California has more distributed energy resources than any other state, pressuring it to find ways to integrate them into the grid. The interconnection rules that tell developers of rooftop solar, behind-the-meter batteries and electric vehicle chargers how much time and money they’ll need to spend to get them grid-connected — or whether they’re even allowed — are a big part of that integration puzzle. 

Last week, the California Public Utilities Commission approved revisions (PDF) to Rule 21, which sets interconnection policies for everything from net-metered solar to large-scale generators, that could allow distributed energy resources (DERs) ​​​​​​to play a more active role on the California grid, depending on how they’re implemented.   

The changes include ways for battery-backed solar systems to incorporate their inherent flexibility into the grid, not by being aggregated as a virtual power plant or as a non-wires alternative to grid upgrades, but as a precondition of their interconnection. 

That, in turn, could help solve growing problems for California, like grid voltage imbalances caused by distributed solar systems or grids being overloaded by EV chargers or batteries — again, not as a response to their presence on the grid, but within the same process that brings them online. 

“The functions we’re talking about here in terms of power control systems and scheduling — they tie into microgrids and other things utilities are grappling with,” said Sky Stanfield, an attorney representing the Interstate Renewable Energy Council, a nonprofit policy advocacy group active in interconnection regulations. “They get us to this distributed grid that’s more customer-driven but also more flexible.” 

Grid flexibility built into grid interconnection 

That’s the big change enabled by a Rule 21 revision entitled “conditions that allow distributed energy resources to perform while avoiding upgrades.” In simple terms, it orders California’s three big investor-owned utilities to develop processes to allow fast-track interconnection of DER projects that use “limited generation profiles” to modify their impact on the grid.   

Under state law AB 327, California’s utilities provide Integration Capacity Analysis (ICA) maps online showing DER hosting capacity on individual grid circuits. That capacity can change from hour to hour or season to season, largely from the daily rise and fall of solar power. A new solar system that might be easily added to a circuit under average conditions could still exceed its capacity during a few hours, such as on cool yet sunny days when solar generation floods the grid.  

Under the old rules, that DER developer would face a lengthy study that could force it to pay for grid upgrades or abandon the project. But the new rules allow systems to promise to manage their output on a set monthly schedule that change from hour to hour, possibly by curtailing solar output, or more likely, by storing it in batteries. 

This kind of automated, data-driven way for new DERs to match up with grid needs is a key goal of ICA process launched in 2014, Stanfield noted. “We want all DERs to be able to do this, as we get into high penetration DER conditions.” Without some method to fast-track interconnections, “you’re going to have huge system study backlogs.” 

Utilities still need to develop rules over the next six months that could make it harder for DER developers, she noted.

If circuit conditions change — for example, if load during critical hours falls due to big customers closing down — utilities can order DERs to curtail in ways that could degrade the economics of DER projects. Whether or not that happens “will come down to how certain it seems, or uncertain it seems, once utilities work out the details.”

Standardizing solar-plus-storage and vehicle-to-grid charging 

This scheduling capability also relies on new Rule 21 regulations on battery interconnection being put in place — specifically, rules around batteries exporting to the grid. 

Behind-the-meter solar-battery systems face strict export restrictions, largely to avoid paying net-metering retail rates for energy stored from the grid instead of from rooftop solar. But as our coverage of last month’s rolling blackouts noted, storage vendors say these rules limit batteries’ grid value.

At the same time, larger-scale solar-storage systems are limited to two categories: completely non-exporting and those assumed to export all of their power. This bars the option of variable export and requires would-be export-capable projects to need enough interconnection capacity to absorb their combined solar and storage output simultaneously. 

The new Rule 21 revisions start to take on these problems by recognizing the concept of “limited export” and setting rules for how utilities can verify that projects are sticking to those limits, Stanfield said. 

These highly technical distinctions matter a lot since they bar interconnection until they’re resolved. For example, Rule 21 already requires all new DERs to use smart inverters with grid-support functions, making them the logical point to manage battery export. 

But the standards for testing whether smart inverter export controls and schedules are operating correctly — the thing needed to make the aforementioned flexible DER interconnections possible — are still being developed. The CPUC gives utilities nine months after technical standards have been developed to implement limited generation profiles, indicating that it will be late 2021 or early 2022 before DER developers can use them 

This kind of lag between technical capability and regulatory reform is not unusual. Most states haven’t gone nearly as far as California has in terms of making hosting capacity data available and allowing interconnections to use it in a streamlined fashion, Stanfield noted. 

The same incremental progress applies to the Rule 21 revisions on vehicle-to-grid (V2G) EV charging, which is common in pilot projects but still not standardized for broad interconnection.

California already has gigawatts' worth of EV chargers, with more gigawatts coming as part of its push to electrify transportation. Enabling them to export EV battery capacity, rather than simply stop charging, could make them an even more valuable grid resource.

The new Rule 21 revisions clarify that V2G DC charging, or bidirectional EV chargers, can be interconnected with utility permission. That’s a first for a state utility commission, said Jin Noh, senior policy manager for the California Energy Storage Alliance. 

As for V2G AC charging or allowing vehicles to charge directly to the grid, the revised Rule 21 sets up a process to study when technical standards will be ready to standardize it. “We now have a pathway for the stationary case and potential next steps for the mobile case,” Noh said.