Blue Hydrogen’s Carbon Management Needs Policy, Scale to be Realized

Efforts to lower emissions and clean up hard-to-abate sectors have many energy industry players championing blue hydrogen.

There are many benefits. Blue hydrogen—derived from natural gas as feedstock—uses carbon capture and storage (CCS) to shrink its carbon emissions while using existing infrastructure.

But there’s still a way to go to start seeing the potential benefits blue hydrogen offers.

Experts studying the emissions’ impact of low-carbon hydrogen say it is crucial to get the carbon management piece right and minimize emissions along the entire value chain.

“We are talking high, high capture rates consistently that really haven’t been demonstrated and practiced for hydrogen facilities,” Nichole Saunders, director and senior attorney for the Environmental Defense Fund (EDF), recently told Hart Energy, “and we’re talking about moving a lot of carbon for the blue hydrogen industry through pipelines that don’t currently have federal safety standards and storing that carbon permanently in systems that are very hard and time consuming to permit.”

Several companies are pursuing blue hydrogen projects because of their potential to lower carbon emissions, use existing infrastructure and help decarbonize hard-to-abate sectors. Given the abundance of natural gas, many of those companies are taking the blue hydrogen and CCS route. However, in addition to regulatory uncertainty surrounding incentives, there are concerns about emissions footprints.

To qualify for the clean hydrogen production tax credit offered in the Inflation Reduction Act’s Section 45V, lifecycle greenhouse gas emissions of the hydrogen production process must be no greater than 4 kg of CO₂e per kilogram of hydrogen produced, according to the U.S. Treasury Department. The maximum credit amount is $3/kg of hydrogen produced. Emissions are calculated based on the Department of Energy’s (DOE) 45VH2-GREET model.

Companies can also qualify for the 45Q tax credit for carbon capture, utilization and storage (CCUS) projects. The credit is tied to how much carbon is captured and stored or used. Companies can qualify for a maximum of $85 per metric ton of CO₂ captured and permanently stored and $180 per metric ton for direct air capture of CO₂.

High expectations

Saunders, who focuses on CCS for the New York-based nonprofit environmental advocacy group, was among the speakers during a recently held hydrogen conference in Houston. She pointed out that global expectations are high for carbon capture rates for hydrogen to meet clean standards.

Australia’s National Hydrogen Strategy specifies at least 90% capture to be called low carbon, while guidance in the U.K. directs operators to hit a 95% capture rate to  justify the lower rate.

“That obviously gives an out, but there’s a demonstration requirement to that end,” Saunders told Hart. “In the U.S., on the other hand, our incentives for hydrogen come down to meeting the tax incentive. There’s not a regulatory requirement, and the tax incentive leaves a lot of room to play with those numbers. That doesn’t necessarily require you to meet high carbon capture rates.”

The DOE’s National Energy Technology Laboratory (NETL) assessed the cost and performance of select hydrogen plants using fossil fuels as feedstock, including capture rates, in a 2022 report. As part of the report comparing commercial fossil-based hydrogen production technologies, six hydrogen plant configurations were analyzed.

The NETL modeled a 96.2% CO₂ capture rate for steam methane reforming; 94.5% CO₂ capture rate using autothermal reforming technology and capture rates of 92.5% and 92.7% with gasification.

However, some blue hydrogen facilities currently operating are not hitting the 95% or higher carbon capture rate, as Saunders pointed in her presentation, citing information from the Institute for Energy Economics and Financial Analysis. Outcomes can be skewed, considering different entities define capture rate differently, and not all companies regularly report such data.

“If industry alone doesn’t [achieve] a carbon capture target closer to 95% to 98% and instead is hovering around the average we see now at like 60%, you lose half of the carbon benefit of blue hydrogen from a climate perspective,” Saunders said. And, “if you don’t control for methane and hydrogen emissions in the short term, that hydrogen can be even worse for the climate than natural gas. So, it’s really important that these targets are targets in real life and not on paper alone.”

Companies developing new CCS projects are aiming high.

Exxon Mobil’s proposed hydrogen facility in Baytown, Texas, aims to capture more than 98% of the associated CO₂ and safely store it underground. The CCS part of the project, which is pending a final investment decision (FID) in 2025, would be one of the world’s largest—storing up to 10 million metric tons of CO₂ per year.

Shell’s Polaris carbon capture project in Alberta, Canada, is designed to capture about 650,000 tonnes of CO₂ annually from its Scotford refinery and chemicals complex. The project reached FID in 2024 and is expected to begin operations by year-end 2028. Shell has said the project builds on its Quest CCS large-scale demonstration facility that has captured and stored more than 9 million tonnes of CO₂ since 2015.

Global picture

Some regulators and purchasers on the global market remain focused on carbon intensity. The EU’s Carbon Border Adjustment Mechanism (CBAM), for example, aims to “put a fair price on the carbon emitted during the production of carbon intensive goods that are entering the EU, and to encourage cleaner industrial production in non-EU countries,” according to its website. Hydrogen is among the imported products that will be subject to a carbon price based on emissions associated with its production. The regime takes effect in 2026.

“If industry were to go after 45Q, instead of 45V, then we’re not really looking at lifecycle emissions at all of blue hydrogen. We’re only looking at how many molecules of carbon they store and so that doesn’t incentivize, outside of an economic reason, a high capture rate at all,” Saunders said. “It’s going to be really interesting to watch how it plays out between 45V and 45Q and which targets industry goes after meeting.”

EDF plans to launch in the spring a hydrogen emission study campaign. The effort will involve working with developers of new tools used in the field to measure and detect hydrogen emissions at the size and rate needed to understand climate impact, according to Saunders.

Her focus is on the CCS side, working to ensure the regulatory systems have strong safeguards regarding infrastructure buildout and permanent carbon storage.

“States are seeking primacy over the Class VI program, and so we do a lot of work in thinking around not only what does it look like to have the primacy over a program, implement Class VI safely and effectively, but also highlight the fact that one permit isn’t the full answer to getting carbon storage right,” she said. “We need to think about other things, learn about new emerging challenges, like seismicity, like pressure. ... So, we’re thinking through a lot of that and doing regulatory and policy advocacy on that front.”