Hydrogen Production Technology and Infrastructure Restrictions
Hydrogen is not found freely in the atmosphere, and the pathways of producing hydrogen differ significantly in their carbon intensity. These pathways are typically referred to by colors — grey, blue, and green — based on the various inputs required to produce the hydrogen, with conventional means of producing hydrogen emitting most significant carbon dioxide into the atmosphere.
Grey hydrogen is produced using fossil fuel hydrocarbon feedstocks, most typically, natural gas. As such, it is the most carbon-intensive pathway of generating hydrogen. The conventional methods use either steam methane reforming or autothermal reforming processes to separate hydrogen from carbon and make up about 75% of total hydrogen production.1 Coal is also sometimes used in a gasification process to produce hydrogen, among other chemicals. The cost of these methods of producing grey hydrogen is low, ranging from less than $1 to $2 per kilogram of hydrogen,2 depending on the cost of natural gas or coal, but no carbon emissions are captured during these processes, contributing to the carbon intensity of this means of production.
Blue hydrogen is produced through the same conventional processes as grey hydrogen discussed above. However, these processes are augmented with carbon capture utilization and sequestration technologies (“CCUS”) to catch the emitted carbon and store it for other uses before it makes its way into the atmosphere.
Governments are providing incentives for grey hydrogen producers to install CCUS units to control carbon emissions and meet decarbonization goals. The U.S. Government offers CCUS tax credits for qualified CCUS equipment owners. However, CCUS adds about half a dollar per kilogram to the cost of conventional grey hydrogen processes, resulting in a range of $1.5 to $2.5, final price depending on the cost of natural gas or coal input.3
Electrolyzers are used to produce green hydrogen from electricity generated using renewable, carbon-free sources of energy such as wind and solar. To date, there are no green hydrogen plants operating at commercial scale in the United States, but there are several pilot and demonstration projects in the pipeline.4 Unlike grey and blue hydrogen, the costs of which rely on commodity prices, the cost of green hydrogen is a function of several variables including (1) plant utilization rates, (2) power prices of renewable sources (the levelized cost of energy, “LCOE”), (3) electrolyzer efficiency, and (4) electrolyzer manufacturing costs.5
With the current technology and efficiency of electrolyzers, the cost of one kilogram of green hydrogen can range from $3 to $8, depending on the LCOE.6 However, the LCOE of renewables is still relatively high compared to traditional electricity sources, putting the actual base cost of green hydrogen well above $4, even in most optimal situations (i.e., solar electricity from the best geographic locations with high utilization rate).7 In short, green hydrogen currently costs at least four times more than grey hydrogen from the conventional pathways.
Besides these three pathways or colors there are other potential pathways — such as pink where hydrogen is generated by electrolysis using nuclear energy — but their current production capacities and technologies make them far less appealing to any decarbonization plan.
Issues With Transport, Storage, and Distribution of Hydrogen
Most hydrogen is used in industry (e.g., in refining oil and producing fertilizers), and it has been produced in close proximity to and in quantities aligned with actual demand of such industries, therefore eliminating the need for long-distance transmission. However, for hydrogen to become a viable part of the transportation fuel infrastructure (among other possible uses), moving and storing hydrogen at disperse locations will become necessary.
Hydrogen is mainly stored in a gaseous or liquid form in storage tanks. Some of hydrogen’s qualities make it difficult to transport and store at scale. For example, it is highly reactive, so it requires careful handling, and it has low energy density, thus requiring high pressure systems — or a much larger space — for economical storage and transportation. Ammonia could be used for storing and transporting hydrogen over long-distance, as it contains twice as much hydrogen as liquid hydrogen by volume and has a higher liquification temperature. A fleet of refrigerated ammonia transportation vessels already exists as well. However, the conversion and re-conversion processes of ammonia require energy and, therefore, impose a significant efficiency toll in the hydrogen lifecycle. Finally, the current natural gas pipeline infrastructure is unsuitable for hydrogen transportation without significant upgrades,8 and blending hydrogen with the current natural gas flow, up to a threshold of 20%, is possible but would accelerate infrastructure deterioration.9 Nonetheless, a dedicated hydrogen pipeline network would present significant financial and logistical challenges to the widespread distribution of hydrogen for non-industrial applications.
The carbon intensity of hydrogen use is dependent on whether grey, blue, or green hydrogen is being utilized, as the different production processes differ dramatically in their effectiveness as low-carbon energy solutions. Currently, cost, technology, and infrastructure constraints inhibit the expansive development and utilization of green hydrogen. Developers with innovative technology could attempt to develop pilot projects and then commercial scale projects in an attempt to overcome some of these constraints. Our next article in this series will explore possible structures for the development of a hydrogen project.
1 Goldman Sachs, Carbonomics: The Rise of Clean Hydrogen, at 11 (Equity Research, July 2020).
2 Wood Mackenzie, Future Energy: The Technologies Shaping The Energy Transition, at 4 (2020); Jay Bartlett & Alan Krupnick, Decarbonized Hydrogen in the US Power and Industrial Sectors: Identifying and Incentivizing Opportunities to Lower Emissions, Resources for the Future, at 10 (Dec. 2020) Goldman Sachs, supra note 1, at 17, exhibit 22.
4 International Renewable Energy Agency (IRENA), Green Hydrogen Cost Reduction, sec. 5, at 82-85 (2020).
5 See id.; Wood Mackenzie, supra note 2, at 4.
6 See supra note 2.
7 See supra note 2.
8 Unsuitable due to, among other things, pipe embrittlement and leakage (material integrity) and incompatibility with end-use systems/appliances. For a detailed report on blending hydrogen into the natural gas pipeline, see M. W. Melaina et al., Blending Hydrogen into Natural Gas Pipeline Networks: A Review of Key Issues, National Renewable Energy Laboratory (March 2013).
9 National Renewable Energy Laboratory: News, HyBlend Project To Accelerate Potential for Blending Hydrogen in Natural Gas Pipelines (Nov. 18, 2020). See Christopher Findlay, What’s your purpose? Reusing Gas Infrastructure for Hydrogen Transportation, Siemens Energy (Sept. 11, 2020).
This information is provided by Vinson & Elkins LLP for educational and informational purposes only and is not intended, nor should it be construed, as legal advice.