Assessment of Fuel Cell Technologies
at Ports
£% United States
Environmental Protect
Agency
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Assessment of Fuel Cell Technologies
at Ports
Transportation and Climate Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
Prepared for EPA by
Eastern Research Group, Inc.
EPA Contract No. EP-C-17-011
Work Assignment 3-27
4>EPA
United States
Environmental Protection
Agency
EPA-420-R-22-013
July 2022
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Notice
This document is disseminated under the sponsorship of the U.S. Environmental Protection Agency in
the interest of information exchange. The U.S. Government assumes no liability for the use of the
information contained in this document.
The U.S. Government does not endorse products or manufacturers. Trademarks or manufacturers'
names appear in this report only because they are considered essential to the objective of the
document.
The contents of this report reflect the views of the authors, who are responsible for the facts and
accuracy of the data presented herein. The contents do not necessarily reflect the official policy of
the U.S. Environmental Protection Agency.
This report does not constitute a standard, specification, or regulation.
Quality Assurance Statement
EPA's Office of Transportation and Air Quality, Transportation and Climate Division (TCD) provides
high-quality information to serve Government, industry, and the public in a manner that promotes
public understanding. Standards and policies are used to ensure and maximize the quality, objectivity,
utility, and integrity of its information. TCD periodically reviews quality issues and adjusts its
programs and processes to ensure continuous quality improvement.
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EPA Overview-Assessment of Fuel Cell Technologies at U.S. Ports
Ports in the United States are gateways for trade and critical to the economy. While future growth in global
trade and goods movement at ports is expected, it is critical to be cognizant of environmental protection.
The Environmental Protection Agency's (EPA) Office of Transportation and Air Quality (OTAQ) recognizes the
air quality, environmental justice, and economic significance of the U.S. port sector and established the EPA
Ports Initiative. EPA's Ports Initiative supports efforts to improve efficiency, enhance energy security, save
costs, and reduce harmful health impacts by advancing next-generation, cleaner technologies, and practices
at ports. Fuel cells, in addition to other technologies, have the potential to replace diesel engines across a
variety of sectors and thus significantly reduce emissions at ports. To better inform port stakeholders, EPA
contracted Eastern Research Group (ERG) to research and develop a report characterizing different fuel cell
technologies and how they might be utilized at ports.
The predominate equipment power source at ports are diesel engines, however, diesel engines are often a
significant source of air pollutant emissions. While there are a variety of technologies used to address
emissions at ports, this report specifically examines fuel cell technologies compared to traditional diesel
applications in order to gain a better understanding of this particular technology.
The Assessment of Fuel Cell Technologies at Ports report characterizes fuel cell systems, their history, and
their potential utilization at ports. The report consists of four main components: 1) fuel cell background
information, 2) current fuel cell applications at ports, 3) emission analysis of fuel cell technologies, and 4)
economics and impacts of using fuel cells. This report illustrates that fuel cell technologies have the
potential to replace diesel engines across a variety of sectors and thus significantly reduce diesel emissions
at ports.
Important Findings & Points Regarding the Assessment of Fuel Cell Technologies at Ports Report
~ Fuel cell equipment and fuel cell power generation options are currently commercially available in
certain applications (e.g. forklifts). Fuel cells generate electricity to power equipment much like a
battery supplies electricity to power equipment. However, fuel cells use a fuel such as hydrogen I
rather than recharge from the electric grid. Fuel cell electric technologies produce only water vapor
and warm air. Consequently, fuel cell electric and battery electric are common terms that distinguish
these two zero emission technologies as both are types of electric, clean technologies.
~ This report focuses on fuel cell electric applications compared to the traditional diesel applications at
ports to learn more about the technology and its various applications. Other technologies, such as
battery electric applications, are not examined in this report. Information on how fuel cells compare to
battery electric applications is available from other sources, including a 2009 Department of Energy
report titled "Fuel Cell and Battery Electric Vehicles Compared"1 by Dr. C.E. Sandy Thomas at H2Gen
Innovations, Inc. Also, more information on alternative fuels and advanced vehicles can be found at
https://afdc.energy.gov/fuels/. [More information provided on the footnote below2.]
~ Different sources of hydrogen are currently available, but the environmental benefits vary.
1 https://www.energy.gov/sites/default/files/2014/03/f9/thomas fcev vs battery evs.pdf
2 https://innovation.luskin.ucla.edu/wp-content/uploads/2019/10/Zero Emission Dravage Trucks.pdf
https://kentico.portoflosangeles.org/getmedia/31d5e97c-37f9-4519-953d-dcl49968a7dc/zero-emissions-roadmap-
technical-report, https://kentico.portoflosangeles.org/getmedia/f5183c7e-3731-4cd6-a4d0-
346955al7e3a/Zero Emmissions White Paper DRAFT, https://cleanairactionplan.org/documents/final-cargo-handling-
equipment-che-feasibilitv-assessment.pdf/
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~ While some fuel cell equipment is currently cost competitive with diesel equipment, for other
equipment applications the incremental capital and operating costs will need to decrease over the
next decade to achieve parity with diesel equipment.
~ EPA recognizes that demonstrating long term durability of the various applications fuel cells is critical
to fully capturing the benefits of the technology. Additional research will be critical to fully understand
the complexities of fuel cell technologies beyond the demonstration phase.
For more information about this Assessment of Fuel Cell Technologies at Ports
Web: https://www.epa.gov/ports-initiative
Email: TalkAboutPortsffiepa.gov
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Table of Contents
Glossary of Terms xi
Executive Summary 1
Port Fuel Cell Equipment Applications 2
Hydrogen Fuel Production, Supply and Dispensing 4
Hydrogen Fuel Cell Lifecycle Emissions 7
Port Fuel and Fuel Cell Equipment Costs 11
Future Hydrogen and Fuel Cell Market Penetration 13
Key Stakeholder Considerations for Current Port Fuel Cell Equipment Implementation 15
1. Introduction 1-1
1.1 Study Purpose, Objectives, and Approach 1-1
2. Fuel Cell Technology and Market Status 2-1
2.1 Fuel Cells Explained 2-1
2.2 Fuel Cell Types and Characteristics 2-3
2.2.1 Polymer Electrolyte Membrane 2-3
2.2.2 Alkaline 2-4
2.2.3 Phosphoric Acid 2-5
2.2.4 Molten Carbonate 2-6
2.2.5 Solid Oxide 2-7
2.2.6 Summary of Common Fuel Cell Type Characteristics 2-8
2.3 Fuel Cell Market Status 2-8
2.3.1 Worldwide Market Status 2-8
2.3.2 Transportation Market Applications 2-11
2.3.3 Stationary and Portable Power Applications 2-12
3. Fuel Cell Applications and Characteristics for Ports 3-1
3.1 Nonroad Materials Handling Equipment 3-1
3.1.1 Forklifts 3-1
3.1.2 Yard Tractors 3-3
3.1.3 Cargo Handlers 3-5
3.2 Switcher Locomotives 3-7
3.2.1 Diesel-Fueled 3-7
3.2.2 Fuel Cell-Powered 3-9
3.3 Marine Propulsion and Auxiliary Power 3-9
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3.3.1 Diesel-Fueled 3-9
3.3.2 Fuel Cell-Powered 3-10
3.4 Stationary Power 3-11
3.4.1 Diesel-Fueled 3-11
3.4.2 Fuel Cell-Powered 3-11
4. Fuel Cell Fuel Supply Infrastructure 4-1
4.1 Hydrogen Production, Storage, and Transport Technologies 4-1
4.1.1 Hydrogen Production Technologies 4-1
4.1.2 Hydrogen Production Process Feedstock, Water Requirements, and Emissions 4-4
4.1.3 Hydrogen Storage and Transport Technologies 4-5
4.2 Future Potential Hydrogen Production and Delivery Pathways 4-10
4.2.1 Centralized Hydrogen Pathways 4-11
4.2.2 Distributed Hydrogen Pathways 4-13
4.3 Non-Hydrogen Fuel Supplies for Direct Fuel Cell Use 4-14
4.3.1 Natural Gas 4-14
4.3.2 Methanol 4-14
4.3.3 Ammonia 4-14
5. Port Fuel Cell Equipment, Infrastructure, and Fuel Costs 5-1
5.1 Hydrogen Infrastructure and Delivery Costs 5-1
5.1.1 Refueling Station Capital and Operating Costs 5-1
5.1.2 Dispensed Hydrogen Price 5-2
5.2 Port Fuel Cell Equipment Costs by Port Application 5-4
5.2.1 Forklift Costs 5-5
5.2.2 Yard Tractor Costs 5-6
5.2.3 Cargo Handlers (Top Loaders) Costs 5-7
5.2.4 Switcher Locomotive Costs 5-8
5.2.5 Marine Propulsion and Auxiliary Power System Costs 5-9
5.2.6 Stationary Power Generator Costs 5-10
5.3 Port Fuel Cell Equipment Annual Savings and Capital Cost Recovery 5-11
5.3.1 Lifecycle Savings and Payback 5-11
6. Hydrogen Fuel Cell Lifecycle Emissions 6-1
6.1 Hydrogen Fuel Cycle and Fuel Cell Equipment Cycle 6-1
6.2 Hydrogen Fuel Cycle Pathways 6-1
6.2.1 Centralized Hydrogen Production Scenarios 6-2
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6.2.2 Distributed Hydrogen Production Scenarios 6-4
6.3 Fuel Cell Equipment Cycle Pathways 6-6
6.3.1 Raw Material Recovery and Processing 6-6
6.3.2 Equipment Component Production and System Assembly 6-6
6.3.3 Fuel Cell Equipment Application Assembly 6-8
6.3.4 Fuel Cell Equipment Application Disposal/Recycling 6-8
6.4 Lifecycle Emissions Estimation Methodology, Tools, and Resources for Port Equipment
Applications 6-8
6.4.1 Proposed Lifecycle Emissions Estimation Framework 6-8
6.5 Port Locations and Regional Analysis Results 6-19
6.6 Additional Analytical Sources 6-20
7. Future Hydrogen and Fuel Cell Market Penetration 7-1
7.1 Primary Factors for Future Fuel Cell Commercial Viability and Competitiveness 7-1
7.1.1 Equipment Capital Cost 7-1
7.1.2 Equipment Durability/Reliability 7-2
7.1.3 Equipment Power and Duty Cycle Performance 7-2
7.1.4 Equipment Operational Hours/Range 7-3
7.1.5 Equipment Maintenance/Serviceability 7-4
7.1.6 Hydrogen Fuel Price 7-4
7.2 Future Potential Hydrogen Fuel Supply and Demand 7-6
7.3 Future Fuel Cell Equipment Market Penetration 7-10
7.3.1 Fuel Cell Forklifts 7-11
7.3.2 Fuel Cell Cargo Handling Equipment 7-12
7.3.3 Fuel Cell Switcher Locomotives 7-13
7.3.4 Fuel Cell Marine Propulsion and Power 7-14
7.3.5 Fuel Cell Power Generator Systems 7-15
8. Areas of Uncertainty 8-1
8.1 Uncertainty in the Economics and Emissions Analysis 8-1
8.1.1 Economics 8-1
8.1.2 Emissions 8-1
8.2 Current Barriers to the Fuel Cell Implementation at Ports 8-1
8.3 Potential Areas for Future Work 8-2
9. Summary and Conclusions 9-1
9.1 Study Overview and Scope 9-1
9.2 Summary of Key Findings 9-1
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9.2.1 Fuel Cell Types and Characteristics 9-1
9.2.2 Fuel Cell Market Status 9-2
9.2.3 Fuel Cell Equipment Applications and Characteristics for Ports 9-3
9.2.4 Fuel Cell Fuel Supply Infrastructure 9-4
9.2.5 Port Fuel Cell Equipment, Infrastructure, and Fuel Costs 9-7
9.2.6 Port Fuel Cell Equipment Costs by Port Application 9-7
9.2.7 Hydrogen Fuel Cell Lifecycle Emissions 9-8
9.2.8 Future Hydrogen and Fuel Cell Market Penetration 9-10
10. References 10-1
Appendix A-Summary of Recent Fuel Cell Equipment Demonstrations and Deployments at U.S. Ports
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List of Tables
Table 1. Primary Benefits and Remaining Challenges for Fuel Cell Technology Applications at Port
Facilities 3
Table 2. Typical Diesel-Fueled Equipment Used at Port Facilities and Common Fuel Cell Replacement
Characteristics 4
Table 3. Centralized and Distributed Hydrogen Pathway Production Processes and Characteristics 5
Table 4. WTP Emissions Characteristics for Hydrogen Fuel and Diesel Fuel Pathways for Year 2020 7
Table 5. PTW Emission Characteristics for Diesel-Fueled Port Equipment 8
Table 6. WTW Emission Reductions for Fuel Cell Equipment and Four Gaseous Hydrogen Fuel Pathways
Relative to Comparable Diesel-Fueled Equipment 10
Table 7. Summary of Fuel Cell Equipment Capital and Operating Cost Results 13
Table 8. Summary of Operating Characteristics by Fuel Cell Type 2-10
Table 9. Fuel Cell and Diesel Back-up Power System Comparison 2-13
Table 10. Typical Port Location Diesel-Fueled Forklift Operational Characteristics 3-2
Table 11. Typical Port Location Diesel-Fueled Yard Tractor Operational Characteristics 3-3
Table 12. Port of Long Beach/Port of Los Angeles Yard Tractor In-use Data Summary 3-4
Table 13. Port of Long Beach/Port of Los Angeles Minimum Performance Guidelines for Zero/Near-
Zero Yard T ractors 3-4
Table 14. Port of Long Beach/Port of Los Angeles Design Duty Cycle - 8-hour Shift Minimum
Requirements 3-4
Table 15. Typical Port Location Diesel-Fueled Top Loader Operational Characteristics 3-5
Table 16. Typical California Switcher Locomotive Specifications 3-7
Table 17. Federal Switcher Locomotive Duty Cycle under 40 CFR § 1033.530 3-8
Table 18. Typical Switcher Locomotive at Port of Portland's OIG Railyard 3-8
Table 19. Port of Long Beach 2014 Harbor Craft Inventory Information 3-10
Table 20. Examples of Recent International Marine Vessel Fuel Cell Projects 3-11
Table 21. Comparison of Electrolyzer Types 4-3
Table 22. Summary of Hydrogen Production Process Characteristics 4-4
Table 23. Midlife Lifecycle Emission Values (per kg hydrogen) of Hydrogen Production Processes 4-5
Table 24. States with High Potential for Centralized Hydrogen Production 4-12
Table 25. Estimated Hydrogen Refueling Station Capital and Operating Costs by Hydrogen Delivery
Method 5-3
Table 27. Final Estimated Dispensed Hydrogen Costs by Production and Delivery Type 5-4
Table 26. Estimated Hydrogen Production and Transport Costs 5-4
Table 28. Estimated Cost Comparison of Diesel and Fuel Cell Forklifts 5-6
Table 29. Estimated Cost Comparison of Diesel and Fuel Cell Yard Tractors 5-7
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Table 30. Estimated Cost Comparison of Diesel and Fuel Cell Cargo Handlers 5-8
Table 31. Estimated Cost Comparison of Diesel and Fuel Cell Switcher Locomotive 5-9
Table 32. Cost Comparison of Diesel and Fuel Cell Ferry Boat 5-10
Table 33. Estimated Cost Comparison of Diesel and Fuel Cell Power Generator 5-11
Table 34. Estimated Port Fuel Cell Equipment Payback by Calendar Year 5-12
Table 35. Assumed Near- and Mid-Term Port Fuel Cell Equipment Applications 6-4
Table 36. 2019 GREET WTP Results for Gaseous and Liquid Hydrogen Production 6-11
Table 37. Recommended Emission Estimation Models/Sources by Port Equipment Application 6-12
Table 38. PTW Factors for Diesel-Fueled Port Equipment per Gallon Diesel Fuel 6-14
Table 39. Summary of WTW Emission Reductions for Fuel Cell Equipment/Gaseous Hydrogen Fuel
Pathways Relative to Comparable Diesel-Fueled Equipment 6-15
Table 40. Estimated Fuel Cell System Costs by Application and Production Volume 7-1
Table 41. Typical Fuel Cell Power Requirements and Range Extender Design for Various Container
Handler Duty Cycles 7-3
Table 42. DOE Estimated Retail Hydrogen Price Projections Compared with Retail Diesel Price 7-5
Table 43. Future Technical Potential Hydrogen Demand by Market Sector 7-9
Table 44. NREL Hydrogen Demand Economic Potential Scenarios 7-9
Table 45. Economic Potential Hydrogen Demand Equilibrium Point Results by Scenario 7-10
Table 46. Common Fuel Cell Type Characteristics 9-2
Table 47. Typical Diesel-Fueled Equipment Characteristics Used at Port Facilities and Common Fuel Cell
Replacements 9-3
Table 48. Feedstock, Water, and Electricity Requirements for Hydrogen Production Processes 9-5
Table 49. Implementation Timeframes for Centralized and Distributed Hydrogen Pathways 9-6
Table 50. Fuel Cell Equipment Capital and Operating Cost Results 9-8
Table 51. WTP Emission Reduction Summary for Port Fuel Cell Equipment Relative to Diesel Equipment 9-9
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List of Figures
Figure 1. Estimated Port Fuel Cell Equipment Market Penetration (2020-2050) 15
Figure 2. Basic Fuel Cell Schematic 2-2
Figure 3. PEMFC Process Schematic 2-4
Figure 4. AFC Process Schematic 2-5
Figure 5. PAFC Process Schematic 2-6
Figure 6. MCFC Process Schematic 2-7
Figure 7. SOFC Process Schematic 2-8
Figure 8. Worldwide Fuel Market Data (E4tech, 2018) 2-9
Figure 9. NREL Total Cost of Ownership for Material Handling Equipment 3-3
Figure 11. Typical Energy Usage for Top Loader Operation under Rail Duty Cycles 3-6
Figure 10. Typical Energy Usage for Top Loader Operation under Yard and Dock Duty Cycles 3-6
Figure 12. Hydrogen Transport and Distribution Modes 4-6
Figure 13. High-Pressure Gaseous Hydrogen Delivery System 4-8
Figure 14. Liquid Hydrogen Delivery System 4-9
Figure 15. Current and Future Potential Centralized and Distributed Hydrogen Production Technologies 4-11
Figure 16. General Hydrogen Fuel Cycle and Fuel Cell Equipment Cycle Pathways 6-2
Figure 17. Centralized Hydrogen Fuel Cycle Pathways 6-3
Figure 18. Distributed Hydrogen Fuel Cycle Pathways 6-5
Figure 19. Fuel Cell Equipment Cycle Pathways 6-7
Figure 20. Natural Gas Consumption and Price Projections 7-7
Figure 21. Electricity Price Projections 7-7
Figure 22. Projected Annual Electricity Generation Capacity (GW) Additions/Retirements (Reference
Case) 7-8
Figure 23. Estimated Annual Class IV-V Fuel Cell Forklift U.S. Market Penetration 7-11
Figure 24. Estimated Annual Fuel Cell Cargo Handling Equipment Market Penetration 7-12
Figure 25. Estimated Annual Fuel Cell Switcher Locomotive Market Penetration 7-13
Figure 26. Estimated Annual Fuel Cell Harbor Craft Market Penetration 7-14
Figure 27. Estimated Annual Fuel Cell Generator Market Penetration 7-15
Figure 28. Worldwide Fuel Cell Market Status in 2018 9-2
Figure 29. Estimated Port Fuel Cell Equipment Market Penetration (2020-2050) 9-11
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Glossary of Terms
Alkaline fuel cell (AFC) -a type of fuel cell that uses an aqueous electrolyte solution of sodium hydroxide or
potassium hydroxide and reacts pure hydrogen with oxygen to produce electric current.
Ammonia cracking - a thermal catalytic cracking process using temperatures above 400°C.
Anode-the electrode of a fuel cell in which electrochemical oxidation occurs.
Biomass- An energy resource derived from organic matter. These include wood, agricultural waste, and other
living-cell material that can be burned to produce heat energy3. They also include algae, sewage, and other
organic substances that may be used to make energy through chemical processes.
Biomass feedstocks- include dedicated energy crops, agricultural crop residues, forestry residues, algae, wood
processing residues, municipal waste, and wet waste (crop wastes, forest residues, purpose-grown grasses,
woody energy crops, algae, industrial wastes, sorted municipal solid waste [MSW], urban wood waste, and
food waste).1
Biomass-to-liquids (BTL) Pro a multi-step thermochemical process for producing synthetic hydrocarbon fuels
made from biomass feedstocks.
Boil-off-the vaporization and release of liquid hydrogen while stored overtime.
Capital payback-the economic recovery ofan initial capital investment overtime. Payback can be measured
in dollar value, percent or time (e.g., years).
