Geothermal Energy: Capital Costs and Scalability Issues
Master the Moment and Reach Your Peak with Defoes
“Defoes looks past the headline that ‘geothermal is too expensive’ — unpacking how drilling risk, capital structure and policy design actually determine which projects stay stranded and which scale into a global, next‑generation baseload asset class.”
Geothermal’s biggest paradox is that it looks like an infrastructure investor’s ideal asset — local fuel, long asset life, baseload output — yet has struggled to scale at anything like the pace of wind and solar. The main reason is not resource scarcity but capital structure: most of the risk and cost sit upfront, in exploration and drilling, before cash flow is secured. From a Defoes perspective, the bullish stance is that these cost and scalability issues are real but increasingly addressable, and that investors who understand how they are being tackled — rather than treating them as immutable — will be better placed as next‑generation geothermal moves out of the niche.
Where the capital actually goes
In geothermal, the bulk of expenditure is CAPEX, not fuel or operating costs. Studies of projects in Switzerland and other European markets show that exploration and drilling are the largest cost components and the main sources of uncertainty: wells can underperform, fail to find adequate permeability, or encounter problematic chemistry, all of which undermine the project’s economics. The World Bank’s comparative work on geothermal risk notes that resource uncertainty at the drilling phase pushes up the cost of capital and can leave otherwise viable projects stranded, especially in emerging markets where risk capital is scarce or expensive.
The 2024 US National Renewable Energy Laboratory (NREL) Annual Technology Baseline (ATB) quantifies how this front‑loaded profile translates into technology costs. In the conservative scenario, NREL still assumes materially higher overnight capital costs for geothermal than for mature wind and solar, but notes that drilling costs in its 2024 update are already around 7% lower than in previous editions as industry learning and oil‑and‑gas know‑how spill over. Put simply, each well matters more than each turbine: geothermal projects bet a large lump of capital on subsurface conditions that are only partly known in advance.
How scalable is geothermal really?
At a resource level, scalability is not the problem. The International Energy Agency’s “Future of Geothermal Energy” report finds technical potential on the order of hundreds of terawatts, and, in its central scenario, sees up to 800 gigawatts of cost‑effective next‑generation geothermal capacity by 2050, providing around 8% of global electricity and roughly 15% of the growth in generation between now and mid‑century. The Cascade Institute’s reaction paper emphasises that this would still tap only a fraction of total technical potential, but would require between 700 billion and 2.1 trillion US dollars of cumulative investment by 2050, with annual spending peaking around 200 billion US dollars — roughly a quarter of today’s global clean‑electricity investment.
The real scalability constraint is therefore not geology but the ability to mobilise and de‑risk that volume of capital at acceptable returns. Only about 30 countries have clear geothermal policies today, and many lack the regulatory and data frameworks needed for bankable project pipelines. Experience in markets like the Netherlands and selected EU states shows that government‑led resource mapping, data repositories and cost‑shared exploration drilling can materially reduce project‑level risk and attract private capital, but these approaches are far from universal. Without such frameworks, geothermal remains confined to a thin set of high‑resource, policy‑supportive jurisdictions.
Cost‑reduction trajectories: ambitious, but not speculative
One reason for a constructive view on capital intensity is that policymakers and industry have explicitly targeted geothermal CAPEX. The US Department of Energy’s “Enhanced Geothermal Shot” — referenced in the IEA report — aims for a 90% reduction in the cost of EGS by 2035, while the IEA’s own scenario calls for roughly an 80% cut in capital costs over the same period. The Cascade Institute summary notes that the IEA expects first‑of‑a‑kind next‑generation geothermal plants to fall from around 14,000 US dollars per kilowatt today to 3,000–7,000 by 2035 and 2,000–5,000 by 2050, with levelised costs of energy dropping from about 230 US dollars per megawatt‑hour to 50 by 2035 and 30 by 2050 as learning, standardisation and oil‑and‑gas supply chains kick in.
Parallel work from NREL and national laboratories suggests that the LCOE of EGS could converge towards that of today’s conventional flash hydrothermal plants over the next decade if drilling, reservoir‑stimulation and plant technologies follow the assumed learning curves. These are not guaranteed outcomes, but they are underpinned by tangible initiatives: drilling‑accelerator programmes, transfer of rigs and crews from oil and gas, and public‑private partnerships around demonstration projects. In other words, the industry is not passively hoping for cost reductions; it is actively investing in the specific levers — drilling productivity, better subsurface imaging, modular surface plants — that drive them.
De‑risking models: from public exploration to contract design
On the risk side, there is growing evidence that structured de‑risking can make geothermal capital more scalable. The World Bank’s analysis of global approaches highlights tools such as cost‑shared exploration drilling, public reservoir data, insurance pools and targeted guarantees to lower the effective cost of risk capital at the pre‑drilling stage. The European Commission’s Joint Research Centre similarly points to national databases and government‑backed exploration campaigns as ways to reduce development risk and compress timelines in EU markets.
Contract structures also matter. Where regulators and offtakers recognise geothermal’s firm‑capacity value — through long‑term power‑purchase agreements, capacity payments or tariffs that account for its baseload contribution — project cash flows become more predictable, supporting higher leverage and lower equity hurdles. That is particularly relevant for next‑generation geothermal, where the system value (reduced storage and backup costs, local resilience) is not fully captured by energy‑only pricing.
A bullish but disciplined view on capital and scale
The bear case says that high upfront costs, complex subsurface risk and policy gaps will keep geothermal on the margins while cheaper, modular renewables dominate capacity additions. That is a credible risk, especially in jurisdictions that do not value firm low‑carbon capacity explicitly or lack the institutional capacity to manage subsurface projects. Cost and scalability issues are real, not narrative artefacts.
Yet the combination of technical potential, targeted cost‑reduction roadmaps and emerging de‑risking models paints a more constructive picture. The IEA’s 800‑gigawatt scenario implies that next‑generation geothermal could become the third‑largest source of global electricity‑generation growth after wind and solar by 2050, with capital requirements well within the scale of today’s clean‑energy finance flows if policy and project pipelines align. From a Defoes perspective, the bullish stance is not that capital costs and scalability constraints will disappear, but that they are now the central design problems being worked on — and that as drilling technology, data and policy converge, geothermal will move from being limited by capital fears to being scaled by capital discipline.