Geothermal Energy: Long‑Term Investment Outlook

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“Defoes steps out of today’s tiny geothermal numbers and into the IEA’s trillion‑dollar horizon — arguing that next‑generation geothermal is less a niche bet and more a long‑duration, 24/7 clean‑infrastructure theme now moving into view for disciplined capital.”

For now, geothermal barely registers in global energy statistics, meeting less than 1% of electricity demand and concentrated in a handful of high‑resource countries. Yet the International Energy Agency’s new “Future of Geothermal Energy” report sketches a radically different 2050 landscape: up to 800 gigawatts of cost‑effective geothermal capacity, providing around 6,000 terawatt‑hours per year — equivalent to the current electricity demand of the United States and India combined — and meeting roughly 15% of global electricity demand growth between now and mid‑century. From a Defoes perspective, the bullish stance is that while geothermal will not displace wind and solar, it is now credibly positioned to move from niche to system‑relevant — and that this shift is increasingly visible in the capital and policy trajectory.

Growth potential and capital flows to 2050

On the central IEA pathway, geothermal investment could reach 1 trillion US dollars cumulatively by 2035 and 2.5 trillion by 2050, with annual spending peaking around 140–200 billion US dollars — more than today’s global onshore‑wind investment in some scenarios. News coverage of the report notes that this scale‑up would make geothermal one of the largest single destinations for clean‑electricity capital over the next three decades, despite its tiny starting base. Importantly, up to 80% of required investment involves skills and technologies transferable from oil and gas — drilling, reservoir management, subsurface imaging — positioning parts of the upstream sector as natural partners and hedges against declining fossil demand.

Parallel projections from NREL’s 2024 Annual Technology Baseline show geothermal capacity factors remaining high and stable through 2050, with improvements focused on capital‑cost reductions rather than utilisation, underscoring its role as a mature baseload profile with room to improve on cost. Market‑research forecasts, although more conservative, still see the geothermal market more than doubling in revenue terms between 2025 and 2035, implying steady, if uneven, commercial pipeline growth even outside the most optimistic policy scenarios. Taken together, the picture is of a sector with relatively low current penetration but a plausible path to become a material, trillion‑dollar‑plus asset class within a single investment horizon.

Cost and competitiveness over time

The long‑term outlook hinges on whether geothermal can close the cost gap with other low‑carbon options. The IEA’s central scenario expects project costs to fall by roughly 80% by 2035, bringing generation costs down to around 50 US dollars per megawatt‑hour and potentially to 30 US dollars per megawatt‑hour by 2050 for next‑generation plants. That would make geothermal broadly competitive with existing hydro and nuclear fleets and with new wind and solar paired with storage in many markets. The Cascade Institute’s technical response highlights that these reductions are not assumed to appear spontaneously; they rely on deliberate learning in drilling speed, reservoir‑stimulation techniques and modular surface‑plant design, as well as policy frameworks that systematically de‑risk the exploration phase.

NREL’s ATB data, while more technology‑focused than scenario‑driven, are directionally consistent: capital‑cost assumptions for both conventional hydrothermal and enhanced geothermal systems (EGS) fall over the forecast period, with dispatch characteristics remaining baseload‑oriented. Legal and industry commentary on the IEA report also emphasises an additional, non‑LCOE source of competitiveness: geothermal’s ability to provide 24/7 clean power, reducing system‑level spending on storage, peakers and grid reinforcement compared with portfolios dominated by intermittent resources. For investors, these dynamics suggest that simple cost‑per‑megawatt‑hour comparisons understate geothermal’s value in reliability‑constrained or storage‑constrained systems.

Policy, permitting and structural risks

The bullish outlook is not guaranteed. The IEA and others are explicit that permitting and administrative delays remain a major drag, with geothermal projects often taking close to a decade from conception to commissioning. While more than 100 countries have policies for solar and wind, only about 30 have comparable frameworks for geothermal, and many lack clear permitting regimes for deep wells, integrated heat‑and‑power projects or EGS developments. The result is a wide dispersion of risk: some markets, such as parts of the United States, Indonesia, Kenya and Iceland, have strong project pipelines; others have favourable geology but fragmented or immature policy environments.

There is also non‑trivial subsurface and social risk. Exploration wells can fail or underperform; induced seismicity concerns can slow or halt projects; and developers are exposed to technology‑execution risk as next‑generation concepts move from pilot to scale. Analysts responding to the IEA report therefore stress that large‑scale deployment depends on governments implementing dedicated geothermal permitting regimes, sharing early‑stage drilling risk and providing stable, long‑term regulatory frameworks that allow developers and lenders to price risk with confidence. For capital allocators, this means that country selection, policy due diligence and partner choice will remain central to the investment thesis.

A differentiated long‑term role in portfolios

The strategic attraction, if these conditions are met, is clear. In the IEA’s scenario, geothermal becomes the third‑largest contributor to global electricity‑generation growth after wind and solar, while also expanding its role in low‑ and medium‑temperature heat for buildings and industry. At its peak, annual geothermal investment exceeds today’s global onshore‑wind spending, but remains a modest share of total clean‑energy finance, suggesting that it grows as part of a broader diversification rather than as a direct competitor to other renewables. Commentary around the report notes additional demand‑side drivers: data‑centre operators and other 24/7 loads are already signing long‑term power‑purchase agreements with geothermal projects to secure clean, continuous supply, creating a natural offtake base aligned with the technology’s profile.

From a Defoes standpoint, the long‑term investment outlook is bullish but selective. The sector’s success is likely to be uneven across jurisdictions and technologies, with the most attractive opportunities emerging where three conditions align: high‑quality resources (including engineered EGS potential), robust policy and permitting frameworks that explicitly value firm low‑carbon capacity, and credible partners able to execute complex subsurface projects using oil‑and‑gas‑grade capabilities. For investors building transition‑aligned portfolios, geothermal is unlikely to replace wind and solar, but it is increasingly well‑positioned to sit alongside them as a differentiated source of 24/7 clean power and heat — one whose value may be most visible not in today’s deployment statistics, but in the trajectory of capital, policy and system needs out to 2050.