Blue hydrogen, produced from fossil gas with carbon emissions captured and stored, has often been touted by industry as an essential part of any clean H2 discussion, as it can be made at a cheaper cost than green while theoretically having net zero emissions.

Stay ahead on hydrogen with our free newsletter
Keep up with the latest developments in the international hydrogen industry with the free Accelerate Hydrogen newsletter. Sign up now for an unbiased, clear-sighted view of the fast-growing hydrogen sector.

But figures released by the US Department of Energy (DOE) in its new Hydrogen Shot Technology Assessment suggest that most blue hydrogen will not only be much higher-cost than the US target of $1/kg by 2031, but have an emissions footprint beyond what can be considered “clean” H2, making it ineligible for tax credits.

The US standard for clean hydrogen sets a threshold for well-to-gate emissions of 4kg of CO2-equivalent (CO2e) per kilo of H2.

Meeting this standard is a requirement for producers to access the clean hydrogen production tax credit, which starts at $0.60/kg and scales up to a maximum $3/kg as lifecycle emissions decrease (see table).

45V tax credits tiered by emissions intensity

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

Source: US Department of Energy

However, modelling by the DOE for steam methane reforming (SMR) and autothermal reforming (ATR) — the two main methods of extracting hydrogen from natural gas — with CCS suggests that these technologies will not produce hydrogen at this threshold, despite an assumption of much higher CO2 capture rates than the 60% maximum seen at blue H2 facilities operating today.

For SMR, the report calculates a lifecycle emissions intensity of 4.6kgCO2e/kgH2* — including a baseline carbon capture rate of 96.2%, based on current, commercially-ready technology.

ATR — with a baseline CO2 capture of 94.5% — fares even worse with 5.7kgCO2e/kgH2.

This is compared to a baseline emissions intensity of 12kgCO2e/kgH2 for grey hydrogen produced from SMR without CCS or steam displacement, the latter of which drops emissions down to 10kgCO2e/kgH2.

“These life cycle results may be higher than expected given the addition of CCS,” the DOE notes.

This is because even though the actual greenhouse gas emissions from the exhaust stack are extremely low if CCS is added — 0.38kgCO2e/kgH2 for SMR and 0.51kgCO2/kgH2 for ATR — upstream emissions associated with natural gas production and electricity to run these processes both push up the global warming potential of blue hydrogen beyond the clean threshold.

Sourcing natural gas is assumed to account for 2.9kgCO2e/kgH2 for SMR and 2.7kgCO2e/kgH2 for ATR, which has a slightly higher hydrogen yield.

Meanwhile, emissions associated with grid electricity to run these processes account for 1.2kgCO2e/kgH2 for SMR with CCS, and 2.4kgCO2e/kgH2 for the more energy-intensive ATR with CCS.

However, these figures vary significantly based on project location and the source of the gas.

The absolute minimum carbon intensity, based on the lowest possible emissions for both grid and upstream gas, calculated for both SMR and ATR was below 4kgCO2e/kgH2 — and the maximum more than double the threshold for SMR and nearly triple for ATR.

The actual transportation and storage of CO2 was “never a significant contributor to the overall estimated variability in the [global warming potential] results”, the report notes, adding that blue hydrogen producers must focus on how they source electricity and gas to drive down this emissions intensity.

In addition to managing fugitive methane emissions from upstream gas production, the report suggests using blends of biogas, electrification of gas compressor stations, decarbonisation of power generation, and more efficient gas reforming technology as steps that could all reduce lifecycle emissions.

Costs off target

The DOE calculates a baseline cost (in 2020-dollars) of blue hydrogen production from SMR at $1.69/kg and from ATR at $1.64/kg, with the actual cost of CO2 transportation and storage fairly minimal at $0.10/kg for the former and $0.09/kg for the latter.

The capital costs — including for carbon capture or air separation units — make up a greater share of the cost of producing H2, at $0.34/kg for SMR and $0.27/kg for ATR.

However, the biggest share of the levelized cost of blue hydrogen comes down to fuel, which accounts for $0.85/kg for SMR and $0.80/kg for ATR.

As such, while the DOE raises technological advancements, such as alternative carbon capture systems and more energy-efficient processes, as a way to reduce costs, these alone are unlikely to drive the levelised cost of hydrogen down to the 2031 target.

It adds that “non-technology factors considered during the planning stages of a project are also drivers towards the $1/kg H2 goal”.

These could include scaling up plants, siting them where gas and electricity are cheap, and for ATR, selling argon gas produced during air separation on the market.

“In lieu of considering a CO2 tax credit, selling captured CO2 up to a price of up to $50/t was another important method for cost reduction,” the report notes.

While some state-level or regional carbon markets exist, the US currently has no tax or other mechanism at a federal level that would put such a price on CO2.

However, the US does currently offer a tax credit worth up to $85 per tonne of CO2 geologically sequestered ($180 if directly captured from air), although this maximum drops to $60 if it is used for enhanced oil recovery or otherwise used as a feedstock.

These tax credits, which are neutral to how carbon-intensive a project capturing its CO2 actually is, have been suggested as a reason why large-scale blue hydrogen projects in the US appeared to have a head start over their green counterparts, which are still awaiting Treasury guidance for the clean hydrogen production tax credit.

Turquoise still marginal

The DOE did not perform a full technology assessment for the emissions footprint for so-called “turquoise” hydrogen produced from methane pyrolysis — which produces solid carbon black as a byproduct rather than emitting CO2 gas.

However, from preliminary research, the report suggests that “the current footprint of the technology is estimated to be comparable to, but slightly higher than, ATR with CCS, but lower than SMR without CCS”. This is again due to upstream fossil gas emissions and electricity.

Additionally, the DOE points out that the maximum theoretical yield of hydrogen from plasma pyrolysis of methane is half that of SMR.

In practice, the yield is likely to be considerably lower “due to the presence of side reactions that can produce undesired hydrocarbon by-products”, requiring extra purification of delivered H2 and disposal or use of these by-products.

Similarly, the report adds that “this issue is further exacerbated when the feedstock is [natural gas] rather than CH4, due to the presence of higher molecular weight hydrocarbons, e.g., C2-C4+”.

The DOE also assumes that because pyrolysis is performed at atmospheric pressure, turquoise hydrogen will need extra power input to compress it to the delivery pressure, pushing up operating costs.

As such, the report estimates a levelised cost of hydrogen 3% higher than for the ATR baseline of $1.64/kg.

*All lifecycle emissions in this article were calculated using characterisation factors from the IPCC’s fifth assessment report with a 100-year time horizon and atmospheric carbon climate feedback.