In 2022’s Inflation Reduction Act (IRA), the Biden administration put forth the goal of generating 80% of U.S. electricity without fossil fuels by 2030 and eliminating those sources entirely by 2035. Since then, we’ve learned how challenging meeting these targets will be, given the difficulty of adding new solar panels, wind turbines and batteries to local grids. A new approach to the agreements signed between power developers and utilities could help ease some interconnection bottlenecks and get more carbon-free electricity flowing soon.

When thinking about renewable energy projects to meet the IRA’s goals, we often focus on large, utility-scale installations that require hundreds of acres—or more, in the case of wind power. But smaller commercial- and community-scale projects also provide a substantial percentage of the nation’s carbon-free electricity. 

Connections problems

However, getting these projects, which typically top out at 1 or 2 megawatts (MW), connected to local utility systems is challenging. They’re often planned for locations in the middle of a grid where existing infrastructure wasn’t designed to host power generation and distribution. So, there can be concerns that introducing new power sources into a system could overload wires and transformers during high-demand periods. This is why utilities require developers to pay for upgrades to address these risks, and those costs can be deal-breakers.

This isn’t entirely the utilities’ faults. Their grids might be over a century old and have grown over time. Understanding what effect a new 1-MW rooftop solar system will have on local transformers or switching equipment can require expensive and time-consuming studies. As a result, they might simply require developers to upgrade utility equipment to ensure the added power won’t affect system performance during all worst-case scenarios, including during high-temperature, high-demand days when wires might already be stressed.

These interconnection challenges stand in the way of $7 billion of new IRA investments in community solar projects targeted to serve low-income ratepayers. State programs get swamped by applications within days of announcing new opportunities, and those applicants are facing years-long queues for utility interconnection approvals.

In part, this is due to applicants’ lack of knowledge of where capacity exists in the local utility’s grid to add new distributed energy resources (DERs). As a result, many developers submit multiple applications in hopes that one might pan out. This floods program inboxes further with applications for projects that stand no chance of getting built. Several states, including California, Massachusetts, Minnesota and Oregon, now require utilities to publish monthly hosting-capacity maps to help identify high-opportunity locations and weed out projects with problematic sites.

Interconnection assumptions

Another new approach addresses the basic assumption of an interconnection agreement: developers should be able to prove their project, when producing at its maximum capacity, will pose no risks to utility operations, even during demand peaks. Novel, flexible interconnection agreements allow power producers to address this concern by curtailing their output when utility lines are overburdened. If the money lost to curtailment is less than the cost for upgrades, these contracts can make financial sense for developers.

In California, “limited generation profiles” developed for each project outline how much power they’ll add to the grid. The profiles are developed using the detailed hourly models state utilities must produce for each node on their distribution systems. This is a unique requirement for U.S. utilities, so California’s approach might not be generalizable in other states. In New York, for example, Avangrid has been testing new DER management system software to control connected DER output in real time, matching it to actual grid conditions.

In the short term, flexible interconnection agreements could certainly help speed time to market for smaller-scale solar developers that could see fair value in losing, say, 5% of their production, versus paying millions in utility system upgrades. But they also might just be buying time for utilities and DER owners to work out more durable solutions. 

As whatever excess carrying capacity a utility network has gets used up through these contracts, adding more DERs will become even more difficult. At some point, upgrades will need to be made. However, these new contracts are just one tool utilities and their regulators are using to accommodate more local renewables. Combining the contracts with technologies like dynamic line ratings that monitor and adjust to real-time grid conditions could push needed upgrades off until years in the future.

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