Hydrogen

Hydrogen is an alternative fuel that can be produced from a variety of resources. Government and industry are engaged in R&D to improve production and distribution and reduce emissions and costs for hydrogen use in fuel cell electric vehicles(DOE 2019). For information about hydrogen production pathways, see the National Renewable Energy Laboratory's Hydrogen Analysis Production Case Studies.

On this page, explore the fuel price and emissions intensity of hydrogen fuel at the retail level.

Key Assumptions

The data and estimates presented here are based on the following key assumptions:

  • The high and low fuel prices are associated with particular years; because we do not provide a time-series trajectory, we show fuel price at a frozen level for all years so we can offer a range of fuel price values. In the levelized cost of driving and emissions charts, this approach clearly distinguishes effects of fuels from those of vehicle technologies because fuels remain constant while vehicle technologies change over time.
  • The fuel price for hydrogen includes the production cost and the cost of infrastructure for hydrogen delivery and dispensing. We do not add a tax to hydrogen, because hydrogen is not currently taxed.
  • Current hydrogen prices are highly variable due to the nascent market maturity. Fuel costs are often included in leases for fuel cell electric vehicles, are not paid by the user at the pump. The hydrogen price at the pump in California is approximately $16.50/kg (California Energy Commission and California Air Resources Board 2019). For the ATB, we base the Current market scenario on modeled production costs and current delivery and dispensing costs, as described below.
  • The delivery and dispensing cost for the steam methane reforming Current market scenario is $12.53/ gge of the $13.70/gge. The estimate is the average of the range of current cost estimates from Rustagi et al. (2018) of $12.07/gge–$12.99/gge (corresponding to $11.80/kg-$12.70/kg in 2017$ from the original source). This range corresponds to the costs of hydrogen delivery and dispensing from two common station types today- a 180 kg/day station supplied by a gaseous tube trailer, and a 350 kg/day station supplied by a liquid tanker.
  • The delivery and dispensing cost for the other non- Current market scenario pathways is estimated at $10.89/gge in the Current Modeled technology, Current Volume scenario, based on mid-volume tube-trailer delivery and low-volume manufacturing; $6.27/gge in the Current Modeled, High Volume scenario based on high-volume tube-trailer delivery and high-volume manufacturing; and $2.05/gge in the Future Modeled, High Volume scenario, based on the ultimate, high-volume hydrogen delivery and dispensing cost target. All delivery costs were modeled in the Hydrogen Delivery Scenario Analysis Model 3.2 (Argonne National Laboratory 2019c) and are based on gaseous hydrogen delivery. All values are converted based on 1.019 gge/kg hydrogen and updated to 2018 dollars (the delivery and dispensing costs above correspond to $10.65/kg, $6.13/kg, and $2.00/kg in 2016$ from HDSAM, respectively).
  • Production costs for all pathways except for the two byproduct pathways are based on the production case studies from U.S. Department of Energy H2A: Hydrogen Analysis Production Case Studies (DOE 2018b), which use Annual Energy Outlook 2017 projections for electricity and natural gas feedstocks (EIA 2017). The delivered industrial electricity prices and the delivered industrial natural gas prices are used.
  • For steam methane reforming production, the Current Market and Current Modeled, Current Volume production scenarios are estimated from the "Current Central Hydrogen Production from Natural Gas without CO2 Sequestration Version 3.2018" H2A case study, and the Future Modeled, High Volume scenario is estimated from the "Future Central Hydrogen Production from Natural Gas without CO2 Sequestration Version 3.2018" H2A case study.
  • For low-temperature electrolysis production, production estimates are based on the 2019 Polymer Electrolyte Membrane (PEM) case study from the DOE Hydrogen and Fuel Cell Technologies Office (Peterson, Vickers, and DeSantis 2020), which is consistent with the 2019 H2A case studies. The Current Modeled, High Volume scenario is estimated from the "Current Central Hydrogen Production from Polymer Electrolyte Membrane (PEM) Electrolysis (2019) version 3.2018" H2A case study. The Future Modeled, High Volume scenario is estimated from the "Future Central Hydrogen Production from PEM Electrolysis (2019) version 3.2018" H2A case study. The Transportation ATB assumes low-temperature electrolysis to be paired with wind and solar generators, therefore a lower capacity factor of 40% is assumed.
  • For high-temperature electrolysis production, the Current Modeled, High Volume scenario is estimated from the "Current Central Hydrogen Production from Solid Oxide Electrolysis Version 3.2018" H2A case study, and the Future Modeled, High Volume scenario is estimated from the "Future Central Hydrogen Production from Solid Oxide Electrolysis Version 3.2018" H2A case study. The Transportation ATB assumes high-temperature electrolysis to be paired with nuclear generators.
  • For biomass gasification production, the nth plant scenario is estimated from the "Current Central Hydrogen Production via Biomass Gasification Version 3.2018" H2A case study. Both the current and future case studies in H2A use Future Modeled, High Volume assumptions; the current case study is used here as a conservative estimate.
  • Emissions estimates for all hydrogen pathways except byproduct (chlor-alkali plants) and byproduct (cracking) are from GREET(Argonne National Laboratory 2018). All delivery is assumed to be gaseous.
  • Byproduct (chlor-alkali plants) and byproduct (cracking) production estimates are based on analysis from Lee and Elgowainy (2018). Lee and Elgowainy (2018) do not provide specific plant design assumptions, so plant metric values are not presented here.
  • The data downloads include additional detail on assumptions and calculations for each metric.

