Hydrogen-Ready Gas Turbines Are an Option, Not a Plan. The US Hydrogen Market Is Still a Refinery Market

Several new gas-fired power plants in the United States are being marketed as hydrogen-capable. Kindle Energy says its 678 megawatt Magnolia plant in Louisiana, due in 2025, could cofire up to 50% hydrogen. The Intermountain Power Agency's new 840 MW combined-cycle plant in Utah, replacing an 1,800 MW coal plant, is designed to burn a 30% hydrogen blend. Entergy's 1,158 MW Orange County Advanced Power Station in Texas, expected by mid-2026, is reported in the trade press to be capable of 30% hydrogen.

Duke Energy plans to convert its 74 MW DeBary peaker in Florida to run on hydrogen alone. Operators of gas turbines have successfully tested blends from 5% to as much as 44% hydrogen. The Energy Information Administration's survey data show that US hydrogen is overwhelmingly an industrial feedstock. In 2018, the chemicals subsector paid an average of $6.18 per million British thermal units, and the average across all manufacturing was $6.82. The National Energy Technology Laboratory estimated the levelized cost of hydrogen from a new merchant steam methane reformer at $1.06 per kilogram in 2018, or $8.00 per MMBtu including compression, without carbon capture.

Electrolyzers, which split water using electricity, are the route to low-emission hydrogen that does not depend on carbon capture. The economics depend heavily on the clean hydrogen production tax credit created by the Inflation Reduction Act, known as 45V, worth up to $3 per kilogram for the lowest-emission hydrogen. Burning hydrogen in a gas turbine is technically straightforward at low blends. There is one role where hydrogen in power has a real case: long-duration, seasonal storage for systems with very high renewable shares.

For utilities and regulators, the label is best read as an option. What the label should not do is justify building a gas plant on the assumption that it will become low-carbon later.