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In western Illinois, ComEd is tapping a rarely used technique to fast-track community solar installations — working with, not against, environmental groups and solar project developers.
For years, utilities have explored the concept of flexible interconnection, in which solar projects are allowed to come online even when, by the books, there’s not enough space on the grid for these arrays. In return, these solar farms must promise to curtail output during the handful of hours each year when their production would overwhelm power lines and substations.
Flexible interconnection is a speedy way to get cheap new solar online without requiring utilities to spend even more on costly grid upgrades, which are a key driver of the nation’s fast-rising utility bills.
But U.S. utilities haven’t made use of the technique at any significant scale — until ComEd got its program off the ground late last year.
Since then, the utility has fast-tracked more than 50 megawatts of community solar projects using flexible interconnection, and more are likely to be approved before federal tax credits sunset in July.
That’s much faster than utilities in other states have been able to move on flexible interconnection, said Samantha Weaver, senior director of interconnection and grid integration policy at the Coalition for Community Solar Access, a trade group representing community solar developers. In fact, ComEd is “leading the country right now,” she said.
ComEd plans to accelerate that work, said Jessie Bauer, the utility’s senior manager of smart grid and innovation. “Our plan was to do 50 megawatts a year, and we’re hitting that cadence,” he said. “We’re proposing in our grid plan to go even faster, and do 100 megawatts a year, and get to 650 megawatts by 2031.”
The utility has previously committed to deploying 240 megawatts of distributed energy capacity by 2030 to meet its requirements under Illinois’ landmark 2021 climate law.
ComEd was able to succeed where other utilities haven’t thanks to a nudge from regulators that spurred it to collaborate with solar developers and environmental groups.
Historically, utilities and solar developers have struggled to establish the basic mutual trust required to move a flexible interconnection program forward, Weaver said. Utilities are often skeptical that solar farms will reliably cut back as promised during those key hours of potential grid overload. Meanwhile, solar developers suspect utilities will force them offline more than is absolutely necessary.
Illinois’ flexible interconnection process didn’t go that way.
Instead, in 2024 ComEd collaborated with environmental groups represented by the consultancy Eclipse on a flexible interconnection plan. Then, the utility worked out mutually agreeable solutions with those groups, solar developers, and the nonprofit collaborative the Charged Initiative, in a series of workshops that resulted in a program design that gave each side enough of what they needed to move ahead.
Both the utility and solar developers had to make some compromises, Weaver said. But that effort bore its first fruit last November, when 27 megawatts of community solar was green-lit in a region where it would have been excluded by traditional processes. Another 25 megawatts of projects were approved in February.
This coordinated approach is now gaining some momentum in Maryland, Massachusetts, New York, and other states where community solar is struggling, said Nikhil Balakumar, Eclipse’s CEO and founder.
“Now, more than ever, especially in this climate, we need unprecedented collaboration,” Balakumar said. We can’t just slog it out and fight and litigate every little thing till the end of time. There has to be a new way forward.”
ComEd’s push into flexible interconnection was less a choice than a necessity.
Since 2016, Illinois has created and expanded programs that offer lucrative incentives to build community solar projects, which are generally limited to no larger than 5 megawatts. Households can subscribe directly to these projects, which often allow them to lock in cheaper, cleaner energy. The state’s programs are explicitly meant to reduce utility rates for low-income customers.
In Illinois, developers have flooded into the programs over the years, snapping up the most suitable land for community solar arrays.
This posed a problem for ComEd: Everyone wanted to build their solar arrays in the same relatively concentrated geographic area — the rural western reaches of its territory — where there simply wasn’t enough space on the grid.
“We quickly saw all that grid capacity evaporate with the community solar being connected,” Bauer said.
In a situation like this, the standard utility playbook is to require community solar developers to shell out for grid improvements. In western Illinois, that would mean multimillion-dollar system upgrades, he said — a cost that few solar developers can afford.
However, the grid actually does have the space to accommodate those solar farms — at least, most of the time.
Distribution grids are built to serve the times when electricity demand is at its highest. These peaks in demand are relatively rare, happening only during a handful of hours per day, or days per year. That means for the vast majority of the year, there’s unused capacity sitting there.
Flexible interconnection takes advantage of this fact — and helps developers and consumers avoid exorbitant grid upgrade costs as a result.
“If you can give up some of your energy during times of system constraints, you can interconnect much more affordably,” Bauer said.
But this is easier said than done. Utilities can’t perfectly predict how often demand will peak. They need flexibility to handle unexpected changes and respond to emergencies. A major storm or flood could knock out an entire substation for months, leaving other parts of the grid straining to supply power until it’s repaired.
That uncertainty constrains utilities from setting guaranteed limits on how often they’ll ask solar projects to curtail their generation. But for solar developers, “projects aren’t financeable if curtailment is unpredictable,” Weaver said. “We need certain details to be able to literally take to the bank.”
To resolve this conundrum, ComEd and solar developers collaborated on a compromise.
Solar developers calculated that they — and their investors — could bear having about 5% of their annual solar production curtailed. They conceded that ComEd couldn’t guarantee it would stick to that curtailment limit. But if the utility was willing to share historical data on how often its grid was likely to face overloads, developers could use that to convince those investors that the risk was worth taking.
