Eversource is moving beyond broad demand response programs
Eversource has launched two targeted pilot programs in Massachusetts that reflect a broader shift in how utilities are preparing for a grid shaped by electrification, localized congestion, and growing amounts of distributed solar. Rather than relying only on systemwide demand response, the company is testing geographically focused programs designed to solve problems at specific substations and at specific times of day.
The pilots, announced June 25 and now live, are extensions of Eversource’s ConnectedSolutions approach. One program in the Greater Boston area is aimed at reducing stress during summer heatwaves in places where the utility expects above-average loading. The other, in southeastern Massachusetts, is designed to encourage charging during midday periods when excess solar production is available.
That distinction matters. These are not generic efficiency campaigns. They are operational experiments in matching flexible customer devices to very local grid conditions.
Two pilots, two different grid problems
The Greater Boston pilot uses the ConnectedSolutions+ label and is focused on capacity stress. Eversource says it will recruit eligible stationary batteries, electric vehicles, building management systems, and smart thermostats from homes and businesses in targeted areas. The purpose is to reduce strain in places where summer peaks can create congestion during periods of extreme heat.
The pilot is open to customers served by the Alewife, Hyde Park, and Dewar substations, covering parts of Cambridge, Milton, and south Boston. Events can be called from June through September, which aligns with the period when hot weather-driven demand is most likely to push local equipment toward heavy utilization.
The southeastern Massachusetts pilot, Managed Charging+, addresses a different challenge: what to do with periods of high behind-the-meter solar generation. Instead of asking customers to pull back during peaks, the program encourages them to charge stationary batteries and electric vehicles during midday windows when solar output is abundant.
Together, the pilots illustrate the two-sided balancing act utilities increasingly face. At some moments the problem is too much demand in the wrong location. At others it is how to absorb abundant distributed generation without wasting flexibility.
Why this matters now
The timing is not accidental. Utility Dive reported the pilots went live as southern New England was under an intense heat dome, and ISO New England forecast 478,450 MWh of net load for July 2, among the highest daily readings of the decade. That gives the programs immediate real-world relevance rather than leaving them as paper exercises.
The longer-term rationale is structural. Eversource is effectively preparing for two trends that planners expect to intensify over the next several years:
- Electricity demand is expected to rise as buildings and transportation electrify.
- Distributed solar is expected to keep expanding, creating larger swings in net load and more localized operational challenges.
ISO New England has said the region’s wintertime behind-the-meter solar production could reach 6.5 GW by the late 2030s. That figure helps explain why a utility would want more precise control over when flexible devices charge, discharge, or reduce load. A grid with more rooftop and small-scale solar needs more than bulk generation planning. It needs orchestration at the edge.
From consumer devices to grid assets
One of the clearest signals in these pilots is that devices once treated mainly as customer conveniences are being recast as grid resources. Smart thermostats, EVs, home batteries, and building automation systems are no longer peripheral tools in utility planning. They are becoming dispatchable assets that can be called on to relieve constrained substations or soak up surplus local generation.
Eversource hopes to enroll about 2,800 devices in the two pilots, with most in the Greater Boston ConnectedSolutions+ program. That is not a massive fleet, but the point of a pilot is not scale for its own sake. It is to test whether more granular targeting produces better operational results than broad, one-size-fits-all programs.
If the answer is yes, the implication is significant. Utilities may increasingly segment demand flexibility not just by device type, but by feeder, substation, neighborhood, and time-of-day conditions. That would mark a more sophisticated stage of distributed energy management, one in which local signals become as important as regional ones.
A preview of more localized grid management
The pilots are expected to generate data this year, and Eversource anticipates continuing and potentially expanding them through 2029. That suggests the company sees them as part of a development path rather than a one-season test.
What utilities learn from such programs could shape future program design in several ways:
- Compensation models could become more location-specific, rewarding flexibility where it has the most grid value.
- Managed EV charging could shift from simple off-peak incentives to solar-aligned and distribution-aware schedules.
- Grid planning could rely more heavily on customer-sited resources as non-wires alternatives to traditional infrastructure upgrades.
- Utilities could build more automated, event-driven control systems across homes and businesses.
There are still open questions. Customer participation can be uneven, device interoperability remains a challenge, and targeted programs are more complex to explain and administer than broad seasonal incentives. The pilots also need to prove they can deliver measurable relief where constraints are most acute, rather than simply adding another layer of program administration.
But the direction is clear. Utilities are under pressure to handle rising electrification load without overbuilding infrastructure, while also integrating growing volumes of distributed solar. That combination favors flexible demand and storage, especially when they can be deployed surgically.
Eversource’s pilots are notable not because they solve every part of that problem, but because they show how utilities are starting to operationalize distributed flexibility at a more precise level. In one neighborhood, the right move may be to curb demand on a sweltering evening. In another, it may be to encourage charging when rooftop solar is flooding the system around noon.
That is a more dynamic model of grid management than the one many customers are used to. It is also likely to become more common. As the electric system decentralizes, utilities will need tools that can respond not just to how much electricity is being used, but where, when, and under what local conditions. These Massachusetts pilots offer a concrete look at that transition in progress.
This article is based on reporting by Utility Dive. Read the original article.
Originally published on utilitydive.com
