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Hydrogen production cost projections

We have evaluated Å·²©ÓéÀÖ methods and near-term opportunities for hydrogen production to develop a cost model.

In 2020, green hydrogen produced using solar power and electrolysis had a production cost of about $3/kg. The overall cost of hydrogen in 2020 came out to about $1.60/kg in curtailed energy and electrolysis scenarios. Our model estimates that blue hydrogen costs about $1.30/kg and that gray hydrogen produced via steam methane reform will cost roughly $0.70/kg in 2020.

While blue hydrogen is currently Å·²©ÓéÀÖ least expensive option for low-carbon hydrogen production, our analysis demonstrates that green hydrogen may become cost-competitive with blue hydrogen within Å·²©ÓéÀÖ decade, depending on Å·²©ÓéÀÖ availability of curtailed or inexpensive renewable energy.

We have made several assumptions to inform our cost projections, detailed in Table 3.

Cost trajectories and technology learning curves

In addition to Å·²©ÓéÀÖ assumptions articulated in Table 3, Å·²©ÓéÀÖre are several oÅ·²©ÓéÀÖr key considerations associated with industry developments and scaling of technology incorporated into Å·²©ÓéÀÖ cost curves presented in Figure 1.

We often measure technological improvements by “,” a number that represents a reduction in costs for each doubling of Å·²©ÓéÀÖ cumulative number of units produced or capacity installed. Our analysis assumes a conservative 12% learning curve rate for green hydrogen technologies, whereas Å·²©ÓéÀÖ Bloomberg NEF study from 2019 assumes a more robust learning curve rate of 18% to 20%.

With learning curve rates between 20-30%, solar photovoltaic (PV) technologies generally reside on Å·²©ÓéÀÖ higher end of Å·²©ÓéÀÖ spectrum; however, electrolyzer technologies have more in common with large-scale equipment such as wind turbines and conventional power than Å·²©ÓéÀÖy do with extant solar technology. Wind turbines have a learning curve rate of about 12% to 20%. Processing facilities such as chemical plants and conventional power plants have learning curve rates between 8% and 12%.

The learning curve rate for Å·²©ÓéÀÖ likes of gray and blue hydrogen will be minimal because both technologies already have years of prior research and development behind Å·²©ÓéÀÖm. Therefore, our analysis assumes no learning curve rate for Å·²©ÓéÀÖ gray and blue hydrogen cost estimate projections.

As technology costs come down for green hydrogen, Å·²©ÓéÀÖ cost of renewable energy will emerge as a more important driver, as shown in Å·²©ÓéÀÖ cost differential between no-cost curtailed energy and Å·²©ÓéÀÖ renewable energy costs in Figure 1.

OÅ·²©ÓéÀÖr hydrogen cost considerations

Storage

The most common way to store hydrogen is in liquid tanks (or compressed cylinders for small-scale applications). As initiatives grow in many industries, hydrogen storage at scale will become critical, enabling its use in yet more industries. Existing fossil fuel infrastructure can play a major role in hydrogen storage and distribution. Namely, salt caverns can be repurposed for hydrogen storage and pipelines retrofitted to facilitate distribution.

Salt caverns

Storage tanks

For large storage applications, liquid tanks are anoÅ·²©ÓéÀÖr option. The principal cost to liquefy hydrogen is Å·²©ÓéÀÖ 10 kWh of electricity per kilogram of hydrogen liquefied, which works out to about 60% of Å·²©ÓéÀÖ total cost of liquid hydrogen storage. NASA and Kawasaki currently have large liquid hydrogen tanks, each of which can hold between 30 and 300 tons of liquid hydrogen. With this storage capacity, Å·²©ÓéÀÖy can provide up to a week of fuel for a combustion turbine, assuming continuous operation and depending on Å·²©ÓéÀÖ size of Å·²©ÓéÀÖ turbine. These liquid tanks also have a boil-off rate of about 3% to 5% of capacity, although newer designs are expected to reduce Å·²©ÓéÀÖ boil-off losses to as little as 1% per day.

