Many have asked whether electrolysis technologies would see cost reduction curves similar to solar panels (solar) or wind turbines (wind). While it may be tempting to assume electrolysis costs will decline at rates similar to energy technologies of the recent past, but it is important to realize these technologies produce fundamentally different products.
Unlike solar or wind, electrolysis produces a nascent product. Power from solar and wind serves the same demand for electric power as dispatchable production assets. Power markets in the US are mature and infrastructure exists to allow for the diffusion of new energy technologies. Ready access to a market, offered by this infrastructure, allowed for the power produced from these new energy technologies to be sold to end consumers. As installations of solar and wind increased, the cost for the technology decreased led by “learning by doing” and economies of scale.
Hydrogen, on the other hand, is different. Essentially all of the hydrogen production capacity in the US reserved for use in industrial activities. In 2014, crude oil refining made up 70% of demand for hydrogen and ammonia production for fertilizer manufacturing made up 20%. Moreover, 95% of hydrogen is produced via a steam methane reformer (SMR) in the US. This demand is realized through bilateral contracts between hydrogen suppliers and consumers – more succinctly, each kilogram of hydrogen produced is produced for a specific customer as there is no market for hydrogen akin to the power market. Even if demand for hydrogen grew beyond these industrial customers, the minimal hydrogen infrastructure in place only connects existing hydrogen supply to large hydrogen customers on the Gulf Coast.
Understanding the nuance of the comparison, the question shifts from “will electrolysis technologies see cost reduction curves similar to solar and wind” to “what changes need to be made in order to see cost reductions for electrolysis technologies?”
If cost reductions for electrolyzers are going to be driven by “learning by doing” and economies of scale, similar to other energy technologies, it is imperative that market structure for hydrogen transactions and infrastructure to move the gas be built. Even still, in a world where a market is established an infrastructure exists, there are still regulatory issues around hydrogen production that must be faced before any substantial decrease in electrolyzer technologies will be realized. Ownership of these assets is at the top of this list.
It could make sense to regulate ownership of electrolysis assets similar to natural gas production wells. After all, hydrogen would likely directly compete with natural gas in many applications. Who would own this electrolysis production capacity? Using natural gas production as a proxy, let’s compare how state-level regulatory structures might shape this question.
Consider the state of Texas. Natural gas production in Texas is regulated by the Railroad Commission through the issuance of drilling permits. Specifically, Statewide Rule 5 mandates any entity seeking to drill a new well in the state may not do so until a permit has been granted by the Railroad Commission – permits are subject to other rules that dictate technical elements of the specific proposal. If demand for hydrogen were to grow beyond industrial applications in Texas, would a new statute need to be drafted by the Texas legislature giving the Railroad Commission jurisdiction over issuing permits to construct hydrogen production facilities? In Texas’s deregulated power market, there is precedent to assume a utility might not own an electrolysis asset based on restructuring, but there is little reason to assume there would be strict limitations concerning ownership of these assets otherwise.
Contrasting with Texas, consider the state of Massachusetts. Massachusetts, has no natural gas reserves or production. In a regulatory sense, the comparison between hydrogen and natural gas production is not possible in the context of Massachusetts – regulatory agencies do not have any regulations on the books concerning natural gas extraction. Therefore, there are no regulations against which one can compare concerning hydrogen production. So, in the case of Massachusetts, who would have the right to own hydrogen production capacity? As a point of reference, if an offshore wind project wanted to maximize revenues by incorporating an electrolyzer to produce hydrogen when power prices were not high enough, there is no regulatory precedent to determine whether they would be allowed to do so. The rules have yet to be written.
So, returning to the initial point, I do not believe costs for hydrogen electrolysis will, necessarily, decline in a fashion similar to solar and wind. This assessment is based on the fact that hydrogen production is feeding into a fundamentally different and nascent market. Given hydrogen will likely displace natural gas for many applications, it is possible that regulation of hydrogen production could look similar to that of natural gas production. But, even using natural gas production as a proxy for a possible regulatory structure is not a feasible across states, as there are many states that do not have any existing policies concerning natural resource extraction.
Will electrolyzer technologies see declining cost curves similar to those of solar and wind? Maybe they will – but, there are layers of market, infrastructure, and regulatory uncertainty facing the future of hydrogen that must be address before we see how cost declines will materialize.
About The Author
Drake Daniel Hernandez
Graduate Researcher, MIT Energy Initiative (MITEI)
Drake is an energy economist with expertise at the intersection of economics, regulation, and finance – with a particular emphasis on the hydrogen, natural gas, and electric power sectors. He is currently a graduate researcher in the MIT Energy Initiative (MITEI) where he’s a co-author on the MITEI Future of Storage study and the architect of the hydrogen production tecno-economic analysis (TEA) module of the Sustainable Energy Systems Modeling Analysis Environment (SESAME). Drake’s Master’s thesis focused on modeling hydrogen network dynamics and assessing federal regulatory frameworks for the development of interstate hydrogen transmission infrastructure within the United States.
Prior to MIT, Drake was an Associate at Charles River Associates (CRA) where he supported the development of expert testimony in multi-billion-dollar domestic litigation and international arbitration disputes related to energy infrastructure.
Drake’s work has been published in The Electricity Journal and other academic texts. Drake’s been invited to speak both domestically and internationally on matters related to the regulation of hydrogen and system planning.
Drake is pursuing a Master of Science in Technology and Policy, with a particular emphasis on Energy Economics and Finance, from MIT and a Bachelor of Science in Mechanical Engineering, with a focus on Operations Research and Economics, from the University of Texas at Austin.