Can utility operations keep pace with the multidirectional grid?
For much of the past century, power flowed in one direction. Today, as rooftop solar, batteries, EVs and flexible loads become more common, that model is breaking down. The grid is not simply becoming more distributed. It is becoming more dynamic, with energy and information moving between utilities, customers, aggregators and energy markets.
Forecasting alone can no longer address this change. With more assets connecting at the edge of the grid, the pressures becomes operational. Connection assessments grow more complex, export limits become more restrictive and operators need to maintain stability across assets they may not own or directly manage.
Once Distributed Energy Resource (DER) reaches meaningful scale, utilities have to move beyond knowing an asset exists to knowing where it is, what it is doing and whether it can respond when network conditions change.
The question is no longer whether the grid will become multidirectional. It is whether utility operating models can evolve quickly and adapt enough to manage it.
What global markets are signalling
Recent developments across different energy markets point in the same direction. DER growth is beginning to influence connection rules, network planning and the capabilities expected of utilities.
In June 2026, Vietnam increased the share of generation that qualifying rooftop solar systems can sell to the grid from 20% to 50%. Higher exports may be permitted where the network has adequate hosting capacity and can continue operating securely.
By September, Ho Chi Minh City had more than 22,000 rooftop solar systems. These included 6,241 self-generated, self-consumed systems with a combined capacity of 472 MWp. EVNHCMC also reported receiving notifications for almost 3,000 additional systems in around three months.
This illustrates a tension utilities increasingly face. Policies can encourage greater DER participation, but the amount of energy that customers can export still depends on what the local network can accommodate safely.
In July 2026, Indonesia’s state-owned utility PLN selected Bali for a Distributed Energy Resource Management System proof of concept. Bali has an estimated 500 MW of rooftop solar potential, equivalent to approximately 43% of its average system load. The project is intended to test how DER management and digital communications can support network monitoring, renewable energy integration and faster operational decisions, with the potential to inform wider deployment across Indonesia.
Brazil is moving in a similar direction through regulation. In September 2026, energy regulator ANEEL proposed updated connection rules covering distributed solar, batteries, EVs and flexible loads. The proposal includes requirements for monitoring, communication and response to commands, alongside protection, power-quality and export-control requirements.
These markets are moving beyond simply registering distributed assets. The emerging requirement is to observe their behaviour, communicate with them and coordinate their operation when network conditions require it.
SwitchDin has seen the same capability shift through its work with utilities. Projects with Horizon Power and Endeavour Energy show how utilities are moving beyond basic solar management towards standards-based visibility, communications and control across growing DER fleets. The broader lesson is that operational readiness must evolve with the network, rather than being built as a one-off response to an immediate constraint.
Coordination creates options within existing constraints
Many markets have already tested DER pilots, standards and policy approaches, but knowing about a problem is not the same as being ready for it. A utility has to make thousands of assets work reliably every day across different manufacturers, owners, communications protocols and commercial arrangements. It must also connect new DER capabilities with established network systems, operational processes and regulatory obligations.
Electricity networks operate critical infrastructure, so careful evaluation is essential. But visibility, communications and control cannot be created immediately after network pressure becomes critical.
By that point, operators may already be relying on tighter connection conditions, restricted exports or planned network augmentation. These responses may protect the network, but they can also limit how effectively customers and utilities use the distributed assets already connected to it.
Better coordination of what is already connected can make more of the existing network usable. DER management gives utilities better visibility and control, helping them connect more customers and use existing capacity before turning to physical infrastructure.
Pacific Gas & Electric has demonstrated what this can look like. A Pepsi-owned depot designed to charge 50 Tesla trucks would have created a peak load of approximately 5 MW. Conventional network upgrades were expected to take around three years.
Instead, PG&E used its DER management and communications systems to establish a flexible connection. Pepsi agreed that charging could be reduced following automated notifications when the local network was under pressure. The upgrade was still required, but coordinated control allowed the depot to connect sooner while that work progressed.
The example illustrates an important distinction. DER management does not remove every physical constraint. It gives utilities more options for operating safely within those constraints.
Managing thousands of small assets changes the model
Utilities may soon need to manage huge numbers of small, customer-owned assets spread across the grid.
“They could be managing hundreds of thousands of individual inverters, not just half a dozen big power stations,” says Ian Griffiths, Product Strategy Lead at SwitchDin. “Instead of coordinating a small number of big things, you now need to coordinate a massive number of small things.”
Those assets also behave for different reasons. A household battery may be trying to reduce a customer’s electricity bill, while an aggregator responds to a market signal and the utility works to maintain local network stability.
These priorities do not always conflict, but they cannot be managed independently. The operating model must allow network requirements, customer objectives and market participation to work together.
Experience from Project Symphony demonstrated that network and market requirements do not have to be treated as competing objectives. With the right coordination layer, diverse customer assets can participate in wider energy programmes while continuing to operate within local network limits.
DER adoption can accelerate quickly when incentives, falling technology costs and customer demand align, creating a gap between how quickly customers adopt new technology and how quickly utilities can adapt.
If a utility cannot see or predict what those assets are doing, it has less confidence in how much capacity is available. The result can be tighter export limits, slower connections, greater curtailment or infrastructure investment that might otherwise have been deferred.
Visibility helps a utility understand what is happening across the network. Coordinated control gives it another way to respond when conditions change.
Visibility is only the starting point
Preparing for a multidirectional grid is not simply a matter of installing a new platform. DER coordination must become part of normal network operations.
Utilities need to know which assets are connected, understand their behaviour and communicate across different manufacturers and technologies. They also need to apply operating limits when conditions change and bring DER information into the systems operators already use.
Interoperability is central to this model. A utility cannot manage a diverse fleet efficiently if every manufacturer, asset type or programme requires a separate integration pathway. Secure, standards-based communications provide a common foundation while allowing customers and utilities to retain equipment choice.
Security is equally fundamental. As assets become remotely visible and controllable, utilities must be able to trust the identity of connected devices and the source of data and control instructions. That trust cannot be added after a large fleet has already been connected. It needs to be designed into the operating model from the beginning.
Most importantly, utilities need to look beyond a single pilot or compliance deadline. The communications and control foundation created for one requirement should be capable of supporting future connection models, flexible exports, demand response and other forms of DER participation.
Keeping pace starts before the pressure peaks
The future grid is not simply a stronger version of the old one. It needs a different operating model that allows distributed assets to work together.
Utilities can keep up, but DER coordination must become an operational capability before constraints become critical. It cannot be treated only as a response to an immediate regulatory deadline or network problem.
The markets now revisiting their rules provide an early signal. Visibility, secure communication and coordinated control are becoming part of the infrastructure needed to operate an increasingly distributed energy system.
Customers are already changing the grid. The defining question is whether utilities will build the operational capability to keep pace before grid pressure narrows their choices.