Carbon capture and sequestration (CCS) - a set of technologies involving the capture, transport, and
underground injection or geological sequestration (storage) of carbon dioxide (C02) emissions.
Cascade storage system - a subsystem used in hydrogen refueling stations, cascade storage is comprised of
high-pressure storage cylinders typically arranged in three or more banks manifolded together. Hydrogen
compressors pressurize the banks as needed to maintain pressure levels. A cascade control system or fuel
dispenser supplies high pressure gas preferentially from each bank to the equipment requiring refueling based
on the pressure level of the equipment's storage system and the final desired delivered pressure.
Cathode-the electrode of a fuel cell in which electrochemical reduction occurs.
Centralized hydrogen delivery pathway-the process of producing pure hydrogen at large scale plants (50,000
to 500,000 kg/day) followed by hydrogen transport via pipeline, truck, or rail to serve regional or national end-
use markets.
Combined heat and power (CHP) - also known as cogeneration, CHP is a type of energy recovery technology
that involves the simultaneous production of electricity and recovery of heat from plant waste
Cryo-compressed hydrogen storage - the process of storing hydrogen gas at cryogenic temperatures but
within a pressure capable vessel.
Cryogenic liquid - a liquid stored at extremely low temperatures.
3 According to DOE's EERE Bioenergy Technologies Office, https://www.energy.gov/eere/bioenergy/glossarv.
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Diesel gallon equivalent - an amount of fuel equivalent to a gallon of diesel fuel on an energy basis.
Distributed hydrogen delivery pathway-the process of producing hydrogen in small scale plants (typically less
than 1,500 kg/day) at or near hydrogen end-use locations using hydrogen carrier feedstocks such as natural
gas or hydrocarbon fuels that have been transported via pipeline or truck to the plant.
Economic equilibrium point - a quantity measurement at which product demand and supply prices are
equivalent.
Economic hydrogen demand potential - a subset of technical hydrogen demand potential in which hydrogen is
less expensive than other options that can supply the end-use.
Electrochemical reaction - a reaction produced by or accompanied with electricity involving the transfer of
electrons between two substances.
Electrolysis -the process of splitting water into hydrogen and oxygen when applying an electric power source.
Electrolyte - a substance that produces an electrically conducting solution when dissolved in a polar solvent,
such as water.
Ethanol steam reformation (ESR) - a process for producing hydrogen that uses ethanol as the feedstock.
Flammability range -the range in which a fuel in the presence of air is flammable, usually expressed as volume
of fuel in air.
Flash point -the lowest temperature at which a flammable liquid gives off enough vapors to form an ignitable
mixture with air.
Fuel cell stack - multiple individual fuel cells of the same type stacked in a series.
Fuel cycle - under total energy analysis methodology, the fuel cycle encompasses all energy and emissions -
related processes and activities of fuel feedstock extraction, fuel production, fuel product transport,
distribution, dispensing, and fuel usage by end-use vehicles and equipment.
Gasification -the process whereby the reaction of coal or biomass feedstocks with oxygen and steam at high
pressures and temperatures produces synthesis gas consisting of carbon monoxide (CO), hydrogen and
impurities. The impurities are removed from the synthesis gas, which then undergoes the water-gas shift
reaction to produce C02 and additional hydrogen.
Fiber reinforced polymer (FRP) - a recently emerging, advanced material under development as a cheaper
alternative to steel used in pipeline materials.
Hydrogen kilogram equivalent (kg-e) - an amount of fuel equivalent to a kilogram of hydrogen on an energy
basis.
Hydrogen storage module (HSM) - refillable storage devices used to supply hydrogen to various applications.
Storage volumes vary, but HSMs can be substituted for refilled units once depleted in the field.
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Inland port -term sometimes used to describe a port that is not located on a coast (e.g., Great Lakes or
Mississippi River ports) or an area with large intermodal freight facilities that is not near navigable water (e.g.,
landlocked intermodal rail and truck facilities).4
Internal reforming - the ability of some types of fuel cells to convert natural gas or other hydrocarbon fuels
directly into hydrogen at the anode of the fuel cell, thereby eliminating the need for an external fuel processor
for performing the same function.
Liquefaction - the process of converting gases into liquids at very low temperatures.
Microbial biomass conversion - a fermentation process in which biomass feedstock is broken down by
selective microbes to produce hydrogen gas. The process is referred to as "dark fermentation" since it does
not involve light or photosynthetic activity.
Molten carbonate fuel cells (MCFC) -a type of fuel cell that uses a molten carbonate salt in a porous,
chemically inert matrix as an electrolyte and reacts pure hydrogen or hydrocarbon fuels with oxygen to
produce electric current.
Phosphoric acid fuel cell (PAFC) - a type of fuel cell that reacts pure hydrogen or hydrogen carbon fuels and
oxygen, while also using an electrolyte consisting of phosphoric acid soaked in a porous matrix or imbibed
polymer membrane to produce electric current.
Partial oxidation - a process involving the reaction of natural gas or other feedstocks with less than
stoichiometric levels of oxygen (usually from air), resulting in a synthesis gas stream of hydrogen, CO, nitrogen
(if air is used as a reactant rather than oxygen), and a small amount of C02 and other trace products.
Polymer electrolyte membrane fuel cells (PEMFC) - a type of fuel cell that reacts pure hydrogen and oxygen
and uses a polymer electrolyte membrane to produce electric current.
Port - generally refers to places alongside navigable water (e.g., oceans, rivers, or lakes) with facilities for the
loading and unloading of passengers or cargo from ships, ferries, and other commercial vessels. These facilities
may be operated by different entities including state or local public port authorities, private terminal
operators, and federal agencies. Activities associated with ports include operation of vessels, cargo handling
equipment, locomotives, trucks, vehicles, and storage and warehousing facilities related to the transportation
of cargo or passengers as well as the development and maintenance of supporting infrastructure (also see
inland ports).2
Pump-to-Wheels (PTW) - under total energy analysis methodology, PTW refers to the portion of the Fuel Cycle
that covers the delivery to and use of the fuel source by the end-user equipment application.
Semi-centralized hydrogen delivery pathway-the process of producing pure hydrogen at facilities between
1,501 and 49,999 kg/day for transport by pipeline, truck, or rail to directly serve municipal or multiple
municipal markets.
Steam methane reformation (SMR) - a hydrogen production process in which natural gas is reacted with high
temperature steam over a catalyst to produce synthesis gas containing hydrogen, CO, and a small amount of
C02. The CO and steam are then reacted to produce C02 and additional hydrogen, commonly referred to as the
4 According to EPA's Ports Primer for Communities Glossary, https://www.epa.gov/communitv-port-collaboration/ports-primer-a3-
glossarv.
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water-gas shift reaction. In a final pressure swing adsorption step, the C02 and impurities are removed,
resulting in highly pure hydrogen gas.
Solid oxide fuel cells (SOFCs) - a type of fuel cell that reacts pure hydrogen or hydrocarbon fuels with oxygen
and uses non-porous ceramic compounds or metal as an electrolyte to produce electric current.
Technical potential hydrogen demand -the market and resource potential of hydrogen, which is determined
by existing end-uses, real-world geography and system performance, as opposed to economic indicators.
Tube trailer-a type of gaseous hydrogen transport involving the use of high-pressure cylinders mounted on a
mobile trailer.
Vaporizer-a device used in hydrogen liquefaction plants and equipment refueling stations. Vaporizers serve
as heat exchangers to convert liquid hydrogen to gaseous hydrogen at pressure using ambient air or warm
water.
Vehicle/equipment cycle - under total energy analysis methodology, the vehicle/equipment cycle includes the
energy and emissions -related processes and activities of raw material extraction and transport, component
production and assembly, vehicle and equipment transport to end-use, and vehicle/equipment post-life
disposal and/or recycling.
Well-to-Pump (WTP) - under total energy analysis methodology, WTP refers to the portion of the Fuel Cycle
that covers production and collection of fuel feedstock, fuel production, and transport of the fuel source to the
refueling station or end-use site.
Well-to-Wheels (WTW) - under total energy analysis methodology, WTW represents the full Fuel Cycle
covering feedstock collection, fuel production, fuel transport and fuel dispensing, and usage by the end-user
equipment application.
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Executive Summary
Port facilities play a critical role in the nation's economy. Marine port operations and activities include the
marshalling of freight into and out of the country, often operating older diesel engines and equipment. As
such, their continued operation can contribute significantly to local and regional emission inventories and
mitigation objectives. The EPA recognizes the economic and environmental significance of the U.S. port
industry sector and has established the EPA
Ports Initiative to identify and advance
technologies and strategies that reduce
emissions. Fuel cell technology promises
significant advantages over current diesel-
fueled port equipment for a broad array of
port applications, including lower criteria
pollutants, greenhouse gas, and noise
emissions, higher energy efficiency and lower
petroleum use, diverse fueling capability, and
potentially lower maintenance requirements.
In this report, ERG provides insight for EPA
into the opportunities, impacts, and
challenges associated with current and future
fuel cell applications at ports.
The key findings presented in this report
include the following:
• For ports, a number of fuel cell-powered equipment are currently available or under development.
Commercial fuel cells are currently available for forklifts and stationary power applications. Pre-
commercial fuel cell platforms have been demonstrated and continue to be further developed for drayage
trucks, yard tractors, cargo handlers, switcher locomotives, and marine vessels, and harbor craft.
• In examining lifecycle emissions, hydrogen fuel cell-powered equipment in various port applications
achieve significant lifecycle emission reductions for air pollutants examined. However, higher S02
emissions were seen for many gaseous hydrogen fuel pathways within the feedstock collection,
production, transport (for centralized pathways), and dispensing processes. Higher CH4 and N20 emissions
were seen for some hydrogen pathways as well.
• Gaseous hydrogen fuel pathways with lower fossil energy resource inputs exhibited the lowest criteria
pollutants and GHG emissions. Note, liquid hydrogen fuel pathways have higher energy use requirements,
which is generally correlated with higher GHG and criteria pollutant emissions, than gaseous hydrogen
pathways.
• Upstream emissions results associated with distributed grid-based electrolysis are highly dependent on
the sources of electricity. Grid-based electrolysis using high fossil energy and low renewable energy
resources require high energy use and produce higher emissions than grid-based electrolysis using low
fossil energy and high renewable energy resources. Thus, distributed grid-based electrolysis in areas of the
country served by electrical grids with high renewable energy input will have better lifecycle emissions
than those with high fossil energy inputs.
• Due to its early stage of development, higher hydrogen fuel prices, lower volume production, and
current delivery options, port fuel cell-powered equipment currently costs more to operate relative to
comparable diesel-fueled equipment counterparts. However, in the future there is the opportunity for
ports to realize significant benefits from the increased use of fuel cell equipment overtime. Costs can be
How a Fuel Cell Works
Fuel cells generate electricity through chemical reactions that
take place at the fuel cell electrodes, the anode (negative
electrode) and cathode (positive electrode). The anode and
cathode are separated by electrolyte material. In typical fuel
cells, hydrogen-rich fuel is fed continuously to the anode, and an
oxidant (typically oxygen in air) is fed to the cathode. The anode
breaks down the hydrogen molecules into free electrons, which
are routed through an external circuit to the cathode, producing
direct current electricity output and charged particles that are
conducted internally through the electrolyte material to the
cathode. At the cathode, the charged particles combine with the
incoming oxygen and free electrons to produce water and heat.
Additional information can be found at:
https://www.energy.gov/eere/fuelcells/fuel-cells
https://afdc.energy.gov/vehicles/fuel cell.html
https://www.epa.gov/greenvehicles/hvdrogen-fuel-cell-vehicles
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further reduced due to economies of scale that support lower hydrogen fuel prices, with greater
availability, and increasing production levels for fuel-cell powered forklifts, yard tractors, cargo handlers,
harbor craft, and power generators. Hopefully, these savings will be sufficient to make port related fuel
cell equipment competitive with available alternatives from a cost standpoint.
• Durability and reliability across fuel cell-powered applications have improved considerably, including
port equipment. Fuel cell systems are expected to meet durability targets (of 5,000 hours for mobile
applications and 80,000 hours for stationary applications) within the next two to four years.
• Current annual hydrogen production in the U.S. is about 10 million metric tons, but recent research
suggests a hypothetical hydrogen demand potential of about 166 million metric tons by year 2050.
Currently, the primary hydrogen markets are the petroleum refining (68 percent) and fertilizer production
(about 21 percent) industries. Steam methane reforming using natural gas feedstock makes up about 95
percent of hydrogen supplies today. There are a variety of other hydrogen production processes already
commercially available or under development including gasification of biomass or coal, and water
electrolysis.
• There are two likely pathways for near-term hydrogen delivery: centralized and distributed pathways.
Centralized pathways involve large-scale hydrogen production (50,000-500,000 kg/day) for serving
regional or national markets via pipeline, truck, or rail. Distributed pathways involve local or onsite
hydrogen production (less than 1,500 kg/day) fed by hydrogen product carriers like natural gas or water.
Semi-centralized plants (between the 1,500 and 50,000 kg/day) may also arise for meeting regional
hydrogen markets. In addition to hydrogen, other fuel sources can be used directly by some types of fuel
cells. These fuels include natural gas, ammonia, and methanol.
Port Fuel Cell Equipment Applications
There are five primary types of commercial fuel cells defined according to their electrolyte type: 1) Polymer
Electrolyte Membrane Fuel Cells (PEMFCs), 2) Alkaline Fuel Cells (AFCs), 3) Phosphoric Acid Fuel Cells (PAFCs),
4) Molten Carbonate Fuel Cells (MCFCs), and 5) Solid Oxide Fuel Cells (SOFCs). Worldwide fuel cell markets
include both stationary power and transportation applications (primarily on-highway applications and material
handling equipment). The most prominent fuel cell types in the marketplace include PEMFCs and SOFCs. In
2020, PEMFCs accounted for about 64 percent of total worldwide fuel cell shipments, while SOFC shipments
contributed to about 30 percent (E4etch, 2020). On a total megawatt shipped basis, PEMFCs accounted for
about 77 percent and SOFCs comprised about 11 percent of the new fuel cell market in 2020. The market
dominance of PEMFCs likely results from their high efficiency, low temperature operation (allowing for quick
start-up and higher durability), high power density, and low weight and volume relative to other fuel cell types.
SOFC technology has found a strong market niche in the stationary power sector due to their fuel flexibility
(ability to operate on a variety of hydrogen containing fuels), high efficiency (especially when coupled with
combined heat and power systems), and high tolerance to fuel impurities.
For port managers and stakeholders, fuel cell technology offers a potentially significant new approach to
improving port air quality and reducing petroleum fuel use. However, several challenges exist as fuel cell
technology continues to evolve in the marketplace as a replacement for traditionally diesel-fueled applications.
Table 1 provides a summary of the benefits and challenges associated with the use of fuel cell equipment at
port facilities. The remainder of this Executive Summary discusses these elements in greater detail.
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Table 1. Primary Benefits and Remaining Challenges for Fuel Cell Technology Applications at Port
Facilities
Parameter
Benefits
Remaining Challenges
Port Fuel Cell Equipment
Availability
[See Sections: 2.3,
3.0, 7.1, 7.3]
Available for many on-road, nonroad
and stationary power port
applications.
Pre-commercial status for many port applications but
expected to become commercial in the near-term,
including heavy forklifts, yard tractors, and cargo
handlers.
Fuel Efficiency
[See Sections: 2.3,
3.0]
Up to 2.5 times more efficient than
diesel for some applications.
Additional R&D for improving fuel cell system
efficiency and equipment platform effectiveness for
meeting specific equipment duty cycles is necessary.
Exhaust and
Lifecycle Emissions
[See Section: 6.0]
Zero fuel cell equipment exhaust
pollutants, only water vapor and heat.
Significant lifecycle emission
reductions.
Continued improvements in hydrogen fuel pathways
(production, transport, and dispensing) along with
greater long-term use of renewable energy sources
will increase lifecycle emission benefits. Primary
challenges include S02, CH4, and N20 emissions for
some hydrogen fuel cell pathways.
Performance
[See Sections: 2.3,
3.0, 7.1,7.3]
Comparable to diesel equipment in
many applications, although pre-
commercial systems still lacking in
some applications with challenging
duty cycles.
In many applications, systems are still under
development for meeting the demanding port
equipment operational environment. Research on
hybrid fuel cell/battery platforms for meeting peak
power and operational range requirements
continues.
Durability
[See Sections: 2.2,
2.3, 7.1.2]
Comparable to diesel for many
applications.
Additional long-term testing and implementation
experience necessary for some applications.
Capital Costs
[See Sections: 2.3,
3.0,5.3, 7.1.1]
Projected future capital costs
comparable to diesel following
further system development and
high-volume production.
Current capital costs are higher than comparable
port-related diesel equipment, ranging significantly
(e.g., 24-212% higher) across applications depending
on their commercial status.
Maintenance Costs
[See Sections: 2,3,
5.2, 5.3, 7.1.5]
Projected maintenance costs likely to
be lower than diesel.
Currently maintenance costs are equivalent or higher
than diesel depending on the application.
Hydrogen Fuel Supply
Fuel Availability
[See Sections: 4.0,
7.3]
Hydrogen currently produced for
range of end-use sectors.
Currently regionally based production but projected
to expand with rising demand.
Supply Infrastructure
[See Sections: 4.0,
7.2]
Large, centralized plant production
and small onsite port (distributed)
production.
Currently limited pipeline capacity, mostly truck
transport and delivery.
Onsite Infrastructure
[See Section: 4.0]
Fuel dispensing equipment available
for both gaseous and liquid hydrogen
product.
Lower energy content of hydrogen requires larger
storage footprint than diesel fuel. Dispensing and
storage equipment costs are higher than diesel fuel.
Fuel Price
[See Sections: 5.1,
5.3,7.1.6]
Long-term; forecasted to be lower
than diesel price based on energy and
efficiency equivalent basis.
Currently priced significantly higher than diesel based
on energy and efficiency equivalent basis.
Fuel Safety
[See Section: 4.1.3.5]
Gaseous fuel that dissipates quickly
without need for environmental clean-
up.
Significant additional site/facility safety requirements,
procedures, and special equipment due to hydrogen
fuel property differences.
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Current port applications for fuel cell technology cover on-highway vehicles, nonroad vehicles and equipment,
rail, marine, and stationary power applications. In this study, the following port-related equipment
applications were selected for further analysis based on EPA's interest, their use across port facility types and
locations (including typical annual utilization and fuel use), and overall criticality for port operations: forklifts,
yard tractors, cargo handlers (e.g., top loaders), switcher locomotives, marine propulsion and auxiliary power,
and stationary power generation. This report does not focus on heavy duty drayage trucks; however, there are
a number of ongoing port demonstrations as discussed in Section 2.3.2.3 and Appendix A of this report.5 As
noted in Table 2, PEMFCs are the primary technology used in the port-related equipment listed.
Table 2. Typical Diesel-Fueled Equipment Used at Port Facilities and Common Fuel Cell Replacement
Characteristics
Diesel
Equipment Type
Common
Fuel Cell
Types
Estimated Fuel Cell
Equipment
Commercial Status*
Application Summary
Forklift
PEMFC
TRL 7 Class IV, V and
higher
Commercially available for Classes 1, II and III; pre-
commercial demonstration for Classes IV, V and higher.
Yard Tractor
PEMFC
TRL 7
Pre-commercial demonstrations.
Cargo Handlers
PEMFC
TRL 7
Pre-commercial demonstrations.
Switcher
Locomotives
PEMFC
TRL 6-7
Pre-commercial switcher and line-haul demonstration;
recent domestic and international pre-commercial
passenger train demonstrations could benefit future
switcher.
Harbor Craft
Propulsion
Auxiliary
PEMFC
PEMFC, SOFC
TRL 7
TRL 7
Both domestic and international pre-commercial
demonstrations for propulsion and onboard power.
Power
Generator
PEMFC, AFC,
PAFC, MCFC,
SOFC
TRL 9
Commercially available in 5 kilowatt (kW) -10 megawatt
(MW) capacities for stationary, back-up, and portable
power applications.
*Based on the U.S. Department of Energy (DOE) Technology Readiness Level (TRL) Scale
Hydrogen Fuel Production, Supply and Dispensing
Current annual U.S. hydrogen production is about 10 million metric tons, which has increased over the last
several decades to meet the primary hydrogen market demand for petroleum refining and fertilizer
production. The significant expansion of existing production, storage and distribution infrastructure will be
necessary to meet future hydrogen demand for widescale fuel cell equipment use, including port users.
Hydrogen production to end-use delivery will follow two pathways: centralized or distributed pathways.
