A growing number of mid-market energy firms are converting decommissioned oil and gas assets into geothermal energy projects and carbon storage leasing sites. This article examines the commercial logic, regulatory drivers, risks and outlook for this emerging asset class.
The Asset Conversion Thesis
The decommissioning of oil and gas infrastructure is often viewed as a cost burden. In the North Sea, the Gulf of Mexico and the Permian Basin, operators face billions in abandonment liabilities. However, a subset of mid-market firms is beginning to treat these liabilities as assets. The core idea is straightforward: depleted reservoirs, wellbores and pipeline corridors retain physical and geological value that can be leased or repurposed for low-carbon energy and storage.
Two primary conversion pathways have emerged. The first is geothermal energy production, where hot water or steam is extracted from deep formations via existing wells, often with enhanced geothermal systems (EGS) to improve permeability. The second is carbon capture and storage (CCS), where depleted reservoirs are leased to emitters seeking permanent CO2 sequestration. Both pathways leverage existing subsurface data, surface infrastructure and regulatory permits, reducing upfront capital requirements compared to greenfield projects.
Why It Matters
For mid-market firms, the conversion play offers a way to extend the economic life of assets that would otherwise be written off. It also provides a hedge against the long-term decline of hydrocarbon demand. For investors, it creates a new asset class with revenue streams from energy sales, storage fees and potentially carbon credits. For regulators, it addresses the growing problem of orphaned wells and idle infrastructure. The commercial relevance is heightened by the Inflation Reduction Act in the United States and the UK's Net Zero Strategy, both of which include tax credits and subsidies for CCS and geothermal projects.
Commercial Impact
Revenue models vary by pathway. Geothermal projects typically generate income from electricity sales via power purchase agreements (PPAs) or from direct heat supply to industrial users. CCS projects earn revenue through storage fees, typically $20-$50 per tonne of CO2 stored, plus 45Q tax credits in the US of up to $85 per tonne for dedicated storage. Some operators also monetise the surface rights for pipeline corridors, leasing them to third-party developers of solar or wind farms.
A typical conversion involves three stages. First, the operator conducts a technical assessment of the reservoir's suitability for geothermal or CCS, including temperature, porosity and seal integrity. Second, they secure regulatory approvals, which may include environmental impact assessments and pore-space ownership clarification. Third, they negotiate lease or service agreements with end users. The capital expenditure is significantly lower than a greenfield project, often 30-50% less, because the wellbores and surface facilities already exist.
Risks / Unknowns
The conversion play is not without risks. Reservoir performance is uncertain; a depleted field may not have sufficient permeability or temperature for economic geothermal production, or its seal integrity may be inadequate for long-term CO2 storage. Regulatory frameworks for pore-space ownership and long-term liability are still evolving in many jurisdictions. In the UK, for example, the Oil and Gas Authority (now the North Sea Transition Authority) has issued guidance but not yet a comprehensive licensing regime for CCS on decommissioned assets.
There is also the risk of stranded assets. If carbon prices fall or geothermal technology advances more slowly than expected, the economics of conversion projects may deteriorate. Furthermore, the mid-market firms pursuing this strategy often have limited balance sheets, making them vulnerable to cost overruns or delays in regulatory approval. Finally, there is the question of public perception: communities may oppose the repurposing of old oil and gas sites for new industrial uses, particularly if they associate them with past environmental damage.
FY Outlook
Over the next three to five years, the conversion play is likely to gain traction in regions with mature oil and gas infrastructure and supportive policy frameworks. The US Gulf Coast, the North Sea and the Permian Basin are early candidates. We expect to see more joint ventures between mid-market operators and specialist geothermal or CCS developers, as well as the emergence of dedicated conversion funds. The key catalysts will be clarity on pore-space ownership, the extension of 45Q tax credits beyond 2033, and the development of a UK CCS business model that includes decommissioned assets.
However, the market remains nascent. Most projects are still in the pilot or feasibility stage. The first commercial-scale conversions are expected to reach financial close in 2025-2026. For investors, the opportunity lies in identifying operators with high-quality subsurface data, strong regulatory relationships and a clear strategy for managing long-term liability. For operators, the window to act is now, before the best assets are claimed by larger competitors or lost to decommissioning.
Conclusion
The conversion of decommissioned oil and gas assets into geothermal energy and carbon storage sites represents a commercially rational response to the energy transition. It turns a liability into a revenue-generating asset, reduces the cost of decommissioning and supports decarbonisation goals. The risks are real but manageable for firms with technical expertise and patient capital. For mid-market firms, this is not a speculative bet but a pragmatic hedge. The question is not whether the conversion play will happen, but who will capture the value first.
