Geothermal lease sale sets federal record as utilities push for ratepayer-funded networks
A New Mexico lease sale and a new utility financing model signal geothermal's shift from pilot projects to rate-base expansion.
A June lease sale in New Mexico by the Bureau of Land Management netted more than $16.5 million, the second-highest grossing geothermal auction in BLM history, with the top bid hitting a federal record of $701 per acre, an agency spokesperson told Utility Dive in an email.7
The price per acre matters because it shows established developers now value geothermal acreage near transmission infrastructure at levels that would have been unthinkable when the Framingham, Massachusetts neighborhood-scale network came online two years ago. Back then, the first-of-its-kind system owned by the state's largest utility was hailed as groundbreaking. Now the financial metrics are moving from demonstration economics to something that looks like a bankable resource play.7,2
That shift is pulling a regulatory question to the surface: who gets to own and rate-base these assets? The Framingham model, where a utility owns the network and recovers costs through rates, is no longer a single experiment. It is becoming the template that developers and utilities are pushing state regulators to adopt, and the federal government is helping with money.2
The US Department of Energy and AEP Texas reached financial close on a loan of up to $3.26 billion from the Trump administration's Energy Dominance Financing program. DOE and AEP claimed the loan will unlock $685 million in electricity cost savings over the next 30 years for more than one million households and businesses in Texas.6
That is a big number, but it comes with a caveat worth flagging. The savings estimate is DOE and AEP's own claim, not an independently verified figure. The loan guarantee also covers "nearly 5,000 miles of transmission lines in Indiana, Michigan, Ohio, Oklahoma, and West Virginia," which is a different grid problem than Texas, and the estimated $275 million in customer financing savings is an agency projection.6
The scale of federal backing is what has changed. Earlier in 2026, Southern Co's Alabama Power and Georgia Power secured a combined $26.54 billion in EDF loans. Those 30-year loans, around $22.42 billion for Georgia and $4.09 billion for Alabama, could result in $7 billion in savings for 4.3 million customers, according to Southern.6
The Permian Basin connection runs through this financing structure. AEP's Texas subsidiary is the utility counterpart to what the DOE's EDF program is trying to do across the country: treat grid upgrades as national energy infrastructure rather than state-by-state marginal investments. Geothermal developers in the Permian, where oilfield drilling expertise transfers directly to enhanced geothermal projects, watch this financing model closely because it determines whether their off-takers can afford the power purchase agreements.6
The resource potential is not the constraint. US Department of Energy projections state that enhanced geothermal projects could provide about 90 gigawatts of carbon-free energy in the US by 2050, roughly enough to power 65 million homes. That is the DOE's central case, not a guarantee.5
Congress is moving on the permitting side. The House passed bipartisan legislation on Tuesday (2026-06-02) aimed at easing permitting rules for geothermal development, a package that drew support from Republicans, Democrats and the Trump administration. Faster permitting does not solve the rate-base question, but it shortens the gap between lease sale and revenue.3
The uncomfortable part of this story is the divergence between the federal push and the state-level regulatory reality. The BLM lease sale showed that proximity to high-voltage transmission was the strongest financial factor in land value, with access to transmission adding about $43 per acre in estimated value. But the utilities that must build those transmission connections are the same ones negotiating with state commissions over who bears the cost and who earns the return.7
Fervo Energy, the leading next-generation geothermal startup, signed a three-year binding turbine supply agreement with Turboden America in April, a sign that the development pipeline is moving from land acquisition to equipment procurement. More turbines moving through supply chains means developers expect to drill, and drilling requires the demand certainty that only regulated utilities or large corporate off-takers can provide.1
Analysts have pegged the geothermal market's compound annual growth rate at 10.42% through 2031, with Asia-Pacific the fastest-growing region, according to a Mordor Intelligence forecast distributed via press release. That forecast is promotional material; treat its precision with suspicion. The direction is right, the exact rate is not something anyone can verify.4
What decides the US trajectory is whether state regulators outside Massachusetts and Texas adopt the utility ownership model in the next two biennial rate cases. The Framingham experiment worked as a pilot. The federal money and the BLM record prices provide the capital and the acreage. The missing piece is a regulatory precedent that lets utilities put geothermal networks in rate base as a standard practice rather than a special project. The next signal is any state commission order that approves a geothermal network under a general rate case, not a pilot program.2,7