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Massachusetts can reduce pressure to expand natural gas pipelines by cutting building heat demand, electrifying heating, using networked geothermal where it fits, managing peak electricity use, and making better use of existing transmission. These measures do different jobs: reducing gas use in buildings is not the same as ensuring enough electricity is available on the coldest days. The state’s planning still treats winter reliability as an open constraint.
Why there is no single pipeline substitute
A gas pipeline moves fuel to many customers; no single alternative replaces that function everywhere. Weatherization and heat pumps can reduce a building’s direct gas use. Demand response and storage can help balance the electric system as more buildings use electricity for heat. Transmission upgrades can move electricity more effectively across the region. Which mix works depends on location, building condition, winter peaks, cost, and the readiness of local electric infrastructure.
That distinction matters because replacing gas heating with electric heating shifts some energy demand onto the power system. A proposal that reduces gas consumption may still require electric distribution upgrades, new supply, or peak-management measures. Massachusetts’ Department of Public Utilities (DPU) has directed gas utilities to consider non-gas alternatives in relevant infrastructure planning and cost-recovery decisions under Order 20-80; it has not established one universally least-cost option.
Which alternatives can reduce demand for gas?
Improve building efficiency
Insulation, air sealing, and other building-shell improvements can reduce the amount of heat a building needs. That can lower fuel use and make a future heating-system conversion more manageable. Efficiency is a demand-reduction measure, not a stand-alone fix for regional gas supply or electric-grid constraints.
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Massachusetts energy-efficiency planning recognizes targeted efficiency and thermal-demand reduction. The DPU’s annual report on gas-system planning also identifies efficiency, behavior change, and market transformation among non-gas alternatives.
Electrify heating with heat pumps
Air-source and ground-source heat pumps can replace or supplement gas heating, reducing direct gas use at the building. Their suitability and customer economics depend on the building, local electrical capacity, installation costs, winter performance, and any backup heating needs. Those factors should be assessed for the specific property rather than assumed from a statewide claim.
Electrification can help reduce the need for gas infrastructure, but it increases electricity demand. Massachusetts’ energy planning therefore treats building electrification alongside grid readiness and system planning, rather than as a fuel switch with no electric-system consequences.
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Consider networked geothermal for suitable projects
Networked geothermal systems connect multiple buildings to a shared thermal network. They are a neighborhood- or project-scale planning option, not a simple appliance replacement. The DPU lists geothermal networks among the non-gas alternatives considered in gas investment planning, but the available state summaries do not establish where a project is feasible, what it would cost, or how quickly it could scale.
How can the electric system handle additional heating demand?
Manage when electricity is used
Demand response and load management encourage or enable customers to shift or reduce electricity use during high-demand periods. Managed electric-vehicle charging, virtual power plants, and microgrids are among the measures identified by Massachusetts. Their contribution depends on when resources are available, how reliably they can be dispatched, customer participation, and program design.
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In an executive order dated March 16, 2026, Massachusetts set a target of 3.5 GW of new electric-demand reduction through measures including efficiency, virtual power plants, microgrids, managed EV charging, and demand response. This is a target, not a report of reductions already delivered. The state’s April 2026 Peak Potential reports address load management as part of affordability and net-zero-grid planning.
Use storage and flexible resources
Storage can shift electricity across time, while flexible demand can reduce or move consumption during system peaks. These tools can complement heat pumps and clean generation; they do not directly reduce the amount of gas a particular building burns unless paired with measures that change that building’s heating demand.
Make existing transmission work harder
Advanced transmission technologies can improve use of existing electric infrastructure and complement new clean supply and storage. They address the movement of electricity, not building gas consumption. Massachusetts DPU’s 2025 reporting cites an ISO New England 2050 Transmission Study projection that regional transmission-grid investment could reach $26 billion by 2050. That is a regional estimate reported by the DPU, not a Massachusetts-only spending forecast.
What winter reliability evidence says about gas today
Massachusetts has not declared that non-pipeline measures have eliminated the region’s need for gas during winter peaks. The state describes the Everett Marine Terminal as supporting Massachusetts and New England on the coldest days or during disruptions. The March 2026 executive order says Everett can provide up to 10% of New England gas on the coldest days; that figure describes peak conditions, not an annual share. The order also frames gas as serving critical sectors and regional electricity generation.
A state work group assessed options for reducing and ultimately eliminating local distribution companies’ reliance on Everett LNG. At the same time, contracts held by the three largest gas utilities maintain use through 2030. These facts make the distinction important: a transition plan can reduce reliance over time without proving that current winter reliability needs have already been resolved.
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How to compare proposals in a town or utility service area
There is no supported statewide ranking that says one option is always cheapest or sufficient. A local comparison should evaluate the same measures against the same conditions, including a severe winter peak.
- Peak reliability: How much deliverable capacity does the option provide when and where demand is highest?
- Full costs and who pays: Include capital and operating costs, customer bills, conversion costs, and the effects on customers who remain on the gas system as others leave.
- Electric readiness: Can local distribution infrastructure support new heating loads, and what upgrades or flexible resources would be needed?
- Timing and suitability: How long will implementation take, and which buildings, neighborhoods, or utility areas can use the option?
- Emissions: Consider the relevant electricity mix and operating conditions rather than treating electrification as having identical emissions in every circumstance.
The DPU’s annual report flags affordability concerns, including conversion costs and cost shifting between customers who leave and those who remain on gas. Massachusetts law also calls for electric planners to consider alternatives to proposed investments, including rate design, load management, flexible demand, and dispatchable demand response. These rules make alternatives part of planning; they do not by themselves show which project will perform best in a particular place.
What a credible non-pipeline plan should show
A credible plan should connect building measures to system needs instead of counting them as interchangeable solutions. It should specify how much gas demand efficiency or electrification is expected to reduce, what winter peak conditions it addresses, and what electric supply, distribution capacity, storage, or demand response would support the change. It should also identify costs and how they fall on customers who convert and those who stay on gas.
That level of local evidence is necessary to judge whether a proposed pipeline expansion can be reduced, deferred, or avoided. Massachusetts’ policy requires consideration of non-gas alternatives in relevant planning contexts, but the available statewide summaries do not establish a universal least-cost answer for every municipality, building, utility zone, or winter peak.
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