to maximise the value of their flexibility, especially if they can invest in enabling technologies and work with sophisticated market players.
Note: when we say “customers”, we are referring to consumers of electricity, which could be residential, small-to-medium enterprise (SME), or Commercial & Industrial (C&I) customers. By definition, all of these sit on the demand side of the grid.
Regulatory reform is ongoing. We’re slowly seeing a recognition that investing in and driving reforms in demand-side flexibility can yield efficient price and reliability outcomes. This is particularly attractive given the costs, delays and social licence complexities associated with the buildout of supply-side assets like transmission and bulk generation (anyone want to bet on the eventual cost of the currently $5b Marinus Link project, all of which will be borne by taxpayers?).
Government-led spending on energy projects is doing my head in at the moment tbh
As you’ll see in this post, we haven’t yet achieved the vision of a truly two-sided market, but we’re well on the way.
A few definitions
Before we get into it, let’s define some key terms and describe the four services that demand-side resources can provide to an electricity system.
For the purpose of this post, we’ll be using the term demand-side resources to refer to assets or technologies on the customer’s side of their electricity meter (“behind the meter”) that enable them to increase, decrease or shift electricity usage in response to an external signal, e.g. a price or direct instruction. Customers’ ability to do this is referred to as flexibility, because they can be flexible with when they consume electricity from the grid.
Demand-side participation therefore relates to the ability of demand-side resources to provide flexibility services to an electricity system, either directly or via a 3rd party such as a retailer or flexibility aggregator.
Demand-side resources can provide four main types of flexibility services, each procured and activated in different ways, as explained in the table below:
Tables are the sh*t
As always, we’ll be focusing on the regulatory frameworks as they apply to commercial and industrial energy users (or large customers as defined in the National Electricity Rules). The threshold for what defines a “large customer” varies by jurisdiction but generally covers energy users that consume more than 100MWh per annum.
Let’s start at the very beginning, a very good place to start
Fun fact: I sent Julie Andrews a letter when I was kid to wish her well after her throat surgery. See? Even losers can eventually run companies.
When the NEM was designed in the 1990s, one of the underpinning ideas was that both supply (generators) and demand (loads) should be able to participate in the market. The idea of a "two‑sided market" in electricity means that consumers are not passive price-takers but can increase, decrease, or shift load in response to price signals, and thus can influence dispatch, price, and reliability outcomes.
The original rules conceptually allowed for demand-side participation – large loads could bid into the spot market and reduce load during scarcity conditions. But in 2002, the Parer review noted that the NEM was heavily supply-side focused, finding, among other things, that:
“there are many impediments to the demand side playing its true role in the market”, and
“the system requires more generation capacity than it should”.
The paper made recommendations to address these findings. More than 20 years on, we can’t say that we’ve fully achieved the vision set out by Parer and the panel, but there are certainly more opportunities for the demand side to participate now. The intervening years have seen incremental reforms to move towards a more two-sided market. In this post, we’ll pull out the ones that have moved the needle.
Timeline of key demand-side participation initiatives
2013 – introduction of the Small Generation Aggregator (SGA) framework
In November 2012, the AEMC made a final rule to establish the Small Generation Aggregator (SGA) as a registered participant category in the NEM. Its purpose was to reduce barriers to the efficient utilisation of small generators, particularly embedded generators. The final rule enabled small generating units to be aggregated and for their output to be sold at the prevailing spot price. This meant that they wouldn’t have to incur the significant upfront and ongoing costs and compliance risks of being a fully Registered and Scheduled Generator, but could still access the benefits of providing a wholesale energy flexibility service – specifically, by running the generator to supply site load when spot prices were high.
The SGA participant category was open to any small generating unit that was exempt from the requirement to register as a Generator, either automatically (so, below the 5MW registration threshold) or otherwise exempted by AEMO at AEMO’s full discretion.
