A rule change regarding DNSPs and CER planning was recently published. I think it’s an indicator of a local demand response market forming.

Three bits of regulatory housekeeping have been released in the last year, all of which are independently unremarkable. Together, I think they’re indicators of a new market.

The claim: within a few years, DNSPs will pay third-party asset operators to fix problems at specific substations, in specific suburbs, on specific feeders. Non-network solutions will evolve into a live, dynamic market, open for participation from DER.

Of course, I could be wrong here, as there are more than a few ways to solve the distribution problem. However, there are a few pieces of evidence for a new market forming.

The rule change: more visibility on specific DNSP-level issues

The 16 July determination forces networks to publish what’s happening below the substation.

On paper the rule is dry: twenty-year development plans instead of annual ones, plus a requirement for the regulator to write guidelines on what network data the distribution businesses must publish. The rationale was that currently, nobody can see what’s happening on the low-voltage network, and that blindness is itself a barrier to sensible investment. After submissions, it confirmed that low voltage is a focus of this new policy, with DER / CER explicitly called out as a participant, and the DNSPs being required to give more visibility to drive investment here.

Right now, LV-scale applications are a bit of a black box for most asset operators. Certainly at a residential level, planning installs against where the network needs them is almost non-existent. This could change that - to see assets installed where they will be most effective.

Timing is slow, though. Some parts commence December 2027, and one schedule not until 2032. However, with Ausnet releasing tools like GridView, it’s clear DNSPs have the ability to make this available much sooner.

The networks: community batteries on the open market?

When Ausgrid wanted to own and benefit from storage, the regulator’s price of entry was to ensure third-party markets can also participate, with the same connection timelines, and with Ausgrid’s own internal costings as the benchmark.

Distribution networks are currently barred from owning generation and storage, so each community battery needs a waiver, and each waiver comes with conditions. In December 2025 the regulator approved Ausgrid’s five-year trial: 130MWh storage, 70MW solar, two areas, 32,000 customers, $187m.

However, it had a big condition. Ausgrid has to nominate a third area it isn’t operating in, publish the network data, and let the commercial market work there under the same settings Ausgrid gives itself: same tariffs in front of and behind the meter, same connection fees, same timelines. And it’s not self-assessed. Ausgrid hands the regulator its own internal connection costings, and the regulator uses those to assess what the third party is entitled to.

Reading that as a template, it’s possible that owning and operating DER for the benefit of reduced network spend might become the standard very quickly.

Some caveats. Ausgrid has a funding gap of roughly $73m, meaning the project might be delayed (however, the template still stands). Plus, one submission argued the chosen areas don’t have much congestion, which if true weakens the case. The third location hasn’t been named. So there’s still some work to do before we see the results of this project.

The technology: the control layer is being built

The tech standard that lets a network control a household battery or solar is now certified, public and mandatory in more states each year.

CSIP-Aus lets a network send instructions to household solar and batteries in a standardised format, regardless of manufacturer. It exists mostly so regulators could curtail solar during minimum-load events, also known as emergency backstop: the stick. The current certified version handles export and curtailment - i.e. stopping too much energy entering the grid. The next version in development adds battery charge and discharge control, which means the networks will have a method to control DER directly.

An interesting opportunity: many VPP businesses have prided themselves on connectivity across multiple OEMs. This feature will ultimately be valued less if CSIP continues to be developed - meaning a lower cost of entry. However, if local demand response does form, more value will be up for grabs, ready for those smart, nimble providers to capture.

The market design: it’s already been trialed in Australia

Piclo’s Victorian marketplace shows the model can work, and the networks are open to it.

Piclo launched in Victoria in 2024 with CitiPower, Powercor and United Energy: the network publishes a constraint, a price and a direction, and assets on that part of the grid offer in. It’s the first genuine price discovery on network flexibility in this country, and the numbers are public.

They also expose the design problem. Median contracts ranged between $9,000 and $21,000 per MW, with one area as high as $210,000/MW. However, availability ran from six hours to seven hundred hours per contract - meaning your revenue in $/MWh could be very low.

The other issue here: it’s tough for operators and asset owners to commit their asset hours ahead of time, let alone months. The Piclo product asked assets to be bid and available for use when the grid is under stress - which often corresponds to high wholesale events. There’s a real opportunity-cost that’s tough to factor in here.

Finally, there’s a structural reason this is awkward for retailers. Households can’t participate directly, only through an aggregator entitled to act for them. And customers in Australia can churn between retailers any time they want. So it’s hard for an energy retailer to bid CER assets into the market, as they could relinquish control of those assets to fulfil the contract at any time. Again, this is mostly an issue when asking assets to be bid in months ahead of them being used.

Why local is important

The instinct is to size any new market statewide. Ausgrid’s two trial areas: one is mostly apartments and renters who can’t install anything, where the only addressable assets sit on commercial roofs; the other is residential, batteries already there, and the problem is coordinating excess exports. Same network, same state, and almost nothing about a product built for one works in the other. They have completely different demand and supply profiles, and therefore need unique solutions.

Do that for every zone substation and layer in local variation in EV uptake, hot water and gas disconnection. The problem of each individual area is not the mean. Local markets are small, fragmented and expensive to serve, which is exactly why this becomes a market rewarding smart investment, and smart operation of DER.

The doors this opens

If this market forms, here’s where the value opens up.

Assets in the right place become worth more. The whole point of locational value is that a battery on a constrained feeder can earn something an identical battery two suburbs over can’t. Site selection stops being about easiest install, and starts being about where the network actually hurts. For anyone buying or backing DER, that turns “where do we operate” from a sales problem into a real part of the return.

The visibility and opportunity-identification layer becomes a product. Companies like Rosetta already sell network data and mapping to the DNSPs, and are the folks behind Ausnet’s GridView. Once the rule forces standardised low-voltage data across all thirteen DNSP businesses, interpreting the data, trends and constraints to maximise value becomes a product itself.

Someone builds the marketplace, properly. Piclo has the shape of it, but its model asks assets to commit months ahead, against an opportunity-cost nobody can price that far out. The version that works prices a local constraint against everything else the asset could be doing and lets it move interval by interval. That’s a harder platform to build and a more valuable one.

And maybe, finally, a resi product worth the friction. This is the speculative one. Residential VPP has already struggled with either friction or value. Locational value doesn’t fix that on its own. But a household with solar, a battery, an EV and controllable hot water, sitting on a constrained feeder, might be the case where there’s enough stacked revenue to be worth the effort. Time will tell.

What would change my mind

The whole thing rests on volatility, and there is tension there. Even Ausgrid’s project relies on wholesale volatility as a significant revenue stream. With more storage entering the market, generally the market will become less volatile - meaning we might see revenue cannibalisation from increased battery investment.

Things to watch:

• If the Ausgrid project goes ahead; what it looks like, and how much value is assigned to the non-Ausgrid assets.
• If networks embrace and accelerate more access to data.
• How the Piclo product evolves, and any adjustments they make to it.
• The underlying guidelines of how much data will be shared through the new rule change.
• Any changes to the emergency backstop program.

Any of this could go the other way. However, generally the biggest beneficiaries of new markets aren’t companies that start when the markets start - it’s those already running and able to pivot into new opportunities.

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Sam Fitz-Roy runs Inflection Energy, technical and commercial advisory for energy startups, investors and operators.