SPECIAL REPORT | GEOTHERMAL ENERGY
Introduction: Why the Asset Bundle Matters More Than the Heat
The conventional approach to geothermal screening begins underground: identify a promising thermal resource, then work backwards to assess whether a project can be built around it. Applied to coal assets, that logic is seductive but strategically inverted. It fills a register with technically interesting sites that are commercially undevelopable, because it mistakes the resource for the business case.
The argument advanced here is the opposite. A retiring or defunct coal complex leaves behind a bundle of hard assets — grid interconnection, district-heating pipework, water rights, cooling infrastructure, permitted brownfield land, an experienced workforce, and a subsurface dataset that cost its original owners hundreds of millions to acquire. That bundle, not the geothermal gradient beneath it, is where the value resides. Heat is one way to monetise it, and today it is not always the highest bidder. Retrofitting coal-fired power plants with clean technology eliminates the requirement for greenfield site development and reuses much of the existing grid infrastructure, but only if infrastructure proximity to demand is treated as the primary screen.
This argument has acquired fresh urgency. Global Energy Monitor's Boom and Bust 2026 report finds that global coal power capacity grew by 3.5% in 2025 even as coal-fired generation fell by 0.6% — a paradox that crystallises the central challenge: coal is increasingly maintained not as a primary generation source but as system insurance. The world is building coal it does not use, while simultaneously failing to retire coal it can. Nearly 70% of coal-fired units scheduled to retire in 2025 did not do so. That gap between capacity and generation — stranded thermal capital — is exactly the inventory the infrastructure-first screen is designed to monetise.
The Weisweiler programme illustrates the geological asymmetry precisely. Temperature is not the binding constraint — permeability is. A resource-first screen selects for heat and is blind to flow, offtake, and connection. An infrastructure-first screen selects for demand and pipe before interrogating the subsurface. The sections that follow explain how to build that screen, where it should be deployed first, and why the policy context as of July 2026 reinforces rather than undermines the core argument.
The Geological Thesis: Coal as Thermal Blanket and Its Binding Constraint
Coal is a poor conductor of heat. Where thick coal-bearing sequences overlie or intercalate with deeper sedimentary successions, vertical heat loss from the subsurface is suppressed, and temperatures accumulate in the strata beneath. The Latrobe Valley is the most rigorously documented demonstration of this effect: the thick brown coal layers act like a thermal blanket, making the underlying aquifers hotter than aquifers elsewhere and producing 65°C water at roughly 650 m depth. Measured borehole data confirm gradients of about 35–80°C/km through the Cainozoic section, because thermal conductivity on Cainozoic cores is below the global average owing to high porosity, abundant coal, and low quartz content.
Numerical simulations incorporating Latrobe Valley coal geometries show that the coal alone could elevate rock temperatures at 4 km depth by approximately 30–35°C relative to a condition with no coal present, effectively boosting the average geothermal gradient by around 30%. Crucially, this insulating effect produces a negative surface heat-flow anomaly directly above the most prospective areas — the resource is masked, not advertised, at the surface. This means that standard geothermal prospecting methods, which prioritise surface heat-flow data, will systematically rank coal-thermally-enhanced basins as unexceptional and pass over them in favour of volcanic provinces. The infrastructure-first screen corrects for this blind spot.
The Weisweiler drilling programme corroborates the same physics in a Carboniferous setting and simultaneously exposes the binding constraint. Fraunhofer IEG, in collaboration with RWE Power AG, drilled exploratory boreholes EB1 and EB2 ahead of the plant's 2029 closure. The sandstone formations encountered were dense and largely impermeable; permeable limestone favourable for geothermal water circulation is expected only at around 1,300 m depth. The consortium accordingly plans wells to 3,000 m to reach the prospective carbonate target — a depth that shifts the project into a materially different risk and capital class. Fraunhofer IEG's €52 million Geo³ Living Laboratory at Weisweiler, funded in part through Germany's Coal Regions Investment Act, is now moving from planning to implementation.