As explained in this post, the rule required each small generating unit to have its own connection point for settlement purposes. Given that most small generators were co-located with load, the solution found by prospective SGAs was to set a customer’s site up as an embedded network, with the existing grid connection point turned into a parent connection point, and a new child connection point established in front of the generator.
What’s changed since?
There have been a few amendments to the framework over time, including a name change to Small Resource Aggregator (SRA) in 2024 to enable small BESS to be used. The flexible trading relationships rule change, which will commence in 2026 and is explained in more detail in the post linked above, will do away with the fiddly embedded network framework as used on SRA sites with co-located load, and will introduce a new streamlined approach to deliver the same outcome.
We have not included the flexible trading relationships rule change as a separate notch on the timeline as we don’t think it will materially increase levels of demand-side participation — it will just make an existing route to market slightly easier for C&I flexibility providers.
Nevertheless, the SRA framework arguably remains the simplest and most valuable way for owners/operators of standalone or co-located BESS/small generation assets to provide a wholesale energy flexibility service in the NEM.
2017 – unbundling the provision of FCAS from the provision of energy
In November 2016, the AEMC made a final rule to “unbundle” the provision of Frequency Control Ancillary Services (explained here) from the provision of energy. Until the rule was implemented, the only parties able to offer frequency control services were parties that were also providing wholesale energy through the spot market. Technically, retailers were able to aggregate C&I customer load and offer it into the FCAS markets before the rule was made, but until the rule was made, the only demand-side participants in the FCAS markets were large scheduled loads.
To give effect to the unbundling, the rule created another new market participant category (the Market Ancillary Service Provider or MASP) that would be able to offer customer load into FCAS markets. Importantly, the MASP did not need to be the customer’s retailer, which paved the way for independent flexibility providers to contract with customers directly. The Regulation FCAS markets remained out of bounds for technical reasons, so the Contingency FCAS markets were a perfect place for aggregators to offer C&I customer demand response.
The AEMC expected that the rule would increase the diversity of suppliers of FCAS, and it certainly did. In our view, it was this rule change that really kicked demand-side participation off with a bang in the NEM, showing the market bodies and others what it was capable of and paving the way for future reforms.
The rule commenced on 1 July 2017, and not long after, AEMO reported a decline in FCAS costs in Q4 2017 compared to Q3 2017. This was, in part, as a result of the new supply brought on by EnerNOC (now Enel X) – the first MASP to offer C&I customer load into the Contingency Raise FCAS markets. The impact of competition on price continued to play out in the FCAS markets, as new MASPs entered and large-scale BESS came on the scene.
What’s changed since?
Three notable things have changed since the rule’s introduction:
The MASP participant category was re-branded to Demand Response Service Provider – Ancillary Services (catchy!) in October 2021, via the rule that introduced the Wholesale Demand Response Mechanism (discussed below).
Two new FCAS markets opened up in October 2023 for the provision of very fast raise and very fast lower FCAS, requiring a <1 second response time. Demand-side resources proved very capable of meeting the performance requirements of this service, so reaped the price benefits of early registration when those markets first opened.
The impact of competition on price has continued to play out in all of the contingency FCAS markets, to the point where FCAS value plays a diminishing role in a BESS business case, as explained in this post.
2017-2020 – AEMO + ARENA demand response trials
In 2017, AEMO and ARENA signed a Memorandum of Understanding to develop POC (that’s proof-of-concept, not people of colour) projects to demonstrate that demand-side response could be used effectively as reserve capacity.
For more on reserve capacity, read the section on RERT in this post.
The idea was to use the outcomes of these projects to help inform future regulatory reforms on demand-side participation, and help address any commercial or technical barriers to greater demand-side participation.
A three-year short-notice RERT trial was established and ten projects across Victoria, South Australia and NSW were awarded funding through ARENA. The projects were operated by a combination of retailers, individual customers, and flexibility aggregators and offered a mix of demand-side resources across residential and C&I customers.
