Should power plants burn clean hydrogen to make electricity?

Canary Media thanks Verdagy for its support of the Clean Hydrogen series.

Utilities want to burn clean hydrogen in gas plants to unlock a reliable, carbon-free electricity system. But a lot of climate hawks have different words for hydrogen as a power-plant fuel: a colossal waste of money, a dangerous distraction, greenwashing par excellence and ​“a crime against thermodynamics.”

Elsewhere this week, Canary Media has covered efforts to make large-scale clean hydrogen production a material reality. While that supply works its way into existence, other people are figuring out what to actually do with the hydrogen. Power companies’ interest in this molecule stems from a simple proposition: If you burn hydrogen, you make electricity without carbon emissions. Short of a long-awaited nuclear renaissance, hydrogen could be the best option for carbon-free power at times when the sun isn’t shining, the wind is slack, and your batteries have discharged their stores.

Utilities might eventually be able to rely on novel long-duration batteries, advanced geothermal, gas plants with effective carbon capture, small modular nuclear, and even a late-stage revival of big old-school nuclear. Or clean hydrogen, tucked away in salt caverns for the big peak hours of the year when other clean power plants can’t produce enough. No clear winner has emerged for this category.

“Every utility should be thinking about how they’re going to meet demand as their grid shifts toward more intermittent resources and what sorts of clean, firm power they have in their mix,” said Emily Kent, U.S. director for zero-carbon fuels at the Clean Air Task Force. ​“We don’t know what technologies will be available in the future, but for now it’s a gap that hydrogen could help fill.”

But burning clean hydrogen can take many forms, many of which don’t look so appealing. Several utilities are exploring hydrogen combustion by mixing small amounts into the fossil-gas supply at existing plants. This produces very marginal greenhouse gas reductions at considerable cost. For now, the industry just needs to kick the tires on hydrogen combustion to know how to do it safely and efficiently in the future.

“We need to test starting up [and] shutting down, and to validate that systems and controls and best practices can be documented and repeated,” said Jeffery Preece, who oversees hydrogen research at EPRI, the largely utility-funded nonprofit research institute for the electricity sector. ​“There’s a lot of fundamentals we haven’t quite documented that we think will be necessary.”

The ambitions don’t stop with a 5% hydrogen blend. Several utilities have described large new gas-plant projects as ​“cleaner” options because they have the theoretical capacity to one day burn hydrogen. This fuel substitution isn’t happening anytime soon — for now, utilities have no way to obtain enough clean hydrogen for substantial operations. But plans for large-scale hydrogen combustion concern climate analysts because it is a roundabout, expensive and energetically wasteful way to turn clean electrons back into clean electrons, especially when there are so many more efficient and cost-effective alternatives for clean power generation.

“If hydrogen is going to play a long-duration energy storage role, it’s really small,” Kent said. ​“You don’t need a huge buildout of hydrogen for power plants to play that role.” Significant hydrogen combustion for round-the-clock baseload power ​“is probably not an appropriate path,” she added.

Vague promises about far-off hydrogen capabilities could also lend a green halo to fossil fuel infrastructure that may never actually use clean hydrogen to generate power.

Can you just burn hydrogen in a fossil gas plant?

Today’s fleet of gas turbines — the largest electricity source in the U.S., thanks to the shale revolution — can burn hydrogen. But both practical and legal reasons limit the amount.

Natural gas is basically methane; hydrogen is much less energy-dense, so you need to burn more of it to get the same amount of energy output. That necessitates bigger valves, pipes and nozzles to deliver higher volumes of gas. Hydrogen also burns hotter than methane, which produces more NO_x, a regulated air pollutant that needs to be mitigated.

Long Ridge Energy Terminal, an independent power producer on Ohio’s riparian border with West Virginia, claimed in 2022 that it was the first large combined-cycle plant in the U.S. to blend hydrogen into its fuel mix. Large corporate customers were asking for carbon-free electricity in the hours that renewables weren’t supplying the regional PJM wholesale markets, said the plant’s program manager, Mark Barry. The plant owners decided to use their own money to test if hydrogen power could meet that demand for clean energy at specific times.

