The affordable housing development is putting a different geothermal financing model to work: shifting part of the cost of underground heat-exchange infrastructure away from the property developer and toward the local utility.
Dandelion Energy and Vermont Gas Services (VGS) are partnering on the 44-unit Riggs Meadow development in Hinesburg, Vermont. Under the arrangement, VGS will help finance the geothermal ground-loop infrastructure, while Dandelion will design and install the system.
The project is notable less for its size than for the role VGS is taking. Instead of extending natural gas service to the development, the utility is investing in infrastructure that will support all-electric heating and cooling.
For developers, the structure could address one of geothermal's most persistent commercial hurdles: high upfront installation costs. For gas utilities, it raises a broader question about whether thermal infrastructure could become part of their business as building electrification reduces long-term demand for natural gas.
Ground-source heat pumps use relatively stable underground temperatures to provide heating and cooling. They can reduce electricity consumption compared with electric resistance heating and, in some applications, moderate peak demand associated with building electrification.
The obstacle is often capital cost.
Drilling boreholes and installing underground loops can add significant expense early in a construction project, even when the resulting system offers lower or more predictable operating costs over its useful life. Those economics can be particularly difficult for affordable housing projects, where development budgets and financing requirements leave less room for large infrastructure premiums.
At Riggs Meadow, VGS is absorbing part of that upfront infrastructure burden rather than requiring the housing developers to finance the full geothermal system through construction costs.
Champlain Housing Trust and Evernorth, the organizations developing the project, evaluated geothermal with VGS before Dandelion was brought in to handle system design and drilling.
The arrangement effectively separates some of the long-lived underground infrastructure from the buildings it serves. That approach resembles the way utilities traditionally finance assets such as distribution lines, where infrastructure costs are recovered over time rather than being paid entirely by the first property owner connected to the system.
For geothermal, that distinction could matter.
If ground loops can be financed and managed as utility assets, developers may be able to evaluate geothermal based more heavily on lifecycle operating costs instead of treating the drilling expense as part of the initial building budget.
The model also changes the utility's role. VGS is moving beyond supplying a fuel and toward providing infrastructure for heating and cooling, even when the resulting buildings do not consume natural gas.
The larger test is whether the approach can work beyond one Vermont development.
Gas utilities face growing pressure to determine how existing business models fit within state and local policies aimed at reducing building emissions. As electric heat pumps gain market share, utilities with businesses centered on gas distribution may need additional sources of revenue and new ways to use their infrastructure expertise.
Geothermal offers one possible path.
VGS already provides efficiency services, equipment support and electric heating and cooling options in addition to its conventional gas operations. President and CEO Neale Lunderville has described geothermal as another potential heating and cooling service the utility could support as Vermont adds housing.
Turning that concept into a repeatable utility model, however, introduces regulatory and financial questions.
Traditional gas utilities typically earn returns on approved infrastructure investments, with costs recovered through customer rates. Applying similar treatment to geothermal ground loops could require regulators to determine who owns the infrastructure, which customers pay for it, how maintenance responsibilities are assigned and whether utilities can earn a regulated return on the investment.
Those questions could become increasingly relevant if other utilities consider thermal networks or individual geothermal systems as alternatives to extending gas infrastructure.
Local economics will also limit how broadly the Riggs Meadow model can be replicated. Geology, drilling costs, electricity prices, incentives, housing density and utility regulation can all influence whether geothermal makes financial sense.
Affordable housing nevertheless provides a useful test case because heating expenses can materially affect household affordability. Geothermal systems rely primarily on electricity rather than delivered fuels, which can reduce exposure to some fuel-price volatility while providing relatively consistent heating and cooling demand.
Drilling at Riggs Meadow is expected to begin in early 2027, with residents scheduled to move into the development later that year.
The 44-unit project will not determine whether utility-financed geothermal works nationally. It could, however, provide an early indication of whether gas utilities can apply familiar infrastructure-financing models to a heating market that is becoming increasingly electric.
If the economics prove workable, the more important outcome may be the precedent: geothermal ground loops beginning to look less like building equipment and more like infrastructure a utility might own.
