In the United States, community solar installations are expected to total more than 14 gigawatts by 2028. And much of that growth is near-term: installations are predicted to increase by 10% in 2024 alone.
Within that trend is another: the country’s deployments of community solar plus storage projects are set to increase by more than 200% in the coming years, thanks to anticipated growth in Massachusetts, New York, and California.
The addition of storage is changing the way projects interact with the grid, and with local utilities, and is transforming them into small solar plants that can act as grid services providers. And the evolution comes at a time when utilities and regulators alike are grappling with how to meet the massive energy requirements that data centers and new manufacturing capacity are predicted to bring.
Jeff Cramer, president and CEO of the Coalition for Community Solar Access, said the rise of community storage is a key indicator of how far the concept of community solar has come in the last decade: from what was essentially an expensive pilot concept, to a scaled industry with eager financiers.
And that scale, he said, is key to the evolving role community solar is playing today.
“At a very small scale, community solar is a niche industry and doesn’t need to act as a grid resource, because there’s not much of it,” Cramer told Latitude Media. But as more community solar is deployed, he added, the potential for projects to become real grid assets grows.
“Community solar 2.0 is a more sophisticated market, where community solar can pair itself with storage or be closer to load to be able to serve more sophisticated grid needs,” he said, adding that community solar 3.0 has the potential to serve as a “generation hub within a broader distributed energy resource ecosystem.”
And as that new generation of community solar arrives, it can serve as a tool to reduce both load on the grid and strain on transmission systems.
Inside community solar 3.0
The shift is already underway, Cramer said, but new community solar-plus-storage is highly concentrated in parts of the country that have high renewables penetration.
“Places like New York or California or Massachusetts are creating more and more granular market structures to incentivize the pairing of storage,” he explained.
In contrast, in places like Wisconsin or Pennsylvania, low penetration of solar means there really isn’t a need for storage yet: “They’ve got gigawatts of run room to just build solar, and put it close to load growth,” Cramer added.
Boston-based Nexamp, which owns and operates community solar programs in 17 states, began adding storage to its projects a few years ago. Today, the company has around two dozen operational storage projects, which act as capacity resources for local grids, and roughly five GW in development or under construction.
State-level incentive programs have helped bolster certain projects. In ISO New England, for example, two of Nexamp’s solar-plus-storage projects offer a total of four megawatts of battery storage; both participate in Solar Massachusetts Renewable Target, a state solar development program that incentivizes storage, and Clean Peak, another state incentive program.
But Nexamp has gone beyond adding storage in terms of its interaction with the local grid.
In 2022 the company teamed up with National Grid for a pilot in which Nexamp will manage the construction of local distribution system upgrades in the areas where it plans to bring a 4-MW solar project online.
And the company is also experimenting with a non-wired model, including via an 8.4-MW project in Watertown, New York that’s paired with 31 megawatt-hours of storage. For that particular project, National Grid will be able to access an additional 29 MW of energy up to 25 times per year. Construction on that project, which is designed to solve a substation overload problem, is currently underway and is expected to be completed in the coming months.
According to Nexamp chairman and CEO Zaid Ashai, it was just before the Covid-19 pandemic started that the company started its own dialogue with utilities about the role that community solar could play in grid service operations.
But it’s a complicated process, he added, and one that has taken time and buy-in from everyone from utility C-suites to engineering teams, and those conversations are ongoing. Accordingly, it’s not a path that Ashai expects the entire community solar industry to follow just yet.
“I’m not sure, candidly, how many companies are fully investing,” he said. “Utilities and grid service operations take time. It’s complicated; it’s a long life cycle, and it really takes a lot of pipeline to make it worth your while.”
Joel Gamoran is the vice president and general manager of energy services at Arcadia, a Denver-based community solar and software company that operates both solar-plus-storage and standalone community storage projects. He said community solar is in a better position to leverage the benefits of storage than residential customers or corporations with solar installations.
“Solar is set it and forget it, but storage you have to more actively manage,” Gamoran said.
Community solar companies are “very sophisticated asset owners,” he added: “I do think that third party-owned assets are in a better position to take advantage of whatever incentives are available, and community solar, by and large, is all third-party owned.”
Growing pains
Meanwhile, the comfort of financiers is a key “litmus test” as to whether the market for these new generations of community solar pencil out, Cramer said.
Project finance for community solar — and specifically for projects not developed and operated by vertically integrated companies — has traditionally been diverse, and has included private equity and capital from large and small banks alike. And as community solar evolves, it’s becoming a new and increasingly attractive asset class, and enticing the interest of large infrastructure holdings, Cramer added.
But despite the current level of investor interest, community solar’s road to grid asset extraordinaire is far from assured, in part because of the way the market is structured.
“[Unlike Nexamp], most developers don’t own their projects long-term, so they don’t have any incentive to be involved in grid services,” Ashai said, adding that the new owners and operators of a project tend to be investment funds, underwriting a project based on its projected revenue.
“That’s the fundamental issue: the way our industry ecosystem is designed,” Ashai said. “We don’t have strong industry interest yet — and I’m optimistic it will change in the future — in fixing the state of the grid.”
Getting to that reality, he said, requires “strong signaling” from public utility and public service commissions, making sure that where new projects are sited and how they’re developed (including whether or not they include storage) take into account the state of the local grid.
“It’s hard for either the owner/operator community or the development community to respond until there’s really good frameworks,” he said.
And there are just a handful of states where that framework is coming into place. Gamoran, at Arcadia, pointed to Massachusetts as an example of a state that is “ahead of the curve” with its financial incentives for solar plus storage.
Policy isn’t the only driver, Gamoran said — in downstate New York, for example, a lack of real estate for large solar installations has led to a boost in storage-only projects — but it’s an essential one to scale, and it isn’t moving in the right direction everywhere.
In California, for example, the frameworks that community solar companies hoped would come to fruition this year have already fallen short of expectations.
In early March, the California Public Utilities Commission released a proposed decision on reforming rules for community solar projects, which represented its rejection of a net value billing tariff proposal. A group that included the Coalition for Community Solar Access was pushing for a model that would have, among other things, established minimum bill credits for subscribers and required projects to include a minimum four-hour storage system to help shift solar production into evening hours and iron out the state’s infamous duck curve.
CCSA’s position, which it outlined in comments filed last week, is that if the commission’s final decision rejects the net value billing tariff model and instead opts for a proposal put forward by the state’s utilities, fewer projects will ultimately be built in California. The state reportedly has the capacity to corner 19% of the national community solar market, but CCSA added that it would likely fail to meet that potential — Cramer said it might even end up building emergency gas plants at the end of the decade to meet the immense load growth to come.
Cramer said he remains hopeful that the final decision, which could be reached as soon as this month, will circle back to the net value billing tariff. But barring that, he added that the state could step in to create incentives.
“We are at an inflection point in distributed energy resource deployment, policy, and management, including community solar,” Cramer said.
The industry is going through “growing pains” in parts of the country, he added, but in places like the Northeast, where incentives are more aligned, community solar and utilities are working well together, and innovating around the potential role of projects to support the grid.
