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.
These projects are real, and the engineering is not in doubt. Operators of gas turbines have successfully tested blends from 5% to as much as 44% hydrogen. The question is whether there will be hydrogen to burn, at a price that makes sense, and whether burning it in power plants is the best use. On the evidence of current federal data, the answer to the first part is not yet, and to the second part, probably not for most of the hydrogen that will be produced.
Who uses hydrogen today
The Energy Information Administration's survey data show that US hydrogen is overwhelmingly an industrial feedstock. Total production in 2018 was about 10 million metric tons. Petroleum refiners used 68% of it and nitrogen fertilizer producers 21%. Around 40% was merchant hydrogen sold by industrial gas companies. About two-thirds came from steam methane reforming of natural gas, and the remaining third was a byproduct of other industrial processes.
Large industrial users pay the least. 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. Industries needing very pure hydrogen, such as electrical equipment makers, paid $86.19.
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. That is the benchmark any cleaner hydrogen has to compete with in its current uses.
The electrolyzer pipeline
Electrolyzers, which split water using electricity, are the route to low-emission hydrogen that does not depend on carbon capture. Current US capacity is small, at 116 MW. Planned installations tracked by the Department of Energy's Hydrogen Program would expand that to 4,524 MW if all were built.
That would be a large proportional increase from a small base. In energy terms, it would still be modest compared with the volume of hydrogen refiners and fertilizer plants already consume. The first tranche of clean hydrogen, if it arrives at scale, has obvious buyers in those industries, where it would directly displace hydrogen made from unabated natural gas.
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. Treasury's proposed guidance, released in December 2023, would require electrolyzers to match their power use with new clean generation in the same region and, eventually, in the same hour. Developers have argued that these requirements would make many projects uneconomic. Supporters argue they are necessary to prevent electrolyzers from raising emissions by drawing power from fossil plants. Until the final guidance is issued, much of the planned pipeline is waiting.
Why power plants are a hard market for hydrogen
Burning hydrogen in a gas turbine is technically straightforward at low blends. At high blends, combustion behavior changes, nitrogen oxide emissions can rise and turbine modifications become necessary. A 30% blend by volume also delivers much less than 30% of the plant's energy from hydrogen, because hydrogen has about a third of the energy content of natural gas per unit volume. The emission reduction from a 30% volumetric blend is therefore well below 30%.
Cost is the larger obstacle. Hydrogen at current clean production costs is far more expensive per unit of energy than pipeline gas at Henry Hub prices of $2 to $3. A power plant can switch to hydrogen only when hydrogen is available in volume, delivered by pipeline or produced on site, and when either policy or market prices make it worthwhile.
There are also competing uses that value hydrogen more highly. A refinery or ammonia plant uses hydrogen as a chemical input that cannot be replaced by electricity. A power plant uses it as a fuel that can be replaced by many other things, including batteries, other low-carbon generation and demand response. When clean hydrogen is scarce, it will be worth more in the refinery than in the turbine.
Where hydrogen in power might make sense
There is one role where hydrogen in power has a real case: long-duration, seasonal storage for systems with very high renewable shares. Hydrogen can be produced from surplus electricity during periods of high wind and solar output, stored in salt caverns, and burned in the rare weeks when renewable output is low for long periods. The Intermountain project in Utah is designed partly around this idea, with nearby salt caverns as storage.
That is a niche, but a valuable one. It does not require hydrogen to be cheap. It requires hydrogen to be available in the few hundred hours a year when alternatives are scarce.
How to read the hydrogen-ready label
For utilities and regulators, the label is best read as an option. A plant built to cofire hydrogen can keep burning natural gas if hydrogen never becomes economic, and can switch if it does. That flexibility has some value, and the cost of building it in at the design stage is usually modest compared with the cost of retrofitting later.
What the label should not do is justify building a gas plant on the assumption that it will become low-carbon later. The fuel to make that happen does not yet exist in volume, its price is uncertain, and its best uses lie elsewhere. The United States has a hydrogen market. It is a refinery and fertilizer market, and it will probably stay one for most of the next decade.