Massachusetts Is Quietly Building a Software-Defined Energy Grid

In April 2026, the Massachusetts Department of Energy Resources filed a petition with the state’s Department of Public Utilities requesting a formal investigation into time-varying electric rates. On its face, this reads like routine utility regulatory procedure — the kind of filing that generates a handful of trade-press mentions before disappearing into a comment docket. It is not that.

What DOER has set in motion is the regulatory scaffolding for a fundamentally different kind of electric grid — one where the timing of energy consumption becomes economically meaningful, where residential batteries function as dispatchable capacity, and where software increasingly manages the physical infrastructure of electricity delivery. The target horizon is 2028. The implications extend considerably further.

To understand why this matters, it helps to understand how residential electricity pricing works today — and why that simplicity has quietly become an engineering liability at grid scale.

The Problem With Flat Rates

The overwhelming majority of Massachusetts residential customers pay a blended, largely static rate for electricity. Eversource and National Grid customers see per-kilowatt-hour charges that vary by season or tier, but not by hour. Whether a customer runs their dishwasher at 2 p.m. on a sweltering August afternoon or 2 a.m. on a mild October night, the commodity cost of that electricity looks roughly the same on their bill.

From a consumer standpoint, this simplicity is intuitive. From a grid operations standpoint, it is a significant mismatch between what electricity actually costs to deliver and what customers pay to consume it.

Electricity is not like natural gas stored in a pipeline or gasoline in a tank. It cannot be economically stored at grid scale, which means every megawatt-hour consumed must, at that moment, be generated. During periods of peak demand — hot summer afternoons, cold winter evenings — the grid must dispatch its most expensive, least efficient generation assets to balance supply and demand. Those costs are real. Under current rate structures, they are socialized across all customers regardless of when those customers actually used power.

Time-of-use rates change this. Under TOU structures, electricity is priced higher during peak demand windows and materially cheaper during off-peak periods. The DOER petition contemplates applying time-varying components across supply charges, transmission charges, and distribution charges — meaning TOU signals would run through the full stack of what Massachusetts customers pay. The spread between peak and off-peak prices creates, for the first time, an economic case for the average residential customer to care precisely about when they consume electricity — not just how much.

Why 2028 Is the Right Horizon

Regulatory filings don’t happen in a vacuum. The 2028 implementation target isn’t arbitrary — it’s pegged to the completion of Massachusetts’ Advanced Metering Infrastructure rollout, which utilities are expected to finish by the end of 2027.

AMI is the hardware foundation that makes dynamic pricing operationally feasible at residential scale. Traditional meters are read once a month by a utility technician or via drive-by radio signal. They record cumulative consumption; they have no concept of when that consumption happened. Smart meters communicate continuously, typically at 15-minute or hourly intervals, giving utilities granular consumption data and — critically — enabling the two-way communication necessary to send price signals and, eventually, direct control commands to customer devices.

Without AMI, utilities cannot bill TOU rates accurately. They cannot see whether a customer’s load shifted from 4 p.m. to 10 p.m. They cannot verify that a battery discharged during a peak event. The meter is the data layer, and TOU pricing is one of the first meaningful applications built on top of it. Massachusetts is completing that data layer first, and building the pricing regime afterward. The sequencing is correct.

What TOU Rates Actually Incentivize

The most direct read of time-varying rates is behavioral: utilities hope customers will run energy-intensive appliances — dishwashers, laundry machines, EV chargers — outside peak windows. Some customers will respond this way, and studies from other TOU deployments suggest meaningful load shifting occurs even with minimal automation. But behavioral response alone is not the core engineering value of the policy.

The deeper value is what TOU pricing does to the economics of residential hardware investment.

At today’s Massachusetts electricity prices — among the highest in the continental United States, ranging from approximately $0.28 to $0.32 per kilowatt-hour and higher — residential solar already pencils out in favorable roof and financing conditions. But solar generation peaks midday, and peak grid demand in New England typically runs from late afternoon through early evening. Without storage, a solar-equipped home’s ability to reduce its peak-period grid draw is limited.

