ANALYSIS | Why blue hydrogen may grow faster than green H2 in the US

“There are more projects for green, but more spread out,” explains Minh Khoi Le, Rystad’s head of hydrogen research.

Meanwhile, a Hydrogen Council report published last month indicates that more than 70% of North America’s announced capacity up to 2030 is “low-carbon hydrogen”, ie, blue.

And these projects also represent 90% of the capacity that had taken final investment decisions (FID) by the end of last year — some 1.8 million tonnes annually.

In contrast, only about 200,000 tonnes of green hydrogen capacity has gotten to this stage, although new projects continue to be announced, with many progressing to feasibility studies or front-end engineering and design.

So why has large-scale blue hydrogen taken an early lead?

But the scale of upstream methane emissions and carbon intensity of power generation means that even if a steam methane reforming or autothermal reforming facility has a 95% capture rate, its emissions intensity might keep it relegated to the lower tiers of the 45V tax credit which only award $0.75 or $0.60 per kg.

“Developers need a high carbon capture rate, lower upstream and power emissions to reach Tier 2,” says van Dorsten.

“What the IRA does is it makes blue hydrogen just a tiny bit more expensive than grey and green just a tiny bit more expensive than blue — although green is going to get cheaper at some point,” he says.

Part of the reason for the cost gap between green and blue is that natural gas is extremely cheap in the US. While the country saw major volatility in 2022, with spot prices on the Texas Henry Hub exchange spiking to nearly $10 per MMBTU in the second half of the year, gas has remained steady below $3 per MMBTU in recent months.

This means that hydrogen made from fossil gas is also cheap to produce.

Green is estimated to cost between $2-7.08/kg — again, depending on region and electrolyser technology — meaning that at the lower end, assuming producers can meet all requirements for the full $3/kg tax credit, it could be competitive with grey.

However, Le cautions that it is not just a case of subtracting the $3/kg tax credit from the levelised cost of hydrogen in a given location, because costs for electricity transmission and hydrogen storage — and transportation to end users — can vary from project to project.

“[The tax credit] is helpful, but it doesn’t bring the cost to zero,” he says.

But the preference for blue over green might not just be a matter of attractive government subsidies closing the cost gap, but a case of project economics and familiarity with the feedstock.

“If you look at who’s developing and buying [low-carbon] hydrogen, they tend to be companies already versed in grey hydrogen today, which would see producing blue as a bit easier than green,” Tengler says.

“The same goes for the buyers — they often need hydrogen to come in large, uninterrupted volumes,” he adds.

Green hydrogen production depends on variable renewable electricity input — requiring either energy storage or grid back-up to keep powering the electrolyser, or large-scale hydrogen storage to keep reserves on hand for steady supply to offtakers, all of which adds to costs.

The US Treasury is due to set definitions for how clean hydrogen can be produced by the end of the summer, and it is considering setting similar rules to the EU, such as requirements for “additionality” — ie, that all renewable energy providing power to electrolysers is new ­— and “temporal correlation” — how closely renewables generation must be matched with electrolyser usage.

The idea behind these is to ensure that electrolysers do not increase the overall demand for ggrid electricity, which might require additional fossil-fuel power generation to plug the energy gap.

But some industry voices have argued that meeting these rules would substantially add to the cost of producing green hydrogen — further widening the cost gap with grey.

Le agrees that blue hydrogen has an advantage over green when it comes to storage and production on demand, due to existing natural gas infrastructure and the fact that most grey H2 is currently produced close to major offtakers in the refining and chemical sectors.

“Green hydrogen, if it’s produced further away from demand centres, will have to think about new use cases,” he says, raising heavy-duty transport as a possible option for offtake from smaller projects.

But Tengler is doubtful that there is enough push on the demand side to incentivise industrial users to switch from grey to blue to begin with.

“Today, unless you have another incentive to actually use blue or green, nobody’s going to buy it,” he says.

Le notes that the tax credits are only a short-term measure to cover a cost gap and are “not something you can keep sustaining [financially] in the long term”, in contrast to carbon markets such as the EU’s Emissions Trading System (ETS), which progressively lowers its cap on the number of emissions allowances every year to push industries to decarbonise.

Some US states have introduced demand-side incentives, such as Colorado, which is offering a $1/kg tax credit for companies using clean hydrogen that passes the Tier-1 emissions intensity threshold and meets additionality and hourly matching criteria.

Companies can also only claim a maximum of $1m a year between the start of 2024 and the end of 2025, which then halves to $500,000 a year up to the end of 2029 and halves again to $250,000 annually until the end of 2032.

Tengler notes that the Colorado tax credit may only support several megawatts of electrolyser capacity, “but it does help close that gap [between supply and demand]” and “more such incentives will probably be needed”.