For decades, geothermal energy occupied an awkward corner of Canada’s clean energy conversation—technically promising, perpetually pre-commercial, and chronically underfunded compared to wind and solar. That positioning is changing, and the shift is happening faster than many institutional investors have recognized.

Two Vancouver-based firms are currently negotiating multi-year commercial heat supply agreements for geothermal district energy projects in BC’s Interior and northeastern regions. These are not demonstration projects or feasibility studies; they are contracted-revenue infrastructure deals. The economics underpinning them have been fundamentally restructured by three converging forces: federal investment tax credits, maturing drilling technology, and a strategic repurposing of legacy oil and gas well infrastructure that is cutting development costs by as much as 40 per cent.

The federal catalyst

The most consequential input is fiscal. The federal clean technology investment tax credit—set at 30 per cent for eligible geothermal projects—materially changes project pro formas that previously could not clear institutional return thresholds. For a capital-intensive resource like geothermal, where drilling and surface infrastructure represent the bulk of upfront costs, a 30 per cent refundable credit on eligible capital expenditure is a project-enabler.

The credit applies to geothermal systems that meet Canadian net-zero criteria, and the Canada Energy Regulator’s clean energy investment tracking suggests the policy signal is already attracting capital that previously remained on the sidelines.

The well repurposing advantage

BC’s northeastern region—the Peace River country that has produced oil and gas for generations—holds a structural advantage for geothermal development. Natural Resources Canada’s geothermal resource atlas identifies the region as holding some of Canada’s strongest geothermal gradients, with subsurface temperatures sufficient to support district heating at commercially viable depths.

The twist is what is already in the ground. The BC Energy Regulator’s (BCER) legacy well registry documents thousands of inactive and orphan wells across the northeast—infrastructure that is now a liability on industry balance sheets. Geothermal developers are discovering that many of these wells reach the precise depth and temperature profiles required for heat extraction. Repurposing them, rather than drilling new wells, eliminates the most expensive and technically risky phase of geothermal development. The cost reduction—up to 40 per cent compared to greenfield drilling—is what closes the gap between geothermal’s theoretical promise and its financial reality.

Reality check: what "negotiating contracts" means

It is worth being precise about where these projects stand. Negotiating heat supply agreements is not the same as signing them, and signing is not the same as commissioning. Geothermal district energy projects carry meaningful execution risk: drilling outcomes are probabilistic, permitting timelines in BC can extend unexpectedly, and heat offtake agreements require creditworthy counterparties—typically municipalities, universities, or large commercial real estate portfolios—willing to commit to 20-plus-year contracts.

What has changed is that these risks are now being priced and absorbed by sophisticated capital rather than treated as disqualifying. Geothermal Canada’s member disclosures reflect a sector that has moved from advocacy to execution, with BC-based developers among the most active in advancing project pipelines toward financial close.

The investor case

For cleantech investors and the institutional capital increasingly circling BC’s infrastructure sector, the geothermal district energy profile is distinctive. Heat supply contracts—particularly those anchored to municipalities or large real estate portfolios—generate stable, inflation-linked, long-duration cash flows. That is a profile that pension funds and infrastructure funds actively seek. It is categorically different from merchant power risk or technology-dependent project finance.

The 30 per cent investment tax credit effectively functions as first-loss protection on eligible capital, compressing the equity required to reach project returns that clear institutional hurdles. Combine that with the legacy well cost reduction and BC’s geothermal resource quality, and the argument for capital allocation becomes structurally coherent rather than aspirational.

The question for investors is no longer whether BC geothermal can work. It is which projects will reach financial close first, and whether the permitting and offtake negotiation timelines can be compressed enough to capture the current policy window. Those are execution questions—and execution questions, unlike resource questions, have answers that disciplined capital can influence.