Long Ridge bought truckloads of hydrogen from a nearby chlor-alkali plant, which produces the gas as a byproduct. Then the 485-megawatt plant successfully combusted a mix of 5% hydrogen, the maximum that the Ohio Power Siting Board allowed it to do, Barry noted. If they got the appropriate permissions, the plant could push to the 20% level with the current turbine by adding more catalysts to absorb the added NO_x emissions. Beyond that, Long Ridge needs to wait a few years for a new generation of GE combustors to raise the hydrogen blend to the 50% level, and then ultimately further on to the 100% level.

“The technical capability is there,” Barry said. ​“We would have no issue with round-the-clock operation — with [hydrogen] supply at a good price.”

A 230-megawatt Siemens Energy engine at Constellation’s Hillabee plant in Alabama hit a 38% hydrogen threshold last May, ​“with only minor modifications” to existing equipment. That test succeeded in ​“nearly doubling the previous blending record for similar generators,” per a company spokesperson. The carbon-reduction outcome was less impressive, given the lower energy density per volume of gas: Carbon emissions fell by just 15.6% compared to running solely on natural gas.

Some specialized turbines have indeed burned 100% hydrogen. Siemens Energy, one of the top global turbine manufacturers, successfully burned a pure hydrogen stream at a generator in Saillat-sur-Vienne, France last October. But that was a small industrial unit, generating roughly 14 megawatts. GE, too, is fast-tracking full hydrogen capabilities for its smaller gas turbines to complement wind and solar farms, said Jeremee Wetherby, carbon solutions leader at the turbine manufacturer; small turbines have the added benefit of not needing as much hydrogen.

Down the road, GE and Siemens Energy have both pledged to make all their new turbines capable of burning 100% hydrogen by 2030.

In short, technical and regulatory constraints prevent large power plants from burning more than a low-level blend of hydrogen with gas today. But the turbine industry is working to make standard turbine models ready to handle a pure stream of hydrogen. Finding that supply is the next major barrier to this purported clean energy solution.

Hydrogen won’t work for power plants until there’s a radically larger supply

Right now, U.S. clean hydrogen production has advanced slightly beyond zero. But there’s nowhere near enough to supply a fleet of power plants continuously. GE’s Wetherby estimates that the hydrogen needed to run a 1-gigawatt combined-cycle plant, the workhorse of the large gas fleet, would gobble up about 2% of global hydrogen production today.

EPRI has worked on several real-world tests of hydrogen-fired power plants. The longest test ran for eight whole hours, the time it took to consume all the gas delivered to the site by tube trailer.

Even if a power plant lucked into a hydrogen pipeline hookup, current costs make it bonkers to burn. For comparison to gas, Wetherby calculated that renewable hydrogen selling for $3 to $4 per kilogram equates to about $20 per million Btu. Natural gas at Henry Hub goes for less than $3 per MMBtu right now. Long Ridge actually extracts its own gas on-site, straight from the Marcellus Shale; clean hydrogen wouldn’t compete with its homegrown supply until it gets down to 25 cents per kilogram, way beyond the Department of Energy’s wildest dreams.

“This is all going to fundamentally come down to economics,” said GE’s Wetherby. ​“Today, the cost of hydrogen is really high, so it fits well in a peaking application where the demand and price for power is really high.”

In other words, even if a turbine installed today technically could burn 100% hydrogen around the clock, the costs would be outrageous. Scarcity dominates clean hydrogen supply currently, and will for the foreseeable future. That alone should curb any excessive desire to burn huge amounts of the stuff anytime soon. But if a jurisdiction needed more peak capacity to avoid seasonal outages and had serious climate policies in place preventing it from adding more fossil gas capacity, a hydrogen peaker could make sense when the right turbine product is available.

In the longer term, the key variable is how cheap and abundant clean hydrogen becomes. Some renewables evangelists I’ve interviewed see great things ahead: The cost of renewable-powered electrolysis will plummet just like the costs of wind, solar and batteries did in recent decades; this will make renewable hydrogen cheaper than any fuels humanity has ever seen, in their view. If you predict that the renewables success story will play out again in clean hydrogen, then it should assuage anxiety over rationing hydrogen to only the most worthy of causes.

