Coal Country’s Second Act: Abandoned Mines Become Grid Batteries
As lithium supply chains tighten and renewable integration strains the US grid, underground gravity batteries and compressed-air systems turn stranded industrial assets into domestic energy storage infrastructure.
Researchers at Oak Ridge National Laboratory published modeling tools in March 2026 that could transform thousands of abandoned US coal mines into underground pumped storage hydropower facilities, marking a shift in how the country addresses grid-scale energy storage without dependence on lithium batteries.
The work developed advanced hydrodynamic and chemical models to assess the feasibility of converting abandoned Coal mines into underground pumped storage hydropower (PSH) facilities, according to Oak Ridge Today. PSH currently accounts for over 90 percent of all utility-scale energy storage in the United States, and the development offers a dual solution for the US energy landscape by providing long-duration storage needed for a carbon-neutral grid while revitalizing former mining communities, according to Interesting Engineering.
The United States faces approximately 550,000 abandoned mines, according to Reasons to be Cheerful. These sites represent stranded infrastructure in regions where coal employment has collapsed, but they also hold structural advantages for energy storage: deep vertical shafts, existing grid connections, and geographic distribution across states where renewable integration is accelerating fastest.
Gravity and Compressed Air Challenge Lithium Dominance
Two competing technologies are vying to exploit underground mine infrastructure: Underground Gravity Energy Storage (UGES) and compressed-air energy storage (CAES). Both bypass lithium-ion batteries entirely, eliminating exposure to supply chain vulnerabilities concentrated in Chinese refining and Democratic Republic of Congo mining operations.
UGES generates electricity by lowering sand into an underground mine and converting the potential energy of the sand into electricity via regenerative braking, then lifting the sand from the mine to an upper reservoir using electric motors to store energy when electricity is cheap, according to research published by the International Institute for Applied Systems Analysis. Investment costs for UGES range from one to 10 dollars per kilowatt-hour, with global potential estimated between seven and 70 terawatt-hours, concentrated in China, India, Russia, and the USA, according to Interesting Engineering.
Compressed-air systems follow different mechanics. In times of excess electricity on the grid, a compressed air energy storage plant can compress air and store it in a cavern underground, then at times when demand is high, the stored air can be released and the energy recuperated, according to the Climate Technology Centre & Network. A 110-megawatt CAES plant has been in operation near McIntosh, Alabama since 1991, proving commercial viability at scale.
| Technology | Energy Medium | Storage Duration | Cost ($/kWh) | Self-Discharge |
|---|---|---|---|---|
| UGES (Gravity) | Sand/rock | Weeks to years | $1-10 | Zero |
| CAES | Compressed air | Hours to days | Variable | Low pressure loss |
| Underground PSH | Water | Hours to days | Higher capex | Minimal |
| Lithium-ion | Electrochemical | 2-4 hours | $150-200 | ~5% monthly |
Lithium Dependency Creates Strategic Vulnerability
The shift toward mine-based storage responds to tightening constraints across lithium battery Supply Chains. The Democratic Republic of Congo accounts for 70 percent of the world’s cobalt production, while Australia and Chile combined account for 75 percent of global lithium production, according to the International Energy Agency. Chinese companies control 95 percent of cobalt refining capacity and dominate downstream battery cell production.
Since January 2025, battery storage costs have risen 56 to 69 percent due to tariffs, and new Foreign Entity of Concern (FEOC) regulations starting in 2026 threaten to increase costs and complexity further, according to pv magazine. Battery energy storage systems are expected to see mid-double-digit growth in 2026 and continue to be the fastest growing lithium demand source, according to S&P Global, but that growth depends on supply chains the US does not control.
Domestic manufacturing capacity remains limited. Wood Mackenzie and the American Clean Power Association expected the United States to install 49 gigawatt-hours of storage across all markets in 2025, an amount that can be met by four established domestic lithium cell manufacturers in 2026, according to Solar Power World. But that capacity came from retooled electric vehicle battery lines, not purpose-built stationary storage plants, and remains vulnerable to policy shifts affecting EV subsidies.
