Planning for a Changing Gas System
The gas system will serve customers for years as more buildings move to electric heat. Decisions made now will shape what that transition costs and who pays for it.
What history can teach us
Gas utilities have adapted to major changes before. Electric lighting displaced one of their main markets. Pipeline gas replaced local gas production. More recently, cheap domestic gas undermined investments in imported LNG. Each change required decisions about infrastructure that people still depended on, even as its future became less certain.
Electric lighting changes the gas business
When electric lighting arrived in the late nineteenth century, gas companies faced a new competitor. They responded with improvements of their own. The incandescent gas mantle made gas lighting brighter and more efficient, helping it compete as electric networks expanded. For years, customers used both systems.
Natural gas replaces local production
New England utilities once manufactured gas locally from coal. Some were still making substantial investments in those plants just before natural gas became available by pipeline. Springfield Gas Light Company, for example, spent roughly $2.5 million on plant upgrades between 1947 and 1949.
At the same time, the supply system was changing. The Big Inch and Little Big Inch pipelines, built during World War II to carry oil and petroleum products, were sold in 1947 and converted to carry natural gas. Utilities in the Northeast began preparing to replace manufactured gas with pipeline supplies. The federal engineering history documents that conversion.
The change reached into every customer’s home. Appliances had to be adjusted before a neighborhood could receive the new fuel. John Bacon, a former president of Boston Gas, recalled the work:
"We bought a company from the South. They were good at it. They had these trucks with lathes and machine shops, and they went from house to house and did the work. They hit Boston of course, which had some of the oldest appliances in the country. And we had to alter every range, every water heater, every single appliance. If we couldn't get to a house on the list, we'd keep trying to get in it, until the end when we'd connect an area. If the houses weren't converted, they were cut off. We had a couple of situations where he had to break in to get the appliances converted. We'd get a permit from the city, and we'd have an officer with us, and we'd go there and make things work."
— John Bacon, former president, Boston Gas, quoted in the 2022 Boston Climate Progress Report
In Springfield, converting one section of the service territory in late 1951 required more than 400 workers and over 100 vehicles. The full conversion was expected to take six weeks. Changes to the supply network depended on careful coordination with the people using it.
Shale gas changes the case for LNG imports
In the 2000s, companies invested in two offshore LNG import facilities in Massachusetts Bay: Northeast Gateway, commissioned in 2008, and Neptune LNG, commissioned in 2010. Together, they represented roughly $750 million in investment.
Growing shale gas production then lowered domestic gas prices and weakened the case for importing LNG. Neptune received no commercial cargoes between its commissioning in 2010 and its suspension in 2013. Infrastructure built for one set of market conditions had little use under another.
These examples do not tell us exactly how electrification will unfold. They do show why a utility’s investment plans need to account for changes in technology, fuel supply, and customer choices over the life of its assets.
Keeping the system working through change
Engineer and sociologist Emily Grubert uses the term mid-transition to describe the period when existing energy systems and their replacements must operate together. Her work asks how to maintain reliable service while building a new system and winding down parts of the old one.
The gas network illustrates the problem. Pipes still need maintenance when some customers have switched to electric heat. If the costs of that network stay the same while the number of customers falls, those who remain can face higher bills. Grubert discusses this challenge in her conversation with Volts.
That makes the timing of investment and retirement important. Utilities need to keep serving customers safely while avoiding spending that could become unnecessary as demand changes. Customers who cannot readily electrify need particular attention: they may have little control over the costs left for them to pay.
Look beyond the next pipe replacement
A new gas main can remain on customers’ bills for decades. Before replacing one, utilities should consider how the buildings it serves are likely to use energy over that time. In some locations, coordinating building electrification with pipe retirement can avoid replacement costs. Finding those opportunities requires local analysis.
Connect climate plans to utility decisions
Climate plans have practical consequences for utility investment. A state expecting buildings to use less gas needs to consider what that means for new connections, pipeline replacement, and the recovery of past spending. Regulatory proceedings provide a place to examine those questions and test whether utility proposals are consistent with the state’s goals.
Compare the full cost of the options
Heat pumps give customers another way to heat their buildings. Whether a switch saves money depends on the building, equipment, energy rates, and any necessary upgrades. The wider system matters too: electrification may avoid a gas pipe replacement, require an electric grid upgrade, or make better use of capacity already available. A useful comparison accounts for those costs together.
Better information for the decisions ahead
Our work starts with specific questions. What does this infrastructure cost? What alternatives could serve the same customers? Who would pay under each option? We bring together data about buildings, utility networks, and costs to help clients answer those questions and decide where to act.