The problem with making green hydrogen to fuel power plants

Today, utility Florida Power & Light will begin operations at its Cavendish NextGen Hydrogen Hub, one of the country’s first green hydrogen facilities. The 25-megawatt project will use solar power to split water into oxygen and hydrogen atoms, and then blend that hydrogen into fossil gas used to power a turbine generating electricity.

It’s one of the first attempts by a U.S. utility to curb emissions using green hydrogen, a fuel that is in short supply today but which experts expect will play an important role in decarbonizing heavy industries.

Many U.S. utilities are staking similar hopes on green hydrogen as a path to help the power sector reach a low- or zero-carbon future. FPL, for example, says the new green hydrogen project will help it ​“assess the long-term viability of green hydrogen” as part of FPL parent company NextEra’s goal of eliminating carbon emissions from its operations by 2045.

But according to energy experts, converting clean energy into hydrogen just to use that hydrogen to generate more electricity later is, in most cases, a bad idea. The main concern is that the process will end up wasting enormous amounts of clean power — and green hydrogen far more valuable for use in other ways — in pursuit of a zero-carbon chimera.

That’s a problem, because several utilities, FPL included, are using these plans as a rationale to continue investing in new fossil-gas power plants, even though it will be costly to switch that infrastructure from burning fossil gas to burning hydrogen.

The fundamental problem lies in the laws of physics. Between 50 and 80 percent of the energy value of clean electricity is lost in the process of making hydrogen and then burning it to generate electricity. Some of those losses occur in the electrolysis process, which is roughly 70 to 75 percent efficient. But the lion’s share of losses come in burning hydrogen to spin a generator, a process which at best is roughly 64 percent efficient using the latest combined-cycle gas turbines and can drop to 35 to 42 percent efficiency in older combustion turbines.

So unless clean electricity can’t possibly be used in its original form, it’s almost always better to avoid the wasteful process of using it to make hydrogen meant to generate electricity later. That point has been hammered home over and over by one of the world’s preeminent experts on clean energy systems, Michael Liebreich, chair of Liebreich Associates and founder of BloombergNEF.

Liebreich’s widely circulated ​“clean hydrogen ladder” graphic has consistently ranked ​“power-system balancing” — the activity that FPL’s gas-fired power plants will likely perform — as one of the least competitive applications of green hydrogen in terms of both cost and carbon-reduction capability.

Energy experts say the country will need millions of tons of low- to zero-carbon hydrogen to replace the millions of tons of fossil-gas-derived hydrogen now used for refining and fertilizer and chemicals production, as well as to fuel heavy industries including shipping, aviation, steelmaking and cement production.

But ​“in the power system, you won’t routinely use hydrogen to generate power because the cycle losses — going from power to green hydrogen, storing it, moving it around and then using it to generate electricity — are simply too big,” Liebreich wrote in his latest LinkedIn update to his ladder graphic.

Lithium-ion batteries that can store excess clean energy for hours at a time at roughly 80 to 85 percent round-trip efficiency, and software and payment structures that encourage buildings to reduce and shift when they use electricity to reduce demand for power, ​“will simply be waaaay cheaper and simpler than hydrogen” when it comes to short-term power balancing.

The problem with power-to-hydrogen-to-power

Liebreich’s critiques have been echoed by a number of other analyses in recent years.

One example is a 2022 report by San Francisco–based think tank Energy Innovation, which concluded that many of the green hydrogen use cases being proposed by utilities are both economically and environmentally impractical — and even counterproductive.

Those include plans like FPL’s new project, where increasing amounts of hydrogen are blended with fossil gas to displace — and eventually replace — it for use in power generation. This idea is being used by many utilities to justify investment in new fossil-gas power plants, including FPL, Gulf Coast utility Entergy, Southeastern utility Duke Energy and giant municipal utility Los Angeles Department of Water and Power.

While potentially technically feasible, burning blends of hydrogen and fossil gas isn’t a viable large-scale solution to the power sector’s emissions challenges, Energy Innovation policy analyst Dan Esposito told Canary Media. (The exception is when that hydrogen is providing long-duration energy storage services — more on that below.)

In fact, blending hydrogen over the usual course of a fossil gas plant’s operations risks diverting zero-carbon hydrogen from being used where it’s really needed to an application where hydrogen stands little to no chance of being cost-effective in the long term, he said.

Today, the U.S. produces nearly no ​“green” hydrogen, which is hydrogen made via electrolysis using zero-carbon energy. Green hydrogen is currently about three times more expensive than making hydrogen via steam methane reforming of fossil gas — the ​“gray hydrogen” method used to produce the vast majority of today’s supply.

Reducing the cost difference between green and gray hydrogen is a chief goal of the Biden administration, which has launched a Hydrogen Shot initiative aimed at driving down the price of clean hydrogen to $1 per kilogram in the next decade, compared to today’s cost of $5 to $6 per kilogram. It’s also the target of $9.5 billion in federal grants and incentives from 2021’s Bipartisan Infrastructure Law. But most important is the potentially game-changing tax credit created by last year’s Inflation Reduction Act of up to $3 per kilogram to hydrogen made with zero to very low carbon emissions.

That subsidy could make green hydrogen cost-competitive with hydrogen made from fossil gas in the near term, industry experts say. The flip side is that it could also make it highly lucrative to produce the fuel for less-than-ideal purposes, like power-system balancing.