Centralized pathways involve large-scale hydrogen production (50,000-500,000 kilograms per day (kg/day))
and serve regional or national end-use markets (depending on plant location). In these cases, hydrogen
product can be transported via pipeline (in pressurized gas form), truck (in pressurized gas or cryogenic liquid),
or rail (in pressurized gas or cryogenic liquid form) to end-use markets. Hydrogen transport mode is contingent
on a variety of factors, including transport distance, capital investments and permitting restrictions. Pipelines
represent the most economically viable method of transport of large quantities of hydrogen over about 1,000
miles. At present, 1,600 miles of hydrogen pipelines exist in the U.S.; California, Louisiana, and Texas account
for the majority of existing pipeline, with the primary purpose of supporting the petroleum refining industry.
5 Numerous research and development projects are underway by original engine manufacturer's and others around the world related
to fuel cell powered heavy duty truck application. DOE has recently launched two consortia to advance fuel cell tuck and electrolyzer
research and development. Information on this than can be found at, https://www.energy.gov/eere/articles/doe-launches-two-
consortia-advance-fuel-cell-truck-and-electrolvzer-rd.
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Additional hydrogen pipeline implementation may evolve overtime as hydrogen demand increases and
markets expand.
Regarding distributed pathways, hydrogen is produced locally or onsite to support local or regional end-users
such as ports. For example, hydrogen carriers (e.g., natural gas or water) are transported to the end-use site to
be used as feedstock in small scale (less than 1,500 kg/day) hydrogen production processes. The choice of
centralized versus distributed hydrogen pathway delivery depends on the availability of, and proximity to,
feedstocks and process energy sources; the size of regional or local markets; the degree of efficiency and costs
associated with hydrogen production processes; and the market, environmental and socioeconomic impacts of
hydrogen production. While it is convenient to define centralized and distributed production plants according
to size, especially in terms of near-term market conditions, it should be noted that facilities may also produce
between 1,500 and 50,000 kg/day for meeting larger local or regional hydrogen markets (U.S. Drive
Partnership, November 2017). These so-called semi-central facilities may evolve and grow into centralized
plants serving broader geographical regions.
Currently available or emerging hydrogen production processes include steam methane reformation (SMR),
gasification of biomass or coal feedstocks, water electrolysis using electricity, biomass-to-liquids (ethanol)
followed by reformation, microbial biomass conversion (or dark fermentation), and ammonia cracking. Natural
gas SMR is the leading hydrogen production process and produces about 95 percent of hydrogen supplies
(Ogden, 2018). Refinery and chemical processing by-products (including hydrocracking plants and chlorine
production plants) as well as small-scale water electrolysis, account for the remaining 5 percent of current
hydrogen production supplies. Table 3 lists the hydrogen production processes according to their application in
centralized or distributed pathways. Note that only natural gas SMR and grid-based electrolysis are currently
for sale and available for purchase. Hydrogen by-product production from hydrocracking and chlorine
production plants can also be considered as commercially available, although these processes are more likely
to serve in market support roles than as full-scale centralized plants. For this reason, they are not included in
Table 3 as centralized plants specifically established for purposes of hydrogen product.
Table 3. Centralized and Distributed Hydrogen Pathway Production Processes and Characteristics
Hydrogen Pathway
Hydrogen Production Process
Commercial Status6
Process Water Use
Centralized
Natural Gas SMR
Current
Moderate
Biomass Gasification
Mid-term
High
Coal Gasification
Mid-term
Low
Electrolysis - Renewable Energy
Mid-term
Moderate
High Temperature Electrolysis
Long-term
Low
Distributed
Natural Gas SMR
Current
Moderate
Grid-based Electrolysis
Current
Moderate
Electrolysis - Renewable Energy
Current
Moderate
Bio-derived Liquids Reforming
Mid-term
Moderate
Microbial Biomass Conversion
Long-term
High
Several other processes may offer significant potential for commercialization in the coming decade(s), mid-
term (2030-2040) and long-term (2040+). Additionally, many of the hydrogen production processes are
associated with significant water use requirements, an important consideration for plant siting, especially in
locations with water resource limitations and/or use restrictions. Further, while each of the centralized
6 As characterized by DOE's Hydrogen and Fuel Cell Technologies Office,
https://www.energv.gov/eere/fuelcells/hvdrogen-production-pathwavs
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pathway production processes provides opportunities for serving national hydrogen markets, many of these
processes may be more regionally significant due to feedstock, energy resource, and transportation distance
constraints.
In terms of distributed pathways, the existing natural gas pipeline system can support the use of natural gas as
a viable hydrogen carrier source for onsite hydrogen production given that small-scale SMR plants are already
commercially available across the country. Similarly, small-scale water electrolysis plants are commercially
available, the water distribution system in the U.S. is ubiquitous, and port locations are therefore well-served.
For biomass-derived liquids reforming, biomass-derived ethanol is already mass produced across the country,
and ethanol is transported widely because of its use in chemical markets and as a gasoline additive. Although
commercially unavailable at present, ethanol steam reforming (ESR) plants are similar to SMR in terms of
operating temperatures, hydrogen yields, energy efficiency and production costs.
Once hydrogen is produced onsite or arrives as pressurized gaseous or cryogenic liquid product, the hydrogen
can be stored locally until ready for use. Stationary power fuel cell applications can typically be fed gaseous
hydrogen directly. For mobile fuel cell equipment, gaseous hydrogen is typically boosted in pressure before
dispensing to increase the stored hydrogen energy density onboard the equipment. For liquid hydrogen
dispensing systems, a cryogenic pump increases the liquid hydrogen pressure before a heat exchanger
(vaporizer) converts the liquid hydrogen to required gaseous hydrogen pressures. A gaseous hydrogen
dispenser then delivers product to the fuel cell equipment at required equipment onboard storage pressures,
typically at either 350 bar (5,000 pounds per square inch (psi)) or 700 bar (10,000 psi).
Additional safety considerations remain for the storage, handling and dispensing of hydrogen fuel product due
to differences in hydrogen fuel properties relative to diesel fuel. At ambient conditions, diesel fuel is a low
volatility fuel, while hydrogen is a gas with wider flammability limits. It can readily mix with air and burns
almost invisibly when ignited. Enclosed facilities that store or maintain hydrogen fuel cell equipment must be
properly designed to account for hydrogen gas releases and leaks. Liquid hydrogen product should be handled
with care to prevent exposure to fuel spills or uninsulated dispensing equipment, which could result in severe
frost bite upon skin contact. Notably, however, hydrogen gas is lighter than air and thus disburses quickly in
open areas. Hydrogen leaks (either as a gaseous or liquid product) do not require extensive clean-up like diesel
fuel, and hydrogen is non-toxic, unlike diesel fuel.
While hydrogen fuel presents significant potential for fuel cells, there are non-hydrogen fuels such as natural
gas, ammonia, and methanol that can be considered. Section 4.3 discusses these fuels in greater detail. Natural
gas, widely availability in the U.S., currently is a key fuel source for supporting onsite production of hydrogen
under distributed hydrogen pathways, but it can also be used directly as a fuel in some types of fuel cells such
as MCFCs and SOFCs. MCFCs and SOFCs are generally relegated to stationary power applications, so natural
gas could be delivered via pipeline directly to these onsite applications. Methanol, or methyl alcohol, is
another fuel for potential direct use in certain types of fuel cells. As a liquid fuel, methanol's energy content is
higher than natural gas but lower than gasoline. Methanol is currently used extensively in the U.S. chemical
market and is available widely. Methanol can be used in direct methanol fuel cells (DMFCs), which is a
specialized form of a PEMFC. Currently, DMFCs are used in small portable power applications for cell phones
and laptop computers but could be adaptable to other power applications. Lastly, ammonia is extensively used
in the U.S. for serving agriculture, pharmaceutical, and other industries, and thus is supported by an extensive
supply infrastructure. Ammonia has comparable energy density to methanol and can be utilized directly in
some fuel cell types. These include AFCs, AMFCs, and SOFCs but further research is needed before
commercialization.
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Hydrogen Fuel Cell Lifecycle Emissions
Based on a Well-to-Wheels (WTW) construct that comprised Well-to-Pump (WTP) and Pump-to-Wheels (PTW)
components, lifecycle emissions analyses were conducted to represent fuel cell equipment usage and
hydrogen production, distribution and delivery routes at U.S. ports. The WTP component includes hydrogen
feedstock collection and transport, hydrogen fuel production, and hydrogen fuel storage, transport, and
dispensing at the end-use site. As presented in Section 6, a comparison of WTP energy, water use and
emissions from various hydrogen fuel pathways was conducted. The analysis used the 2019 Argonne National
Laboratory's (ANL) Greenhouse Gases, Regulated Emissions, and Energy use in Transportation (GREET) model
and default model assumptions. Assumptions covered hydrogen production feedstocks and process
efficiencies, gaseous hydrogen transport modes, and gaseous hydrogen transport distances. WTP results for
year 2020 are listed in Table 4 for low sulfur (15 ppm) diesel fuel and various centralized and distributed
hydrogen fuel pathways, including both gaseous and liquid hydrogen.
Note that the low sulfur diesel pathway results are presented on a per gallon basis, while the hydrogen fuel
pathway results are listed on a per kg basis. In general, the WTP results for most hydrogen production
pathways are more energy and water use intensive than diesel fuel production on a per unit fuel production
basis. Natural gas SMR and solar-based electrolysis displayed the lowest water consumption rates among the
hydrogen pathways and are roughly on par with diesel fuel. Hydrogen production pathways with lower fossil
energy exhibited the lowest criteria pollutants and GHG emissions in general, with pathways using natural gas
having significant C02 emissions. Compared with gaseous hydrogen, liquid hydrogen pathways have higher
energy use requirements, and as a result typically produce higher criteria pollutant and GHG emissions. (It
should be noted that in the case of liquid hydrogen produced from centralized biomass gasification, biomass-
generated electricty was assumed for the liquefaction process resulting in lower net C02 emissions. For liquid
hydrogen produced from centralized solar-based electrolysis, solar-based electricity generation was assumed
for the liquefaction process resulting in significantly lower emissions compared with gaseous hydrogen
produced from centralized solar-based electrolysi.) For additional consideration, one gallon of low sulfur diesel
fuel produces approximately 10% more total energy than one kg of hydrogen.7
Table 4. WTP Emissions Characteristics for Hydrogen Fuel and Diesel Fuel Pathways for Year 2020
Hydrogen WTP Pathway
Total
Energy
(BTU)
Fossil
Energy
Fraction
Water
Use
(gal)
Pollutant Emissions (grams)
VOC
CO
NOx
PMio
PM2.5
SOx
COz
Diesel Fuel Production [per Gallon]
Low Sulfur Diesel
23,149
0.99
2.9
0.97
1.54
2.61
0.20
0.16
0.88
1,640.00
(Centralized Hydrogen Production (Gaseous Product) [per kg]
Natural Gas SMR
63,511
0.96
5.6
1.37
2.71
3.35
0.54
0.38
3.36
10,550.00
Biomass Gasification
174,888
0.15
7.6
0.92
2.79
3.64
0.55
0.33
7.54
3,170.00
Electrolysis Solar
69,375
0.12
5.7
0.21
0.93
1.04
0.22
0.08
1.86
1,750.00
Distributed Hydrogen Production (Gaseous Product) [per kg]
On-site Natural Gas SMR
79,618
0.97
5.4
1.94
6.29
7.43
0.43
0.29
3.34
11,470.00
On-site Electrolysis Solar
62,663
0.00
14.2
0.00
0.00
0.00
0.00
0.00
0.00
0.00
On-site Electrolysis Grid (US
Average)
207,958
0.77
38.2
2.28
10.11
11.41
2.43
0.84
20.29
19,070.00
7 https://afdc.energy.gOv/files/u/publication/fuel comparison chart.pdf
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Hydrogen WTP Pathway
Total
Energy
(BTU)
Fossil
Energy
Fraction
Water
Use
(gal)
Pollutant Emissions (grams)
VOC
CO
NOx
PMio
PM2.5
SOx
COz
On-site Electrolysis Grid
(High Coal/Low Renewable)
341,742
0.98
35.8
3.28
2.54
10.75
4.39
1.03
75.30
44,060.00
On-site Electrolysis Grid
(Low Coal/High Renewable)
91,501
0.01
148.3
0.35
10.68
2.76
3.50
1.04
1.55
200.00
Centralized Hydrogen Production (Liquid Product) [per kg]
Natural GasSMR
110,666
0.92
9.9
1.71
4.21
5.23
0.89
0.51
6.22
13,360.00
Biomass Gasification1
257,339
0.07
5.3
1.94
3.37
5.22
0.74
0.50
21.88
1,770.00
Electrolysis Solar2
86,760
0.00
4.5
0.02
0.07
0.26
0.01
0.01
0.00
46.86
Distributed Hydrogen Production (Liquid Product) [per kg]
On-site Natural GasSMR
151,994
0.92
12.2
2.45
8.57
10.00
0.98
0.48
7.89
15,760.00
On-site Electrolysis Solar
94,841
0.00
15.3
0.00
0.00
0.00
0.00
0.00
0.00
0.00
On-site Electrolysis Grid (US
Average)
265,628
0.77
42.3
2.69
11.92
13.45
2.87
0.99
23.92
22,490.00
On-site Electrolysis Grid
(High Coal/Low Renewable)
423,312
0.98
40.8
3.86
2.99
12.67
5.18
1.22
88.77
51,940.00
On-site Electrolysis Grid
(Low Coal/High Renewable)
128,200
0.01
174.4
0.42
12.59
3.25
4.12
1.22
1.82
240.00
1 Pathway includes hydrogen liquefaction process supported by electricity generated from switchgrass integrated gasification
combined cycle (IGCC) power plant.
2 Pathway includes hydrogen liquefaction process supported by electricity generated from solar power.
Results for distributed, grid-based electrolysis vary significantly depending on electricity grid generation mix.
For instance, coal-based electricity generation in the U.S. varies from zero to over 90 percent (U.S. Energy
Information Administration, 2020). For this reason, three grid-based electrolysis scenarios are shown: 1) U.S.
Average Generation Mix 2) High Coal and Low Renewable Generation Mix and 3) Low Coal and High
Renewables Mix. The U.S. Average Mix results are based on the U.S. Energy Information Administration's (EIA)
Annual Energy Outlook 2020, which estimates coal-fired generation at 22 percent (U.S. Energy Information
Administration, 2020). In comparison, the High Coal/Low Renewables and Low Coal/High Renewables
scenarios assume 92 percent and 0 percent coal-based electricity generation, respectively.
The PTW component for ports covers the use of port equipment onsite. Based on average port equipment
power levels and EPA-approved emission factors, PTW emission estimates were derived for low sulfur diesel-
fueled port equipment, as shown in Table 5 (U.S. EPA, 2019) (U.S. Energy Information Administration, 2020)
(U.S. EPA, Office of Transportation and Air Quality, 2019) (U.S. EPA, Office of Transportation and Air Quality,
2016) (U.S. EPA, Office of Transportation and Air Quality, 2018).There are no PTW emissions for comparable
hydrogen fuel cell port equipment since hydrogen fuel cells emit only water vapor and heat. It is a zero-
emission tailpipe technology.
Table 5. PTW Emission Characteristics for Diesel-Fueled Port Equipment
Diesel Port
Equipment Type
Typical
Propulsion
Power (hp)
Pollutant Emissions (grams/gallon)
VOC
CO
NOx
PMio
PM2.5
S02
co2
Forklift
100
5.10
70.40
63.26
0.57
0.56
0.09
10,023
Yard Tractor
200
2.84
1.47
22.03
0.22
0.22
0.07
10,029
Cargo Handler
310
2.84
1.68
26.32
0.24
0.23
0.07
10,029
Assist Tug
1,908
3.81
35.25
138.17
3.64
3.53
0.09
9,729
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Diesel Port
Equipment Type
Typical
Propulsion
Power (hp)
Pollutant Emissions (grams/gallon)
VOC
CO
NOx
PM10
PM2.5
S02
co2
Ferry
1,718
2.82
70.50
98.70
2.43
2.35
0.09
9,729
Harbor Tug
711
2.82
70.50
98.70
2.43
2.35
0.09
9,729
Switcher
Locomotive
2,000
11.06
27.82
187.0
4.10
3.98
0.09
10,208
Generator
135
21.18
70.50
56.40
4.23
4.10
0.09
10,210
Combining WTP and PTW emission results provided full WTW emissions estimates for the port applications
considered. Table 6 lists the efficiency adjusted mass of WTW emission reduction results8 on a per hydrogen kg
equivalent basis for fuel cell equipment types versus comparable diesel equipment for various gaseous
hydrogen fuel delivery pathways. Note that the results captured in Table 6 account for the increased fuel
efficiency of hydrogen fuel cells compared with their diesel engine-powered counterparts. For each port
equipment application, fuel cell equipment energy efficiencies were estimated based on assumed PEMFC fuel
cell stack and drivetrain efficiencies relative to their diesel counterparts. Based on these estimates, port fuel
cell equipment was estimated to be up to 2.5 times more efficient than comparable diesel equipment. Table 6
values that are shown in green are positive emission reductions, indicating that hydrogen fuel cell equipment
WTW emissions are lower than those of diesel equipment per hydrogen kg equivalent consumed, while values
shown in red are emission increases signifying higher hydrogen fuel cell WTW emissions than diesel. Note that
in general hydrogen fuel cells primarily provide WTW emission reductions (i.e., primarily 'green' Figures in
Table 6) relative to diesel equipment. And criteria air pollutants, such as nitrogen oxides and particulate
matter, for hydrogen pathways are not being emitted in port areas, so their human exposure and health
impacts are far less significant than diesel equipment tailpipe emissions that occur at or near ports.
Based on these results, hydrogen fuel cell-powered equipment in various port applications can achieve
significant WTW emission reductions. Volatile organic compound (VOC) and nitrogen oxide (NOx) emissions
reductions were achieved across all port equipment types for each of the hydrogen fuel delivery pathways.
Carbon monoxide (CO) emissions were generally lower for the majority of fuel cell equipment and hydrogen
pathways. Similarly, lower particulate matter 10-micron (PMio) emissions were determined for fuel cell
equipment applications and hydrogen fuel pathways, except for yard tractors, forklifts, and cargo handlers
under some grid electrolysis pathways. The higher PMio emissions for this equipment can be attributed to
higher WTP emissions for grid electricity generation, especially for those generation mixes with high coal
and/or high biomass resources. In fact, biomass-based electricity generation may produce more PMio
emissions than coal-based generation dependent on the feedstock. Thus, PMio emissions with grid electrolysis
from the low coal/high renewables electricity generation mix was higher than the U.S. Average mix because it
assumed over three times more biomass-based generation. Particulate matter 2.5-micron (PM2.5) emissions,
however, were lower for all hydrogen pathways except for yard tractors and cargo handlers under some grid-
based electrolysis pathways.
8 Port equipment emission reductions for various hydrogen fuel pathways are compared to diesel fuel pathways. NG SMR and
Electrolysis Solar hydrogen pathways are highlighted here because NR SMR is a common source of hydrogen production and
electrolysis solar is the cleaner hydrogen production pathway. For a more detailed summary of port equipment emissions reductions on
a hp-hr basis across additional pathways, please see Section 6, Table 39.