This asymmetry — coal measures that deliver anomalous temperatures whilst denying reservoir permeability — is the master constraint for the entire screening framework. Temperature is readily inferred from existing drillhole records; mine water temperatures follow the geothermal gradient and can reach 40°C at depths of around 1 km. Permeability cannot be assumed and cannot be modelled away. The decisive question at every site is whether a permeable unit — mined void, sub-coal aquifer, or deep carbonate — is accessible at a depth compatible with the target temperature and available capital.
Three Distinct Plays and a Proven Entry Point
Three geothermal plays are available at retired coal complexes, and conflating them is the single most reliable way to destroy a project's investability. They differ so fundamentally in reservoir type, depth, temperature, geological risk, and commercial scale that the same screening criteria cannot be applied across all three.
Only Play A is proven, bankable, and repeatable today. The Gateshead scheme is the definitive reference: it accesses 6 MW of mine water heat via boreholes drilled to 150 m into 200-year-old workings, lifting 15°C water to 80°C supply temperature through a heat pump, and delivering heat to Gateshead College, the Baltic Arts Centre, and 350 council-owned homes. Funded with £5.9 million of Heat Network Investment Project grant support, it moved from concept to live operation in approximately three years. As of February 2026, approximately 350 homes and businesses in Gateshead are supplied by mine water heat schemes.
The highest-priority category in any asset register is sites where mine water is already being pumped to surface at public expense. At Dawdon in County Durham, the Mining Remediation Authority has treated mine water since 2009; that water arrives at 19–20°C year-round and was until recently discharged to sea with its heat unused. The Seaham Garden Village project bolts a heat-capture energy centre onto that existing treatment scheme, supplying 750 affordable homes with £4.3 million of HNIP support, with construction formally beginning in early 2025.
A landmark study published in July 2025 by the Mining Remediation Authority substantially de-risks the Play A thesis. Analysing 564 boreholes across Great Britain, researchers found an 87% overall success rate, with more than 75% of those targeting mine voids successfully reaching their target. The success rate rises to 97% for boreholes deeper than 300 m. This study is the most important piece of technical risk mitigation the sector has produced — it transforms Play A from 'technically plausible' to 'statistically de-risked'.
Figure 2: UK mine water borehole success rates across 564 boreholes (MRA, July 2025).
97% success rate at depth >300 m transforms Play A from 'plausible' to 'statistically de-risked'.
Source: Mining Remediation Authority (2025). New study provides major boost for mine water heat revolution.
Play C — deep enhanced geothermal systems — is a genuine technological revolution in progress. Quaise Energy raised $134 million in the first close of its Series B in July 2026 for Project Obsidian in Oregon, the planned world's first commercial superhot geothermal power plant. The US DOE's Enhanced Geothermal Shot targets costs of $45/MWh by 2035. At coal sites, Play C should be structured as an embedded option — a contractual right to drill deeper on sites already in the portfolio — not a standalone investment thesis.
Figure 3: Three geothermal plays positioned by time to first revenue and relative capital intensity.
Play A is bankable today; Play C remains a future option pending EGS cost-curve confirmation.
Source: Brook (2026), framework analysis. Play A = mine void; Play B = sub-coal aquifer; Play C = deep EGS.
Counter-Evidence: Policy Volatility and the Limits of the German Thesis
The German thesis carries more legislative risk than a straightforward reading of the district heating decarbonisation mandate suggests, and the register must be stress-tested against that risk before capital is committed.
The sequence of events is now complete. On 24 February 2026, the CDU/CSU–SPD coalition presented key points for a new Building Modernisation Act (GMG), under which the 65% renewable energy requirement for heating modernisation would be completely abolished. The German Cabinet formally approved the GMG on 13 May 2026, restoring full technology neutrality: gas and oil boilers may again be installed alongside heat pumps, district heating connections, and biomass systems. The Bundestag approved the Act on 10 July 2026. One estimate suggests up to 900,000 dwellings may instead opt for cheaper upfront gas boilers.