There’s now a battle underway over the precise rules for how that carbon emissions footprint is calculated, which the U.S. Treasury Department is expected to announce later this month. A group of climate scientists, energy analysts, environmental groups and would-be hydrogen producers are demanding strict rules that limit the most lucrative tax credits to hydrogen made using electricity from newly built clean energy sources that are matched to when the hydrogen is produced on an hour-by-hour basis, warning that laxer rules could subsidize ​“green” hydrogen that actually emits far more carbon than gray hydrogen.

On the other side of that debate is NextEra Energy, FPL’s parent company, along with a number of other utilities and hydrogen producers that are lobbying the Treasury Department to set more relaxed eligibility standards for the clean electricity they use to make hydrogen, allowing workarounds such as unbundled renewable energy credits and the use of existing zero-carbon resources such as nuclear power and hydropower. Imposing more stringent rules could doom the economics of an industry that’s struggling to come into being, they contend.

But beneath this highly public controversy, clean energy groups are warning of other potential misuses of the tax-credit program that could be enabled by overly lax rules. One example is the risk that ​“power-to-hydrogen-to-power” processes like those that FPL is now testing could benefit financially from a practice that Energy Innovation described in comments to the Treasury Department as ​“hydrogen-washing.”

The Inflation Reduction Act provides tax credits for burning hydrogen to generate power as well as for making low-carbon hydrogen, Esposito explained. This could allow a company that owns both electrolysis facilities and power plants, as FPL does, to make and burn hydrogen in a cycle that provides no value above what renewables could have done on their own, wasting energy while creating a lucrative flow of tax-credit revenue on both sides of the equation.

This kind of practice could include making hydrogen with solar power generated at times when the power grid has ample demand to absorb it, and then immediately using that hydrogen to generate more electricity, he said.

The $3 per kilogram of hydrogen provided by the 45V tax credit equates to a $60 per megawatt-hour subsidy for power generated by turbines using it — quite a bit higher than the typical wholesale price a utility can fetch for clean electricity in the U.S. That could encourage FPL and other hydrogen-producing utilities to make as much green hydrogen as possible and use it as quickly as possible, rather than storing it over the long term for cloudy or windless days.

Using solar power to make hydrogen is ​“going to be significantly more profitable than sending energy to the grid” or using batteries to store that power, Esposito noted. But after burning that hydrogen to generate power, ​“you’re sending about 40 percent of the useful energy out instead of 100 percent.” 

The promise of hydrogen for long-duration energy storage

FPL declined to respond to questions seeking more precise details on exactly how it will use the green hydrogen it produces. Esposito highlighted that FPL’s hydrogen hub appears to be set up to use electricity only from the 74.5-megawatt Cavendish solar farm surrounding the hub, limiting the risk that it will use dirtier grid power to make hydrogen.

But there’s no guarantee that the project will use the hydrogen produced from that solar power in the optimal way: to store surplus clean electricity for long-term use, during days or weeks of cloudy and windless weather, when grids with lots of renewable energy will need always-available resources to step in.

“The standout use for clean hydrogen here is for long-term storage,” Liebreich wrote. His green-hydrogen ladder ranks this use case near the top of his scale, along with shipping, steelmaking and chemical production.

In this case, ​“long-term” means storing hydrogen for months at a time. A handful of large-scale clean hydrogen projects, such as the ACES Delta project in Utah, are targeting this ​“seasonal” energy storage application. But the ACES project is paired with enormous underground salt caverns that can store massive amounts of hydrogen. FPL’s project uses aboveground storage tanks, which are a far more costly way to store large volumes of hydrogen.

There are still potentially valid reasons for smaller-scale ​“power-to-hydrogen-to-power” projects like FPL’s Cavendish NextGen Hydrogen Hub to move forward, Esposito stressed. ​“It’s good to test production, transport and storage of hydrogen,” simply as a way to take the first steps toward building a cost-effective green hydrogen supply chain.

But what’s really needed, he said, are structures that incentivize utilities to invest in the storage capacity needed to save hydrogen for when it’s truly most valuable for the grid. Right now, energy-market structures don’t offer seasonal storage projects of this kind a clear path to earning money, Esposito said.

That makes it hard to fault any utility for failing to invest in long-duration storage for the hydrogen they’re producing, he said. ​“But that’s what we want to get to — and that’s the only thing that makes sense” for hydrogen produced by projects that aren’t already in construction in 2032 when the federal tax credit expires.

Energy Innovation has modeled how the U.S. power grid could reach 80 to 90 percent clean electricity without these kinds of long-duration energy storage resources, giving utilities and regulators time to assess other options for supplying that final 10 to 20 percent. Hydrogen may be part of the answer, but utilities will need to quickly move toward using pure hydrogen rather than blends with fossil gas to meaningfully reduce climate pollution, he said — and other emerging technologies will be battling for this seasonal storage market share.

Also, although hydrogen doesn’t emit fossil gas when it burns, it does increase the emissions of harmful, smog-forming nitrogen oxides compared to burning fossil gas. That puts the onus on utilities to invest in mitigating the harms those increased emissions could cause to the environment and to communities close to power plants.

“It’s good to test making hydrogen, and moving it around, and storing it and burning it, so they can be ready in 10 or 20 years,” he said. ​“But I’d want to watch to make sure they’re making progress toward this long-duration storage, rather than advocating for more production subsidies for making hydrogen and then blending it and burning it in the middle of the day.”

“Only once it becomes not economically optimal to build more renewables or more [battery] storage to get that last bit of gas out of your system — only then do you start thinking about hydrogen,” he added.