*ERG
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Table 6. WTW Emission Reductions for Fuel Cell Equipment and Four Gaseous Hydrogen Fuel Pathways
Relative to Comparable Diesel-Fueled Equipment
Fuel Cell
Equipment
Type
Hydrogen Fuel Pathway
WTW Emission Reductions Relative to Diesel-Fueled Equipment (g/hp-hr) [Efficiency Adjusted]
VOC
CO
NOx
PMio
PM2.5
SO2
CO2
CH4
N2O
Yard Tractor
Centralized NG SMR
0.063
0.035
0.458
0.004
0.004
-0.011
136.668
0.045
0.000
Centralized Electrolysis Solar
0.073
0.051
0.479
0.006
0.007
0.002
215.402
0.250
0.000
Distributed NG SMR
0.058
0.003
0.421
0.005
0.005
-0.011
128.437
-0.078
-0.002
Distributed Electrolysis Solar
0.075
0.060
0.488
0.008
0.007
0.019
231.060
0.283
0.001
Forklift
Centralized NG SMR
0.108
1.400
1.274
0.011
0.011
-0.011
136.549
0.047
0.000
Centralized Electrolysis Solar
0.118
1.416
1.295
0.013
0.014
0.003
215.283
0.252
0.000
Distributed NG SMR
0.103
1.368
1.238
0.011
0.012
-0.011
128.318
-0.076
-0.002
Distributed Electrolysis Solar
0.120
1.425
1.304
0.015
0.014
0.019
230.940
0.285
0.001
Cargo Handler
(Top Loader)
Centralized NG SMR
0.063
0.040
0.543
0.004
0.004
-0.011
136.668
0.045
0.000
Centralized Electrolysis Solar
0.073
0.055
0.563
0.007
0.007
0.002
215.402
0.250
0.000
Distributed NG SMR
0.058
0.008
0.506
0.005
0.005
-0.011
128.437
-0.078
-0.002
Distributed Electrolysis Solar
0.075
0.064
0.573
0.009
0.008
0.019
231.060
0.283
0.001
Assist Tugboat
Centralized NG SMR
0.072
0.683
2.732
0.067
0.067
-0.037
48.922
-0.164
0.008
Centralized Electrolysis Solar
0.091
0.713
2.770
0.072
0.072
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.062
0.623
2.664
0.069
0.068
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.095
0.728
2.788
0.076
0.073
0.019
225.119
0.281
0.009
Ferry
Centralized NG SMR
0.052
1.381
1.950
0.043
0.043
-0.037
48.922
-0.164
0.008
Centralized Electrolysis Solar
0.072
1.411
1.989
0.048
0.048
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.043
1.321
1.882
0.045
0.045
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.075
1.426
2.006
0.052
0.050
0.019
225.119
0.281
0.009
Harbor
Tugboat
Centralized NG SMR
0.052
1.381
1.950
0.043
0.043
-0.037
48.922
-0.164
0.008
Centralized Electrolysis Solar
0.072
1.411
1.989
0.048
0.048
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.043
1.321
1.882
0.045
0.045
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.075
1.426
2.006
0.052
0.050
0.019
225.119
0.281
0.009
Switcher
Locomotive
Centralized NG SMR
0.221
0.547
3.712
0.078
0.077
-0.024
100.225
-0.061
0.000
Centralized Electrolysis Solar
0.235
0.569
3.741
0.082
0.081
-0.004
212.321
0.231
0.000
Distributed NG SMR
0.213
0.501
3.660
0.080
0.078
-0.023
88.506
-0.235
-0.003
Distributed Electrolysis Solar
0.238
0.581
3.755
0.085
0.082
0.019
234.612
0.278
0.001
Stationary
Generator
Centralized NG SMR
0.424
1.397
1.131
0.082
0.080
-0.018
118.051
-0.008
0.001
Centralized Electrolysis Solar
0.436
1.416
1.157
0.085
0.084
-0.001
215.311
0.245
0.002
Distributed NG SMR
0.417
1.357
1.086
0.083
0.081
-0.018
107.883
-0.159
-0.001
Distributed Electrolysis Solar
0.439
1.426
1.168
0.088
0.084
0.019
234.652
0.286
0.002
*ERG
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In the case of sulfur dioxide (S02) emissions, higher WTW emissions for all hydrogen fuel pathways were
estimated except for distributed solar-based electrolysis, and in some equipment cases, centralized solar-
based electrolysis and low coal/high renewables generation grid-based electrolysis. Higher S02 emissions are
produced with all high coal resource pathways (grid electrolysis with U.S. Average and High Coal/Low
Renewables generation mixes) and natural gas SMR-based pathways (both centralized and distributed)
compared with diesel. The S02 emission increases for centralized biomass gasification can be attributed to
higher overall energy requirements, biomass feedstock (corn stover) collection and processing, the biomass
gasification process, and the U.S. average electricity grid mix (higher coal) supporting this hydrogen pathway.
Similarly, S02 emission increases for natural gas SMR hydrogen pathways result from the SMR process and the
U.S. average electricity grid supporting the process. Higher S02 levels with the distributed grid-based
electrolysis using U.S. Average and High Coal/Low Renewables can be attributed to the much higher energy
requirements for these electrolytic processes and their supporting grid electricity comprised of high fossil
energy resources, especially in the case of the High Coal/Low Renewables pathway. As the U.S. electricity
generation mix evolves to higher levels of renewable energy-based generation in the future, reductions in S02
emissions produced from SMR, biomass gasification, and grid electrolysis can be expected.
Finally, WTW carbon dioxide (C02) emissions were significantly lower across all hydrogen equipment and fuel
pathways, except for High Coal/Low Renewables generation grid-based electrolysis and in some limited cases,
U.S. Average generation grid-based electrolysis. The lower C02 emissions result primarily from much higher
energy efficiencies and elimination of fuel cell equipment PTW C02 emissions relative to comparable diesel
equipment.
Regarding individual pathways, all hydrogen fuel pathways provided significant emission reductions for most
port equipment applications although, as noted above, higher S02 emissions were seen for many pathways. In
general, the solar-based electrolysis pathway emerged as the best performing hydrogen fuel pathway for both
centralized and distributed cases. While solar-based electrolysis shows promising results for emission
reductions, it should be noted that this technology requires implementation of supporting solar arrays and
energy storage to provide power to the electrolysis process, significantly increasing capital investments and
requiring additional site space considerations. The analysis also revealed that the performance of distributed
grid-based electrolysis is highly dependent on the electricity generation mix. Regions of the country with high
coal and low renewable resource generation can be expected to produce significantly less favorable grid-based
electrolysis pathway WTW emission results as compared to regions with low coal and high renewable resource
generation mixes. A future electricity grid mix with higher renewable resource generation should also result in
lower PMio and S02 emissions for the hydrogen pathways supported by the grid.
The WTW emission results presented here represent specific assumptions for both WTP and PTW estimates.
WTW results may vary depending on hydrogen production scenarios, feedstock and fuel transport modes, and
port equipment types and sizes. As such, local and regional analysis can facilitate emissions assessments
associated with hydrogen fuel cell equipment use at specific port locations.
Port Fuel and Fuel Cell Equipment Costs
The dispensed hydrogen per kilogram cost ($/kg) to the end-user should account for all production and
delivery pathway factors. In the case of centralized hydrogen production pathways, this includes amortized
costs for production, transport to the site, and dispensing station capital cost recovery and operations.
Currently, most of the hydrogen sold for vehicle or equipment usage is produced by industrial gas suppliers at
low volumes and thus higher costs. There are limited dedicated regional hydrogen pipelines in various regions
of the country, and most of the available hydrogen is delivered via truck at higher cost and dispensed through
low volume stations. For comparison, dispensed hydrogen market prices are roughly $13-16/kg in most areas
of the country (Satyapal, 2018).
*ERG
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Additional research is being conducted and industry development is occurring to improve hydrogen production
and transport technologies, lower refueling station capital costs, and increase station efficiency and outputs. In
addition, as hydrogen demand increases, economies of scale can be achieved by boosting production and
transportation and lowering fuel prices for the consumer. In fact, the DOE has projected a future high-volume
hydrogen price of about $5-10/kg by 2025, and a long-term mature market price of less than $4/kg (Satyapal,
2018).
As discussed in Section 5, capital and operating cost estimates were derived for port fuel cell equipment and
their diesel equipment counterparts, including forklifts, yard tractors, cargo handlers, switcher locomotives,
marine vessels, and power generators. Incremental costing between fuel cell and comparable diesel-fueled
equipment was based on available cost information, typical equipment operating characteristics and
anticipated lifetimes. Notably, many of the current fuel cell equipment costs were estimated for pre-
commercial systems. Future costs for this equipment were estimated based on DOE cost projections for fuel
cell systems (Satyapal, 2018) and assumed an annual inflationary rate of two percent. Annual operating costs
(fuel and maintenance costs) were also estimated for each type of equipment. Diesel fuel price projections
were determined based on EIA Figures. Hydrogen fuel prices were calculated based on the aforementioned
DOE hydrogen price projections.
Table 7 lists the capital and operating cost comparison for port fuel cell and diesel equipment. Capital cost
estimates assumed two percent annual inflation for both fuel cell and diesel equipment costs. In 2020, the
estimated capital costs for the port fuel cell equipment were higher than the comparable diesel equipment. In
2030 and 2045, assuming lower cost fuel cell systems and equipment platforms and increased production
volumes based on DOE estimates, fuel cell equipment costs had greater parity with comparable diesel
equipment. Similarly, annual operating costs were lower for many of the port equipment types due primarily
to the lower projected hydrogen fuel prices starting in 2030 and continuing through 2045.
Based on these results, simple capital payback was assessed for each type of fuel cell equipment using the
incremental capital and annual operating costs. As shown in Table 7, none of the fuel cell equipment provided
capital payback potential in 2020 due to their high incremental capital costs and low operational savings.
However, in 2030, reasonable capital payback values were derived for fuel cell equipment types, except for
switcher locomotives and ferryboat applications. In 2045, very favorable paybacks were derived for all fuel cell
equipment analyzed except for switchers and ferryboats which still must overcome high incremental capital
costs. However, based on recent developments the future costs may be reduced such that a favorable
payback could come within the tine periods projected. These results suggest that port fuel cell equipment
economic benefits will increase in the long-term as equipment capital costs decrease and the hydrogen fuel
market matures.
*ERG
12
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Table 7. Summary of Fuel Cell Equipment Capital and Operating Cost Results
Parameter
Forklift
Yard Tractor
Cargo Handler
Switcher Locomotive
Ferryboat
Generator
Diesel Fuel Cell
Diesel Fuel Cell
Diesel | Fuel Cell
Diesel | Fuel Cell
Diesel Fuel Cell
Diesel | Fuel Cell
Lifetime
10
12
12
20
20
10
Year 2020
Capital Cost ($)
45,000
84,194
110,000
225,000
584,500
727,078
1,544,000
3,466,543
11,600,000
17,166,000
100,000
312,000
Operating Costs($)
11,242
19,736
22,981
38,464
77,717
131,534
188,439
504,700
1,713,086
6,751,790
31,553
64,528
Payback (Yr)
None
None
None
None
None
None
Year 2030
Capital Cost ($)
54,855
71,068
134,089
182,704
712,502
789,997
1,882,127
3,804,663
14,140,335
15,258,100
121,899
174,124
Operating Costs($)
12,996
10,768
26,314
17,799
88,302
54,498
220,955
274,120
1,971,870
2,858,896
36,118
29,279
Payback (Yr)
7.3
5.7
2.3
None
None
7.6
Year 2045
Capital Cost ($)
73,827
74,256
180,467
189,556
958,934
975,157
2,533,096
3,094,292
19,031,030
19,281,258
164,061
180,688
Operating Costs($)
15,059
9,352
29,577
16,376
90,813
40,851
267,335
267,162
2,254,365
2,622,602
40,563
25,711
Payback (Yr)
0.1
0.7
0.3
None
None
1.1
*Operating Cost includes annual maintenance costs and fuel costs
**Lifetime estimate assumes switcher locomotive was previously used for 20 years of line haul duty.
*** Year 2020 [Diesel Fuel Price $3.33/gal, H2 Dispensed Price $13.00/kg]; Year 2030 [Diesel Fuel Price $3.76/gal, H2 Dispensed Price $4.00/kg]; Year 2045 [Diesel Fuel Price $4.05/gal, H2 Dispensed Price $4.00 kg;
Switcher Diesel Year 2020 $2.07/gal, Year 2030 $2.34, Year 2045 $2.52/gal; Ferryboat Liquid Hydrogen Year 2020 $11.64/kg, Year 2030 $4.40/kg, Year 2045 $4.00/kg
Future Hydrogen and Fuel Cell Market Penetration
A variety of factors may impact future fuel cell market viability for ports and other sector applications. These
factors include:
• Equipment capital cost - Current fuel cell system costs are much higher than comparable diesel
powerplants. Much of this cost variance is due to differences in production capacities resulting from
economies of scale. Research and development efforts have resulted in dramatic reductions in fuel cell
system costs over the last decade and are expected to continue reducing costs. For example, the DOE
anticipates forklift and stationary genset fuel system costs to decrease by 61 and 37 percent, respectively,
as the market transitions from low production to high-volume production scales (Satyapal, 2018).
• Required emission reductions - Replacing diesel-fueled equipment with hydrogen fuel cell equipment
provides opportunities for significant emission reductions for port applications, especially with hydrogen
produced with renewable energy sources. For those ports with high future emission reduction targets for
greenhouse gas and criteria pollutant emissions, fuel cell equipment can help ports meet their emission
inventory goals. As state renewable portfolio standards, declining costs of renewable energy technology,
and other factors continue to drive increasing shares of renewable electricity generation and reductions in
average grid emissions, the emissions benefits associated with grid electrolysis-based hydrogen production
pathways will likely increase over time.
• Equipment durability/reliability - Fuel cell durability and reliability across equipment applications,
including port equipment, have improved considerably. Advancements in catalysts and fuel processing
capabilities have improved fuel cell resistance to fuel and air impurities. Significant progress has been
achieved in voltage degradation, operational durability, start-uptimes and cold weather performance.
Additional progress with system voltage degradation is necessary for some transportation applications, but
the DOE supports research and development to meet targets within the next two to four years.
• Equipment power/duty cycle performance - Some port equipment applications present challenging duty
cycle and operational conditions (e.g., cargo handlers). The general scalability of fuel cells should allow fuel
cell systems to meet maximum power requirements for even the most challenging duty cycles. The current
development of hybrid fuel cell/battery platforms for achieving high power and long operational ranges
also provides manufacturers with greater flexibility in meeting these challenging applications.
• Equipment operational hours/range - For port applications such as forklifts, yard tractors and cargo
handlers, operational capacity or driving range is essential to maximizing port operational efficiency and
*ERG
13
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productivity. For most port equipment, operational ranges for fuel cell-powered equipment are like those
of diesel-fueled equipment. For some port equipment such as cargo handlers and marine propulsion,
hybrid fuel cell battery systems and improved hydrogen storage systems are under development to assist
in meeting equipment operational capacity requirements.
• Equipment maintenance/serviceability-While scheduled maintenance for fuel cell systems is generally
less frequent than comparable diesel equipment, pre-commercial systems have exhibited higher rates of
downtime due to unscheduled maintenance. Some fuel cell stack and balance of plant issues have been
experienced in pre-commercial systems, along with non-fuel cell related maintenance for hybrid fuel cell
systems. As pre-commercial fuel cell systems continue to develop, these unscheduled maintenance-related
issues are expected to diminish.
• Hydrogen fuel price - Fuel price is currently a limiting factor for fuel cell equipment market growth. As
noted earlier, dispensed hydrogen market prices are roughly $13-16/kg (or about $7.55-9.30/diesel gallon
equivalent (DGE) when adjusted for the energy content and typical higher fuel efficiency of hydrogen).
Through additional research and higher volume production, DOE targets hydrogen fuel costs to decrease
to about $2.91-5.81/DGE efficiency adjusted in 2025, and to less than $2.32/DGE efficiency adjusted in the
long-term (Satyapal, 2018). These future hydrogen fuel costs compare favorably with EIA diesel fuel price
forecasts of $3.76/gallon in 2030 and $4.05/gallon in 2045.
• DOE's Energy Earthshots Initiative aims to accelerate breakthroughs of more abundant, affordable, and
reliable clean energy solutions. The first Energy Earthshot was Hydrogen Shot, launched June 7, 2021,
seeks to reduce the cost of clean hydrogen by 80% to $1 per 1 kilogram in 1 decade ("1 11")9.
Future hydrogen supply should benefit from the flexibility of hydrogen production across a variety of
feedstocks and processes, extensive networks of natural gas pipelines, electricity transmission and distribution
infrastructure, projected low long-term prices of natural gas and electricity, and anticipated growth in
renewable energy electricity generation. Natural gas steam reforming production can increase in the near-
term, but low-cost electrolysis coupled with renewable energy sources holds significant promise with regards
to long-term sustainable hydrogen production and reductions in emissions. In both cases, higher volume
hydrogen production should lead to economy-of-scale pricing, making fuel cell equipment economically
competitive with traditional diesel equipment.
Market penetration estimates for port fuel cell equipment applications were estimated between 2020 and
2050 based on future market assumptions and by employing an S-curve market penetration methodology.
Results are illustrated in Figure 1 for the following port equipment: forklifts, yard tractors, cargo handlers,
switcher locomotives, marine propulsion and auxiliary power, and stationary power generators. The highest
fuel cell generator market share was estimated at about 62 percent among port equipment applications in
2050, given their commercial status over a range of power levels, as well as assumed limited market
competition (except for diesel engines). Conversely, fuel cell switcher market penetration was at its lowest
(about 15 percent) in 2050 given that little development has occurred over the last decade. However more
recently work has been completed on diesel hybrid platforms and fuel cell platforms for switcher and line haul
locomotives which could increase penetration. In the case of forklifts (about 50 percent) and yard
tractors/cargo handlers (about 24 percent), recent market entries in lighter forklift classes and prototype
demonstrations across a variety of yard tractor and cargo handler applications indicate relatively strong
market penetration overtime. Similarly, recent prototype demonstrations of fuel cell harbor craft both
domestically and internationally, such as passenger cruise boats, ferry boats, tugboats and push boats, project
9 https://www.energy.gov/eere/fuelcells/hvdrogen-shot
*ERG 17
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to about 23 percent of the new vessel market by 2050. Note that these projections could increase significantly
if breakthroughs or other incentives come to into being that are not included in this analysis.
Higher fuel cell equipment market penetration in the long-term correlates with higher equipment
manufacturing volumes and associated high volume fuel demand, both of which would dramatically lower fuel
cell equipment costs and dispensed fuel prices.
Penetration (2020-2050)
Key Stakeholder Considerations for Current Port Fuel Cell Equipment Implementation
While fuel cells may prove instrumental in supporting current and future port equipment applications, port
stakeholders should consider the following factors before implementing the technology:
1. Significant Fuel Savings - Significant fuel use reductions can be achieved for most applications, as fuel
efficiency with fuel cell equipment is approximately two to three times higher than comparable diesel
equipment, depending on the operational duty cycle of the equipment application. These fuel use
reductions will translate directly into lower fuel expenditures.
2. Lifecycle Emission Reductions - Hydrogen fuel cell equipment implementation will typically provide
significant reductions in criteria pollutant, greenhouse gas emissions, and toxic air pollutants relative to
comparable diesel equipment at most port locations.. Hydrogen produced using renewable feedstocks
and/or energy sources will provide the most favorable emissions.
3. Lower Noise Emissions - Fuel cell equipment produces significantly lower noise levels than diesel engine-
powered equipment. Ports located in proximity to residential neighborhoods or other sensitive
populations should note that noise reduction efforts are integral to meeting noise level targets at port
facilities.
4. Pre-commercial Status of Fuel Cell Port Equipment Applications - While some applications such as fuel
cell stationary power generators and small forklifts are available as commercial product, many fuel cell
port equipment types are in pre-commercial stages of development. This may impact the availability of
certain fuel cell equipment, especially for ports with aggressive fuel cell equipment implementation
schedules. The pre-commercial status of equipment also renders direct comparisons with mature market
diesel equipment unclear, given that fuel cell equipment evolves into commercial products over time.
*ERG
15
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Further, pre-commercial fuel cell equipment downtime may be impacted by spare part and replacement
system availability from manufacturers.
5. High Equipment Capital Costs and Hydrogen Fuel Prices - Port operators should expect higher upfront
costs for many fuel cell equipment types since many systems are still in pre-commercial stages of
development or are early market entries. Like vehicle battery technologies over the last decade, prices for
fuel cell systems should continue to decrease in the future as system designs improve, production
increases and economies of scale are achieved. In the near-term, hydrogen fuel prices for port and other
applications will remain high until hydrogen market demand significantly increases and centralized
hydrogen production volumes grow to meet demand. External grant funding will likely be needed to
support significant near-term investment in fuel cell equipment.
6. Considerations for Centralized Versus Distributed Production and Gaseous Versus Liquid Hydrogen -
Ports will need to assess hydrogen fuel supply options to implement fuel cell equipment. Ports must
decide whether to obtain fuel supplies from centralized hydrogen production versus onsite production
using natural gas SMR or water electrolysis, making sure to consider available feedstocks, water
restrictions, upfront capital costs, and lifecycle operating and maintenance costs, among others. For
centralized hydrogen fuel supplies, ports must consider whether gaseous or liquid product is most
favorable for operations. A gaseous product is generally less costly to store and dispense on site, while a
liquid product has higher energy density and requires less frequent re-supplies when serving high volume
consuming equipment applications. Of course, local/regional hydrogen product availability will also dictate
near-term port decisions regarding hydrogen supplies and onsite storage and use.
7. Hydrogen Fuel Properties and Operational and Safety Considerations - As a gaseous fuel under ambient
conditions, hydrogen has significantly different properties than diesel fuel which requires additional
requirements for safely handling, transporting, and storing. Differences in fuel properties should be
addressed and managed through preparation, necessary operational changes, and staff training at ports.
Benefits of hydrogen include its lower toxicity compared with diesel fuel and it does not require
environmental clean-up for leaks or spills.
*ERG
16
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1. Introduction
1.1 Study Purpose, Objectives, and Approach
Marine port facilities and operations are important to the nation's current and future economic well-being.