The GMG's replacement mechanism — a 'bio-ladder' requiring at least 10% climate-friendly fuels in new gas and oil boilers from January 2029, rising in stages to 2040, combined with a green gas quota for distributors starting at up to 1% from 2028 — does not replicate the demand certainty the 65% mandate would have provided. Öko-Institut researchers warned that the reforms 'shift risks into the future and onto third parties without ensuring a reliable path to achieving [climate] targets,' with Germany increasingly risking failure to meet EU Effort Sharing Regulation targets.
Two countervailing considerations prevent a clean write-off. First, a technology-open framework may reduce political vulnerability, creating more predictable investment conditions than a regulation-enforced expansion. The GMG explicitly strengthens the legal and financial framework for district heating networks, incorporating the Federal Funding for Efficient Heating Networks (BEW) into statute. Second, the Weisweiler–Inden rationale is not primarily regulatory: with the Weisweiler plant scheduled to shut by 2029 and lignite mining ending, regional authorities are actively seeking sustainable alternatives to maintain existing district heating supplies.
Germany should remain in Tier 1, but for asset-driven rather than mandate-driven reasons. Screen for sites where the network already exists and the coal closure creates an unavoidable supply gap — not where the thesis depends on regulatory compulsion to connect new buildings, a lever the GMG has dismantled.
A Fifth Force the Paper Underweights: The American Paradox
The paper's geographic deployment logic — Great Britain, Germany/Benelux, Australia — is sound, but it underweights a paradox that will reshape the opportunity set over the next decade: the United States.
The Trump administration has been the world's most aggressive defender of operational coal, issuing executive orders requiring that at least 16 coal-fired units remain operational for grid reliability purposes, and directing $175 million in funding to upgrade six coal-fired power plants. US coal generation rose 10% in 2025 — the only major economy to increase it. Yet the same administration has been the most enthusiastic federal backer of enhanced geothermal systems in US history. Google, Meta, and Microsoft — whose data-centre electricity demand drove half of all US electricity demand growth in 2025 — are backing EGS projects. Quaise Energy's $134 million Series B in July 2026 for Project Obsidian in Oregon is private capital moving on a commercial thesis, not a subsidy.
The American paradox creates a bifurcated opportunity: coal plants that the current administration keeps alive retain grid connections but present no immediate geothermal opportunity; coal plants in states proceeding with retirement regardless of federal pressure — primarily in deregulated markets across the Southeast and Mid-Atlantic — are the near-term targets. Unlike Great Britain's single Mining Remediation Authority, the US has no federal equivalent, and state-level regulation of subsurface access to former mines is patchwork. This is the barrier that prevents American Tier 1 classification today, not geology or infrastructure.
The Emerging Market Dimension: Indonesia and the Limits of Analogy
The IEA's Future of Geothermal Energy report identifies coal-transition regions in China, India, and Southeast Asia as where geothermal's value is greatest. That framing requires significant qualification when applied to the infrastructure-first framework.
Indonesia offers the sharpest case study in the limits of the analogy. Coal supplies approximately 68% of the country's electricity generation; the government reversed its flagship coal plant early-retirement plan in 2025. Indonesia sits on the Pacific Ring of Fire and has more identified high-temperature geothermal resources than almost any other nation — but Indonesian coal assets are overwhelmingly located on Kalimantan and Sumatra, far from the volcanic provinces where high-temperature geothermal resources occur. The infrastructure-first framework requires proximity between asset bundle and heat resource; in Indonesia, they are structurally separated by geology. The CIF Accelerating Coal Transition programme's $500 million in funding, leveraging $2 billion in MDB co-financing, is better directed at solar and pumped-hydro conversion than at geothermal.
China and India present a more nuanced picture. Both commissioned record coal capacity in 2025 — China added 78.1 GW and India 10 GW — yet coal generation fell in China by 1.5% and in India as the monsoon strengthened hydro output. Northern Chinese coalfields in Shanxi and Inner Mongolia do sit above sedimentary basins with geothermal potential and some district-heating networks. But the institutional architecture differs: Chinese coal mines are predominantly state-owned, creating a coordination challenge rather than the competitive fragmentation that bedevils the US.
