Hydrogen Update: H2 Demand Not Likely to Increase Much Until Post-2030/2035 Even Though Many Projects Announced and IEA is Bullish

 

Hydrogen Demand and Production

     The current global demand for hydrogen for 2022 is at 95 MT, a 5% increase from 2020. Expected H2 demand in 2030 is 115 MT, a 3-3.5% increase per annum. Decarbonization models hope for a 5-6% increase per annum to 2030 so it could end up a little higher. While that is a substantial increase from present, it is hardly a “boom.” Even stretching out to 2050 hydrogen may double or triple what it is now but that is not a huge yearly increase. The main reasobn it won’t grow faster is cost. Although many projects have been announced few have reached final investment decisions (FIDs). The graph below from 2020-2021 shows the amount of hydrogen production from different sources. The difference between production and demand reflects that some hydrogen is stored underground and in pipelines. Current hydrogen with CCS, aka. blue hydrogen, is less than 1% of hydrogen production. Current green hydrogen production is closer to 0.3% of hydrogen production. Currently, 26 countries have national hydrogen strategies.   

 

 Adapted from Global CCS Institute, Data from IAE.

Hydrogen in Refining, Petrochemicals, Industry, and Transport

 

     The biggest users of hydrogen by far are the oil refining and chemicals sectors. Hydrogen is used in the refining sector mainly for desulfurization, for hydrogenating aromatics and olefins, and for hydrocracking heavier hydrocarbon molecules into lighter ones in the gasoline range. Currently, North America and China have the highest use of hydrogen in refineries followed distantly by the Middle East and Europe. Oils with higher sulfur content require more hydrogen for processing. New sulfur rules for fuels, including shipping fuel oils and gasoline, also add a little to hydrogen demand. Hydrogen is typically made at refineries by steam methane reforming. That process could be retrofitted to capture carbon. Refineries typically have hydrogen pipelines in place within and between facilities. Hydrogen pipelines are more costly and have more detailed specifications than natural gas pipelines, but hydrogen can be blended with natural gas to a certain amount and be transported in those gas pipelines without modification. However, most hydrogen projects will want to optimize production near to where it is to be used: at or near refineries, power plants, or underground or tank storage fields.

     In industry the biggest use of hydrogen is as a feedstock for ammonia in fertilizer plants. The second biggest use is as a feedstock for methanol. A new use for hydrogen in low emissions steelmaking is direct-reduced iron (DRI) powered by electric arc furnaces. If the hydrogen is green hydrogen and the electricity for the arc furnace is provided by renewables as well, the process will have the lowest emissions. It may also utilize blue hydrogen and standard grid power for less emissions reduction. DRI already takes up about 10% of industrial hydrogen for related processes. Blending hydrogen with natural gas and coal combustion can also lower emissions in existing steelmaking.

     Hydrogen use in road transport doubled from 2019 to 2021. Its use is predominantly in buses and commercial transport, although its use in cars also doubled. The first hydrogen fuel cell train fleet (14 trains) was deployed in August 2022 in Lower Saxony, Germany. The stock of fuel cell electric vehicles, mostly cars, has tripled in less than 4 years. China, Europe, and Japan are leading in hydrogen for transport and hydrogen road fueling infrastructure. Hydrogen, methanol, and ammonia are also being used in rail, cargo handling, and shipping. Its use at ports helps to lower heavy port air pollution. Methanol, followed by ammonia, then hydrogen is the most developed shipping fuel so far. Methanol is a liquid at room temperature and is less toxic than ammonia. However, ammonia has been shipped at significant levels as fertilizer feedstock for many years.

     Other uses for fuel cells are in buildings and as stationary power sources. There are plans to add more hydrogen capacity at power plants mostly to run combined-cycle gas turbines either blended with natural gas or eventually as standalone hydrogen sources. Blends with ammonia have also been announced. Europe and Asia, mostly Japan and South Korea, are expected to lead here. The IEA estimates that global capacity for hydrogen and ammonia for power production will reach about 1.4 GW by 2030.  

 

Blue Hydrogen (w/CCS) and Green Hydrogen Projections (IEA)

     If all announced projects are delivered and delivered on time, then blue hydrogen could increase by 10 MT and green hydrogen could increase by 14 MT by 2030. I would say that this goal is aspirational and unlikely since only 4% of those projects are either under construction or have reached FID. It would require blue hydrogen to grow by 10 times in 80 months and green hydrogen to grow by well over 40 times in those same 80 months. That does not seem likely at all, especially the green hydrogen scenario which is much more costly per kg of H2. I really don’t expect any major ramp-up of hydrogen till after 2030-2035.