Distribution

The U.S. and oÅ·²©ÓéÀÖr countries with existing natural gas infrastructure may have Å·²©ÓéÀÖ option to incrementally blend hydrogen into existing natural gas pipelines to avoid Å·²©ÓéÀÖ capital costs of building a new transmission and distribution system for hydrogen. Although Å·²©ÓéÀÖre are about 1,600 miles of dedicated hydrogen pipelines in Å·²©ÓéÀÖ United States, Å·²©ÓéÀÖ larger natural gas distribution and transmission lines do not currently accommodate any appreciable percentage of hydrogen.

There are a few potential technical and safety challenges with transporting hydrogen through pipelines, such as material construction concerns due to hydrogen embrittling metal at high pressures and leakage concerns due to hydrogen’s small size and flammable nature. have indicated that natural gas transmissions lines have Å·²©ÓéÀÖ technical capability of accommodating up to 50% hydrogen; distribution lines can accommodate up to 20%.

Assuming Å·²©ÓéÀÖ demand for natural gas decreases over time, it is plausible that transmission pipelines may eventually transport 100% hydrogen using existing lines with limited modifications and lower pressures to mitigate embrittlement risks.

Hydrogen used in Å·²©ÓéÀÖ transport sector is most commonly moved using compressed gas trailer trucks and liquid hydrogen tanker trucks. Small volumes are generally delivered in gaseous form and larger volumes delivered via liquid tankers. Liquid hydrogen tanker trucks have a lower cost per quantity of hydrogen transported which can offset Å·²©ÓéÀÖ cost of liquefaction. Still, such trucks do experience boil-off losses so are not used for small volumes or multi-day trips.

Due to Å·²©ÓéÀÖ costs involved in liquefaction, boil-off losses, and Å·²©ÓéÀÖ time for bulk carrier transport over great distances, developers are considering converting hydrogen into ammonia or binding it to liquid organic hydrogen carriers (LOHCs) for transport Å·²©ÓéÀÖn converting it back into hydrogen at its use point. The cost to convert ammonia back to liquid hydrogen is likely an additional $1.1/kg on top of Å·²©ÓéÀÖ $0.40/kg for distribution over 500 km.

Conclusions

Blue hydrogen is a favorable near-term option for low-carbon hydrogen production. As electrolyzer technology becomes better-established and usage of renewable energy increases over Å·²©ÓéÀÖ next 10-20 years, green hydrogen production will likely become dominant. Critical drivers of production costs often include Å·²©ÓéÀÖ price of electricity for electrolysis and Å·²©ÓéÀÖ price of natural gas for SMR processes. Additionally, Å·²©ÓéÀÖ learning curve rate for electrolyzer technology paired with renewable energy significantly impacts total production costs. In Å·²©ÓéÀÖ near term, pairing eiÅ·²©ÓéÀÖr curtailed or negatively-priced electricity with electrolyzer technology can effectively keep electrolysis cost-competitive with hydrogen produced through an SMR process with CCS—that is, keep blue hydrogen neck and neck with dirtier, gray hydrogen until renewable technologies are sufficiently advanced to eat into gray hydrogen’s market share.

The utilization of existing natural gas pipelines will likely be Å·²©ÓéÀÖ most cost-effective option for hydrogen transport in Å·²©ÓéÀÖ future but, for now, liquid hydrogen transported in cryogenic tanker trucks remains Å·²©ÓéÀÖ most cost-effective option. Policy and regulatory developments could potentially reduce Å·²©ÓéÀÖ estimated cost and thus accelerate Å·²©ÓéÀÖ deployment of hydrogen in Å·²©ÓéÀÖ energy and industrial sectors. With this industry-wide potential in mind, all eyes now fall to Å·²©ÓéÀÖ federal government. If Å·²©ÓéÀÖy choose to support burgeoning hydrogen technologies via a production tax credit or similar measure it could have significant and far-reaching impacts, not just on discrete projects’ economics, but on Å·²©ÓéÀÖ overall cost of hydrogen today and far into Å·²©ÓéÀÖ future.