The practical conclusion is that this framework's Tier 1 deployments remain in advanced economies with functioning property-rights regimes, mapped subsurface data, and district-heating networks. The emerging-market opportunity is real but requires development finance, blended capital, and multilateral counterparties rather than the bankable project finance model that makes Gateshead replicable.
Building the Register: Four Sequential Gates and Where to Deploy Screening Capital
The register is built in three layers, run through four knockout gates, and deployed first in the markets where density of qualifying assets is highest. The coal asset spine comes from Global Energy Monitor's trackers. The Global Coal Mine Tracker catalogues operating, inactive, proposed, and post-2015 abandoned assets, with reserves defined to JORC standards — meaning the measured-but-unexploited universe is code-aligned and downloadable at no cost. The thermal layer is supplied by Project InnerSpace's GeoMap, which enables users to compare coal plant facilities against next-generation geothermal suitability, with layers for transmission distance and demand. Do not rebuild this — use it, and add what it lacks: mine-void geometry, district-heating network topology, and title.
The Four Knockout Gates
Gate 1 — Anchor Demand Load
Demands an anchor demand load — district heating, dense residential, industrial process heat, or a generating load above 50 MW — within five kilometres. Sites failing this gate are exited regardless of subsurface quality. Infrastructure proximity to demand is the filter that converts geological abundance into commercial opportunity.
Gate 2 — Retained Connection Asset
Requires existing district-heating pipe or a live grid interconnection point. The value of a brownfield coal site without retained infrastructure is a fraction of one with it. A site with both a district-heating network and a live grid connection point qualifies for both heat and power plays.
Gate 3 — Reservoir Plausibility by Play
For Play A (mine void), the Welsh and Scottish MiRAS criteria apply directly, with depth cut-offs at <30 m, 30–300 m, 300–500 m, and >500 m below ground level. The July 2025 MRA borehole study's 97% success rate for boreholes deeper than 300 m warrants upgrading 300–500 m sites from 'Possible' to 'Good' in revised scoring matrices, subject to mine plan quality.
Gate 4 — Access and Title
In Great Britain, the workings are Crown-held, making the Mining Remediation Authority the single counterparty for both licence and heat offtake. This is the UK's most significant structural advantage over every other market — not geology, not history, but the institutional architecture that converts a complex subsurface right into a single commercial negotiation.
Geographic Tier Rankings (as at 16 July 2026)
Figure 4: Infrastructure-First investability scores by market (July 2026).
Composite of counterparty quality, asset bundle, demand proximity, and title clarity.
Source: Brook (2026) framework analysis. Scores are author's composite assessment scored out of 100.
What Is the Global Potential?
The global potential is large but not undifferentiated. The IEA's Future of Geothermal Energy report found that next-generation geothermal could meet up to 15% of global electricity demand growth to 2050. Geothermal's full technical potential is sufficient to meet global electricity demand 140 times over. Total cumulative investment in geothermal could reach $2.5 trillion by 2050, with costs for next-generation systems potentially falling 80% to around $50/MWh by 2035.
That framing is directionally correct, but the strategy developed here arrives at a more discriminating conclusion: the opportunity set is not every coal-adjacent geothermal resource on the planet — it is every coal complex that already sits beside a heat load, a grid connection, and a mapped subsurface. That population is far smaller and far more valuable than the headline figures imply.
Play A is proven today. The UK alone pumps in excess of 3,000 litres per second from abandoned workings, with an estimated 100 MW of heat energy sitting in that flow, and European countries, the USA, China, and Russia all carry considerable potential to use abandoned mines for energy recovery. Play B is where scale emerges — the Weisweiler model applied across the Rhenish, Belgian, and northern French coalfields — but permeable sub-coal targets must be confirmed before capital is committed. Play C remains an option, not a programme, until the EGS cost curve confirms sub-$50/MWh delivery.
