Why the World’s Largest Solar Thermal Plant Failed

Located on roughly 1,420 hectares near the California-Nevada border in San Bernardino County, Ivanpah began commercial operation in February 2014 after four years of construction. The facility received a massive federal loan guarantee from the U.S. Department of Energy, placing the financial risk of an unproven technology largely on taxpayers. Instead of traditional photovoltaic panels, the installation relies on 173,500 computer-controlled mirrors, or heliostats, that reflect sunlight onto receivers atop three 140-meter towers to heat liquid and drive steam turbines, according to project documentation.

Gas Dependency and Early Production Shortfalls

Performance issues emerged shortly after the facility opened. According to a June 2015 report by the Wall Street Journal, Ivanpah produced only 40 percent of its targeted one million megawatt-hours during its first 15 months of operation. The shortfall stemmed from the operational requirement to heat the plant’s boilers every morning before the mirrors could generate steam.

Despite being marketed as a zero-emission solar facility, Ivanpah consumed significant amounts of natural gas to reach operating temperatures during morning startup cycles, alongside auxiliary and nighttime preservation boilers. To accommodate these operational realities, the California Energy Commission approved an increase in the plant’s authorized annual natural gas consumption from 328 million cubic feet to 525 million cubic feet in August 2014. Critics note that this reliance meant the installation burned fossil fuels daily just to initiate the generation of solar power.

Market Pressures and Contract Terminations

The economic viability of the project eroded as traditional photovoltaic technology experienced steep price declines. Power purchase agreements signed around 2009 priced Ivanpah’s electricity at roughly $200 per megawatt-hour. By the 2020s, utility-scale photovoltaic installations were producing power far more cheaply, rendering the concentrated solar power (CSP) plant’s output economically uncompetitive.

Pacific Gas & Electric (PG&E), the primary utility buyer for two of the plant’s three units, sought to terminate its power purchase agreements in 2023 to lower costs for ratepayers. NRG Energy, an owner of the facility, acknowledged the shift in market dynamics, stating that while Ivanpah successfully demonstrated CSP technology, it was ultimately surpassed by the lower capital and operating costs of photovoltaics. PG&E finalized the termination of two of its three contracts with Ivanpah’s owners in January 2025.

Regulatory Hurdles and Grid Reliability

Despite agreements between operators and buyers to wind down operations, the California Public Utilities Commission (CPUC) rejected the proposed contract terminations without prejudice. The regulatory body cited grid reliability, increasing electricity demand, and the preservation of existing clean energy generation as reasons to keep the units online. Commissioners noted that abandoning the transmission infrastructure investments associated with the site would create losses exceeding those cited by the utilities.

An analysis by the Institute for Energy Research estimated that keeping the facility operational under these terms imposes tens of millions of dollars in extra costs on utility customers. Energy experts cited by SolarPACES point to the plant’s lack of thermal energy storage as a structural flaw, leaving it unable to shift generation to hours when electricity demand and prices peak. Proposals to retrofit the towers with molten salt storage systems have been discussed as a potential alternative to burning natural gas for morning startups, though the facility’s immediate future remains tied to its current regulatory mandates.