By the final year of the trial, 180 MW of demand-side capacity was contracted via the short-notice RERT mechanism, and dispatched by AEMO over the summer period as needed to address Lack Of Reserve (LOR, also explained in this post) periods.
What’s changed since?
The trial is now complete, but much of the flexibility activated through the trial has continued to be offered in as RERT capacity in subsequent years. The trial showcased the demand side’s ability to provide an emergency reliability service quickly (in comparison to build-out of new generation) and helped build the foundation for the development of the WDRM.
The RERT framework is now well set up for demand-side participation, and AEMO relies heavily on demand-side RERT capacity to support reliability during critical grid events. But, as noted in this post, there are challenges. The market bodies are now focused on how to bring more demand-side capacity into the spot market to reduce reliance on emergency backstop mechanisms like the RERT.
That said, the draft report for the NEM wholesale market settings review has recommended the establishment of an out-of-market reserve service, intended to provide a longer term mechanism to address reliability gaps. It also calls for jurisdictions (i.e. the NEM states) and not AEMO to direct its procurement. Bet AEMO loves that.
2021 – introduction of the wholesale demand response mechanism (WDRM)
In June 2020, the AEMC made a final rule to establish the WDRM. We wrote a whole beautiful post on this one so won’t go into the detail of how it works, but it’s fair to say the WDRM squarely delivers on one of the Parer review recommendations: to “introduce a demand-reduction bidding system into the NEM.”
This rule change was huge in what it represented, but implementation has largely failed to deliver on expectations due to strict eligibility requirements and the threat that it would be phased out.
What’s changed since?
Since we published the WDRM post linked above, the AEMC has recommended that the WDRM not be phased out and instead be made a permanent feature of the NEM. The AEMC has also recommended that a rule change to allow sites with multiple connection points to participate in the WDRM be initiated, and AEMO has also been working behind the scenes to relax some of the strict eligibility requirements that hinder further uptake. So, there’s still hope that we will achieve Parer’s original vision, and that it won’t be PARED back!
Pared back! Parer’s vision! That’s gold, folks.
We’ve come so far, we’ve reached so high. What’s next for demand-side participation in the NEM?
I can confirm that I’ve never written Gary Barlow a letter.
The four initiatives covered above are those we consider have made the biggest impact in terms of increasing levels of demand-side participation in the NEM, or laying the groundwork for others that do. These initiatives have seen meaningful levels of demand-side capacity activated to provide wholesale energy, emergency reliability, and frequency control services in the NEM.
But the journey isn’t over.
Keen readers may have noted that none of these initiatives targets the demand side’s ability to provide network support services to DNSPs – the fourth of the flexibility services identified in the table upfront. While there have been some DNSP-led initiatives, the capability of demand-side resources to help meet network needs is woefully untapped. Could it be because DNSPs are naturally incentivised to just build more network infrastructure so that they can increase returns for their shareholders, rather than making better use of what already exists?
Surely Brookfield is just chilling in those board meetings and not pushing for returns to increase?
That’s a story for another day in another post.
The scheduled lite or Integrating price responsive resources rule change will commence in May 2027. While it’s being touted as a game changer for the demand side, there are already avenues for the demand side to provide wholesale energy services. In our view, it won’t drive significant levels of new capacity into the spot market. However, if coupled with an incentive provided through the Capacity Investment Scheme or the Electricity Services Entry Mechanism (ESEM) proposed in the NEM wholesale market settings review, it just might. Similarly, while the technical arrangements are yet to be worked out, the rule change’s commitment to enable scheduled lite participants to provide Regulation FCAS will unlock a value stream that is currently out of bounds for demand-side capacity.
Either way, the demand side is voting with its dollars, backed by billions in institutional capital. The speed at which demand-side capacity can be deployed makes these projects a no-brainer. If you want to start today and see returns before 2030, there’s no other option. Which is good for all of us, including consumers who want lower bills!