Port facilities serve as key gateways for importing and exporting commercial products, and thus constitute
critical economic activities at the national, regional, and local level. Ports often become hubs of commercial
and operational activities, for example, facilitating the movement of equipment (e.g., freight) in and out of
their harbors. Due to their extensive concentration of heavy equipment for operations, including cargo
handling equipment, ships, and locomotives, ports often contribute to a large component of local and regional
emission inventories. Through programs such as the Ports Initiative, the U.S. Environmental Protection Agency
(EPA) aims to better understand and characterize the emission contributions of port facilities and operations,
in addition to identifying and supporting emission reduction strategies and emerging advanced technologies.
With this report, EPA was interested in learning more about fuel cell technologies and the opportunities they
offer to reduce pollution by replacing diesel-powered equipment at port locations. As such, the EPA seeks a
comprehensive analysis of the technical, environmental, economic, and safety aspects of fuel cell technology
applications for marine port facilities and operations.10
Under contract, Eastern Research Group (ERG) was tasked with completing a comprehensive study of fuel cell
technology for marine port equipment applications.
The key objectives of this effort include the following:
• Define the various types of fuel cell technologies and their current market status, as well as ongoing
research at the federal, state, and private levels to address fuel cell performance and costs.
• Define potential fuel cell technology applications for U.S. marine ports, analyzing their critical operational,
cost, maintenance and lifetime pros and cons relative to traditional diesel-fueled equipment.
• Assess potential fuel sources and required infrastructure for supporting port fuel cell applications,
including both centralized and distributed production and transportation solutions.
• Assess the lifecycle emission benefits for fuel cell technologies relative to diesel-fueled equipment in port
applications, including criteria pollutants, mobile source airtoxics (MSATs), and greenhouse gases.
• Assess the economics of using fuel cell technology in port applications, including the future business case
for such applications.
• Assess the current commercial viability of fuel cell technology, and forecast its market penetration for port
applications, including performance, cost, and infrastructure challenges for the technology, as well as its
competitiveness in the future near and long -term marketplaces.
ERG's approach for meeting these objectives included the completion of the following prescribed task research
activities:
• Task 1 - Background Information
• Task 2 -Applications of Fuel Cells at Ports
• Task 3 - Emissions Analysis
• Task 4 - Economic Analysis
10 Note: This reported is intended to examine fuel cell technologies compared to existing, conventional diesel engines. It does not
incorporate other advanced clean technologies as a comparison.
*ERG
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• Task 5 - Future Projections
Each of these tasks incorporated comprehensive research and analysis based on publicly available information
and data obtained from both government and private sources. Each task activity culminated in the
development of a standalone task summary report, which documented ERG's results and facilitated the EPA's
review of those results.
This report contains the following primary sections:
1. Introduction;
2. Fuel Cell Technology and Market Status;
3. Fuel Cell Applications and Characteristics for Ports;
4. Fuel Cell Fuel Supply Infrastructure;
5. Fuel Cell Equipment, Infrastructure, and Fuel Costs;
6. Hydrogen Fuel Cell Equipment Lifecycle Emissions;
7. Future Hydrogen and Fuel Cell Market Penetration; and
8. Summary and Conclusions.
*ERG
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2. Fuel Cell Technology and Market Status
2.1 Fuel Cells Explained
Fuel cell technology has evolved from its conceptual development in the early 19th century to its viable
application in commercial products across multiple market sectors. A fuel cell is an electrochemical device for
converting the chemical energy of a fuel into electrical energy. Since the process of energy conversion is
electrochemical as opposed tothermochemical, as in the case of fuel combustion, fuel cells do not produce
any undesirable post-conversion products. Fuel cells are also simple devices with minimal moving parts and
mechanisms, and thus produce minimal noise. Additionally, fuel cells have much higher energy conversion
efficiencies than traditional fuel combustion power sources.
The initial development of fuel cell technology can be traced back to a variety of experimental electrochemical
research in Britain in the early 1800's. Sir William Grove is generally credited with inventing the fuel cell in
1839 through a collection of research related to a "gas voltaic battery," proving an electrical current could be
produced from a reaction of hydrogen and oxygen in the presence of a platinum catalyst. The term "fuel cell"
was later coined in 1889 by subsequent German electrochemist researchers using coal gas fuel (FuelCellToday,
2019).
The first workable fuel cell device was demonstrated in 1959 by Cambridge professor Francis Bacon. Using
modified fuel cells from Bacon, U.S. manufacturer Allis-Chalmers, in collaboration with the U.S. Air Force,
produced a variety of fuel cell-powered demonstration equipment, including an agricultural tractor, forklift,
golf cart and submersible vessel (FuelCellToday, 2019). Fuel cell technology developed considerably as a result
of the newly formed National Aeronautics and Space Administration (NASA). Several fuel cell applications for
onboard power were implemented for space vehicle applications for the Mercury and Gemini manned space
missions. These efforts culminated in the development of a fuel cell system that provided electrical power and
drinking water for the astronauts onboard the Apollo manned space mission.
National energy security issues and increased emphasis on clean air in the 1970s and 1980s served as market
drivers for the development of clean, energy efficient technologies. Fuel cell research efforts concentrated on
improving hydrogen fuel systems and increasing fuel cell power densities. Manufacturers began concentrating
on market application demonstrations of fuel cells for transportation, stationary power and portable power
devices. As a result of zero emission vehicle mandates introduced in California in the 1990s (FuelCellToday,
2019), manufacturer fuel cell research focused on small stationary applications to improve commercial market
potential and enhance transportation capabilities. The latter caught the interest of the global automaker
industry, resulting in extensive research programs by companies such as Ford, Chrysler, General Motors and
Toyota.
Supported by government and private sector funding and investment and increased concerns over global
climate change, fuel cell research over the last decade has continued to support both early market
applications. Fuel cell commercialization efforts intensified around 2007 when products began selling with
warranties and service capabilities. Commercial markets for fuel cell products have now been established for
material handling equipment, transit buses, passenger cars, freight trucks, portable and auxiliary power units,
and small and large -scale stationary power systems. As a result of early commercial success, the fuel cell
system supply chain has developed in conjunction with advancements in global fuel cell manufacturing
capacity and implementation of hydrogen fuel delivery infrastructure.
In its simplest form (Figure 2), a fuel cell is comprised of a negative electrode (anode) and a positive electrode
(cathode) sandwiched around an electrolyte (membrane). Hydrogen-rich fuel is supplied to the anode while air
(oxygen) is supplied to the cathode. A catalyst at the anode acts to separate the hydrogen molecules in the fuel
into protons and electrons. The protons flow through the electrolyte membrane to the cathode, and the
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electrons flow through an external circuit, creating a flow of direct current (DC) electricity. Electrolytes can be
either solid-based or liquid-based and facilitate the separation and flow of the protons and electrons between
Load
Anode Electrolyte Cathode
Figure 2. Basic Fuel Cell Schematic
the electrodes. At the cathode, the protons combine with the oxygen and the electrons in the presence of a
catalyst to produce the byproducts of water. The electrochemical reaction also produces heat.
Fuel cells are scalable in that they can combine to form fuel cell systems, thereby meeting increasing power
demands for a variety of applications. Although fuel cell systems vary depending on fuel cell type, all systems
include the following basic components (U.S. Department of Energy Fuel Cell Technologies Office, 2019):
• Fuel Cell Stack-The fuel cell stack is comprised of multiple individual fuel cells of the same type stacked in
series. A typical stack contains hundreds of fuel cells. The power density of the fuel cell stack varies
according to fuel cell type, cell size, operating temperatures and pressure of the fuel gases supplied to the
cells.
• Fuel Processor-A fuel processor is used to produce a fuel suitable for supplying the fuel cell stack. The
processor and its components depend on the fuel source and the type of fuel cell. For pure hydrogen gas
fuels, fuel processors may constitute a simple sorbent bed to remove impurities. Hydrocarbon-based fuels
like natural gas may require multiple reactors and sorbent beds. In these cases, external reformers are
typically used to break down the hydrocarbons into hydrogen gas and carbon compounds, which then
continue to be processed to convert CO to its byproduct, C02, and remove sulfur (S) compounds and other
impurities using sorbent beds. The removal of impurities is critical to ensuring catalysts are not "poisoned"
(that is, deactivate catalyst surfaces) in the fuel cells, thereby reduced fuel cell efficiencies. Some fuel cell
types operate at high enough temperatures to allow for "internal fuel reforming" in the fuel cell; however,
sorbent beds are still required to remove impurities.
• Power Conditioners-While fuel cell systems produce DC electrical power, this power must still be
conditioned using inverters to match the electrical needs of the application. This can include modification
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of current, voltage and frequency of output of the fuel cell system. The power conditioning step typically
reduces fuel cell system efficiency by 2 to 6 percent.
• Air Compressors-Since fuel cell efficiency increases with gas supply pressure, air compressors are used to
increase the pressure of the inlet air supply to the fuel cell stack.
• Humidifiers - For some fuel cell systems, humidification is employed to keep the fuel cell membrane from
becoming too dry and impacting efficiency. In some systems, the water byproduct from the fuel cells is
recycled to humidify the air supply.
2.2 Fuel Cell Types and Characteristics
In general, fuel cells are characterized according to the type of electrolyte they contain. The electrolyte
dictates the reactions that take place in the fuel cell, and also determine the fuel cell's operational
temperatures, functionality, and materials composition. The most common fuel cell types are:
• Polymer Electrolyte Membrane
• Alkaline
• Phosphoric Acid
• Molten Carbonate
• Solid Oxide
The following section discusses each common fuel cell type and their respective characteristics, including
design, functionality, operational temperatures and limitations, durability, maintenance considerations, and
market applications to date.
2.2.1 Polymer Electrolyte Membrane
Polymer electrolyte membrane fuel cells (PEMFC) typically use a water-based acidic polymer membrane as
their electrolyte. PEMFCs, also known as proton exchange membrane fuel cells, utilize platinum-based
catalysts at both electrodes. As illustrated in Figure 3, hydrogen is split at the anode via the platinum catalyst
and hydrogen ions pass through the membrane while the electrons are routed through an external circuit,
generating the electrical current output. At the cathode, the hydrogen protons and electrons are combined
with oxygen (introduced in pure form or from air) to produce water and reaction heat.
PEMFCs are one of the most commonly used fuel cell types and can be found in a variety of commercial
applications today. They offer high power density coupled with low weight and volume. PEMFCs also operate
at relative low temperatures, typically below 100°C, allowing for quick start-up times and less thermal wear on
components. All these characteristics make PEMFCs suitable for vehicle and mobile equipment, as well as
mobile power supply devices (FuelCellToday, 2019).
The platinum-based catalysts used in PEMFCs drive up their capital costs and increase their susceptibility to
catalyst site "poisoning" from fuel contaminants like CO or S. Depending on the hydrogen source, an upstream
reactor may be added to PEMC systems to limit anode exposure to such contaminants (Barbir, 2013).
PEMFCs can also operate at higher temperatures by utilizing a mineral, acid-based electrolyte rather than a
water-based version. This allows PEMFCs to operate at up to 200°C. The higher temperature operation makes
PEMFCs less vulnerable to CO poisoning, thus increasing their ability to process hydrogen fuels from reforming
feeds. This use of the mineral, acid-based electrolyte also eliminates the need for a humidifier in the PEMFC
system (FuelCellToday, 2019).
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o
Anode Electrolyte Cathode
Figure 3. PEMFC Process Schematic
PEMFC Characteristic
Typical
Electrolyte
Water- or mineral-based acidic polymer
Operating Temperature
60 - 100°C (high temperature variant up to 200°F)
Contaminant Poisoning Tolerance
Low to CO and S
Commercial Applications
On-road vehicles, mobile nonroad equipment, mobile power
supplies, stationary power sources
Manufacturers
Ballard Power, Plug Power, Horizon Fuel Cell Technologies, H2
PowerTech, Hydrogenics/Cummins, and PowerCell
2.2.2 Alkaline
Alkaline fuel cells (AFCs) were some of the first fuel cells developed, attracting market interest in the early
1960's under NASA's Space Program. Early AFCs utilized an aqueous solution containing potassium hydroxide
in a porous matrix (usually asbestos) as the electrolyte. A variety of catalysts are used for anodes and
cathodes, including nickel, metal oxides and noble metals (E4etch, 2020). As shown in Figure 4, negatively
charged hydroxide ions formed at the cathode pass through the electrolyte and combine with hydrogen at the
anode to produce water and electrons.
AFCs operate at 70-100°C with an electrochemical conversion efficiency of about 60 percent. Conversion
efficiencies can be dramatically affected, however, by AFC susceptibility to C02 poisoning from the fuel or
oxidant side of the fuel cell. Such poisoning leads to carbonate buildup in the electrolyte, requiring the
application of fuel and oxidant supply removal processes and increasing the overall cost of the fuel cell system
(U.S. Department of Energy Fuel Cell Technologies Office, 2019) (Williams, 2011).
Additional operational issues with AFCs include wettability, component corrosion and management of
differential pressures.
Recent developments have resulted in the use of alkaline polymer membrane electrolytes. Known as alkaline
membrane fuel cells (AMFCs), AMFCs are more tolerant to C02 poisoning but exhibit issues with membrane
durability, water management and power density (U.S. Department of Energy Fuel Cell Technologies Office,
2019).
To date, commercial applications of AFCs/AMFCs include space, military, and back-up and distributed power.
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o
Anode Electrolyte Cathode
Figure 4. AFC Process Schematic
AFC/AMFC Fuel Cell Characteristic
Typical
Electrolyte
Aqueous solution containing potassium hydroxide in a porous
matrix, or alkaline membrane
Operating Temperature
70 - 100°C
Contaminant Poisoning Tolerance
Low to C02
Commercial Applications
Stationary power and remote power applications
Manufacturers
AFC Energy and GenCell
2.2.3 Phosphoric Acid
Development of phosphoric acid fuel cells (PAFCs) began in the U.S. in the 1960's. PAFCs utilize concentrated
liquid phosphoric acid on a silicon carbide matrix as an electrolyte. The fuel cell's electrodes consist of porous
carbon with platinum catalysts. In PAFCs, hydrogen ions created at the anode pass through the electrolyte to
the cathode, where they combine with oxygen and electrons to produce water (FuelCellToday, 2019), as
shown in Figure 5. The operating temperatures range between 150-200°C. The electrochemical efficiency of
PAFCs are lower than other fuel cell types at 40 percent, however, when used for CHP applications, overall
efficiencies can exceed 80 percent (U.S. Department of Energy Fuel Cell Technologies Office, 2019) (Williams,
2011).
Compared with other low temperature fuel cells, PAFC tolerance to C02 exceeds that of AFCs, and their
tolerance to CO exceeds that of PEMFCs (FuelCellToday, 2019). Higher tolerances enable PAFCs to operate
with a variety of fuels, including natural gas, petroleum products, and coal liquids and gases. PAFCs tend be
large and heavy, with lower power densities as compared to other fuel cell types. They also require much
higher levels of platinum catalysts and are therefore more expensive than other fuel cells. PAFCs properties
increase the importance of stricter water management practices due to its liquid electrolyte and moderately
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high operating temperatures. Start-up durations are longer with PAFCs compared to other low temperature
O
Anode Electrolyte Cathode
Figure 5. PAFC Process Schematic
fuel cells. To date, most applications of PAFCs have involved stationary power and distributed generation (DG).
PAFC Fuel Cell Characteristic
Typical
Electrolyte
Phosphoric acid in a porous matrix or polymer membrane
Operating Temperature
150 - 200°C
Contaminant Poisoning Tolerance
High to CO and C02
Commercial Applications
Stationary power
Manufacturers
Doosan Fuel Cell America, Fuji Electric, Toshiba
2.2.4 Molten Carbonate
Molten carbonate fuel cells (MCFCs) employ a molten carbonate salt (lithium, sodium, and potassium) in a
porous, chemically inert matrix. MCFCs are considered high temperature fuel cells because they typically
operate at 600-700°C. As a result of these high temperatures, MCFCs do not require precious metal catalysts
for anode and cathode electrodes. Instead, nickel catalysts are typically used for electrodes, thereby reducing
system costs (FuelCellToday, 2019). The high operating temperatures of MCFCs enable internal reforming of a
wide range of fuel sources, including natural gas, other hydrocarbons, and petroleum-based fuels, thus
eliminating the need for external reforming and its associated costs.
Note in Figure 6 that a C02 supply is required at the cathode, as carbonate ions pass through the electrolyte
and are consumed in reactions at the anode. MCFC can achieve electrochemical efficiencies between 50 and
60 percent; when MCFC waste heat is also utilized, however, overall efficiencies can exceed 80 percent (U.S.
Department of Energy Fuel Cell Technologies Office, 2019) (Williams, 2011) (Dincer & Rosen, 2013). MCFCs are
highly resistant to CO and C02 poisoning, which enhances their fuel flexibility. However, the primary challenge
with MCFCs is long-term durability. High corrosivity of the electrolyte and the higher operating temperatures
leads to quicker degradation rates in MCFC components. According to the DOE, researchers are currently
investigating new component materials and cell designs to increase MCFC lifetimes from their current 40,000-
80,000 hours (U.S. Department of Energy Fuel Cell Technologies Office, 2019).
Market applications for MCFCs have primarily focused on stationary power generation for electrical utility,
industrial and military applications, including generation in the megawatt capacity.
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0
Anode Electrolyte Cathode
Figure 6. MCFC Process Schematic
MCFC Fuel Cell Characteristic
Typical
Electrolyte
Molten lithium, sodium, and potassium carbonates in a porous
matrix
Operating Temperature
600 - 700°C
Contaminant Poisoning Tolerance
High to CO and C02
Commercial Applications
Large stationary power generation
Manufacturers
Fuel Cell Energy
2.2.5 Solid Oxide
Solid oxide fuel cells (SOFC) utilize non-porous ceramic compounds of metal (e.g., calcium or zirconium) oxides
as electrolytes. As shown in Figure 7, negative oxygen ions pass through the electrolyte to the anode where
they combine with hydrogen and CO to produce water vapor and C02.
SOFCs operate at very high temperatures, typically ranging between 500-1,000°C. These high temperatures
alleviate the need for catalytic material at the electrodes (FuelCellToday, 2019). The high temperatures also
increase SOFC tolerance to fuel contaminant positioning, such as CO, C02 and even S, and provides
considerable fuel source flexibility (e.g., natural gas and syngas). Further, the high temperature operation of
SOFCs enables internal reforming of a variety of fuel feedstocks in the fuel cell, eliminating the need and
associated cost for an external reformer catalyst. Relative to some other fuel cell types, SOFC fuel conversion
efficiencies are high at 60 percent. If the waste heat generated from SOFCs is properly harnessed, overall
efficiencies can approach 80 percent (U.S. Department of Energy Fuel Cell Technologies Office, 2019)
(Williams, 2011).
As a result of the high temperature operation, start-up with SOFCs takes longer than other types of fuel cells,
and SOFCs are designed to withstand the higher temperatures, including the use of heat resistant (and often
higher cost) materials for sensitive components. The systems also need to be thermally insulated to prevent
heat loss and shielded to prevent personnel exposure. Such requirements often limit or constrain SOFC
applications in the marketplace. Some manufacturers have opted for lower temperature (500-600°C) SOFCs
that use stainless steel as a replacement material for brittle ceramic components, allowing for shorter start-up
times and potentially higher durability for some applications.
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Syngas
O
Anode Electrolyte Cathode
Figure 7. SOFC Process Schematic
SOFC Fuel Cell Characteristic
Typical
Electrolyte
zirconium oxide stabilized with yttrium oxide
Operating Temperature
500 - 1,000°C
Contaminant Poisoning Tolerance
High to CO, C02, and S
Commercial Applications
Stationary power, small portable power, and CHP
Manufacturers
Ceres Power, Bloom Energy, FuelCell Energy/Versa Power, and
Ceramic Fuel Cells
2.2.6 Summary of Common Fuel Cell Type Characteristics
Table 8 lists a summary Table of the primary fuel cell types and their corresponding characteristics (U.S.
Department of Energy Fuel Cell Technologies Office, 2019). The fuel cell types with the highest operating
temperatures, MCFCs and SOFCs, can achieve internal reforming, allowing for a wide range of fuels and greater
tolerance for fuel and oxidant contaminants. PEMFCs, AFCs and PAFCs all operate at much lower
temperatures, requiring greater use of electrode catalysts for supporting reaction processes and consequently
exhibiting lower tolerances for fuel and oxidant contaminants. This, in turn, can lead to catalyst poisoning.
However, the lower operating temperatures also reduce the need for heat shielding and insulation, allowing
for more flexibility in market applications.