Pair that solar with a battery — say, a Tesla Powerwall, Franklin Electric aPower, or Enphase IQ Battery system — and the calculus changes significantly under TOU pricing. The battery absorbs excess solar generation during cheap midday hours (or charges from the grid overnight at off-peak rates), then discharges during peak pricing windows when grid electricity costs the most. The spread between peak and off-peak rates is the financial return on the battery investment. In Massachusetts, where the absolute level of electricity prices is already high, meaningful TOU differentials could materially accelerate battery payback periods beyond what incentive programs alone achieve.

The same logic extends to EV charging. An electric vehicle with a 75 kWh battery represents a substantial discretionary load — discretionary in the sense that the timing of charging is flexible. Most EVs sit plugged in for eight hours overnight. Under flat rates, that charging happens whenever the owner plugged in. Under TOU pricing with managed charging software, the vehicle negotiates with the utility price signal and concentrates its draw in the cheapest overnight hours.

Why Massachusetts Is One of the Best Markets for This

The structural case for Massachusetts as a leading market for distributed energy systems is not primarily about policy ambition. It’s about the underlying engineering and economics of the grid the state operates within.

ISO-NE — the regional transmission organization managing the New England bulk power system — faces a distinctive set of constraints. The region is geographically isolated from neighboring grids by limited interconnections. Natural gas dominates its fuel mix, making it sensitive to winter gas supply constraints and pipeline capacity — a dynamic that produced the 2018 polar vortex price spikes and has driven sustained focus on winter reliability ever since.

Transmission within the region is additionally constrained. The practical result is that certain load pockets — eastern Massachusetts among them — face persistent congestion that raises locational marginal prices above regional averages. A residential battery in central Massachusetts is, from an ISO-NE perspective, potentially worth more than a battery in a less constrained grid region, because its discharge during peak events can reduce locational stress that expensive generation or imports would otherwise have to cover.

Add to this the state’s electrification trajectory. Heat pump adoption is accelerating, driven by state incentives and the economics of avoiding high natural gas prices. EV adoption follows one of the steeper curves in the country. Both technologies concentrate new electric load in ways that interact poorly with existing peak demand patterns — unless that load is managed intelligently.

ConnectedSolutions: The Early Infrastructure

Massachusetts is not starting from zero. The ConnectedSolutions program, administered through Eversource, National Grid, and Unitil, has been paying residential and commercial battery owners to make their systems available for dispatch during peak ISO-NE demand events since 2019. Enrolled battery systems agree to discharge to the grid or reduce home consumption during utility-called peak events, typically occurring on summer afternoons. Participants receive capacity payments based on their demonstrated performance.

ConnectedSolutions is, structurally, an early-stage virtual power plant. It aggregates distributed storage assets — scattered across thousands of residential addresses — into a controllable capacity resource. During a peak event call, enrolled batteries across the territory respond quasi-simultaneously, reducing aggregate demand on the distribution system and providing a measurable capacity service to the utility.

Forward-looking utilities now treat aggregated storage as non-wires alternatives to traditional grid infrastructure. A collection of residential batteries that can collectively discharge 15 MW during peak events can defer or eliminate the need for distribution substation upgrades that would otherwise cost tens of millions of dollars.

The Hardware Stack That TOU Unlocks

TOU pricing doesn’t just change the economics of batteries. It changes the value proposition of an entire ecosystem of residential energy hardware and software that currently operates without strong price signals to optimize against.

Smart panels — products from companies like SPAN and Lumin — add circuit-level intelligence to residential electrical systems. Under TOU pricing, circuit-level intelligence becomes directly monetizable: the panel can automatically shed discretionary loads — a pool pump, a second refrigerator — during peak pricing windows, reducing the home’s consumption cost without requiring any action from the homeowner.

Home energy management systems (HEMS) sit above individual devices, coordinating the behavior of the full distributed energy portfolio within a home. The TOU price signal is precisely the input a HEMS needs to do its job: knowing that electricity will cost $0.38/kWh between 4 and 8 p.m., the system can schedule the water heater to run at 2 a.m., pre-cool the house before the peak window opens, shift EV charging to the overnight valley, and dispatch the battery at the highest-cost hours.