     Green hydrogen will be the favored form of hydrogen in countries that import natural gas due to lack of domestic supply. Those countries pay a higher cost for natural gas so making hydrogen from it is uneconomic compared to countries with abundant domestic supply that export their gas. The U.S. is well situated for blue hydrogen but Europe is better situated for green hydrogen, made from water with electrolyzers powered by renewable energy. Blue hydrogen from the U.S. and other gas producing countries, including Norway, will be much cheaper to produce than green hydrogen, 3 to 4 times cheaper. Blue hydrogen is dependent on the cost of natural gas, which while volatile in 2022 has been steady in most years, especially in places that are pipeline-constrained like Appalachia. Green hydrogen is dependent on the cost of electricity as well as the output of wind and solar, which can vary. China and the EU lead in electrolyzer capacity. The U.S. is third. Japan has done much electrolyzer research but does not have a high electrolyzer capacity. Current electrolyzer capacity is at 10GW but could grow to 60-100GW by 2030. To get over 60GW capacity by 2030 will require strategic development of manufacturing and supply chains. The IEA also suggests in a graph that the cost of electrolyzers will drop by a half to two thirds by 2025. Like most of their H2 predictions, I am quite skeptical. That is less than 2 years away. Electrolyzers require nickel and platinum group minerals so the cost of those commodities will be a factor.

     Policy boosts could help deployment of both pilot and commercial projects. Global standards need to be developed as well as interoperability. Safety standards also need to be agreed. Renewables will likely be sited with electrolyzers as dedicated generation sources tied strictly to making hydrogen. They also have a high land footprint. They will likely have to be overbuilt to some extent to keep the plants running at full capacity, especially to account for daily and seasonal intermittency. They may require some storage or even back-up fossil resources to keep up full utilization. This is especially so of projects that hope to use clipped/curtailed renewables to make hydrogen in those hours when they are overproducing. The economics of those projects are affected by utilization rates that will be much lower than those with dedicated generation. Using grid power to power electrolyzers is not feasible in most cases as it could strain local power and likely require added transmission.

 

Hydrogen Infrastructure, Trade, Byproducts, Storage, and Sequential Development

 

     Hydrogen pipelines have more costly specs than natural gas pipelines. They need special materials and compressors made for hydrogen which are more expensive and more energy consuming than natural gas compressors. Hydrogen can increase the fatigue growth rate of carbon steel pipelines and degrade pipelines faster through the process of hydrogen embrittlement which makes the steel less ductile, more brittle, and thus more likely to crack. Things can be done to reduce that possibility but add to costs. The possibility of transporting and trading hydrogen as a liquid also requires many new logistical considerations. Hydrogen needs lower temperatures to liquify it than does LNG. It also requires tanks that cost about 50% more than LNG tanks. Turning it into ammonia is an option which can use the same tanks and piping, but the tank foundations need to be stronger and smaller since ammonia is much heavier than hydrogen. Thus, there are investment risks to making an LNG facility hydrogen-ready. Liquid hydrogen trade is in its infancy. Currently Japan and Australia trade but that is it. It has been estimated that H2 trade could reach 12 MT by 2030 but that seems unlikely. There are potential customers for about 2 MT and another 2.5 MT possible. Shipping routes, policy, and importing/exporting terminals need to be developed.

     A useful byproduct of green hydrogen production is pure oxygen which can be sold to medical or chemical facilities or to power plants utilizing oxyfuel combustion to optimize pre-combustion carbon capture, like those natural gas plants beginning to be commercialized using the Allam Cycle.

     Underground hydrogen storage in salt caverns is well established in the U.S. Its storage in depleted gas fields is still in the early stages as residual gas in the reservoir, chemical reactions, and the movement of hydrogen through rock porosity have some unknowns. It is likely that porous rock reservoirs, sealed aquifers, and hard rock caverns can store hydrogen adequately. It should also be noted that underground storage projects for gases take a long time to be approved and constructed.

     I and many others think that developing a blue hydrogen economy now where applicable will help in developing a green hydrogen economy later when costs come down due to technology improvements, economies of scope and scale, modularization, standardization, and cheaper, simpler, and more streamlined permitting. However, the IEA believes that the EU will go ahead with big green hydrogen ramp-up as soon as they can. I am quite skeptical of their fast timeline. The blue to green sequence will certainly work better and be more economically favorable in the U.S. and Canada. They do acknowledge their upgraded timeline may be overly ambitious in the following graph from their report which compares their 2021 projections to 2030 with their 2022 projections to 2030. One reason for the increase is the energy crisis brought on by Russian sanctions and turning away from Russian gas. However, the winter has stayed relatively warm and gas prices have stabilized so perhaps they will slow down their predictions a bit next year.

 

Source: IEA Global Hydrogen Review 2022

Conclusions

 

     While lower emissions hydrogen in its blue and green forms will no doubt increase in deployment the rate of that increase is questionable. The IAE’s ambitious near-term forecasts, especially for green hydrogen do not seem obtainable to me. However, I could be wrong as they have policies and subsidization in place to help projects along. Others issues like manufacturing and supply chain challenges don’t bode well for a fast rollout. There are other things still to be worked out. I do think hydrogen will be a growing part of the energy picture in years to come but how many years to come is the question. My guess is closer to 2035 rather than 2030.

 

References:

The Outlook for Hydrogen in an Evolving Energy Landscape (GTI Webinar, Feb. 3, 2023). Gas Technology Institute.

 

Natural Gas and Decarbonization: Key Component and Enabler of the Lower Carbon, Reasonable Cost Energy Systems of the Future: Strategies for the 2020’s and Beyond. Kent C. Stewart. March 2022. Amazon Publishing.

 

Global Hydrogen Review 2022. International Energy Agency. Clean Energy Ministerial, Hydrogen Initiative. Global Hydrogen Review 2022 (windows.net)