References

The following references are specific to this page; for all references in this ATB, see References.

Argonne National Laboratory (2018). GREET Model: The Greenhouse gases, Regulated Emissions, and Energy use in Transportation Model. Argonne National Laboratory. https://greet.es.anl.gov/

Argonne National Laboratory (2019). Hydrogen Delivery Scenario Analysis Model (HDSAM). https://hdsam.es.anl.gov/

California Energy Commission and California Air Resources Board, (2019). Joint Agency Staff Report on Assembly Bill 8: 2019 Annual Assessment of Time and Cost Needed to Attain 100 Hydrogen Refueling Stations in California. (No. CEC-600-2019-039). California Energy Commission and California Air Resources Board. https://ww2.energy.ca.gov/2019publications/CEC-600-2019-039/CEC-600-2019-039.pdf

DOE (2019). Alternative Fuels Data Center. https://afdc.energy.gov/

DOE, (2018). H2A: Hydrogen Analysis Production Case Studies. https://www.nrel.gov/hydrogen/h2a-production-case-studies.html

EIA (2017). Annual Energy Outlook 2017. U.S. Energy Information Administration. https://www.eia.gov/outlooks/aeo/data/browser/

Lee, Dong-Yeon, & Elgowainy, Amgad. (2018). By-Product Hydrogen from Steam Cracking of Natural Gas Liquids (NGLs): Potential for Large-Scale Hydrogen Fuel Production, Life-Cycle air Emissions Reduction, and Economic Benefit. International Journal of Hydrogen Energy, 43(43), 20143-20160.

Peterson, David, Vickers, James, & DeSantis, Dan. (2020). Hydrogen Production Cost From PEM Electrolysis - 2019. (No. Record: 19009). Department of Energy. https://www.hydrogen.energy.gov/pdfs/19009_h2_production_cost_pem_electrolysis_2019.pdf

Rustagi, Neha, Elgowainy, Amgad, & Vickers, James. (2018). Current Status of Hydrogen Delivery and Dispensing Costs and Pathways to Future Cost Reductions. (No. 18003). U.S. Department of Energy. https://www.hydrogen.energy.gov/pdfs/18003_current_status_hydrogen_delivery_dispensing_costs.pdf


Developed with funding from the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy.