For investors frustrated by the BC Hydro interconnection queue—which currently stretches into 2028 for many projects—geothermal energy has long been the answer that never quite arrived. The geology was promising and the resource was present, but the regulatory framework lagged. That obstacle is now being addressed.
BC's updated Geothermal Resources Act, which received Royal Assent in late 2025, represents the most significant overhaul of the province's geothermal regulatory regime in decades. The changes clarify tenure rights for developers, streamline the permitting pathway, and introduce co-production provisions that allow operators to recover lithium-rich brine as a secondary revenue stream. This transforms what was once a single-product energy play into a dual-revenue proposition at a time when critical mineral supply chains are commanding serious investor attention.
The business case starts with the resource itself. Unlike solar and wind, geothermal delivers baseload power—continuous, dispatchable, and unaffected by weather. That characteristic is increasingly valuable in a BC grid under pressure from electrification demand, data centre expansion, and the retirement of legacy thermal capacity. Preliminary assessments from Natural Resources Canada estimate northeastern BC's geothermal corridor holds more than 700 MW of developable capacity—enough to power a mid-sized city and meaningful for the province's electrification agenda.
At least four exploration-stage companies are active within BC's tenure system, concentrated in the northeastern corridor where subsurface temperatures are most favourable. The updated Act matters to each of them: clearer tenure rights reduce the financing risk that has historically made lenders cautious; a streamlined permitting pathway compresses the pre-development timeline; and the co-production provisions open a revenue channel that did not previously exist.
The lithium angle requires discipline
The co-production provisions deserve both attention and scrutiny. Geothermal brines in BC's northeastern formations carry dissolved lithium at concentrations that could support commercial recovery of lithium carbonate equivalent. Lithium carbonate equivalent was trading in the range of $12,000 to $15,000 per tonne as of Q1 2026—well below the peak prices of 2022 but sufficient to improve project economics when layered onto power revenue.
However, co-production is an option enabled by the new Act, not a guarantee of profitability. The lithium content of any specific brine formation must be characterized through drilling and testing. Extraction and processing add capital and operating costs. The dual-revenue narrative is compelling, but developers must validate it formation by formation. The regulatory framework has removed a legal obstacle; the geological and economic work remains.
What the Act changes
Prior to the 2025 amendments, BC's geothermal tenure regime created ambiguity at the intersection of the Geothermal Resources Act and the Oil and Gas Activities Act—a jurisdictional grey zone that complicated financing and deterred some developers. The updated Act clarifies which regulatory body holds authority at each stage, establishes a defined tenure pathway from exploration licence through development permit, and explicitly addresses co-production rights.
The BC Energy Regulator (BCER), which administers geothermal tenure alongside the Ministry of Energy, Mines and Low Carbon Innovation, now operates under a clearer mandate. For developers, that translates to reduced regulatory uncertainty—a primary friction point that has historically made geothermal financing more difficult than comparable renewable energy projects.
The investor timeline
Geothermal is not a fast-cycle investment. From exploration licence to first power typically takes seven to ten years for a greenfield project, encompassing resource characterization, feasibility studies, environmental assessment, and construction. That timeline is longer than wind or utility-scale solar and demands patient capital.
The counterargument for investors: the regulatory clarity introduced by the 2025 Act reduces the front-end risk that has historically inflated geothermal's risk premium. Projects that demonstrate resource quality and secure tenure under the new framework are better positioned to attract institutional financing. The Canadian Geothermal Energy Association has identified BC as one of the country's priority jurisdictions for near-term development, alongside Alberta and the Yukon.
For the BC grid, first power from the current generation of exploration projects is a realistic prospect in the early 2030s. While not a near-term solution to the interconnection queue, it represents a meaningful contribution to the province's baseload portfolio as electrification demand accelerates. The regulatory moment has arrived. Whether the capital follows is the question the next twelve months will begin to answer.