2.3 Fuel Cell Market Status
2.3.1 Worldwide Market Status
As discussed, a variety of fuel cell transportation and power applications have emerged on the global market.
Figure 8 presents a variety of recent worldwide fuel cell market data points (E4tech, 2018). As shown,
transportation (primarily on-highway applications and material handling equipment) and stationary power
applications have dominated the recent market, with a combined total of about 69,000 fuel cell shipments
equating to over 800 MW shipped capacity. Asia is the strongest regional fuel cell market, accounting for almost
75 percent of total worldwide fuel cell shipments in 2018. Although North America accounted for a much smaller
percentage of worldwide shipments at about 13 percent in 2018, the region accounted for about 52 percent of
total MW capacity, and an average fuel cell unit shipment of about 42 kW. This reflects a growing U.S. market
for larger fuel cells in both transportation and stationary power applications, while Asian markets have
capitalized on smaller residential power applications. PEMFCs continue to predominate in the marketplace,
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accounting for about 57 percent of total worldwide fuel cell shipments and 73 percent of total MW capacity in
2018. SOFCs were a distant second, with about 37 percent of shipments and 11 percent of MWs. Direct methanol
fuel cells (DMFCs) (a specialized form of PEMFCsthat can operate directly on methanol), PAFCs, AFCsand MCFCs
collectively made up about 5 percent of worldwide shipments and 15 percent of shipped MW capacity in 2018.
10 20 30 40 50
i Transportation ¦ Stationary ¦ Portable
60
2018 m
? _
i. 2017 I
2- 2016
9- 2015
2014
50 100 150 200
Transportation ¦ Stationary ¦ Portable
250
2018
2017
2016
2015
2014
2018
2017
2016
g- 2015
2014
10 20 30 40 50
Other HAsia ¦ Europe ¦N.America
60
100 200 300 400
Other BAsia ¦ Europe ¦ N.America
500
2018
2017
2016
2015
2014
2- 2016
2015
2014
0 10 20 30 40 50
¦ AFC ¦ MCFC ¦ SOFC ¦ PAFC bDMFC ¦ PEMFC
60
0 100 200 300 400 500
¦ AFC ¦ MCFC ¦ SOFC ¦ PAFC ¦ DMFC ¦ PEMFC
600
Figure 8. Worldwide Fuel Market Data (E4tech, 2018)
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Table 8. Summary of Operating Characteristics by Fuel Cell Type11
Type
Common
Electrolyte
Operating
Temp
Typical
Stack Size
Electrical
Efficiency (LHV)
Applications
Advantages
Challenges
PEMFC
Perfluoro sulfonic
acid
<120°C
<1 kW-100
kW
60% direct H2;a
40% reformed
fuelb
• Backup power
• Portable power
• Distributed
generation
• Transportation
• Specialty vehicles
• Solid electrolyte reduces
corrosion and electrolyte
management problems
• Low temperature
• Quick start-up and load
following
• Expensive catalysts
• Sensitive to fuel impurities
AFC
Aqueous
potassium
hydroxide soaked
in a porous matrix,
or alkaline
polymer
membrane
<100°C
1-100 kW
60%c
• Military
• Space
• Backup power
• Wider range of stable materials
allows lower cost components
• Low temperature
• Quick start-up
• Sensitive to CO2 in fuel and air
• Electrolyte management
(aqueous)
• Electrolyte conductivity
(polymer)
PAFC
Phosphoric acid
soaked in a porous
matrix or imbibed
in a polymer
membrane
150°-
200°C
5-400 kW,
100 kW
module
(liquid PAFC)
<10 kW
(polymer
membrane)
40%d
• Distributed
generation
• Suitable for CHP
• Increased tolerance to fuel
impurities
• Expensive catalysts
• Long start-up time
• Sulfur sensitivity
MCFC
Molten lithium,
sodium, and/or
potassium
carbonates,
soaked in a porous
matrix
600°-
700° C
300 kW-3
MW,
300 kW
module
50%e
• Electric utility
• Distributed
generation
• High efficiency
• Fuel flexibility
• Suitable for CHP
• Hybrid/gas turbine cycle
• High temperature corrosion
and breakdown of cell
components
• Long start-up time
• Low power density
SOFC
Yttria stabilized
zirconia
500°-
1,000° C
1 kW-2 MW
60%f
• Auxiliary power
• Electric utility
• Distributed
generation
• High efficiency
• Fuel flexibility
• Solid electrolyte
• Suitable for CHP
• Hybrid/gas turbine cycle
• High temperature corrosion
and breakdown of cell
components
• Long start-up time
• Limited number of shutdowns
a NRELComposite Data Products, "Fuel Cell System Efficiency"
b Panasonic Headquarters News Release, "Launch of New !Ene-Farm! Home Fuel Cell Product More Affordable and Easier to Install"
c G. Mulder et al., "Market-ready stationary 6 kW generator with alkaline fuel cells," ECS Transactions 12 (2008) 743-758
d Doosan PureCell Model 400 Datasheet
e FuelCell Energy DFC300 Product Specifications
f Ceramic Fuel Cells Gennex Product Specifications
11 U.S. Department of Energy Fuel Cell Technologies Office website, www.energy.gov/eere/fuelcells/fuel-cells.
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2.3.2 Transportation Market Applications
In terms of fuel cells for transportation markets, leading on-road applications include light duty passenger
vehicles, transit buses and drayage vehicles. Small forklifts predominate among nonroad applications. Current
market status for these applications is provided below including those applications not specifically at ports.
2.3.2.1 Light Duty Passenger Vehicles
Given the scalability of fuel cell technology and its potential market size, light duty passenger vehicle
applications will support fuel cell technology market penetration across sectors, including the port sector.
According to the Hydrogen Analysis Research Center (HARC) (Hydrogen Analysis Resource Center, 2019), more
than 5,000 light duty fuel cell prototype or commercial vehicle deployments have occurred at over 25 locations
across the country since 2007. California accounts for the majority of these deployments, primarily due to the
state's commitment to fuel cell vehicles and hydrogen delivery system demonstrations.
2.3.2.2 Transit Buses
A considerable amount of research and development have contributed to fuel cell transit bus applications over
the last decade. Transit bus applications account for some of the first mobile applications of fuel cells. The first
fuel cell transit bus was demonstrated in 2002 in the SunLine Transit fleet in California. Since 2007,180 fuel
cell transit and shuttle buses have been deployed or are soon to be deployed in locations across the country,
according to the HARC (Hydrogen Analysis Resource Center, 2019). The majority of deployments have
occurred in California, but other demonstrations have been rolled out in Delaware, Hawaii, and Ohio.
2.3.2.3 Heavy-Duty Drayage Vehicles
Drayage trucks are a frequent application for demonstrating emerging fuel cell technology platforms. Drayage
services include hauling freight between ports and intermodal terminal and warehouse locations.
A variety of fuel cell and fuel cell range extender drayage truck demonstrations are ongoing across the country.
The HARC database includes a total of 17 fuel cell-powered heavy-duty drayage trucks with planned
deployment dates between 2015 and 2021 (Hydrogen Analysis Resource Center, 2019). The majority of these
pre-commercial trucks, comprising both fuel cell and fuel cell range extender systems, have been deployed in
California at the Ports of Long Beach and Los Angeles.
Some examples of these pre-commercial demonstration programs include the following:
• Zero Emission Cargo Transportation II (ZECTII) Program (Impullitti & Ha, 2019) -This program involves
four OEM project teams that develop and demonstrate fuel cell drayage trucks. Each OEM project team is
developing electric powertrain trucks with PEMFC range extenders as follows:
o BAE/Ballard/Kenworth -The prototype truck under development incorporates a BAE HybriDrive
system powertrain with a 100-kWh Lithium ion battery pack. One 180-kW alternating current (AC)
electric motor is mounted on each rear axle. A Ballard 100-kW fuel cell range extender auxiliary
power unit provides power to charge the battery pack. The truck operates primarily off the battery
pack, with the fuel cell maintaining battery pack state of charge within a specified range. The
system incorporates 30 kg of onboard hydrogen fuel storage, which provides approximately 110-
120 miles of range between re-fueling. The system power output is comparable to that of a heavy-
duty diesel engine.
o Hydrogenics/Siemens - The Daimler truck platform will incorporate a Siemens ELFA electric
powertrain with a Hydrogenics Celerity Plus 60-kW range extender fuel cell. Truck range is
anticipated to exceed 150 miles, with a hydrogen refueling time of 10-15 minutes.
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o TransPower/Hydrogenics/Navistar-Two trucks will be developed with TransPower's ElecTruck
electric powertrain and 120-kWh battery packs. One truck will include a 30-kW Hydrogenics fuel
cell range extender, while the other will include a 60-kW version. Both trucks will store 25-30 kg of
high-pressure hydrogen. Fuel economy is estimated to be 7.37 miles per kg hydrogen. Truck range
is expected to range between 135-200 miles.
o U.S. Hybrid/US FuelCell/lnternational - Two trucks will be developed with a U.S. Hybrid electric
powertrain (320-kW) and a lithium ion 26-kWh battery pack. The trucks will include an 80-kW U.S.
FuelCell PureMotion range extender fuel cell. Each truck will maintain 20 kg of 350 bar hydrogen
storage, with an estimated refueling time of less than ten minutes and an expected range of 150-
200 miles.
All of the project trucks will be operated along major drayage truck corridors between the Port of Los Angeles,
Port of Long Beach, and the Intermodal Container Transfer Facility, a near-dock rail facility. The program was
initiated in 2018, and all trucks are expected to be deployed by early 2020.
• Project Portal and Project Portal 2.0 Programs-Toyota, in cooperation with Kenworth, initiated a program
in 2017 to develop a prototype heavy duty fuel cell-powered drayage truck for demonstration at the Ports
of Los Angeles and Long Beach. The initial "Alpha" truck incorporated two PEMFCs (totaling 230-kW)
originally designed for Toyota's commercially available light duty Mirai vehicle. The truck uses a small
battery pack of 12-kWh, with a range of about 200 miles. The Alpha truck accumulated over 10,000 miles
in actual drayage service. A "Beta" truck was employed in 2018, which offered a longer range (200-300
miles) as compared to the Alpha version.
• FAST TRACK Fuel Cell Truck Project (Landberg, 2019) - In 2019, TransPower is expected to lead the
development and demonstration of five heavy duty drayage trucks with fuel cell range extenders at the
Ports of Los Angeles and San Diego. TransPower is integrating its T-NMC battery-electric and energy
storage system with Loop Energy's FC-REX range extender fuel cells on two Peterbilt 579 truck platforms.
Truck range is projected to exceed 200 miles. The trucks will be deployed for a one-year period in
December 2019.
• Zero-Emission Freight "Shore to Store" Project - Toyota is collaborating with Kenworth, Ballard Power
Systems and Shell Global to develop and demonstrate hydrogen fuel cell-powered heavy-duty drayage
trucks at the Port of Los Angeles. A total often trucks will be developed in conjunction with two hydrogen
fueling stations. The trucks will be developed based on Kenworth's T680 platform. The fuel cell power
system (two 114 kW fuel cell stacks and 12 kWh battery pack) affords the trucks 300 miles of range based
on 60 kg of hydrogen storage. The trucks will be operated by Toyota Logistics Services (4 trucks), United
Parcel Services (3 trucks), Total Transportation Services Inc. (2 trucks) and Southern Counties Express (1
truck). In addition, the project will install two hydrogen refueling stations by Shell Global. The refueling
stations will be integrated with three regional stations, located at Toyota facilities around the Los Angeles
region, to support drayage truck refueling. The first often trucks were deployed in April 2019 (U.S.
Department of Energy-AFDC, 2019), and the project is anticipated to be completed in 2021.
2.3.3 Stationary and Portable Power Applications
The effectiveness of fuel cells in stationary and back-up power applications has been demonstrated in a variety
of sectors. For ports, fuel cell back-up power and auxiliary power may be useful in resiliency planning. The
HARC has tracked stationary and back-up power fuel cell installations greater than 25 kW since 2007
(Hydrogen Analysis Resource Center, 2019). As of September 2018, this database contains 580 active
installations across the country, totaling over 350 MW.
Waste heat from stationary fuel cell systems (especially MCFCs and SOFCs) can also be used to support
thermal heating and cooling loads at facilities. When combining CHP opportunities with fuel cells, overall
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system efficiencies (electrical and thermal) significantly increase. The HARC database listed 64 active
installations of CHP applications, totaling approximately 64 MW. The majority of these applications were
achieved in California, Connecticut, and New York (Hydrogen Analysis Resource Center, 2019)
2.3.3.1 Stationary Power Generation Systems
Stationary power generation remains a dominant application for fuel cell technology across residential,
commercial, and industrial sectors worldwide. SOFC, MCFC and PAFC fuel cell technologies are still prevalent in
high power systems, while PEMFCs occupy a market niche in low power systems. MCFCs have also gained
market foothold due to their use in tri-generation systems (providing electric power, heat, and hydrogen),
including applications in which waste biogas provides a fuel source. Stationary power fuel cell system costs
continue to remain relatively high as compared to competitive traditional technologies. Installed costs for
stationary power fuel cell systems range from about $4,000/kW for large prime power systems to over
$20,000/kW for small prime power systems (National Renewable Energy Laboratory, 2018).
2.3.3.2 Back-up Power Systems
Back-up power systems provide emergency electrical power for critical or required systems during a power
outage. Back-up power is typically used intermittently, with long periods of inactivity. Standby diesel-fueled
generators typically serve as a back-up power source. However, commercially available fuel cells are well-
suited for both small and large back-up power systems. An NREL study on telecommunication back-up power
systems illustrates the effectiveness of fuel cells in back-up power applications (Kurtz, 2015). The study
includes a total of 136 U.S. installations of small (3-6 kW) fuel cell back-up power units with refillable
stationary hydrogen storage modules (HSM). On average, the units exhibited a 99.5 percent start-up reliability
over a three-year period. Over the same period, the average mean time between interrupted operation
(MTBIO) was 94 percent. Annualized cost of ownership for the fuel cell systems was comparable to that of
similar diesel systems. The NREL also offered an assessment of fuel cell back-up power system performance
status, as provided in Table 9. Current shortcomings relative to diesel-fueled generators included capital cost
and long-term durability, but cited advantages included emissions, noise, weight, efficiency, and maintenance
costs.
Table 8. Fuel Cell and Diesel Back-up Power System Comparison
Back-up Power System Parameter
Fuel Cell vs.
Diesel Generator
Reliability
+
Capital Cost ($/kW)
-
Extended Run Time
=
Emissions
++
Noise
+
Weight
+
Efficiency
+
Annual Fuel Cost
+
Annual Maintenance Cost
+
Maintenance Frequency
++
Refurbishment
=
Remote Conditioning and Check
+
Operational Lifetime
-
Table Designations: ++ much better; + better; = same; - worse
*ERG
2-13
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3. Fuel Cell Applications and Characteristics for Ports
Marine port facilities provide potential applications for fuel cell technology, including a variety of on-highway
vehicles, nonroad vehicles, rail, marine, and stationary power applications. Many of these applications have
been or are currently being explored through formal demonstrations of pre-commercial and commercial fuel
cell equipment. This report does not focus on heavy duty drayage trucks; however, there are a number of
ongoing port demonstrations outlined in Appendix A. Appendix A also provides a compilation of fuel cell
equipment demonstrations at U.S. port locations from 2010 to 2020.
The remainder of this report will focus on fuel cell technologies in relation to the following port-related
equipment areas: nonroad materials handling equipment, switcher locomotives, marine propulsion and
auxiliary power, and stationary power generation. Each port equipment topic includes an outline of typical
diesel-fueled equipment and associated fuel cell-powered equipment currently on the market or under
development.
3.1 Nonroad Materials Handling Equipment
Nonroad vehicle equipment has favorable characteristics for fuel cell technology application at port facilities.
In particular, ports material handling equipment such as forklifts, yard tractors and cargo handlers are good
candidates for fuel cells. Each type of equipment is discussed below.
3.1.1 Forklifts
3.1.1.1 Diesel-Fueled
Diesel-fueled forklifts are key to maximizing cargo handling efficiency at most port facilities. A reasonable
representation of average diesel forklift characteristics used at ports is presented in Table 10 (Starcrest
Consulting Group, LLC, 2015) (Starcrest Consulting Group, LLC, 2016) (Lindhjem, 2018) (California Air Resources
Board , 2019). The data incorporates Figures from three ports locations across the U.S. (Starcrest Consulting
Group, LLC, 2015), (Starcrest Consulting Group, LLC, 2016), (Lindhjem, 2018), as well as average Figures from
the California Air Resources Board's (CARB) 2011 survey on 14 ports and 16 rail yards in California (California
Air Resources Board, 2019). Based on these port forklift inventories, forklift age ranges between about 8-13
years. The forklifts displayed average horsepower levels between about 75-175 horsepower and showed
average annual runtimes ranging from about 500-2,200 hours. Representative forklift load factors for the
various port locations ranged from 0.30-0.59.
3.1.1.2 Fuel Cell-Powered
At present, warehouse forklifts represent a strong commercial market for mobile fuel cells, typically in the
electric motor-driven Class I, II or III applications12. Fuel cells in warehouse applications produce zero emissions
and significantly lower noise emissions, both of which benefit warehouse environments for employees. Fuel
cell forklifts in warehouse environments are favorable in many cases to battery-electric versions due to
advantages associated with fuel range, refueling durations and cold climate performance, all of which increase
equipment productivity. Other advantages include smaller energy footprints for associated infrastructure,
lower labor requirements, power consistency over the duty cycle, and lower operational costs (Ramsden,
2013) (U.S. Postal Service, 2018). Through year 2017, the DOE estimates that nearly 22,000 fuel cell forklifts
were deployed across the country, representing over 140 MW of total fuel cell systems (DOE Hydrogen and
Fuel Cells Program , 2018). Similar to other mobile applications, PEMFCs are the predominant fuel cell type
used in forklift applications.
12 Class I are Electric Motor Rider Trucks; Class II are Electric Motor Narrow Aisle Trucks; and Class III are Electric Motor Hand Trucks or
Hand/Rider Trucks.
*ERG
3-1
-------
In support of DOE programs, the NREL has conducted a number of studies and evaluations of fuel cell forklift
applications. In a 2016 study, the NREL presented the results of an evaluation of over 1,000 commercial fuel
cell material handling equipment stationed across the country in various applications (Ainscough, 2016). A key
observation from the study was that current fuel cell stack durability requires continued improvement for
long-term
Table 10. Typical Port Location Diesel-Fueled Forklift Operational Characteristics
Total
Forklifts
Forklift Age (Yr)
Forklift Horsepower
Forklift Annual Operation
(Hr)
Avg Load
Factor
Min
Max
Avg
Min
Max
Avg
Min
Max
Avg
Port of Long Beach Inventory, 2014
100
< 1
35
8
50
200
134
0
2,306
498
—
Port Everglades Inventory, 2015
177
*
—
9
—
—
76
—
—
659
0.59
Port of Oakland Inventory, 2017
14
—
—
—
—
—
169
—
—
561
0.30
CARB, California Port Forklift Inventory, 2011
—
—
—
12.7
—
—
—
—
—
701
0.30
CARB, California Railyard Forklift Inventory, 2011
—
—
—
12.7
—
—
—
—
—
2,234
0.30
* "—" denotes data unavailable
market viability. The NREL found that only about half of the fuel cell equipment in the study have achieved
more than 10,000 hours of operation before reaching 10 percent voltage degradation.
In a separate study in 2013, the NREL evaluated fuel cell forklift equipment implemented under hundreds of
federally funded demonstration projects (Ramsden, 2013). For multi-shift applications of material handling
equipment, the study determined that fuel cell-powered units offered advantages over battery-electric
versions, since fuel cell units can operate longer without refueling, can be refueled in much shorter durations
and can operate in longer durations without power degradation. These benefits translate to improved total
cost of ownership. Results are shown in Figure 9 in 2020 dollars (Ramsden, 2013). The NREL's analysis
reviewed a range of capital and operational costs such as capital costs of battery and fuel cell systems, cost of
supporting infrastructure, maintenance costs, warehouse space costs, and labor costs. Overall, the study
determined that total cost of ownership was 10 percent lower with fuel cell Class I and II forklifts compared
with battery-electric versions, and about 5 percent lower for Class III forklifts. The study did not evaluate
potential improvements in fleet productivity and potential cost savings for the fleet. However, the analysis
included a federal tax credit available to commercial entities for reducing capital cost; nevertheless, the fuel
cell forklifts would still realize cost savings even without the credit. In reviewing the cost components, the
NREL indicated that fuel cell systems are currently more expensive relative to comparable battery-electric
systems. Additionally, although the costs of hydrogen fuel and refueling infrastructure exceed battery-electric
equipment costs, fuel cell-related costs are offset by lower labor costs and lower facilities expenses (e.g., cost
of building space).