That wasn’t the solar industry’s initial ask, Balakumar noted. Solar developers started out asking for “some sort of fund that compensates us if you do go over 5%,’” he said. But ComEd pays for the power it purchases by passing those costs on to its customers — and the prospect of charging customers for power that didn’t actually get onto the grid was a nonstarter for consumer advocates and regulators.
“We went in wanting a guarantee,” Weaver said. “But we came to the understanding that that wasn’t realistic and that we needed to give up a degree of certainty.”
Nor was it easy for ComEd to agree to sharing confidential data on its substations. Bauer said that process was helped along by community solar developers limiting what data they needed and how they would use it.
Already, the real-world data coming in from ComEd’s flexible interconnection projects could allow it to tighten curtailment expectations for future rounds of development, Bauer said. That could make community solar projects more lucrative to financial backers — and given that the alternative was to not be able to build them at all, or to wait for years for utility grid upgrades to plug them in, that’s better than nothing.
Regulated utilities like ComEd earn profits from the investments they make to expand or upgrade their power grids, not from connecting third-party solar projects. If anything, flexible interconnection exposes them to grid instability risks. Meanwhile, sharing data on how efficiently they utilize their grids can weaken the case for investing in moneymaking upgrades.
But in Illinois, policymakers and regulators forced ComEd’s hand.
Under the 2021 Clean Energy Jobs Act, ComEd and fellow utility Ameren Illinois must invest in their grids to improve customer affordability and meet state climate and clean energy goals. In 2023, the Illinois Commerce Commission rejected the initial grid modernization plans filed by ComEd and Ameren Illinois, because of critiques including an absence of commitments to streamline interconnection of distributed energy resources like community solar systems.
That’s when Eclipse started working with the Environmental Law and Policy Center, the Environmental Defense Fund, the Natural Resources Defense Council, the Union of Concerned Scientists, Vote Solar, and other groups to get ComEd to the planning table, Balakumar said. The following year, these groups agreed to a memorandum of understanding with ComEd, which led to the joint plan submitted to regulators in late 2024.
ComEd then set up that workshop series with solar developers and environmental advocates over the course of 2025. That’s where parties hashed out their positions and came up with compromises that they could live with, Weaver said.
“To give credit where credit is due, the utility came with a lot of information and proposals they’d developed in advance for developers,” she said.
That included detailed information on the capabilities — and limits — of the utility’s technologies to make flexible interconnection possible, Bauer said. For example, one solar developer asked for hour-ahead forecasts of when the utility would curtail projects, he said. “We can do that in the future — in fact we plan to,” he said. But if ComEd had been forced to wait until it could warn solar projects that they would be curtailed an hour in advance, “we wouldn’t have launched this year — we would have launched in a year or two.”
ComEd also chose not to immediately incorporate all the different distributed energy resources that state law requires it to eventually handle, he said. “We were deliberate and focused on community solar, because we recognized that those were not only where the need was, but because those are the most technically sophisticated customers.”
The flexible and collaborative approach that ComEd and solar developers have undertaken stands in contrast to some much slower processes in other states. In California, for example, it took nearly four years between regulators ordering utilities to make flexible interconnection possible and finalizing the rules that allow it to happen — and California still hasn’t created a workable community solar program to make use of those rules.
But speed is of the essence as community solar developers rush to start their projects before July. That’s the deadline for achieving “safe harbor” status for earning tax credits set by the massive tax and spending package passed by Republicans in Congress last year. “Because of these changes happening in the tax credits, we realized we needed to move faster,” Bauer said.
Balakumar agreed that “to go from March workshops to a full-blown program in November for a utility is lightning speed.” But regulators and utilities in states with clean-energy and climate goals that haven’t moved as quickly are setting themselves up for even greater costs — and arguments over who’s going to pay for them — once the window for securing federal tax credits has closed, he said.
That’s not to say that other states can’t still learn from Illinois, he said. Take New York and Massachusetts, two states where Eclipse is closely involved in flexible interconnection work.
“We were in workshops in New York with Avangrid and National Grid,” two utilities serving upstate regions with a lot of community solar and grid constraints, Balakumar said. There, solar developers are “talking to banks and thinking about how they can get much more creative.” In January, National Grid filed a proposal to enable flexible interconnection at seven substations, each potentially hosting 30 to 60 megawatts of new projects.
And in Massachusetts, where utilities have struggled for years to connect more community solar projects, Eclipse has been involved in a workshop jointly hosted with a state regulator–created interconnection working group, with the goal of jointly filing flexible interconnection proposals with National Grid and Eversource “as soon as possible this year,” he said.
Those utilities are actively expanding their grids to accommodate more community solar. But flexible interconnection could allow many projects to connect while deferring $239 million in proposed upgrades, Balakumar said in November 2025 testimony in a proceeding reviewing new grid investment proposals.
In March, ComEd engineers came to a Massachusetts flexible interconnection workshop to share their experience, according to Nick Burica, senior director of grid planning and interconnection engineering at community solar developer Nexamp.
Utilities have plenty of reasons to be leery of requests to operate their grids in this new and unfamiliar way, noted Burica, who previously led development of distributed energy engineering for ComEd. But when those kinds of objections arose, ComEd was “in the room,” able to say that “it will provide energy affordability, and you’ll be able to operate your system better,” Burica noted.
“I was so happy to see ComEd come out and champion what can be done with flexible interconnection,” he said. “Getting people together — industry, utilities, and outside consultants — we’re starting to see the fruits of this labor.”
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