Assuming markets price hydrogen efficiently (more on that in a moment), abundant hydrogen combustion in power plants would be a trailing indicator that the clean hydrogen revolution has really arrived. But if there’s not enough clean hydrogen to meet demand, power plant owners may find themselves competing with green steel producers and clean fertilizer factories for the stuff.

Cutting through the hype for clean hydrogen power plants

The complication to that assumption about efficient markets is that monopoly utilities enjoy certain protections from market forces that private competitors like Long Ridge do not.

Namely, regulated utilities pass on the costs of their power plant investments to their captive customers, while taking a markup for their guaranteed profits. They also typically pass along fuel costs to customers. The upshot: Customers and regulators need to keep an eye out for utilities that want to burn reckless amounts of expensive hydrogen anytime soon or claim a green premium for a plant that isn’t really reducing emissions.

Excessive hydrogen fuel costs are worrisome, but so is a utility touting a gas-plant investment as a clean energy advance because of its hydrogen compatibility without saying when — and to what extent — carbon-free fuel will actually enter the mix.

“When we are looking into what a utility is doing, we would want to see specific commitments to hydrogen blends,” said Kent, from Clean Air Task Force. Kicking around in the 5% range achieves ​“pretty insignificant” emissions reductions; a clear timeline to reaching high blends by specific dates shows a utility is serious about carbon-cutting.

Another criterion sounds silly to say but can’t be overlooked: A serious clean hydrogen power plant needs a dedicated supply of clean hydrogen. Otherwise, it’s just an unusually expensive gas plant.

The more enterprising utilities aren’t waiting around for someone else to grab those sweet hydrogen production tax credits. Florida Power & Light installed 25 megawatts of solar-powered electrolyzers at its Cavendish hydrogen test site in Florida. It plans to burn that clean hydrogen in a 5% blend at an existing gas turbine nearby. Self-producing means the utility knows it’s clean and can control the pace of deliveries. If self-supply isn’t possible, there are enough hungry hydrogen developers searching for creditworthy anchor customers that you’d have to try hard not to land a supply deal — especially on the Gulf Coast.

In contrast, lacking a clear plan for hydrogen supply creates problems.

For instance, Entergy Texas proposed to install a big new Mitsubishi turbine capable of burning 30% hydrogen on day one, for an added cost of $91 million. The 1,215-megawatt combined-cycle plant is now under construction near Bridge City, and I’d seen Entergy Texas CEO Eliecer Viamontes praise it as ​“strategically located near hydrogen producers, pipeline, storage and off-takers to leverage this important source of clean and reliable energy in the future.” This looked like a big test case for the viability of large-scale hydrogen power plants.

I reached out to ask where the plant would source its hydrogen, how carbon-intensive it would be and when the plant anticipates reaching high levels of hydrogen combustion.

Entergy did not have answers to share on those questions. It turns out that when Texas regulators approved the gas plant, they did not grant the hydrogen request, and their neutral statement of facts reads more like a dis track:

• “Entergy did not conduct any economic or cost-benefit analysis of the Orange County station’s hydrogen component.”
• “Entergy did not produce any forecasts for the price of hydrogen on a dollar per thousand cubic feet or million British thermal unit basis.”
• “Entergy did not meet its burden to prove the improvement of service or lowering of cost to consumers.”

That rebuke prevented Entergy from charging the costs of a deeply uncertain hydrogen project to its customers. In a statement to Canary Media, though, the company framed the regulator’s decision more hopefully, saying that the rejection ​“preserves the opportunity for Entergy Texas to make upgrades that would unlock the turbines’ off-the-shelf capability to co-fire up to 30% hydrogen by volume in the future.”

The trouble is, a latent ability to unlock future capabilities doesn’t keep the lights on, nor does it avoid any amount of carbon dioxide emissions.

Verdagy manufactures an advanced AWE electrolyzer system that has superior performance to almost any system in the market — high current densities and the largest membranes leading to higher hydrogen production, high efficiencies leading to lower LCOH, and wide dynamic range and fast turndowns to seamlessly integrate with renewables. In addition to its Silicon Valley factory, Verdagy operates its R&D and highly automated commercial pilot plants in Moss Landing, California, where it continues to advance its cutting-edge technology.