While commercial fuel cell-powered products are currently aimed at forklift applications with lift capabilities
generally lower than used by ports, the scalability of fuel cell power plants enables eventual product offerings
in these higher forklift classes. For example, Toyota Industries' commercial forklift product uses the same fuel
cell structure as the Toyota Mirai fuel cell sedan, albeit with only about half the total number of cells in the
stack.
*ERG
3-2
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Forklift Annualized Costs
$25,000
$20,000
$15,000
$10,000
$5,000
$0
I
Battery-Electric Fuel Cell
Class I and II Forklift
Battery-Electric Fuel Cell
Class III Forklift
I Battery/Fuel Cell
Maintenance
i Lift Truck Maintenance
i Infra Warehouse Space
l Electricity/H2 Fuel
Charging/Fueling Labor
Charge/Fuel Infra Cost
per Lift
I Ammortized
Battery/Fuel Cell Capital
I Ammortized Lift Capital
Figure 1. NREL Total Cost of Ownership for Material Handling Equipment
3.1.2 Yard Tractors
3.1.2.1 Diesel-Fueled
Table 11 illustrates typical diesel-fueled yard tractor fleet and operational characteristics at port locations. In
addition to data cited from previous port inventories (Starcrest Consulting Group, LLC, 2015) (Starcrest
Consulting Group, LLC, 2016) (California Air Resources Board , 2019) (Lindhjem, 2018), Table 11 includes the
results of a study of yard tractor load factors for the Port of Long Beach (Starcrest Consulting Group, LLC,
2008). The study evaluated the duty cycles of 85 operational yard tractors to calculate a CARB-approved
average load factor of 0.39. Using the data from these port yard tractor inventories, port yard tractors are, on
average, about 5-12 years old with a horsepower rating between 175-200. Port yard tractors typically operate
at about 1,200-4,600 hours per year.
Table 11. Typical Port Location Diesel-Fueled Yard Tractor Operational Characteristics
Total Yard
T ractors
Yard Tractor Age (Yr)
Yard Tractor Horsepower
Yard Tractor Annual
Operation (Hr)
Avg Load
Factor
Min
Max
Avg
Min
Max
Avg
Min
Max
Avg
Port of Long Beach Inventory, 2014
546
2
11
6
173
249
200
17
4,411
1,985
0.39
Port Everglades Inventory, 2015
156
—
—
12
—
—
175
—
—
1,333
0.39
Port of Oakland Inventory, 2017
105
—
—
—
—
—
201
—
—
1,249
0.39
CARB, California Port Forklift Inventory, 2011
—
—
—
4.6
—
—
—
—
—
2,020
0.39
CARB, California Railyard Forklift Inventory, 2011
—
—
—
4.6
—
—
—
—
—
4,627
0.39
*ERG
3-3
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Recent guidelines for zero/near-zero emission yard tractor testing and demonstrations published by the Port
of Long Beach and Los Angeles offer some additional insight on yard tractor operations at ports (Port of Long
Beach & Port of Los Angeles, 2017). In the guidance, typical yard tractor operations at ports were organized
into three categories: ship work, rail work and dock work. Ship work covers the movement of containers
loaded onto and from vessels; rail work covers containers movements onto and from cargo trains; and dock
work includes the movement of containers within a terminal yard. In-use data indicates that rail work is the
most load intensive for yard tractors. Ship and rail work include highly repetitive activities and constitute the
majority (about 95 percent) of all yard truck activities at the ports. Table 12 provides a breakdown of in-use
data from the ports.
The ports also identified minimum performance metrics for nonroad zero and near-zero yard tractors, shown
in Table 12, and design duty cycle requirements for an 8-hour shift, listed in Table 13. For purposes of Tables
13 and 14, an "8-hour shift" consists of 25 percent rail work, 70 percent ship work, and 5 percent yard work
(Port of Long Beach & Port of Los Angeles, 2017).
Table 12. Port of Long Beach/Port of Los Angeles Yard Tractor In-use Data Summary
Parameter
All Activities
Rail Work Only
Ship Work Only
Average Speed (mph)
7.5
8.9
7.0
Std. Dev. of Speed (mph)
3.4
4.2
3.2
Creep (percent)
21.4
15.1
23.3
Idle (percent)
40.1
31.7
41.8
Creep + Idle (percent)
61.5
46.8
65.1
Table 13. Port of Long Beach/Port of Los Angeles Minimum Performance Guidelines
for Zero/Near-Zero Yard Tractors
Minimum Performance Guideline
Performance Metric
Design Duty Cycle
One (1) 8-hour shift with no opportunity charging/refueling
assumed
Two (2) 8-hour shifts with opportunity charging/refueling
assumed
Freight Load Capacity
70,000 lbs. (loaded container plus chassis)
Top Speed
25 mph at zero grade (0% grade)
Gradeability at Vehicle Launch
20% grade at 81,000 GCW
Gradeability Sustained at 10 mph
15% grade at 81,000 GCW
Table 9. Port of Long Beach/Port of Los Angeles Design Duty Cycle -
8-hour Shift Minimum Requirements
Number of Container
Movements
(Pulls per Shift)
Duration (seconds)
Load (Lbs.)
Average Speed (mph)
84
60
45,000
9
30
45
50,000
8
6
120
30,000
15
*ERG
3-4
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3.1.2.2 Fuel Cell-Powered
Several companies have produced or are in the process of producing fuel cell yard trucks for port
demonstrations, including Loop Energy, Ballard Power Systems and BAE Systems, and Transpower. These
research truck platforms employ unique approaches to satisfy truck requirements. For example, Loop Energy's
fuel cell range extender system incorporates a 56-kW fuel cell that generates electric power to charge an
onboard battery pack (GlobeNewswire, 2017). The battery pack serves to supplement fuel cell electric power,
ensuring that truck peak power demands are met. Through a regenerative braking system, a portion of energy
normally lost from the braking function is captured to add charge to the batteries, enabling the use of a
smaller sized battery pack.
The Ballard Power System approach couples a FCveloCity-HD 85 kW PEMFC with BAE System's HDS200
HybriDrive series propulsion system (200-kW electric motor) on a Capacity TJ9000 yard truck platform (up to
242,000 GCWR) (Ainscough, 2016). Two vehicles are being developed for demonstration at the Port of Los
Angeles. The system includes 31.8-kWh of lithium ion battery storage with regenerative braking and 20 kg of
hydrogen storage at 350 bar. To date, the manufacturers of this prototype truck have not indicated a desire to
use higher pressure hydrogen gas storage, such as 700 bar, although such an approach could be done to
increase onboard hydrogen energy. Similarly, while the manufacturers have not stated an intention to use
liquid hydrogen storage, such an approach may be cost-effective at the high daily fuel volumes typically
experienced in the yard tractor application. Of course, both the higher pressure and liquefied hydrogen
storage approached would increase the fuel cell yard tractor's capital cost.
Appendix A provides additional information on port-related fuel cell yard truck demonstration project
programs.
3.1.3 Cargo Handlers
3.1.3.1 Diesel-Fueled
Diesel-fueled cargo handlers (top loaders, side handlers, rubber-tired gantry cranes, and ship-to-shore (STS)
cranes, among others) serve critical functions in most port operations, facilitating the movement of cargo
containers within the terminal and supporting intermodal container transfers for on-road truck transport. The
majority of cargo handler equipment are high power, heavy fuel use applications resulting from the severe
daily duty cycles they experience. Although all of the cargo handler equipment types are important, the top
loader application was selected as represenative of the cargo handler category and thus analyzed in greater
depth for purposes of this study. Table 15 provides typical diesel top loader fleet and operational
characteristics based on data from a variety of port sources (Starcrest Consulting Group, LLC, 2015) (Starcrest
Consulting Group, LLC, 2016) (Lindhjem, 2018) (California Air Resources Board, 2019). Based on this inventory
data, diesel top loaders are about 6-12 years old, have maximum power ratings between 300-375 horsepower,
and operate annually about 1,400-2,300 hours.
Table 15. Typical Port Location Diesel-Fueled Top Loader Operational Characteristics
Total Top
Loaders
Top Loader Age (Yr)
Top Loader Horsepower
Top Loader Annual
Operation (Hr)
Avg Load
Factor
Min
Max
Avg
Min
Max
Avg
Min
Max
Avg
Port of Long Beach Inventory, 2014
167
< 1
40
7
174
375
295
0
4,148
2,286
—
Port Everglades Inventory, 2015
54
—
—
12
—
—
331
—
—
1,972
0.43
Port of Oakland Inventory, 2017
123
—
—
—
—
—
313
—
—
1,388
0.59
*ERG
3-5
-------
Total Top
Loaders
Top Loader Age (Yr)
Top Loader Horsepower
Top Loader Annual
Operation (Hr)
Avg Load
Factor
Min
Max
Avg
Min
Max
Avg
Min
Max
Avg
CARB, California Port Forklift Inventory, 2011
—
—
—
5.9
—
—
—
—
—
1,884
0.59
CARB, California Railyard Forklift Inventory, 2011
—
—
—
5.9
—
—
—
—
—
1,705
0.59
The operation of cargo handlers in most port
environments is typically demanding, involving both
lifting and transporting freight. Most North American
ports operate according to three types of duty cycles:
yard, dock and rail (Nuvera, 2019). Breakdowns of these
duty cycles are shown in Figures 10 and 11 for the Port
of Angeles as an example (Nuvera, 2019). Yard and dock
duty cycles typically have multiple breaks over an 8-hour
shift and are associated with longer idling times. Rail
duty cycles are typically characterized by more intensive
operations and much less frequent breaks per shift.
Idling in yard and dock duty cycles comprise Figure 10. Typical Energy Usage for Top Loader
approximately 21 percent of total cycle duration, while Operation under Yard and Dock Duty Cycles
idling in rail duty cycles accounts for only 6 percent of
total cycle time. Hydraulics usage in the three cycle types
constitutes between 27-32 percent of total duration,
while combined (simultaneous equipment driving and
hydraulics usage) usage comprises another 29-35
percent.
3.1.3.2 Fuel Cell-Powered
As a result of the demanding duty cycles for typical top
loader operation, pre-commercial fuel cell units have
focused on hybrid platforms with combined fuel cell
electric and battery powertrains. These hybrid platforms
provide additional flexibility for meeting maximum
energy use and power output demands13. For example,
Hyster-Yale Group, along with its subsidiary, Nuvera, is
developing a fuel cell-battery hybrid container handler. The research platform incorporates a 90-kW Nuvera
PEMFC with 20 kg hydrogen storage (350 bar) and 200-kWh lithium ion battery pack (Nuvera, 2019). While the
total onboard energy storage (hydrogen and batteries combined) may not satisfy the energy needs of a
complete shift in some port applications, the use of mobile hydrogen refuelers can be employed, similar to
diesel equipment refueling practices. The platform incorporates an energy recovery system that captures
energy typically lost during braking and lowering loads to charge the batteries. Hyster is also examining 700
bar gaseous hydrogen storage and liquid hydrogen storage as a means of increasing onboard energy storage
density over the original 350 bar pressure system. Both of these types of storage would increase the overall
13 ERG was not able to identify performance data for pre-commercial fuel cell units as of the writing of this report, although this data
will likely become available as equipment demonstration projects across the county progress.
Rail Energy Usage
1%
¦ Idle "Driving ¦ Hydraulics ¦Combined ¦ Transitions
Figure 2. Typical Energy Usage for Top Loader
Operation under Rail Duty Cycles
*ERG
3-6
-------
capital costs of the fuel cell top loader application. In addition, for an upcoming demonstration project at the
Port of Los Angeles, Hyster is collaborating with WAVE to incorporate its inductive ("wireless") charging system
and, consequently, to increase useable daily battery storage for the application. The charging system can be
accessed during periods of equipment idling or staging over the course of the day.
Appendix A provides additional information on port-related fuel cell cargo handler demonstration project
programs.
3.2 Switcher Locomotives
3.2.1 Diesel-Fueled
Switcher locomotives are central to port-related railyard operations. Switcher locomotives are used for
moving, assembling and disassembling freight rail cars in short distances in and around port terminals.
According to the federal regulations for locomotives in 40 CFR § 1033.901, switcher locomotives typically have
a total maximum rated power of 2,300 horsepower or less (one engine or multiple engines combined).
Switcher locomotives are typically powered by diesel- electric generator (genset) systems, in which the diesel
engine drives a generator that provides electricity to the locomotive's traction motors.
As reported in a recent CARB technical document (California Air Resources Board, 2016), the current California
switcher locomotive inventory consists of two types of locomotives depending on their age. The first is a
traditional, older platform locomotive incorporating a single diesel-electric engine genset. The second type
incorporates a newer, multi-engine diesel-electric genset platform. The older type is often a line haul
locomotive that gets relegated to regional or switcher service after 15-20 years of line haul service. Some of
these older switcher locomotives achieve overall service lifespans of 50 years. Switcher locomotives may
receive several engine rebuilds or repowers over the course of their lifetimes.
As shown in Table 16, the older switcher platform incorporates one two-stroke, sixteen-cylinder diesel engine,
while the new platform employs three four-stroke, six-cylinder diesel engines. Total horsepower for both
platforms is similar (2,000 versus 2,100 horsepower). Total locomotive weights between the two platforms are
similar for four-axle versions, but six-axle versions of the new platform are significantly heavier.
Table 10. Typical California Switcher Locomotive Specifications
Key Locomotive Specifications
Traditional, Older Locomotive
Platform (EMD GP38-2)
Newer Locomotive Platform
(NREC 3-Engine Genset)
Locomotive Weight (lbs.)
250,000
268,000 (4 axle)
395,000 (6 axle)
Locomotive Starting Tractive Effort
(STE) (lbs. Force)
61,000
80,000
Engine Maximum Rated Speed
(RPM)
800
1,800
Engine Cycle/Stroke
Two
Four
Engine Cylinders
16
6
Engine Horsepower
2,000
2,100
(3x700 hp)
Fuel Tank Capacity (Gallons)
1,700
2,900
Maximum Rated Locomotive Speed
(MPH)
65
70
*ERG
3-7
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Locomotive operation is comprised of various load/power modes called notches. The federal regulations
(under 40 CFR § 1033.530) for measuring locomotive emissions defines a switcher locomotive duty cycle as
shown in Table 17. Note that idle operation makes up almost 60 percent of the duty cycle, while the lower
notches (#1-4) constitute another 34 percent. Thus, under the federal switcher locomotive duty cycle, idle and
lower notch (lower load/power) operation make up about 94 percent of typical switcher operations. The CARB
has estimated that a Californian switcher locomotive consumes up to 140 gallons of diesel fuel per day and
10,000-50,000 gallons of diesel fuel annually.
A 2018 air emissions inventory report for the Port of Oakland (Lindhjem, 2018) described switcher locomotive
use for the Oakland International Gateway (OIG) rail yard, which is operated by the Burlington Northern Santa
Fe (BNSF) railway. One switcher is typically assigned to the OIG at any given time, although different
locomotives are rotated in and out of this service. In 2018, the switcher locomotives included GM-EMD, GP-25
or GP-60 models. The GP-25 has a single diesel engine rated at 2,500 horsepower, while the GP-60 has two
diesel engines with a total rated capacity of 3,600 horsepower. Table 18 provides the reported switcher duty
cycle for the OIG railyard, indicating total time spent at idle or notch #1-4 load modes is over 95 percent
(Lindhjem, 2018). Average switcher utilization at the OIG yard in 2015 was 2,738 hours, and 2,157 hours in
2017.
Table 17. Federal Switcher Locomotive Duty Cycle under 40 CFR § 1033.530
Test Mode
Percent Time in Mode
Low and Normal Idle
59.8%
Dynamic Brake
0%
Notch 1
12.4%
Notch 2
12.3%
Notch 3
5.8%
Notch 4
3.6%
Notch 5
3.6%
Notch 6
1.5%
Notch 7
0.2%
Notch 8
0.8%
Total
100%
Table 18. Typical Switcher Locomotive at Port of Portland's OIG Railyard
Throttle Notch
Time in Mode
Idle
59.8%
Dynamic Braking
1.4%
1
6.6%
2
15.0%
3
9.5%
4
4.4%
5
1.9%
6
0.3%
7
0.0%
8
1.0%
Total
100%
*ERG
3-8
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3.2.2 Fuel Cell-Powered
The BNSF Railway developed an early pre-commercial fuel cell switcher locomotive in 2009 (California Air
Resources Board, 2016). The BNSF conducted in-service field demonstrations with the fuel cell switcher in Los'
Angeles, CA; Hill Air Force Base, Utah; and Topeka, Kansas (California Air Resources Board, 2016). Called the
BNSF 1205, the switcher incorporated a hybrid platform consisting of a 250-kW PEMFC integrated with a lead
acid traction battery system. The platform was retrofitted on an existing EMD GP9 switcher locomotive
(280,000 lbs.) platform. The BSNF 1205 included 14 carbon-fiber composite 350 bar compressed hydrogen
storage tanks and 600V DC traction motors. The fuel cell provided continuous power to charge the battery
pack, while the battery pack provided peak power demands in excess of the fuel cell's output (about 1,500 kW
total). In 2010, the BNSF 1205 platform was upgraded to include a 500-kW PEMFC, one MW lithium ion battery
pack and twice the hydrogen storage volume (California Air Resources Board, 2016). Following field trials, the
BNSF 1205 was dismantled.
Higher pressure (such as 700 bar) gaseous storage or liquefied hydrogen storage would both be viable design
considerations for future fuel cell switcher locomotive applications. Given the overall fuel use requirements for
typical switcher applications, liquefied hydrogen could in fact be more cost-effective than higher pressure
hydrogen storage both for onboard storage and for onsite delivery/storage or production/storage scenarios.
While the BSNF Railway's fuel cell switcher demonstration provided meaningful data regarding this application,
it should be noted that additional R&D will be necessary to address a variety of fuel supply and infrastructure
needs, safety requirements, and high equipment and fuels costs before fuel cell switcher locomotives can
achieve reasonable market penetration. Listed below are some encouraging recent developments (Caterpillar,
2021):
• In December 2021, Caterpillar, BNSF, and Chevron agreed to pursue hydrogen fuel cell locomotive
demonstration. The goal of the demonstration is to confirm the feasibility and performance of
hydrogen fuel for use as a viable alternative to traditional fuels for line-haul rail. Hydrogen has the
potential to play a significant role as a lower-carbon alternative to diesel fuel for transportation, with
hydrogen fuel cells becoming a means to reduce emissions.
• Canadian Pacific is increasing the number of hydrogen locomotive conversions in its fleet from one to
three and adding hydrogen production and fueling facilities. The program is planned to create a global
center of excellence in hydrogen and freight rail systems in Canada.
The demonstration and conversion listed above along with additional projects are underway are setting the
stage to advance fuel cell locomotive technology worldwide.
3.3 Marine Propulsion and Auxiliary Power
3.3.1 Diesel-Fueled
For purposes of this report and the application of fuel cell power systems, maritime applications refer to
harbor craft such as tugs, ferries, work boats and waste trawlers. Fuel cell power systems are candidate
replacements for conventional diesel engines, diesel engine hybrid systems and auxiliary engine systems.
Table 19 lists the 2014 harbor craft inventory information for the Port of Long Beach and provides a reasonable
summary of the types of diesel-fueled harbor craft in service at U.S. ports (Starcrest Consulting Group, LLC,
2015). The table provides data for both main propulsion and auxiliary power engines.
*ERG
3-9
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Table 11. Port of Long Beach 2014 Harbor Craft Inventory Information
Harbor
Craft
Type
Number
of
Vessels
Engine
Type
Number
of
Engines
Model Year
Horsepower
Annual Hours of
Operation
Min
Max
Avg
Min
Max
Avg
Min
Max
Avg
Assist
Tugboat
14
Main
29
1980
2012
2003
600
2,540
1,908
65
2,197
1,462
Aux
29
1980
2013
2007
67
425
181
9
4,068
1,732
Excursion
8
Main
14
1982
2013
2006
70
650
393
100
2,100
878
Aux
6
2009
2012
2010
50
90
77
50
2,000
1,317
Ferry
12
Main
26
1998
2013
2008
180
2,300
1,718
1,200
1,500
1,258
Aux
18
2003
2013
2009
18
120
67
750
1,500
833
Harbor
Tugboat
12
Main
25
2003
2012
2009
250
1,500
711
85
1,088
389
Aux
21
2005
2012
2009
22
107
48
70
946
302
Work
Boat
4
Main
7
2005
2013
2010
210
675
487
62
1,909
1,237
Aux
8
1968
2013
1998
27
101
57
548
2,079
1,135
3.3.2 Fuel Cell-Powered
Although less common than other applications, fuel cells are being investigated in maritime applications as
possible alternatives to traditional marine diesel and fuel oil power plants across the world. In the U.S., SNL
recently completed a feasibility study of fuel cell propulsion power applicability in maritime vessels (Minnehan
& Pratt, 2017). The study examined 14 different vessel types and routes, from small passenger and fishing
boats on short trips to large ocean-going cargo ships. Study results indicated that hydrogen fuel cells are viable
in all but one of the 14 vessel applications. Liquid hydrogen, rather than high pressure gaseous hydrogen, was
the preferred method of onboard storage. In general, SNL found that the limiting factor for many of the
maritime vessel applications was not power capacity or onboard energy storage, but rather available volume
onboard the vessels for accommodating both the fuel cell and hydrogen storage system(s).