The aggregation layer above individual homes is where the grid value compounds. DER aggregation platforms — software systems that enroll, monitor, and dispatch large numbers of distributed assets — turn a collection of individually small battery systems into a resource that can be bid into capacity markets, participate in demand response, or provide ancillary services.

The Future Home

By 2030, a well-equipped Massachusetts home might look like this:

This is not a speculative technology scenario. Every component described — solar inverters, residential batteries, smart thermostats, managed EV chargers, home energy management software — exists and is deployed at scale today in various markets. What Massachusetts is building is the price signal infrastructure that makes the optimization economically rational for the average customer, not just the early adopter.

Implications for Utilities, Contractors, and Developers

For utilities, the shift is profound. Distribution utilities have historically operated as passive infrastructure providers — maintaining wires and transformers, delivering whatever power customers demanded. The move toward TOU pricing, AMI-enabled real-time visibility, and DER aggregation repositions utilities as active orchestrators of a distributed system. The utility of 2030 increasingly needs software engineering, data science, and DER management capabilities that are orthogonal to traditional T&D operations.

For electrical contractors and solar installers, TOU pricing is a market accelerator. The economic case for battery storage has historically depended on backup power value, net metering economics, and state incentive programs. TOU spreads add a daily arbitrage value that doesn’t depend on utility programs or policy support. The pitch changes from “backup power and bill credits” to “financial optimization against time-varying utility prices.”

For real estate developers and building designers, TOU pricing creates a new variable in building energy system design. Energy performance will increasingly be measured not just in annual consumption but in peak demand management — a metric that TOU rates make financially explicit.

The Regulatory Path Ahead

The DOER petition initiates an investigation, not a rate change. The DPU process will involve utility filings, technical conferences, intervenor comments, and evidentiary hearings before any TOU structure is approved or mandated. The 2028 timeline reflects implementation readiness following AMI completion, not a date certain for TOU rates to appear on customer bills.

Several design questions will be resolved through the DPU process that materially affect the economic signals the eventual rate structure creates. The width of the peak-to-off-peak price spread determines how strong the behavioral and investment incentives are. The definition of peak windows, whether participation is opt-in or opt-out, and how TOU rates interact with existing low-income protections are not trivial design choices, and they will be contested.

But the direction is set. Massachusetts has committed to AMI infrastructure. It has explicitly filed to investigate time-varying rates. The technology ecosystem is mature and commercially available. The regulatory question is not whether Massachusetts moves toward dynamic pricing, but how that pricing is designed and at what pace.

The Grid Is Becoming Software

There is a useful way to think about what Massachusetts is building, borrowed from the technology industry: the electric grid is transitioning from a hardware-defined system to a software-defined one.

In a hardware-defined grid, infrastructure determines capability. Power flows from large generators through high-voltage transmission to distribution substations to end customers. The grid’s flexibility comes from spinning reserves, generator ramping, and demand response contracts with large industrial customers. Residential load is a passive, undifferentiated mass at the end of the wire.

In a software-defined grid, the physical infrastructure remains — wires still carry electrons, transformers still step voltage — but intelligence is distributed throughout the system. Every metered device is a data point. Every controllable load is a potential grid resource. Software manages the dispatch of distributed assets across thousands of nodes in real time, responding to price signals, reliability events, and market conditions faster and more granularly than any centralized control room could.

What Massachusetts is doing — methodically, through utility commission filings and AMI procurement schedules and demand response program design — is building that infrastructure layer. The DOER petition is a regulatory instrument, not a product launch. But the infrastructure it initiates will, over the next decade, restructure the economics of residential energy consumption in ways that reshape investment decisions, product markets, utility operations, and the physical character of the distribution grid.

Massachusetts is quietly laying the groundwork for a future where homes are no longer passive consumers of electricity, but active participants in a dynamic, software-managed energy market. The regulatory docket is open. The metering infrastructure is being built. The technology is ready. The economics are coming into alignment. What arrives on the other side is not the energy grid as it has existed for a century — it is something substantially different, and substantially more capable.