The Overlooked Multiplier: Thermal Storage and Grid Balancing
One dimension the core framework underweights is the value of thermal storage. Mine water systems are not simply heat sources — the flooded void itself constitutes a thermal battery of enormous scale. As variable renewables (solar and wind combined contributed nearly 60% of global energy demand growth in 2025) increasingly dominate electricity systems, the capacity to charge and discharge thermal energy at scale acquires grid-balancing value that is not captured in conventional heat-only revenue models.
A mine water system drawing 6 MW of heat continuously has a fundamentally different revenue stack from one that can modulate abstraction to follow electricity price signals, drawing more during periods of renewable surplus and less during grid stress. The Gateshead system's 15-minute data collection regime creates the foundation for exactly this kind of dispatch optimisation. The next phase of mine water projects should be designed from the outset for thermal storage functionality — not bolted on after construction — because the grid-balancing revenue stream will, in many markets, dwarf the heat revenue on a per-MWh basis within a decade.
IEA modelling shows geothermal's system flexibility — through ramping capability, frequency regulation, and inertia — as one of its most distinctive contributions to power systems dominated by variable renewables. The infrastructure-first screen should therefore add a fifth gate, or a scoring modifier to Gate 1: proximity to electricity grid balancing markets and transmission constraints. A coal plant site with a grid connection at a congestion node is worth materially more than a topographically equivalent site at an unconstrained node.
Conclusions: Three Propositions for Capital Committees
The infrastructure-first framework is not a geological thesis dressed in financial language. It is a claim about where risk is located in coal-to-geothermal conversion and how to price it correctly. The global coal fleet is entering a decade of paradox: capacity growing, generation falling, retirements delayed, and the political conditions for orderly transition fragmenting. In that environment, the coal complex that has already stopped generating but retains its infrastructure bundle is not a liability to be managed. It is an option on the heat transition — and the infrastructure-first screen is the instrument for identifying which options are in the money today.
Proposition 1 Play A Is Investable Now — and the Risk Argument Against It Has Been Empirically Dismantled
The MRA's 564-borehole study — showing 87% overall success and 97% success for boreholes deeper than 300 m — removes the technical uncertainty that has caused risk-averse capital to pass over mine water heat. The residual risks are regulatory, commercial (offtake contract duration), and reputational (proximity to former industrial land). All three are manageable. The cost of capital applied to Play A projects in Great Britain should fall in the next 18 months as this evidence is digested by insurers, lenders, and development finance institutions. Any capital committee still treating Play A borehole risk as a meaningful hold-back is working from stale data.
Proposition 2 Play B Requires Pre-Commitment to Characterisation Capital, Not Project Finance
The Weisweiler experience shows that committing to a deep Play B project without borehole-confirmed permeability is a category error. The appropriate investment at the early stage is geological characterisation — seismic surveys, stratigraphic analysis, and a pilot borehole — at a cost an order of magnitude below project finance, with an explicit decision gate before any material capital is committed. Investors who treat Play B sites as Play A equivalents are systematically mis-pricing permeability risk. Play C — exemplified by Quaise Energy's $134 million Series B in July 2026 and Google/Meta/Microsoft EGS backing — should be structured as an embedded option on sites already in the portfolio, not a standalone investment thesis.
Proposition 3 The GMG Has Not Killed the German Opportunity — It Has Redefined It
Projects whose thesis depended on regulatory compulsion to connect new residential buildings are now stranded. Projects whose thesis rests on filling an existing heating network supply gap created by coal plant closure are stronger than before, because the GMG's technology-open framework reduces the political vulnerability of district heating as an investment class. The correct response to the GMG is not to exit Germany but to re-underwrite the asset list: strike projects that needed new customer mandates; retain and advance projects with captive, existing demand.
The register built on the four gates described here will produce a short, fundable list rather than an exhaustive inventory. Infrastructure proximity is the filter that converts geological abundance into commercial opportunity, and it should govern every allocation decision that follows. Every site that fails Gate 1 should be exited regardless of how compelling the subsurface looks.
Stranded Geothermal Capital needs to be liberated!
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