Pumped storage hydropower traditionally requires mountainous terrain with elevation differentials of hundreds of meters. By moving operations underground and using existing mine shafts as lower reservoirs, the technology becomes viable in flatter regions like the Midwest and Appalachia where coal mining historically concentrated. This eliminates the geographic constraint that has limited PSH deployment to the Pacific Northwest, Northeast, and isolated mountain states.
Grid Integration Challenges Mount
The US grid faces compounding stress from renewable integration at a moment when transmission infrastructure and interconnection processes are already backlogged. The time required to secure a grid connection has increased by 70 percent over the last decade, and withdrawal rates remain high at 80 percent, suggesting a constrained transmission system that jeopardizes energy transition targets, according to research published in Joule.
Global renewable capacity reached 3,372 gigawatts in 2023, but grid adaptation lags, creating a technological gap. Key barriers include voltage fluctuations and frequency instability from reduced inertia, with integration costs exceeding $25 to $40 per megawatt-hour at 50 percent penetration, according to analysis in the International Journal of Sustainable Energy. Storage addresses these issues by providing inertia substitutes and voltage support, but only if it can be deployed at scale and connected to transmission quickly.
Mine-based storage offers advantages here. Using deep shafts of abandoned mines as lower reservoirs instead of building new mountainside facilities significantly slashes construction costs and accelerates deployment timelines, according to Interesting Engineering. Many former mines retain grid connections from their operational years, reducing interconnection delays that have plagued standalone battery projects.
Economic and Political Arithmetic
The economics depend on utilization rates and revenue stacking. Energy recovery efficiency and energy storage density of isobaric CAES are 70.60 percent and 5.74 kilowatt-hours per cubic meter respectively, while energy storage density is much greater than that of pumped hydro storage at 1.14 kilowatt-hours per cubic meter at the same depth, according to research in Energy. Higher storage density means smaller mine volumes generate equivalent output, reducing site preparation costs.
Policy support remains uneven. The Infrastructure Investment and Jobs Act authorized a $500 million program to construct clean energy demonstration projects on current or former mine lands, including energy storage and nuclear projects, according to the Environmental and Energy Study Institute. The Inflation Reduction Act’s energy community tax credits provide additional support for projects in former coal regions, but actual deployment depends on state regulators approving cost recovery for vertically integrated utilities or merchant developers securing power purchase agreements in competitive markets.
Coal communities see potential for employment continuity. The system can be installed in old coal mines, providing jobs for communities where mines have shuttered, according to Big Think. Technical skills in underground engineering, heavy equipment operation, and electrical systems transfer directly from mining to storage facility operation and maintenance.
“Underground PSH is an exciting opportunity, but we have to overcome challenges like chemical erosion and structural stability. Our modeling tools will help industry partners evaluate these risks and make informed decisions.”
– Thien Nguyen, Senior Researcher, Oak Ridge National Laboratory
What to Watch
Oak Ridge’s modeling tools will undergo validation through industry partnerships evaluating specific mine sites in Appalachia and the Midwest. The first commercial-scale underground PSH or UGES project will establish construction timelines, permitting duration, and actual capital costs against theoretical projections. Those figures determine whether the technology scales or remains a demonstration curiosity.
FEOC compliance deadlines will force decisions on domestic versus imported battery systems throughout 2026. Projects already in interconnection queues may pivot to non-lithium alternatives if supply chain restrictions or tariffs make battery economics unworkable. The gap between lithium-ion demand growth and FEOC-compliant domestic supply creates the opening for alternative storage technologies to gain market share.
State integrated resource plans filed in the second half of 2026 will show whether utilities model mine-based storage as a viable capacity resource or continue to default to four-hour lithium-ion batteries. That modeling drives procurement decisions that shape what actually gets built between now and 2030. The difference between treating abandoned mines as liabilities or infrastructure assets plays out in these regulatory filings.