California’s new rules allow solar and batteries to help out the grid

For years, utilities have grappled with how to handle the ever-growing number of solar and battery systems trying to connect to the lower-voltage grids that deliver power to customers. That’s especially true for midsize projects like, say, a solar array that might adorn the roof of a multiunit apartment complex or a community-solar project that generates power shared by hundreds of dispersed customers.

On the one hand, utilities have eyed such projects warily, fearing that if the solar panels or batteries inject too much power onto local circuits at moments when electricity demand is low, it might cause grid instability or safety problems. As a result, utilities have thrown up barriers that have delayed or halted grid connections.

But as advocates have been pointing out for over a decade, these distributed solar and battery resources can also be enormous assets: By holding back power when the grid doesn’t need it, and then sharing their extra power during periods of high demand, they can help alleviate grid strains and lower the cost of keeping the grid running for everyone.

It’s taken California regulators, utilities and clean-energy advocates nearly four years to hash out these conflicting ideas. But in mid-March, the California Public Utilities Commission approved new interconnection rules that take into account how, with the right structures in place, solar and solar-plus-battery systems can be more help than hazard to California’s overworked grid.

“This will open up opportunities for distributed energy resources to be designed in a way that aligns with grid needs,” said Sky Stanfield, an attorney who works with the Interstate Renewable Energy Council, the nonprofit group that’s been the main proponent of the new rules. ​“It’s a long time coming to recognize that distributed energy resources are a whole lot more helpful than they’re allowed to be — and that we don’t have to spend as much to upgrade the grid as a result.”

The ​“Limited Generation Profile option” just approved by the CPUC is a complicated set of regulations that determine how solar and solar-battery systems interact with the lower-voltage grids operated by California’s CPUC-regulated utilities Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.

Today, those utilities make a simplistic set of assumptions when they consider the potential impacts of a project on the lower-voltage grid systems that carry power from substations to homes and businesses, Stanfield said — basically, that each project is producing its peak output at the time of least electricity demand from customers.

That’s pretty much how all U.S. utilities calculate the risks of new generation connecting to their grids, she noted. But this assumption is likely to yield findings that exaggerate how likely a project is to inject too much power onto local grid circuits.

To eliminate those perceived risks, utilities have demanded that project developers pay for grid upgrades themselves or have prevented the projects from connecting at all. Since those grid upgrades can cost hundreds of thousands to millions of dollars and take years to complete, the result either way tends to stop projects in their tracks.

Allowing new solar and battery projects to support the grid

The CPUC’s new policy takes a different tack, one well suited to larger-scale projects that are more likely to trigger grid upgrades. It will allow solar and battery projects to modulate how much power they send to the grid with the help of either solar inverters whose power-control systems can reduce power output from moment to moment or batteries that can soak up excess solar power and inject it back into the grid later.

Limited Generation Profile projects would be able to use these capabilities to alter their grid injections during different periods of the day, based on a set of schedules they can choose from. Those scheduling options are derived from the grid data available in the maps of hosting capacity from Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. (Here’s a snapshot of PG&E’s hosting-capacity map for a downtown section of the central California city of Bakersfield, with circuit capacity represented in red, orange, yellow and green.)

Most utilities in the U.S. haven’t been ordered by regulators to collect the detailed and accurate local grid data needed to create these kinds of maps, Stanfield noted. In fact, the Interstate Renewable Energy Council has played a key watchdog role in alerting the CPUC to problems with these maps as they’ve been developed over the past decade, as well as in making them more useful for customers and project developers looking for good spots to connect to the grid.

Thanks to those improvements, California’s maps now contain accurate information on the hour-by-hour capacity of individual circuits.

With this data in hand, California’s three largest utilities and clean-energy project developers can finally agree on just how much power solar and battery projects can safely inject onto the grid during different periods of the day and night across each month of the year.

That amount may be close to zero during some stretches — say, on a circuit with many homes with rooftop solar systems during sunny and mild spring daylight hours, when self-generated solar power can exceed customer demand for electricity. Within those hours, Limited Generation Profile projects may export little or no energy at all.

