Massachusetts grid breakthrough could benefit customers while boosting solar

A pesky question has long stalled efforts to expand U.S. power grids in the face of growing demand and surging renewable energy: Who should pay for the upgrades?

An under-the-radar breakthrough in Massachusetts may finally provide a template for answering that question.

Over the past year or so, the state’s largest utilities and regulators have approved plans for dividing grid costs between customers and the companies that build solar arrays.

It’s been a long time coming. The plans in question have gone through numerous iterations since utilities, regulators, and solar developers started working on them about six years ago, making progress hard to track. And the name they settled on — ​“Capital Investment Projects,” or CIPs — isn’t exactly an attention grabber.

But behind the staid name lies a significant advance for a state striving to fairly allocate the costs of shifting to clean energy, said Kate Tohme, director of interconnection policy at Massachusetts-based community solar developer New Leaf Energy. In fact, advocates working on similar efforts in states from New York to California are ​“all trying to use the Massachusetts framework as a model,” she said.

The roughly $334 million in CIP grid projects from utilities Eversource and National Grid that have been approved or are being considered by regulators are doing something rare in the world of regulated utilities. Instead of forcing distributed solar and battery projects to pay up-front for grid improvements that allow them to connect to the utility system, the CIPs spread those costs onto customers’ future utility bills. Under the old system, clean energy projects regularly died on the vine because up-front grid costs were prohibitively high.

That doesn’t mean developers are getting a free ride, however. They’ll still have to pay a portion of those costs back as they’re connected to the grid, reducing the burden on customers over time. And every project in question had to prove to regulators that the grid improvements at large also deliver customer benefits, whether through improved grid reliability, enabling access to cheaper community solar power, or both.

Massachusetts can’t avoid these kinds of grid investments if it’s to meet its clean energy and electrification goals, according to Tohme, a former official at the state Department of Public Utilities who was directly involved in some of the earliest CIP work. The state has committed to cutting emissions 50% below 1990 levels by 2030, which will require building lots of renewable energy and electrifying vehicles and home heating.

“In the short term, it’s going to increase our costs,” Tohme said. But ​“once the grid is modernized and we get distributed energy interconnected, it’s going to drastically decrease our electricity costs” by replacing expensive fossil-fueled power with cheaper renewable energy and batteries.

Sharing costs to solve the solar logjam

The landmark plan emerged as a response to what might be seen as a clean-energy success story — Massachusetts had too much community solar trying to get onto an overly crowded grid.

“For a while, the cost to interconnect was tens of thousands of dollars, something a project could absorb,” said Mike Porcaro, director of innovative grid solutions at National Grid, one of the state’s largest utilities. ​“But eventually the modifications grew so large — hundreds of thousands or millions of dollars — that it was hard for projects to move forward.”

One of the best-established ways to relieve interconnection stresses is for utilities and grid operators to stop painstakingly studying each project one at a time and batch them instead. Such ​“group” or ​“cluster” studies of multiple projects seeking interconnection in a particular region allow utilities to conduct a speedier and more holistic assessment of the impacts they’ll cause and upgrades that will solve them.

It also allows grid-upgrade costs to be shared among the projects in the cluster, rather than foisting them on whichever project engineers determined would push that part of the grid over its existing capacity limit, thus triggering an upgrade, Porcaro said.

But the approach has its limits. ​“You’re still sharing the costs among that group,” he said — and forcing projects to pay even a portion of those costs up front can still make them too expensive to move forward.

National Grid and other utilities already plan ahead to accommodate growing electricity demand from customers or to serve big new developments like housing subdivisions or factories, Porcaro noted. The goal of the provisional system planning approach was to find a way to similarly pay in advance for proactive grid investments to bring community solar projects online.

“The review and discovery to get these CIPs approved was no small feat,” Porcaro said. ​“It wasn’t a quick decision.”

Figuring out a fair share

In late 2022, the Department of Public Utilities approved its first test case for CIPs — a cluster of projects put forward by utility Eversource, known as the ​“Marion-Fairhaven Study Group” after two of the Southeastern Massachusetts towns in the area being considered for upgrades.

Eversource estimated at the time that it would cost about $116 million in distribution grid upgrades to enable roughly 140 megawatts of community solar to connect to the grid. To avoid the chicken-and-egg problem of requiring projects to pay up front for the upgrades — something they couldn’t afford to do — Eversource proposed charging them about $370 per kilowatt of solar they connected once the grid work was done.

The risk of this approach is that some of the projects involved in the group study would end up dropping out, leaving customers on the hook for their unpaid share, Lavelle Freeman, Eversource’s vice president of distribution system planning, told Canary Media in a 2023 interview. That put the burden on Eversource to plan a grid upgrade that didn’t just make room for the solar projects but benefited customers as well.