Two major pieces of early-2020s legislation — the Bipartisan Infrastructure Law (2021) and the Inflation Reduction Act (IRA; 2022) — promise to provide billions of dollars in tax credits and other incentives for expanding the production of low-carbon-intensity (LCI) hydrogen. But the hype around clean hydrogen as a fuel of the future has lost some momentum of late, mostly due to spiraling costs. So we’re left with two questions: Can expanded production and use of LCI hydrogen significantly reduce carbon dioxide (CO2) emissions and, just as important, is LCI hydrogen production cost-effective?
This is the second part of a series covering the practical and economic viability of increased utilization of LCI hydrogen to reduce carbon emissions — ultimately to help meet the net-zero-by-2050 goals enshrined in the 2016 Paris Agreement. In Part 1, we explained that in November 2021, the Department of Energy (DOE) asked the National Petroleum Council (NPC) to take a deep dive into low- and zero-carbon hydrogen to help define potential pathways leading to LCI hydrogen deployment at scale. And a deep dive it was: More than 300 individuals contributed to the ensuing analysis, and the final report — Harnessing Hydrogen: A Key Element of the U.S. Energy Future, published 2½ years later in April 2024 — is more than 800 pages long.
In Part 1 we also discussed in some detail the report’s Chapter 3 analysis of existing domestic hydrogen transmission and storage infrastructure, which was RBN’s contribution to the report. Key points in that blog included these facts:
- Almost all of the 11 million metric tons per annum (MMtpa) of U.S. hydrogen production today comes from running natural gas through steam methane reformers (SMR) without capturing and sequestering the resulting CO2 and is known as gray hydrogen. To meet the Paris Agreement goals, U.S. production by 2050 would need to shift to about 75 MMtpa of entirely LCI hydrogen — i.e., either blue hydrogen produced via SMRs with carbon capture and sequestration (CCS) or green hydrogen made via renewables-powered electrolysis. (For more on the hydrogen color scheme, see Don’t Let Me Be Misunderstood.)
- Hydrogen needs to be compressed or liquefied to make it economic to transport over distance — so hydrogen transport costs are high. It’s typically delivered either via pipeline as compressed gas or via truck (either as compressed gas in canisters or liquified hydrogen in cryogenic canisters or tanks).
- The U.S.’s 1,600 miles of hydrogen pipelines are concentrated along the Gulf Coast, where they connect large clusters of oil refineries and petrochemical and hydrogen production plants in the region.
- Substantial infrastructure exists to deliver smaller quantities of hydrogen as well as other industrial gases to a wide base of “merchant” and “package” customers across the U.S.
- In the Gulf Coast region, underground salt caverns are used to store bulk volumes of hydrogen gas. Also, there’s a good bit of onsite bulk hydrogen liquid storage to provide essential buffering for merchant customers supplied with liquid hydrogen by truck.
- The world’s largest liquid hydrogen storage tanks are aboveground spheres at NASA’s Kennedy Space Center in Florida to provide fuel for rockets.
The takeaway from last time is that while the 1,600-mile hydrogen pipeline network is far smaller than the nearly 300,000-mile natural gas transmission system, it operates economically to meet the needs of Gulf Coast refiners and chemical companies and demonstrates it’s possible to move hydrogen gas over long distances. Underground storage caverns, in turn, offer a working buffer system that helps stage pipeline supplies to and from refineries and producers.
Today, we’ll build on all that by discussing the models used and analyses made to assess the degree to which the expanded production and consumption of LCI hydrogen would help the U.S. achieve its emission-reduction goals — and the associated costs.
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