But these ​“minimum-loading” conditions are relatively rare — and at other moments, that same grid circuit may be hungry for all the power it can get. That’s typically during hot summer and autumn evenings, when the state’s ample solar resources are fading away, yet electricity demand for air conditioning remains high — the same conditions that have caused statewide grid emergencies in recent years.

California’s power grid is struggling to deal with the wide swings between times when it has too much solar and times when all available resources still don’t provide enough electricity. In fact, the CPUC and state policymakers have made significant efforts to address this imbalance via state rooftop solar policy — which has reduced the value of solar delivered to the grid while promoting the value of batteries that can store power for when it’s needed — and with utility-scale power procurement policies, which have put gigawatts of batteries into operation over the past few years to store solar power for those evening hours when demand exceeds supply.

But until now, utility interconnection policy ​“has not taken into account, or enabled, distributed energy resources to differentiate when they produce power and when they don’t,” Stanfield said. That’s left interconnection policy misaligned with broader state policy imperatives for how best to use solar systems and batteries, she added.

It’s also put interconnection policy at odds with policy efforts to better manage growing distribution-grid costs, Stanfield noted. Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric are facing tens of billions of dollars of additional grid investment in the coming decades to supply the millions of electric vehicles, heat pumps and electric appliances that the state is asking consumers to adopt in order to reduce carbon emissions.

“Grid upgrades are expensive,” Stanfield said, ​“and we want to avoid them where we don’t need them” — particularly in cases where new solar and battery systems could actually help reduce grid strains.

Even more fundamentally, rules that bar more solar and battery power from reaching the grid based on outdated and inaccurate methods of determining their grid impacts will rob customers at large of the value those projects could provide.

That’s the conclusion reached by Amin Younes, an electric distribution planning and policy engineer with CPUC’s Public Advocates Office, which represents utility customers’ interests. Younes studied the potential for the Limited Generation Profile option to add more clean energy to California’s grids during hours when energy is in short supply.

This graphic from a presentation of his work indicates how widely the capacity of a typical distribution grid circuit can vary from hour to hour. In this case, limiting a solar or battery project to the minimum loading condition — the red line on the chart — would have forced a project to be sized to deliver no more than 1.5 megawatts of power of maximum capacity. But during many more hours of the year, that circuit could accept far more than that — often more than twice that minimum limit, or more than 3 megawatts of power.

According to his analysis, factoring in that extra capacity across the distribution circuits of all three utilities could add up to tens of billions of dollars per year in additional clean energy that could be delivered. And because that power would supply the grid at hours when electricity costs and threats of grid emergencies are the highest, that ​“could lower costs and increase grid reliability,” he said in an interview.

Finally, implementing the Limited Generation Profile option should allow solar and battery developers to avoid having to pay for grid upgrades and give them a much faster interconnection process, Stanfield said. And, if it works as planned, it could be a useful model for other states to follow.

Solving grid-interconnection challenges across the country

In a 2021 blog post, the Electric Power Research Institute, a nonprofit power-sector research group involved in a wide variety of utility technology projects, highlighted the need for more flexible interconnection policies across the U.S. to prevent the tens of billions of dollars of forecasted investment in EV charging, distributed solar and battery backup systems from being stalled out by grid constraints.

The conservative, expect-the-worst approach that most utilities take with interconnection processes may be a way to maintain grid reliability, the institute noted. But it can also ​“lower customer satisfaction and slow progress toward renewable energy targets.”

It’s important to distinguish the problems plaguing this class of clean energy from the similar but distinct issues blocking hundreds of gigawatts of utility-scale wind and solar farms from connecting to transmission grids across the country. The Interstate Renewable Energy Council’s work in California and other states has focused mainly on distribution grid interconnection policies, which cover everything from rooftop solar systems and home battery and EV charging installations to multi-megawatt solar and battery projects.

While these types of interconnection problems can stymie even smaller-scale home rooftop solar systems, the bigger challenges tend to arise with larger-scale installations like community-solar systems that generate power for many different customers (in California, for example, most projects under 1 megawatt in generation capacity aren’t responsible for paying for grid upgrades). In many states, growing grid-upgrade costs and maddeningly slow interconnection timelines have become increasingly significant roadblocks to connecting these mid-sized projects.

