For most of the grid’s history, power flowed one way: from large, centrally dispatched generators, down through transmission and distribution networks, to consumers. That assumption is now wrong for a meaningful share of the National Electricity Market (NEM), and it did not happen gradually. It happened because millions of individual households made their own decision to put solar panels on a roof, and the grid has had to catch up.
Table of Contents
- What counts as DER
- The scale of the shift
- Minimum demand: the new operational headache
- From one-way to two-way flows: what changes technically
- How the grid is adapting: flexible exports and dynamic operating envelopes
- The market-side response
- What this means for developers, networks and asset owners
- What to do next
- FAQ
What counts as DER
Distributed energy resources (DER) are generation, storage and controllable load sitting behind the meter, on the customer’s side of the connection point, rather than in front of it. In the Australian context this means rooftop solar PV first and foremost, alongside a fast-growing base of home batteries, electric vehicle chargers and, in some programs, controllable loads like hot water systems. What makes DER different from a conventional generator is scale and location: no single unit matters much, but millions of them, spread across every distribution feeder in the country, add up to a genuinely large and largely uncoordinated power source.
The scale of the shift
The numbers involved are no longer a rounding error on the NEM’s generation mix. AEMO’s Quarterly Energy Dynamics reporting put cumulative rooftop solar capacity in the NEM at 26.4 GW by the end of the June 2026 quarter, spread across roughly 3.9 million installations, and distributed solar output hit a quarterly record of 4,090 MW in the first quarter of 2026, up 8.1% year on year. Household battery energy storage capacity connected to the NEM grew by almost 3.3 GWh, or 41%, in the June 2026 quarter alone.
The flow-on effect shows up in two places at once: the renewable share of NEM generation reached a new Q2 high of 42.1%, and average NEM wholesale prices fell to their lowest June quarter level since 2020, down 47% year on year to around $74 per MWh. Cheaper average prices are the visible upside. The less visible cost is what this volume of uncoordinated, weather-driven generation does to grid operations underneath the average.
Minimum demand: the new operational headache
Rooftop solar generates hardest in the middle of the day, exactly when many households are out of the house and using relatively little grid electricity. The result is minimum operational demand, the lowest amount of electricity the grid needs to supply from the transmission-connected system, falling further and faster than it ever has under a conventional load profile. Recent quarters have set new minimum demand records across the NEM and in individual states including Victoria, Tasmania and South Australia, with rooftop solar now periodically pushing operational demand into negative territory in parts of the network.
Low minimum demand is not simply a curiosity. It is an operability problem. A grid needs a baseline of synchronous generation online to provide system strength and inertia, the properties that keep frequency and voltage stable when something goes wrong. As rooftop solar pushes minimum demand lower, AEMO has to work harder to keep enough synchronous plant committed, or draw on other tools, to hold the system within safe operating limits. This is a structural challenge, not a temporary one, and it scales directly with how much more DER gets installed.
From one-way to two-way flows: what changes technically
Distribution networks were largely designed and protected on the assumption that power flows in one direction, from the zone substation down to the customer. High DER penetration on a feeder reverses that assumption for parts of the day, which creates real technical consequences: voltage rise as exported solar pushes local voltage upward, protection systems that were never designed to detect a fault fed from the customer end of a feeder rather than the substation end, and thermal limits on transformers and conductors that were sized for one-way peak demand, not two-way peak export.
This is why a feeder’s hosting capacity, the amount of additional DER it can absorb before voltage or thermal limits are breached, has become one of the more important numbers in network planning. It is also why static export limits on many low voltage feeders have historically been set conservatively, in the order of 1.5 kW per phase in constrained areas, well below what a well-managed, dynamically limited system could actually support.
How the grid is adapting: flexible exports and dynamic operating envelopes
The industry’s answer to static, conservative export limits is the dynamic operating envelope (DOE): a time-varying export and import limit calculated for a specific connection point based on real-time or forecast network conditions, rather than a single fixed number set for worst-case conditions. Where a static limit might cap a household at 1.5 kW per phase to protect against a rare worst-case voltage event, a dynamic limit can allow that same connection up to roughly 10 kW per phase when actual network conditions comfortably allow it.
AEMO’s Project EDGE has been the main NEM-based demonstration of this approach, working with SA Power Networks to trial dynamic operating envelopes and investigate how they integrate with AEMO’s own dispatch engine. The results reported from that work show dynamic export limits materially reducing preventative curtailment and delivering double-digit percentage increases in exported energy compared with static limits, while still respecting the underlying voltage and thermal constraints the network has to operate within. The Australian Energy Regulator has also weighed in with export limit guidance, supporting distribution businesses as they roll flexible export arrangements out more broadly.
The market-side response
Network engineering is only half the adaptation. The market side is shifting from a one-directional retail relationship, where a customer only ever buys energy, toward genuinely two-sided arrangements where a customer’s flexibility, when they charge a battery, export solar, or shift a controllable load, has value that retailers and aggregators can compete to capture. Virtual power plants (VPPs) are the most visible expression of this, but two-way tariffs that explicitly price exports by time of day, and that reward flexibility rather than penalising it, are becoming a parallel and arguably more scalable mechanism, since they do not require every household to join a formal aggregation program to participate in the shift.
What this means for developers, networks and asset owners
For anyone specifying DER-connected assets, whether a single commercial rooftop system or a large residential battery program, a few things follow directly from the scale of this shift. Export limits on a given connection are increasingly likely to be dynamic rather than fixed, which changes how a system’s expected annual export, and therefore its financial case, should be modelled. Protection and voltage studies on any DER connection now need to account for two-way flow as a normal operating condition, not an edge case. And network businesses assessing new connections are weighing hosting capacity and minimum demand impact alongside the more familiar peak demand questions that used to dominate planning.
What to do next
If you are developing a DER-connected project, whether that is a commercial solar and battery system, a community battery, or a fleet being built for VPP participation, understanding how dynamic export limits and minimum demand constraints will actually apply to your connection is worth resolving at the design stage, not after a connection application is lodged. We have helped teams work through exactly this kind of technical review early, when it can still change the outcome. If it would help, we can walk through what that review typically covers for a project like yours.
FAQ
What is the difference between DER and a VPP?
DER refers to the physical assets themselves, rooftop solar, batteries, EV chargers and controllable loads. A VPP is the coordination layer that aggregates many DER assets so they can act together as a single dispatchable resource. Not all DER is enrolled in a VPP.
Why does rooftop solar cause problems if it is reducing demand from the grid?
Lower demand from the transmission-connected system sounds positive, but it reduces the amount of synchronous generation that needs to stay online, and that generation is what currently provides system strength and inertia. Very low or negative minimum demand makes it harder to keep the system stable, independent of whether overall emissions or costs are falling.
What is a dynamic operating envelope?
It is a time-varying import and export limit set for a specific connection point based on actual or forecast network conditions, rather than a single conservative limit set for worst-case conditions at all times.
Are dynamic operating envelopes available everywhere in Australia?
No. They are being rolled out progressively by individual distribution network service providers, with South Australia’s Project EDGE trial being the most developed NEM-based demonstration to date. Availability varies significantly by network and by feeder.
Does more DER always mean lower export limits for new solar and battery connections?
Not necessarily. Static, conservative limits are often lower than what a network could actually support under real conditions. Dynamic export arrangements are specifically designed to allow higher exports when conditions allow, rather than assuming the worst case at all times.
