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With the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, the United States is making sizable investments toward the development of a clean hydrogen economy. The cornerstone of U.S. hydrogen infrastructure deployment efforts is the Regional Clean Hydrogen Hubs (H2Hubs) program, through which the U.S. Department of Energy (DOE) will invest $8 billion to develop “a network of hydrogen producers and consumers, and the connective infrastructure located in close proximity.”
Most of today’s hydrogen production occurs at or near consumption centers, while dedicated distribution and transportation infrastructure is still scarce or in the early stages of rollout. However, the limited availability of midstream infrastructure will constrain scaling in cases where co-location is not feasible. As production costs fall, hydrogen distribution and delivery costs will likely make up a larger portion of final hydrogen costs, making the cost-effective development of related infrastructure a must for the U.S. hydrogen economy to become vibrant and sustainable.
There are currently three common methods for distributing and delivering pure hydrogen: (1) as a gas in dedicated pipeline networks, (2) as high-pressure gas in tube trailers, and (3) as a cryogenic liquid in tankers.
Hydrogen pipelines are the lowest-cost alternative for delivering large volumes of gaseous hydrogen over long distances (over 300 km), such as interstate distribution. Due to hydrogen’s lower volumetric energy density but significantly higher volumetric flow compared to natural gas, hydrogen pipelines could carry as much as 88 percent of the energy content of a methane pipeline. However, buildout of new pipelines is a capital- and time-intensive process that requires high and stable hydrogen demand, and the low molecular weight of hydrogen requires compressors to operate at three times the speed of that required for natural gas, further adding to operational costs.
With only about 1,600 miles of hydrogen pipelines currently operating in the United States, some midstream infrastructure developers are looking into repurposing natural gas pipelines or blending hydrogen into natural gas pipelines as more cost-effective alternatives to distribute hydrogen. Pipeline repurposing could reduce costs by as much as 60 percent compared to new hydrogen pipelines, while low hydrogen blends of up to 20 percent by volume would require only minor modifications. But these alternatives will come with an added set of challenges. Hydrogen can lead to the embrittlement of metal pipeline components, which could result in cracking and even pipeline failure. Hydrogen embrittlement is more likely to occur in high-strength natural gas transmission pipelines than in low-strength distribution pipes, although embrittlement susceptibility depends on many other factors, such as operating conditions and properties of materials used. If cracking leads to leakage, hydrogen will pose a higher safety risk than natural gas due to its wide flammability range in air and the near-imperceptibility of its flame, requiring stricter leak-detection systems. If needed, separating hydrogen from a natural gas blend is a complex procedure that will further add to distribution costs, particularly at lower blend ratios. The efficacy of hydrogen blending as a decarbonization pathway has been increasingly debated, and the associated increase in energy costs has come under scrutiny.
In low-volume distribution scenarios over shorter distances, high-pressure tube trailers could become the preferred distribution method due to lower capital intensity when compared to pipelines (not including hydrogen blending). Hydrogen is compressed into long tubelike cylinders that are then stacked into trailers for hauling. Tube trailers are limited to pressures of 250 bar (hydrogen is produced at 20 to 30 bar), with some exemptions operating at higher pressures, carrying up to 900 kg of hydrogen per trailer, hence their limited capacity for high-volume distribution. However, as demand slowly ramps up during the early stages of hydrogen deployment in the United States, tube trailers will provide the flexibility needed for demand to slowly aggregate and eventually justify the capital-intensive investments in hydrogen pipelines.
Transporting hydrogen and its derivatives in its liquefied form is another approach. Liquid hydrogen tankers emerge as an option in cases where higher-volume and longer-distance transport is needed or pipelines are neither accessible nor practical. In the case of liquid hydrogen, the liquefaction process requires cooling hydrogen to -253°C and storing the liquid in large, insulated tanks. An energy- and capital-intensive alternative, it takes more than 30 percent of the hydrogen’s energy content to liquefy it, and liquefier installation costs are higher than those of gas compression equipment. There is also the issue of liquefied hydrogen boil-off, in which some of the fluid is lost to evaporation during vessel transfers or due to heat transfer with the environment. But over long distances, liquid hydrogen can be more economical than tube trailers, given that liquid tankers can hold and transport a much larger mass of hydrogen.
Alternative carriers such as ammonia and liquid organic hydrogen carriers (LOHCs) are also being considered for high-volume, long-distance hydrogen transport. Ammonia transport would rely on already mature transport infrastructure due to its widespread use as a fertilizer feedstock, while LOHCs would open up oil infrastructure as a transport pathway, but their main barriers to adoption are their low round-trip efficiencies and high costs.
Given the different strengths and challenges associated with mainstream methods, optimal delivery and distribution schemes will likely involve a combination of existing and emerging technologies based on regional demand volume, distance, timescale, and end-use requirements.
The DOE issued a Funding Opportunity Assessment (FOA) for H2Hubs applicants in September 2022, outlining that full applications will have to be submitted by April 7, 2023. Applicants received encourage/discourage notifications based on applicants’ concept papers in December 2022, some of whom publicly shared their notification status. Although final applications have not been shared by DOE or their applicants, most public concept papers were focused on laying out what feedstocks will be sourced for hydrogen production and what end-use applications will be demanding the said supply. When it came to midstream operations, applicants touted their existing gas infrastructure and related operational expertise, proposing that these could be repurposed for hydrogen distribution. Some applicants plan to benefit from existing—but limited—hydrogen pipelines, while others are looking into building out new hydrogen pipeline networks. Below are some observations from a select set of publicly available information from H2Hubs applicants:
Much remains to be seen about midstream options that prospective hubs plan to develop under the H2Hubs, as the DOE does not plan on disclosing hub applications until it makes selections later this year. However, a survey of approaches that are considered by aspiring hubs show interest in leveraging existing gas infrastructure as well as expanding the network of hydrogen pipelines.
It was only recently that hydrogen began gaining attention as a major fuel source. Hydrogen associated regulatory regimes in the United States are therefore either limited in scope or addressed only indirectly. A clarified and centralized regulatory environment would allow the energy industry to make the long-term and capital-intensive infrastructure investments necessary to transition away from localized hydrogen production schemes. A report by the DOE’s Sandia National Laboratory, released in April 2021, provided important findings from their examination of federal regulations for hydrogen technologies in the United States.
Oversight of pipeline infrastructure is currently dependent on whether the pipeline is onshore or offshore and whether it is interstate or intrastate. Hydrogen is not specifically included in existing pipeline regulations but rather addressed indirectly as a flammable or hazardous gas. There appears to be a high likelihood that the following existing natural gas distribution regulatory agencies would also oversee hydrogen distribution:
The only regime in which hydrogen is directly regulated is in the PHMSA’s Hazardous Materials Regulations. The PHMSA oversees the management of hazardous materials, requirements for cryogenic and compressed gases, and details for shipping containers such as cylinders and tanks, which would apply to transport via road, rail, and waterways.
Investing in and facilitating the deployment of hydrogen distribution and delivery infrastructure will be an essential component to guaranteeing the long-term prospects of a U.S. clean hydrogen economy. Choices made in the midstream inevitably affect the economics of the production and application sectors. The greater examination of midstream options from technical and economic perspectives would also inform the formulation of a regulatory environment that underpins the successful growth of a hydrogen economy. Greater details of approaches to meeting the distribution and delivery needs through the H2Hubs application would be important insight into the scope and pace of the development of a hydrogen economy in the United States.
Mathias Zacarias is a research associate with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C. Jane Nakano is a senior fellow for the CSIS Energy Security and Climate Change Program.