In Minnesota, solar and consumer groups are fighting a utility policy that can assign hundreds of thousands of dollars in grid-upgrade costs to relatively small rooftop solar and community ​“solar garden” projects. In the community-solar-rich state of Massachusetts, some developers are stuck waiting for years for grid studies to allow projects to move forward. 

States including New York, Minnesota and Massachusetts have begun to explore flexible interconnection policies — the more general term for the approach California is taking, according to Stanfield — but only through pilot projects or laborious ​“non-wires solutions” programs run by utilities. They have yet to embrace a standard way for clean energy developers to work with utilities.

Most other U.S. utilities haven’t been compelled by state law and regulatory mandates to produce the detailed distribution-grid-level data collection and hosting capacity analyses that enable the CPUC’s Limited Generation Profile approach, Stanfield noted. But these kinds of tools are starting to be developed in other states. That’s an important precursor to enable flexible interconnection, she said.

Can ​“flexible interconnection” expand community solar and batteries? 

To be fair, utilities have very good reasons to take a conservative, safety-first approach to interconnection. After all, they’re responsible for keeping grids safe and reliable — and distributed energy resources represent potential disruptions to those grids that utilities can’t directly control.

That’s why California’s Limited Generation Profile option won’t go into effect until nine months after certain power-system control technologies are certified by the Underwriters Laboratory standards organization as being able to reliably perform according to schedule. That’s expected to happen sometime within the coming year, Stanfield said.

Utilities have also been concerned that changes on their grids could leave circuits susceptible to dangerous conditions. CPUC’s new policy does allow utilities to curtail a project during emergencies or request a change to the project’s schedule in the highly unlikely circumstance of a ​“sustained load reduction” on a grid circuit — namely, if a major customer using that circuit closes down and permanently reduces electricity demand.

But under the new rules, utilities are largely required to honor the schedules they’ve agreed to with solar and battery projects, and to take on reasonable costs of grid upgrades to manage them. That’s a vital feature for any successful flexible-interconnection process, Stanfield said, because project developers secure investment for projects based on some level of certainty about how much power they’ll be able to sell over the project’s lifetimes.

Any utility program that injects too much uncertainty into that prospect — by, for example, retaining the right to unilaterally curtail a project’s grid exports without a clear and provable grid problem to justify it — won’t work for developers, she said.

“A flexible interconnection solution, if it’s modeled and can show what the impacts are going to be, might give developers a lot more certainty and more comfort,” said David Gahl, executive director of the Solar and Storage Industries Institute, during a November event held by the Interstate Renewable Energy Council. That nonprofit is leading a flexible-interconnection pilot project in New York state that’s funded by The U.S. Department of Energy’s Interconnection Innovation e-Xchange program.

Utopia Hill, CEO of Reactivate, a joint venture developing community-solar projects for disadvantaged communities, also noted at the November event that the key to future flexible-interconnection processes is increasing their predictability. ​“If we can’t get financing parties comfortable with that, we can’t get the funding to build the projects,” she said.

It’s still not clear if the CPUC’s Limited Generation Profile rules will meet that need for California solar and battery developers, said Kevin Luo, interconnection policy advisor for the California Solar & Storage Association trade group. One big question is whether the scheduling options approved by the CPUC will actually allow developers to design moneymaking projects.

“That’s one of the reasons why we pushed so hard for customers to be able to pick their own schedules,” he said — an option that the CPUC denied. ​“Nobody has done the forecasting work necessary to have the confidence in any one schedule.”

Nor are California’s solar policies and market dynamics aligned to support the 1-megawatt-and-up projects that the Limited Generation Profile option would be best suited to, Stanfield said. California lacks effective policies to promote the development of multi-megawatt, distribution-grid-connected community-solar projects or large-scale rooftop solar projects on warehouses or apartment complexes that would be eligible for the new interconnection treatment — although solar and environmental-justice groups are pushing regulators and lawmakers to change that.

Even so, Stanfield said, starting with a schedule-based approach at least begins to align utilities’ grid needs with the imperative to add far more solar and batteries to California’s grid. That way, ​“you can start to get some of the benefits now — and then we can build on that further.”