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EPA’s Low-Carbon Hydrogen Projections Under Climate Rule Reveal Supply and Demand Risks


By Jonathan Crawford  |  July 21, 2023

This is the fourth Insight in a series covering the U.S. EPA’s historic carbon emissions standards being proposed for the power sector.

While the use of low-carbon hydrogen to curb emissions in the U.S. power sector has garnered a lot of interest over the years, only a handful of commercial facilities currently burn the fuel. However, sweeping climate rules recently proposed by the U.S. EPA could change that, as large numbers of natural gas-fired generators are projected to co-fire the fuel to meet strict pollution caps. In this Energy Market Insight, we analyze what the EPA’s draft rule could mean for future hydrogen supply and demand in the power sector.

The EPA’s proposed climate rules for the power sector released in May set stringent emissions standards for the nation’s natural gas-fired generator fleet. Existing natural gas-fired combustion turbines with generating capacities above 300 MW and utilization rates greater than 50%, and new plants with utilization rates of 20% or more, can meet the emissions standards by co-firing low-greenhouse gas hydrogen at 30% by volume in 2032. The rule requires that the hydrogen have well-to-gate carbon emissions of less than 0.45 kg CO2e/kgH2. To meet this threshold, plants will likely have to use green hydrogen, which is produced with electrolyzers powered by non-emitting generators such as solar, wind, and hydroelectric plants. Plants can also lower their emissions by other means, such as carbon capture and sequestration (CCS), which BTU Analytics outlined in a previous Energy Market Insight.

Recent modeling data issued by the EPA provides projections on the amount of capacity that will adopt hydrogen co-firing to comply with the rules. Moreover, by examining the EPA’s model results, BTU Analytics was able to identify the future and existing plants that are projected by the agency to co-fire hydrogen. In 2035, three years after initial compliance kicks in, at least 46 GW of capacity from new and existing natural gas-fired plants are estimated to co-fire hydrogen in lieu of installing CCS or lowering utilization to avoid the compliance requirement. That amount is equal to nearly 10% of the projected capacity of the entire fleet in that year.


As illustrated in the map above, the largest concentrations of capacity co-firing hydrogen in 2035 are expected to be in California and the Northeast. California and Pennsylvania represent the states with the highest projected hydrogen co-firing capacity, with 6.8 GW and 1.1 GW, respectively.

The green hydrogen demand from these plants is estimated to top 4 Mtpa in 2035, and meeting this demand will likely require a significant buildout of electrolyzers beyond what is already proposed. This comes as many of the announced projects have already secured offtakers or made plans to use their hydrogen for alternative purposes, such as ammonia production. Additionally, while the U.S. Department of Energy is providing federal funding to establish up to ten regional low-carbon hydrogen hubs across the U.S., which could help alleviate supply constraints, many of the larger proposed production facilities are concentrated along the Gulf Coast and in Texas. Without sufficient hydrogen pipeline networks, those supplies are effectively out of reach of the regions where demand for the fuel is projected to be the highest. As a result, many power plants projected to co-fire with hydrogen may need to consider other sources of hydrogen, including the possibility of producing their own green hydrogen onsite to avoid excessive transportation costs, until more proximate regional supply materializes.

Assuming all these plants choose to produce green hydrogen onsite, BTU Analytics estimates that together they would require between 22 and 29 GW of electrolyzer capacity buildout. This would be in addition to the 15.5 GW of announced electrolyzer capacity in the U.S. The bulk of this buildout is projected to land in CAISO.


A green hydrogen project typically requires renewable capacities that are at least 1.5 to 2x the project’s electrolyzer capacities to achieve higher production rates. As a result, in addition to incremental electrolyzer capacity, regions with projected hydrogen co-firing would also need to add even larger amounts of incremental renewable capacity.

Green hydrogen holds many advantages as a means to slash power sector carbon emissions, such as its ability to serve as a dispatchable source of low-carbon energy. But the EPA’s projected hydrogen scenario brings into focus the major supply hurdles that could arise from the co-firing of hydrogen on a large scale. The challenge lies not only in producing sufficient quantities of the fuel by 2032 – including the massive amounts of electrolyzer and renewable capacity to support fuel production – but also ensuring adequate infrastructure exists to get supply to where it’s needed most. For plants that both require large volumes of hydrogen and reside in regions with less renewable generation available, this transition could prove especially difficult.


BTU Analytics is a FactSet Company. This article was originally published on the BTU Analytics website.

This blog post is for informational purposes only. The information contained in this blog post is not legal, tax, or investment advice. FactSet does not endorse or recommend any investments and assumes no liability for any consequence relating directly or indirectly to any action or inaction taken based on the information contained in this article.


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The information contained in this article is not investment advice. FactSet does not endorse or recommend any investments and assumes no liability for any consequence relating directly or indirectly to any action or inaction taken based on the information contained in this article.