PJM has finally greenlit a lot of new clean power. Can it get built?

The country’s biggest energy market has a problem: It can’t build enough power plants to keep up with electricity demand.

For PJM Interconnection’s 67 million customers across 13 states, the consequences are ever-higher utility bills. For PJM itself, it’s unrelenting political pressure, from blue-state lawmakers on up to President Donald Trump.

The situation has spurred many proposed solutions, including Trump’s prescription that PJM should simply ​“build big power plants again,” specifically, coal, gas, and nuclear. State lawmakers have, for their part, focused on trying to limit the development of increasingly unpopular data centers.

Any projects that haven’t yet secured these kinds of interconnection rights are going to have to wait years more for PJM to determine whether they can be plugged into the grid. That makes the power plants that have already won interconnection agreements the only options to be “ deployed fast enough to do something before 2030,” said Nikhil Kumar, a program director for GridLab, an energy analysis nonprofit. ​“Everything beyond that is speculative, both on the load front and on the generation front.”

And now that these projects are finally approved for interconnection to PJM’s grid, it’s up to states and their utilities to actually get steel in the ground. 

“State governors need to force their utilities to help get more generation online,” Kumar said. ​“There’s no two ways about it.”

Although natural gas power plants dominate new interconnection-queue applications and emergency fast-track applications in PJM, the vast majority of projects with approvals in hand are solar, wind, and batteries, per data from think tank RMI. 

These new clean energy projects could help rein in costs. A May report from Aurora Energy Research commissioned by RMI found that adding 5 GW of solar and 5 GW of wind in PJM by 2028 could save utility ratepayers a combined $10.9 billion over a decade.

But an interconnection agreement is no guarantee. Before a developer can get to work, utilities have to complete the necessary grid upgrades. States and localities have to issue permits. Developers also need to secure financing — a task that’s made much easier if they can sign contracts to sell their power.

Projects can drop out at any point in this process. In fact, 41% of U.S. projects that signed interconnection agreements from 2000 to 2022 eventually withdrew, according to 2025 data from Lawrence Berkeley National Laboratory.

These issues are beyond the grid operator’s control. Once PJM has issued interconnection agreements and identified necessary grid upgrades, those projects ​“are done with our process and are free to connect,” said PJM spokesperson Jeff Shields. ​“We would love to see all those projects get built, but we don’t have the authority to make it happen.”

Getting grid upgrades built on time

Once a developer gets an interconnection agreement, they’re on to the next step: paying for the grid upgrades their project requires.

Even though these upgrades are particularly expensive in PJM, cost is not the only hurdle at this stage. There’s also the matter of getting utilities to actually make upgrades in a timely manner.

That’s according to David Mindham, senior director of regulatory and market development at EDP Renewables North America, one of the country’s largest clean energy developers.

Utilities must build local ​“spur lines” and substations to bring new power plants online. Almost all projects also trigger more investments deeper into the high-voltage transmission system. And in Mindham’s experience, ​“utilities want several years to build simple network upgrades.”

Indeed, interconnection upgrades by utilities in PJM were far more likely to be delayed past their scheduled completion date than other types of grid projects, according to an analysis of PJM project construction data shared with Canary Media by Halcyon, a startup that uses AI to analyze utility and energy datasets.

Why the delays? Abraham Silverman, an energy researcher at Johns Hopkins University who co-authored a 2024 report on PJM’s interconnection challenges, had an explanation: Utilities ​“don’t prioritize network upgrades because they don’t get to roll them into rates.”

Utilities earn regulated profits on their capital investments. In the PJM region, utilities have focused the lion’s share of grid spending on projects that undergo relatively little regulatory oversight, like upgrading existing lines, in order to maximize those profits. Given the choice, utilities are likely to prioritize scarce grid equipment for moneymaking projects, not those that developers are paying for, Silverman said.

State policymakers and regulators could take on these delays. A 2025 analysis from RMI and the National Caucus of Environmental Legislators proposed several policy interventions, such as requiring utilities to share data on network-upgrade timelines and holding regulatory hearings to justify lags.

But deadlines won’t speed things up unless utilities face consequences for blowing them, GridLab’s Kumar said. ​“The only way you change this scenario is to have the governors tell the utilities to get these solar and battery projects online,” he said. ​“There should be penalties, or some strict deadlines, on meeting certain milestones. Simply requesting it is not going to work.”

Streamlining permitting

States have another big lever to pull: They can streamline environmental reviews, state and local siting requirements, zoning and land-use approvals, and other processes that fall under the broad term of ​“permitting reform.”

It’s a messy subject. Local opposition to clean energy projects is rising in rural areas where solar and wind tends to be built, and any state efforts to push projects through could trigger drawn-out legal challenges.