The US is widely expected to be the most attractive market for international hydrogen developers, mainly due to the generous 45V tax credit of up to $3/kg of green H2 production, introduced in the Inflation Reduction Act (IRA) last November.

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But the picture emerging from project announcements is that many are more focused on so-called blue hydrogen — produced from natural gas using existing production methods with added carbon capture — than making green H2 through renewable electricity and water electrolysis.

“The vast majority of projects that have been announced in the US — at least in terms of capacity — are blue rather than green,” Martin Tengler, head of hydrogen research at research firm BloombergNEF, tells Hydrogen Insight, noting that many were announced well before any clean H2 tax credits were even on the table.

Similarly, Rystad Energy data indicates that while a greater number of renewable H2 projects have been announced since the IRA was passed, the two types of hydrogen add up to a similar capacity, with blue having bigger individual projects centred around the Gulf Coast.

“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?

One reason could be that while renewable H2 subsidies were only signed into law in November, blue projects were already able to access the 45Q tax credit for carbon capture and storage (CCS), which has been in place since 2008.

The IRA has also expanded the subsidy to $85 per tonne of CO2 that is permanently stored, and to $60/tonne if the greenhouse gas is used for enhanced oil recovery or used in other industrial processes. The $60 band also applies for carbon dioxide that is used in making other chemicals, such as e-fuels or methanol — which are both made by cleverly combining hydrogen with CO2.

This means that companies now have multiple routes for claiming subsidies on the blue H2 they produce, although the hydrogen production and carbon capture tax credits cannot both be claimed by the same project, even if there are separate companies operating the carbon capture and H2 facilities.

The tax credit for carbon capture may also be a better bet for blue hydrogen developers than the one for H2 production.

While “on paper, the 45V would actually be a better subsidy than the 45Q”, according to Bridget van Dorsten, senior research analyst for hydrogen at consultancy Wood Mackenzie, this is only as long as projects are able to maintain emissions intensity below 1.5kg of CO2-equivalent per kilogram of hydrogen produced. This would award companies with $1/kg, compared to around $0.75/kg if 95% of CO2 from the facility was captured and permanently stored.

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.

45V tax credits tiered by emissions intensity

Emissions intensity (kgCO2e/kgH2) Maximum tax credit ($/kgH2)

Source: US Department of Energy

“If counting upstream emissions from methane, you are unlikely to get 3kgCO2e/kgH2 with blue, so you are only going to get the lowest tax credit for the 45V if you were to apply for that,” Tengler concurs, adding that “without strong measures” to prevent upstream methane emissions, blue H2 producers might not be eligible for the tax credit at all.

But Tengler points out that these subsidies on offer only shave off the cost of producing low-carbon H2.

“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.

Financial research firm S&P currently lists the cost of grey H2 production as ranging from $0.82-1.83/kg, depending on which region of the US it is made.

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.

S&P does not currently list blue hydrogen costs in the US, and Hydrogen Insight has reached out to the company for further detail on how it calculates green hydrogen costs.

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.

Grid back-up may also be problematic for developers seeking to keep project emissions below 0.45kgCO2e/kg H2 for the full $3/kg tax credit.

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”.

Similarly, the US Department of Energy will also fund six to ten Regional Clean Hydrogen Hubs under the 2021 Bipartisan Infrastructure Law, which are expected to demonstrate production, processing, delivery, storage, and end use of H2, from a pot of $7bn.

Many of the consortia applying for funding include potential offtakers from the fertiliser, steel and transport sectors. But this government assistance will take the form of grants or cooperative agreements to cover capital costs — putting into question whether industrial partners will continue to use low-carbon H2 beyond these demo projects.

The Bipartisan Infrastructure Law requires at least one of the Regional Clean Hydrogen Hubs to demonstrate the use of fossil fuels as a feedstock for low-carbon H2 production.