Two Revenues from One Well: How Co-Production Is Rewriting Geothermal’s Risk

Most clean energy assets have a risk profile that a lender learned to price years ago. A solar farm’s output varies with the weather in ways that decades of data now describe well. A wind project’s curve is understood. Geothermal has always been an exception, and the reason sits underground. The largest risk in a geothermal project arrives before the plant exists, before a single megawatt is sold, when the drill bit goes down and the developer finds out whether the reservoir is actually there. That single feature, more than cost or technology, is why geothermal has been so much harder to finance than its steadier, more predictable output would suggest. What is quietly changing is not a breakthrough in drilling. It is a change in what a geothermal well is asked to produce. 

Where Is The Risk?

In geothermal, the dominant risk is resource risk, the uncertainty about the temperature and flow rate of the reservoir. Until the first well is drilled and pump-tested, a developer cannot confirm the parameters the entire financial model depends on, and that uncertainty sits directly on the project’s bankability (European Commission, n.d.). This is the opposite of what project finance is like. A non-recourse lender wants cash flows it can model, and geothermal asks it to commit capital against a hole in the ground that might not deliver. Utility-scale geothermal projects frequently exceed 100 million dollars, with much of that spent on exploration and drilling before any revenue exists (Altfin, 2025). The result is a financing gap precisely where the risk is highest. 

For years, the answer has been to move that risk off the private balance sheet. Several European countries built public geological-risk insurance funds so developers could transfer part of the exploration risk to the state (European Commission, n.d.). The mechanism is still evolving. In December 2025, Germany’s development bank KfW launched a program, built with the reinsurer Munich Re, that pairs concessional loans with drilling-risk cover and can secure up to the full loan amount against the chance that a well fails to find a reservoir with adequate temperature and flow (ThinkGeoEnergy, 2025). These schemes work, and they tell you something important. Geothermal has historically needed a public or reinsurance backstop at the drill bit because the private market would not price that risk on its own. 

Co-Production Possibilities

Co-production changes the question. Rather than asking a single well to justify itself on electricity alone, developers are increasingly asking it to produce two things, and the second one reshapes the credit story. There are two versions of this. The first is repurposing existing oil and gas wells for geothermal generation, which sidesteps the exploration problem entirely by using infrastructure that has already been drilled and paid for. A 2024 techno-economic study of repurposing oil and gas wells for enhanced geothermal systems in New Mexico found that reusing existing wells produced a levelized cost of electricity 31 to 70 percent lower than drilling new wells at the same sites, largely by eliminating the upfront cost and risk of exploratory drilling, with the estimate built on the National Laboratory of the Rockies' modeling tools (Higgins et al., 2024). When the biggest source of resource risk is removed from the model, the asset starts to look financeable in a way a conventional geothermal project never quite did. 

The second and more ambitious version is lithium. Geothermal brines in places like Germany’s Upper Rhine Valley and California’s Salton Sea carry dissolved lithium, and direct lithium extraction lets a single brine resource yield both baseload power and battery-grade material. For a credit analyst, the interesting part is not chemistry but cash flow. A project with one revenue stream that depends on power prices becomes a project with two streams, one of which can be contracted for years in advance. Automakers including Stellantis have signed binding offtake agreements for exactly this reason, giving the lithium output a committed buyer and turning a commodity into something closer to a contracted receivable, though those agreements are typically contingent on the project reaching commercial operation and qualifying its product, which limits how much they de-risk the build phase (Stellantis, 2021). Diversification and an offtake are precisely the features that make a difficult asset easier to lend against. 

Europe’s clearest test of this is the Lionheart project in Germany. In December 2025, a group of European and Australian investors closed a roughly 2.2 billion euro, or 2.5 billion dollar, financing package for phase one, which aims to produce enough lithium hydroxide for around 500,000 electric vehicle batteries a year alongside heat for nearby homes when it comes online in 2028 (RMI, 2026). What matters to the finance audience is how it was put together. Analysts who studied the deal describe a carefully layered set of de-risking measures and a blend of funding sources, structured deliberately to make a first-of-a-kind industrial project bankable rather than speculative (RMI, 2026). It is, in effect, a demonstration that the two-revenue model can carry a real capital structure. 

None of this makes the risk disappear, and it would be a mistake to write it up that way. What co-production does is trade one kind of risk for another. Adding lithium swaps part of the old geological uncertainty for commodity-price risk and technology-execution risk. Techno-economic work on Salton Sea brines suggests production costs that could run near 10,000 dollars a ton and rise toward 22,000 under less favorable assumptions, which is a wide band against a volatile lithium price, though the same analysis notes that by-product sales and capital-cost improvements can pull the break-even down materially (Wesselkaemper et al., 2026). On top of that sits the execution risk of running direct lithium extraction at commercial scale for the first time. The metrics that will decide these early projects are operating costs, sustained lithium recovery rates, and plant uptime, none of which is proven until the plants run at commercial scale for a sustained period.  

That trade is the whole point, and it connects to a pattern worth naming. Geothermal's historical problem was that its dominant risk sat in the worst possible place for a lender, before commercial operation, in the form of geological uncertainty that private markets could not price without a public backstop. Co-production moves the risk downstream, into commodity prices and technology performance, which are risks that debt and credit markets already know how to underwrite, hedge, and structure around. The asset did not get cheaper or safer in any simple sense. It became legible. For a sector that spent years dependent on insurance funds and development banks just to reach the starting line, making the risk something the private market can hold on its own may turn out to be the more durable breakthrough. 

References 

Altfin. (2025, June 4). Geothermal financing: How to finance geothermal power plants. https://www.altfin.net/geothermal-financing/ 

European Commission. (n.d.). GEORISK: Developing geothermal and risk insurance across Europe (Project ID 818232). CORDIS. https://cordis.europa.eu/project/id/818232 

Higgins, B., Pratson, L., & Patiño-Echeverri, D. (2024). Techno-economic assessment of repurposing oil & gas wells for enhanced geothermal systems: A New Mexico, USA feasibility study. Energy Conversion and Management X, 24. https://doi.org/10.1016/j.ecmx.2024.100811 

RMI. (2026, May 18). 10 project finance lessons from Europe's geothermal-lithium lighthouse. https://rmi.org/resources/10-project-finance-lessons-from-europes-geothermal-lithium-lighthouse/ 

Stellantis. (2021, November 29). Stellantis signs lithium supply agreement with Vulcan Energy. https://www.stellantis.com/en/news/press-releases/2021/november/stellantis-signs-lithium-supply-agreement-with-vulcan-energy 

ThinkGeoEnergy. (2025, December 18). Germany launches KfW geothermal loan and drilling risk cover. https://www.thinkgeoenergy.com/germany-launches-kfw-geothermal-loan-and-drilling-risk-cover/ 

Wesselkaemper, J., Renaud, T., Araya, N., Dekkers, K., Popineau, J., Riffault, J., O’Sullivan, J., & Haddad, A. Z. (2026). Pathways to cost competitive and viable lithium production from Salton Sea geothermal brines. Nature Communications. https://doi.org/10.1038/s41467-026-75389-8