Clean hydrogen and related technologies can play a key role in decarbonizing many sectors, including medium- and heavy-duty transportation; industries such as ammonia and steel; heating applications; and power generation, including enabling long duration energy storage.
The 2021 Bipartisan Infrastructure Law, or BIL, authorizes and appropriates $8.0 billion over the five-year period encompassing fiscal years 2022 through 2026 to support the development of at least four regional clean hydrogen hubs (H2Hubs), which are networks of clean hydrogen producers and consumers and include a connective infrastructure within a region. The bill also requires the production of clean hydrogen, defined as "hydrogen produced with a carbon intensity equal to or less than 2 kilograms of carbon dioxide-equivalent produced at the site of production per kilogram of hydrogen produced" or 2kg CO2e/kg H2.
While all projects will be required to meet the minimum clean hydrogen production standard, Department of Energy (DOE) intends to also evaluate full lifecycle emissions for each application and will give preference to applications that reduce greenhouse gas (GHG) emissions across the full project lifecycle, inclusive of hydrogen production, compared to current industry standards. It is important to define the boundary of the lifecycle analysis of hydrogen hubs and recognize their impacts on a broader scale, including energy markets, industries, employment, GHG emissions, environment, and communities.
Further, the Inflation Reduction Act of 2022 (IRA), which was signed into law on August 16, 2022, includes significant hydrogen incentives. The new clean hydrogen production tax credit, or Section 45V, creates a new 10-year incentive for clean hydrogen production with four tiers, and yet will only be available to projects that can demonstrate lifecycle GHG emissions of less than 4kg CO2e/ kg H2 produced, as demonstrated in Figure 1.
The Greenhouse gases, Regulated Emissions, and Energy use in Transportation model, also known as GREET model, is specifically called out in the IRA to determine GHG emissions of hydrogen production through the point of production, or well-to-gate. To obtain the max credit value as $3/kg H2, the hydrogen production carbon intensity must be lower than 0.45kg CO2e/kg H2, or 3.75g CO2e/MJ H2, which would likely be available to green hydrogen produced through electrolysis with electricity generated from solar or wind and produced through renewable natural gas from dairy manure.
Carbon intensity and lifecycle analysis
To make BIL hydrogen hub application and to evalue 45V tax credits, it requires a deep understanding of hydrogen carbon intensity through lifecycle analysis. With upstream emissions in the lifecycle GHG emissions, such as natural gas recovery and processing, it is important to check the carbon intensity by production technology and by feedstock.
Would any of types of hydrogen except green hydrogen qualify for 45V credits?
Currently, the most widely used method in the mass production of hydrogen is steam methane reforming (SMR), referred to as gray hydrogen. Through SMR, natural gas is leveraged as methane to produce hydrogen and carbon dioxide as the principal products. In Figure 2, the latest version of GREET model, GREET1 2021, shows that even with steam or electricity as co-products to generate displacement credits, gray hydrogen production carbon intensity is still close to 10kg CO2e/kg H2. The variation of methane leakage from 1% to 3% would easily increase the carbon intensity of gray hydrogen production by 1.4 kg CO2e/kg H2, or around 14%.
Combined with carbon capture and sequestration (CCS), hydrogen produced from SMR is called blue hydrogen. With the maximum 90% of CO2 capture rate, the carbon intensity of blue hydrogen could be reduced to approximately 3.2kg CO2e/kg H2. However, using the default GREET 2021 inputs, the capture rate could be no lower than 82% if it intends to maintain the carbon intensity below 4kg CO2e/kg H2. Coal gasification, coupled with CCS with a carbon capture rate up to 87%, could make the carbon intensity for hydrogen production close to 4kg CO2e/kg H2, but it is quite a stretch.
If the feedstock of SMR changes from fossil natural gas to renewable sources, the carbon intensity of hydrogen production could decrease significantly because of biogenic CO2 and/or avoided methane (CH4) emissions. For example, when landfill gas is used to feed SMR, the carbon intensity of hydrogen production would be reduced to less than 1kg or even close to 0.5 kg CO2e/kg H2, as shown in Figure 2. The important role of renewable natural gas to reduce carbon emissions has been demonstrated by California’s Low Carbon Fuel Standard (LCFS) program.
Last but not least, hydrogen from biomass gasification—and as a byproduct of chlorine plants with mass-based allocation method—can achieve carbon intensities of hydrogen production close to 1.5 kg CO2e/kg H2. The scale of this production is relatively small compared with other technologies.
What can we learn from California’s LCFS program?
California Air Resources Board (CARB) has certified over 80 hydrogen pathways both in gaseous and liquid phases and around 10 pathways are under public comment so far in 2022. Most feedstocks are fossil natural gas (NG), landfill gas (LFG), and dairy manure, as shown in Figure 3. CARB’s LCFS program provides valuable information about the impacts of renewable feedstock on the carbon intensity of hydrogen production.
Since the LCFS program focuses on hydrogen as transportation fuels and includes well-to-wheel GHG emissions, it is challenging to make apples-to-apples comparison with production carbon intensity without excluding emissions from transmission and distribution and other end uses. However, it is worth noting that the lifecycle GHG emission reduction occurs during the production phase when the feedstock is switched from fossil natural gas to landfill gas, and to dairy manure, with the reduction values on average as 29-53 gCO2e/MJ H2, and 326-344 gCO2e/MJ H2, respectively, or 3-6kg CO2e/kg H2 and 39-41kg CO2e/kg H2, respectively.
Emissions from other processes
There are approximately 1,600 miles of dedicated hydrogen pipelines in the United States. If gaseous hydrogen is piped from central plant to bulk terminal and to refueling stations with a total distance of 750 miles, emissions of 0.5 kg CO2e/kg H2 would be added using GREET 2021 default inputs. The emissions would be more than 10 times higher if it is transported by diesel trucks with gas tube trailers. Hydrogen can also be liquefied and transported with tanker trucks, which have larger payload with higher transportation efficiency, yet additional emissions from liquefaction and boil-off losses need to be considered as liquefaction of hydrogen is an energy intensive process.
The full lifecycle emissions vary depending on end uses—such as transportation, industry, and power generation. We will discuss each end use separately in forthcoming papers.