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Community and commercial solar projects—typically between 2 and 10 megawatts—play a critical role in the clean energy transition. These mid-size systems can bring clean, affordable electricity to schools, farms, apartments, and local businesses. But across the country, many of these projects are hitting the same roadblock: they can’t connect to the grid without triggering multi-year delays and costly utility upgrades.
These aren't large-scale transmission-connected solar farms. Most are designed to connect at the distribution level—feeding power into local circuits that were originally built to serve demand. Yet even modest backfeed from a solar project can trigger a rejection under current interconnection rules.
There’s a better way forward. Flexible interconnection offers a faster, more collaborative path that lets utilities protect the grid—while allowing solar projects to move ahead today.
The main challenge comes down to how distribution utilities screen solar projects for grid impacts. Most rely on a simple point-in-time comparison: they look at the lowest hourly load from the previous year, then compare it to the maximum rated output of the proposed solar array. If the solar output could exceed local load—even for a single hour—the project is flagged as a backfeed risk and often sent down a long path of upgrade requirements.
In most cases, the concern is backfeed: excess solar energy flowing upstream onto the grid, which can interfere with legacy protection systems designed for one-way power flow. In rarer cases, the backfeed can be large enough to overload equipment in reverse, such as when a 10 MVA substation transformer is hit with 11 MW of net export.
While these concerns are real, the methods used to identify them are blunt. Many feeders are only at risk of backfeed for a few hours each spring or fall, when solar output is high but local demand is low. Yet today’s interconnection processes treat them as constant threats.
This isn't just about cautious engineering—it’s about tools. Most utility planning systems can't rapidly simulate hourly generation and loading over the course of a year. As a result, the industry has defaulted to overly conservative assumptions, even when more nuanced approaches are available.
Flexible interconnection changes the equation. Instead of assuming that solar will export at full output during all hours of the year, it allows projects to connect now—with a commitment to reduce output only during the few hours when constraints occur.
At the planning stage, developers submit a typical 8760-hour generation profile for the project. Camus overlays that profile with loading data from the past year—sourced from utility systems or low-cost sensors—to simulate how the solar would interact with the grid over time. The analysis identifies which hours would result in backfeed or exceed equipment ratings, and provides a clear estimate of expected curtailment: both in terms of percent of annual energy and total MWh. We've included a quick interactive demo of this analysis below.
These curtailment estimates are crucial for developers. They can be incorporated directly into pro formas, giving project teams and financiers a clear sense of how much generation might be affected and when.
Once the system is connected, utilities issue operating limits to the project based on either season, time of day, or real-time grid conditions. These limits are delivered to an on-site energy management system or directly to the inverter, ensuring that generation is adjusted to stay within safe limits during constraint hours—without requiring constant oversight.
There are two primary ways to implement flexible interconnection. In the developer-led model, the solar project manages its own curtailment using local controls, while providing the utility with visibility into system output. This model is faster to deploy and avoids potential friction around curtailment signals from the utility, since the developer maintains control of the system’s behavior.
Alternatively, the utility-led model involves direct integration with the utility’s DERMS platform. The utility dispatches operating limits to the inverter, ensuring alignment with broader grid operations. While this model can be more familiar to utility staff, it may take longer to implement and requires more coordination between the utility and the developer.
In either model, utilities will likely require a failsafe mechanism—such as a recloser or disconnect—to be in place as a last resort. This isn't used for routine control, but serves as a critical safety measure if the site exceeds agreed limits and puts grid reliability at risk.
Flexible interconnection helps developers avoid the two biggest pain points in today’s process: long delays and expensive upgrades. By enabling faster interconnection—often 2 to 4 years faster—it allows projects to begin generating revenue and delivering local clean energy much sooner. And by avoiding upgrades, developers can reduce upfront costs and risks.
Equally important, curtailment is typically very low. A recent demonstration by Rochester Gas & Electric found that while pre-project estimates forecasted curtailment at 0.27% of annual energy, the actual curtailment was just 0.00049%. And because the constrained hours often coincide with lower market value periods, the impact on project economics is even smaller.
The load profile for many utility substations look similar to the example above. The blue lines show historical net load for a 10 MVA, winter-peaking substation. Loading drops down to ~1 MVA in the spring. A traditional static solar interconnection would therefore be limited to 1.0 MW rated capacity. A flexible interconnection, however, would usecurtailment to avoid backfeed (occuring when blue and red lines overlap). For a 3 MW system, flexible interconnection would only require an estimated 1.1% total curtailment (or 67 MWh of the total ~6,200 MWh generated). The 3x increase in capacity for ~1% total curtailment is a tradeoff that many developers would be eager to make.
These curtailment hours—typically during mid-day in the spring and fall—also align well with solar-plus-storage strategies. By charging a battery when export is limited and discharging later, developers can mitigate curtailment entirely. In fact, flexible interconnection may become a major driver of battery adoption, allowing solar projects to maintain full output and tap into additional grid services without requiring upgrades.
Flexible interconnection is no longer hypothetical. Utilities like PG&E, National Grid, Avangrid, Southern California Edison, and RG&E are actively piloting or implementing programs that use flexible operating limits to connect solar and storage more quickly.
Regulators are getting involved as well. Illinois and Minnesota are both exploring frameworks to support broader adoption, creating more certainty and consistency for developers and utilities alike.
And the concept isn’t limited to pilots. In Australia, more than 2.9 million export customers are participating in a two-way energy system, enabled by dynamic export limits and flexible interconnection practices.
Flexible interconnection isn’t just a technical upgrade. It’s a mindset shift—one that sees solar not as a static burden on the grid, but as a dynamic, responsive resource. It’s also a collaboration model, bringing utilities and developers to the table with a shared goal: get more clean energy online, faster.
At Camus, we’re helping both sides make this shift. By simulating 8760-based impacts and enabling real-time constraint monitoring, we help unlock grid capacity that would otherwise sit unused. And by supporting both developer- and utility-led implementations, we make it easier to move from theory to deployment.
If you have a project stalled in queue—or you’re tired of waiting on utility infrastructure upgrades—we’d love to talk. Let’s find a faster, smarter path—together.
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