Under funding by the U.S. Maritime Administration and in collaboration with the Port of San Francisco, SNL
conducted a feasibility and design study of a high-speed passenger ferry powered by fuel cells (Pratt &
Klebanoff, 2016). The conceptual ferry, commonly called the "San Francisco Bay Renewable Energy Electric
Vessel with Zero Emissions" (SF-BREEZE), would be capable of carrying 150 passengers and traveling two, 50-
mile roundtrips at a top speed of 35 knots before requiring refueling. The vessel would incorporate 41120-kW
PEM fuel cell racks, 1,200 kg (4,500 gallons) of liquid hydrogen. The study results found the SF-BREEZE concept
technically and economically feasible in San Francisco Bay. An additional well-to-"waves" analysis of the
concept determined that, in conjunction with liquid hydrogen produced from renewable energy, fuel cell
vessel emission reductions equated to 99.1 percent NOx emissions, 99.2 percent hydrocarbons, and 98.6
percent particulate matter (PMio) relative to a comparable diesel-fueled, Tier 4 compliant engine-powered
vessel (Klebanoff, et al., 2017). Fuel cell vessel cost was estimated at 1.5-3.5 times higher than a comparable
diesel vessel. O&M costs were 2-8 times higher due to PEMFC costs. However, with the zero emissions and
renewable hydrogen benefits associated with the SF-BREEZE, SNL estimated that the 30-year lifetime societal
benefits would range between $2.6-11 million. Although the study found that the SF-BREEZE concept could
viably meet the ferry needs of the San Francisco Bay Area at high speeds, SNL also recognized that its
specifications (most notably the 35-knot top speed) were unique relative to more common ferry applications
in the U.S. For example, the average ferry speed across all applications is 6-15 knots. Thus, for most common
ferry applications, fuel cell and fuel storage requirements could be decreased, resulting in lower overall vessel
costs, especially in comparison with comparable diesel vessels.
Following the completion of the Sandia National Laboratories' report "Feasibility of the SF-BREEZE: a Zero-
Emission, Hydrogen Fuel Cell, High-Speed Passenger Ferry", technology partners and the US Coast Guard
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began working on permitting the hydrogen fuel systems for maritime vessels. In 2022, All American Marine,
Inc. (AAM) and the vessel owner SWITCH Maritime (SWITCH) began conducting sea trials of the vessel "Sea
Change", a 70-foot, 75-passenger zero-emissions, hydrogen fuel cell-powered, electric-drive ferry that will
operate in the California Bay Area (All American Marine, 2022).
International research and development of fuel cell propulsion systems for marine applications has progressed
steadily, with particular focus on harbor craft applications with lower power and shorter-range requirements
(U.S. Department of Energy-AFDC, 2019). Some examples of fuel cell marine vessel demonstration projects
undertaken in the last three years or planned for the near-term are provided in Table 20 (Tronstad, 2017)
(Blenkey, 2019). The German National Innovation Program (NIP) has funded the development of several
E4Ships marine vessel fuel cell projects. Two of the projects concentrate on fuel cells for onboard auxiliary
power, while the other two projects incorporate fuel cell propulsion power systems. These projects use a
range of fuel cell types and fuels. Vessel types include passenger ferries, inland cruise boats and push/tow
boats. In a separate FLAGSHIPS project in France, a new build fuel cell push boat is in the development stage,
with projected delivery in 2021. In each of these push/towboat applications, fuel cells are part of hybrid
platforms that also incorporate substantial battery packs for meeting overall power and energy demands.
Table 20. Examples of Recent International Marine Vessel Fuel Cell Projects
Euro Project
Vessel Type
System
Fuel Cell Application
Timeframe
Fuel
E4Ships - Pa-X-ell
Passenger Cruise
Two 30 kW
HTPEMFC
Onboard Auxiliary Power
Phase 2:
2017-2022
Methanol
E4Ships-SchlBZ
Passenger/Goods
100-kW SOFC
Onboard Auxiliary Power
Phase 2:
2017-2022
Low Sulfur
Diesel
E4Ships -
RiverCell
Inland River Cruise
250-kW
HTPEMFC
Baseload Hybrid
Propulsion and Auxiliary
Power
Phase 2:
2017-2022
Methanol
E4Ships- Elektra
Inland
Push/towboat
Two 100-kW
HTPEMFC
Baseload Hybrid
Propulsion and Auxiliary
Power
Phase 2:
2017-2024
Gaseous
Hydrogen
FLAGSHIPS-CFT
Inland
Push/towboat
400-kW PEMFC
Hybrid Propulsion and
Auxiliary Power
2021
Gaseous
Hydrogen
3.4 Stationary Power
3.4.1 Diesel-Fueled
Documented inventory and operational data for current diesel genset power applications at port locations
were not available in the literature. However, a multitude of diesel-fueled stationary power applications at
ports provide both primary and back-up power supplies for buildings, processes, and critical infrastructure. The
power output of these applications ranges from a few kW to over one MW.
3.4.2 Fuel Cell-Powered
Various opportunities exist to displace diesel-fueled power generation applications with fuel cell systems at
port locations. Fuel cell types for such applications include PEMFCs, PAFCs, MCFCs and SOFCs. Fuel cell power
applications at ports may include shore-side power for ocean going vessels, overhead electric cranes, office
buildings, warehouses, control systems and security operations. Fuel cells provide high quality and reliable
electrical power, consequently improving site resiliency and power redundancy. Fuel cells generate higher
electrical efficiencies and produce less noise as compared to diesel gensets.
For example, two stationary power fuel cells were installed at the U.S. Navy Submarine Base in Groton,
Connecticut. The Fuel Cell Energy SureSource 4000™ MCFC power plants were developed to provide long-term
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power supply, with a total system capacity of 7.4 MW. The fuel cell park met a majority of the average daily
energy needs of Submarine Base New London, and any excess power was exported to the Groton Utilities
distribution system.
In another example of a fuel cell power system, SNL led the development and demonstration of a
containerized fuel cell generator (Pratt & Chan, Maritime Fuel Cell Generator Project, 2017). Project partner
Hydrogenics designed and built this first-of-its-kind generator to meet the technical specifications determined
jointly by the project team. It consisted of a 20-foot ISO standard "hicube" shipping container with a 100-kW
PEMFC rack, a power inverter, ultracapacitors for short term transient loading, a cooling system, hydrogen
storage, a system controller, and data acquisition equipment. The system's Type III hydrogen tanks held 72 kg
of hydrogen at 350 bar and had a rated power of 100 kW, 240 VAC 3-phase. This particular generator was
designed to provide power for up to 10 refrigerated containers at a time. The system was assumed to have a
10-year lifetime, with one fuel cell replacement over its lifetime.
Following a six-month field trial at the Foss Maritime facility, the fuel cell generator was placed in service to
power refrigerated containers pier side between August 2015 and June 2016. The generator was used on 52
different days for a total of 278 hours. The generator achieved a 5-minute continuous peak power of 91.3 kW
(gross) and averaged 29.4 kW (gross) during this period, for a total energy generation output of 7,285 kWh.
The system's net energy efficiency ranged from 36-54 percent over a load range of 16-62 percent. The fuel cell
generator displaced 865 gallons of diesel fuel and more than 16 metric tons (MT) of CO2 emissions as
compared to an existing 350-kW Tier 3 diesel generator. Generator operators reported inconsistent start-up as
the primary issue, which was attributed to a communication problem between the overall system controller,
inverter, and fuel cell rack. In this case, the start-up issue related to control system issues and not the PEMFC
itself. (PEMFC start-up is typically fast, as opposed to high temperature MCFC or SOFC, which require much
longer start-up durations to reach operational temperatures). The generator did not experience any safety-
related issues and did not exhibit any signs of deterioration.
SNL's cost analysis found that the capital cost of the generator system was likely three-times higherthan a
comparable diesel-fueled generator due to balance of plant (BOP) costs, even with fuel cell system costs
achieving DOE cost targets. Fuel costs are expected to make up a large portion of operating expenses in the
near-term.
While liquid hydrogen storage is certainly a viable option for supporting stationary power fuel cell applications,
high pressure gaseous hydrogen storage is generally a more cost-effective option. In many stationary power
applications, available space for locating hydrogen storage is less of a concern and so lower cost higher
pressure storage would be selected. For facilities with higher hydrogen fuel volume requirements, and/or
multiple fuel cell applications (including stationary power) supported by central storage, liquid hydrogen
storage could be a more cost-effective option. Appendix A provides additional information on port-related fuel
cell stationary power demonstration programs.
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4. Fuel Cell Fuel Supply Infrastructure
While hydrogen is considered the predominant fuel for future fuel cell applications, other fuel sources offer
potential as both hydrogen carriers and as direct fuels in fuel cell technologies. This section focuses primarily
on hydrogen supply infrastructure but also discusses current non-hydrogen fuel supplies and their possible
utility to future fuel cell demand.
4.1 Hydrogen Production, Storage, and Transport Technologies
Current annual hydrogen production in the U.S. is about 10 million metric tons. The primary markets for
hydrogen are the petroleum refining industry (68 percent) and fertilizer production (about 21 percent)
industry. Refinery-related production of hydrogen is the most common today, followed by merchant and then
captive production (DOE Hydrogen and Fuel Cell Program, 2018). In the U.S., about 1,600 miles of hydrogen
pipeline are laid out to support the local and regional delivery of hydrogen.
While the hydrogen market is positioned to support the petroleum refining and fertilizer industries in the U.S.,
the hydrogen fuel cell market is still in its infancy. At present, end-users can secure a local supply of hydrogen
from equipment manufacturers. Fuel cell equipment manufacturers work directly with hydrogen suppliers, in
many cases offering turn-key solutions for delivering and dispensing hydrogen onsite to support their
customers. Industrial gas supply companies such as Air Products, Praxair, and Air Liquide USA are the primary
suppliers of hydrogen.
The expansion of existing production, storage and distribution infrastructure is necessary to meet future
market hydrogen demand for fuel cell equipment and other end sectors. The expansion of hydrogen
infrastructure will likely begin near existing hydrogen production centers. The sections below discuss the
various approaches to hydrogen production, storage, transport, and dispensing, all of which can be adopted in
the near- and long-terms to meet future fuel demands for ports and other end users.
4.1.1 Hydrogen Production Technologies
Multiple existing or developing hydrogen production technologies can be employed to meet hydrogen fuel
demand. Several of these technologies are discussed below.
4.1.1.1 Steam Methane Reformation
About 95 percent of hydrogen today is produced through a thermochemical process known as SMR. SMR has
been widely used in the chemical and refining industries, with current large-scale hydrogen plant capacities
over 500,000 kg/day and conversion efficiencies around 72 percent (Ogden, 2018). The SMR process typically
utilizes natural gas as the feedstock, although other hydrocarbon-based fuels can also be used. Natural gas and
natural gas liquid feedstocks are derived from gas wellheads, gas production plants and refineries. The existing
natural gas pipeline transmission and distribution system is expansive, providing fuel access to the majority of
the U.S. According to the EIA, the system is comprised of about three million miles of pipeline, linking
production and storage facilities with end use markets across the nation (U.S. EIA, 2019). In 2017, over 25
trillion cubic feet of natural gas was delivered through the U.S. pipeline system (5). Pipeline natural gas varies
considerably across the country but is primarily a mixture of methane (about 90 percent) and small amounts of
light hydrocarbons (e.g., ethane and propane), nitrogen, oxygen, and C02.
Since natural gas contains a small amount of sulfur (and pipeline natural gas contains sulfur mercaptans for
odor), the fuel may first undergo a desulfurization process that uses activated carbon and/or zinc oxide to
prevent poisoning of the SMR catalysts. The natural gas is then reacted with high temperature steam over a
nickel-based catalyst to produce synthesis gas containing hydrogen, CO, and a small amount of C02. The water-
gas shift reaction is then applied, in which the CO and steam are reacted to produce C02 and additional
hydrogen. Lastly, pressure swing adsorption removes C02 and impurities, resulting in highly pure hydrogen gas.
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SMR is energy efficient and cost-effective for large-scale hydrogen production. One drawback of SMR is that
C02 emissions are produced as a byproduct. However, C02 emissions can be reduced by 80-90 percent through
the use of carbon capture and sequestration (CCS) technologies. CCS typically adds 10-20 percent to a large
SMR plant's capital costs, 10-30 percent to the levelized cost of hydrogen production, with a 1-2 percent
decrease in overall plant efficiency (Ogden, 2018).
SMR processes are also available for onsite, small plant applications. While more costly to operate per unit
volume of hydrogen production, these small-scale units have been implemented to directly support fuel cell
power systems as well as hydrogen refueling stations (Ogden, 2018). Of course, the use of small-scale SMR
plants onsite also reduces hydrogen transport costs, as the existing natural gas distribution system can deliver
natural gas to the site for hydrogen production. In addition to onsite SMR hydrogen production for hydrogen-
fueled fuel cells, recent research on new anode catalyst materials for solid oxide fuel cells has increased the
potential for onsite direct fueling of fuel cells (that is, internal reforming) with natural gas.
4.1.1.2 Partial Oxida tion
Another existing process, partial oxidation of natural gas (methane), involves the reaction of natural gas with
less than stoichiometric levels of oxygen (usually from air), resulting in a synthesis gas stream of hydrogen, CO,
nitrogen (if air is used as a reactant rather than oxygen), and a small amount of C02 and other trace products.
Using the water-gas shift reaction then converts the CO to C02 and produces additional hydrogen. The partial
oxidation process for natural gas tends to be faster but has a lower hydrogen conversion efficiency than SMR.
4.1.1.3 Gasification
Gasification processes have been developed for hydrogen production from both coal and biomass feedstocks.
Gasification involves the reaction of coal with oxygen and steam at high pressures and temperatures. This
reaction produces synthesis gas made up of CO, hydrogen, and impurities. The impurities are removed from
the synthesis gas, which then undergoes the water-gas shift reaction to produce C02 and additional hydrogen.
One disadvantage of coal gasification processes is that coal has a high carbon density, resulting in high C02
emissions. Thus, the C02 byproduct from the process must generally be collected using CCS technology, which
decreases overall system cost efficiency.
Biomass gasification involves the high temperature reaction of biomass with oxygen and/or steam to produce
CO, hydrogen, and C02. The CO is then processed using the water-gas shift reaction to produce C02 and
additional hydrogen. The C02 from the process is collected and processed using CCS technology. Since biomass
also consumes C02 in its growth cycle, overall net C02 emissions are much lower as compared to the coal
feedstock gasification process. When coupled with CCS technology, biomass gasification can potentially
achieve near-zero net C02 emissions.
4.1.1.4 Electrolysis
Electrolysis is the process of splitting water into hydrogen and oxygen when applying an electric power source.
Electrolyzers are devices that employ electrolysis for producing hydrogen gas. Electrolyzers are similar to fuel
cells in many ways but are designed to receive electricity rather than produce it. Likewise, electrolyzers
produce hydrogen rather than consume it. In its simplest form, electrolyzers are comprised of an anode,
cathode, and electrolyte. Like fuel cells, electrolyzer cells are categorized by their electrolyte type and can be
combined to form a cell stack. In addition to the cell stack, an electrolyzer system typically includes a cooling
system, an upfront water treatment system to purify the water supply and a post-processing phase to meet
hydrogen purity requirements. For power supplied by the electricity grid, the system also includes an inverter
for converting alternating current (AC) to DC power for use in the electrolysis process.
As illustrated in Table 21, modern commercial electrolyzers utilize polymer electrolyte membrane (PEM) and
alkaline electrolytes, while solid oxide versions remain in the developmental phase (U.S. DOE Hydrogen and
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Fuel Cell Technologies Office, 2020). PEM electrolyzers operate at low temperatures (70-90°C) using a solid
polymer electrolyte, enabling hydrogen ions to pass through the membrane to combine with electrons at the
cathode and form hydrogen gas. Alkaline electrolyzers operating at low temperatures (100-150°C) create and
transfer hydroxide ions through the electrolyte (alkaline solution of sodium or potassium hydroxide) to
generate hydrogen at the cathode. Current solid oxide electrolyzers, which operate at much high temperatures
(700-800°C), utilize solid ceramic oxygen ion-conducting electrolytes. At the cathode, water combines with
electrons to form hydrogen and negatively charged oxygen ions. The oxygen ions then pass through the
electrolyte to the anode to form oxygen and electrons for the external circuit. Another promising solid oxide
electrolysis concept involves proton-conducting electrolytes. In this concept, ion transfer through the
electrolyte passes from anode to cathode. The lower operating temperatures of the proton-conducting solid
oxide electrolytes facilitates thermal management and lower cost stack and BOP materials use. Additional
research is needed to improve durability and reliability and to optimize electrolyte and electrode material
selections.
Table 12. Comparison of Electrolyzer Types
Parameter
Electrolyzer Type
PEM
Alkaline
Solid Oxide
Advantages
• Commercial
• Low operating temperatures
• High power densities
• Low start-up time
• Low electricity consumption
• Commercial
• Low operating temperatures
• Low start-uptime
• Low system costs ($/kW)
• Low electricity consumption
• High median system lifetime
• High system efficiency
• High current densities
• Low electricity
consumption
Remaining
Challenges
• Higher system costs ($/kW)
• Low current densities
• Low power densities
• Pre-commercial
• High operating
temperatures
• Durability
• High start-up time
Commercial electrolyzers available today consist of smaller plants (up to 1,500 kg/day capacity) that are best
suited for onsite hydrogen production. Electrolysis generally relies on power generated from the electrical grid
(U.S. DOE Hydrogen and Fuel Cell Technologies Office, 2020). As such, electricity generation sources of
electricity an vary significantly, affecting the economic viability of the electrolyzer and increasing its overall net
C02 and other pollutant emissions. For this reason, researchers are investigating the use of onsite renewable
energy sources (e.g., wind and solar) to power electrolyzers. There is emerging consensus on the role of
renewable energy sources in improving electrolyzer plant capacities and, in turn, making electrolyzer products
more competitive in the marketplace. Further, the intermittent nature of renewable energy offers
opportunities to synergize with electrolyzer hydrogen production to expand the available energy from both.
That is, electrolyzers can use excess electricity generation from renewable sources to produce hydrogen for
storage which can then be used later as an onsite or transportable energy source.
4.1.1.5 Biomass-to-Liquids (BTL)
Liquid fuels derived from biomass, such as ethanol or bio-oils, created from thermochemical processes could
prove viable for end-use processing into hydrogen. As liquid fuels, BTL fuels have much higher energy densities
than pure hydrogen. BTL fuels can be produced in large quantities at centralized plants and can then be
transported much more cost-effectively relative to pure hydrogen. The net C02 emission footprints of BTL fuels
are lower than other hydrogen carriers, especially when accounting for efficiencies in liquid fuel transportation
and storage. Upon reaching end-use sites, BTL fuels can be stored in liquid tanks and then reformed to
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hydrogen product (using processes similar to SMR for natural gas). BTL fuels are, however, more chemically
complex than typical natural gas fuels and, consequently, different catalyst packages are required.
4.1.1.6 Microbial Biomass Conversion
Microbial biomass conversion is a fermentation process in which biomass feedstock is broken down by
selective microbes to ultimately produce hydrogen gas. The process is referred to as "dark fermentation" since
it does not require light or photosynthetic activity. Depending on the biomass and types of microbes, the
fermentation process uses a variety of enzymes to facilitate hydrogen production. Reactor temperature
control is key to maintaining microbe life and process activity. Microbial biomass conversion systems are still in
the research phase, but plant capacities are projected to scale up in the mid-term. However, increased
hydrogen yields, as well as production rates, are essential to commercializing the technology.
4.1.1.7 Ammonia Cracking
As a carbon-free hydrogen carrier, ammonia (NH3) is a potential future fuel source for fuel cells. Ammonia is
the second most-produced chemical globally at over 100 million tons per year for a variety of industrial sector
markets (Lan, 2014). Ammonia is an attractive potential fuel source for fuel cells because existing
infrastructure can support storage and transportation. The predominant method of ammonia production is the
Haber-Bosch process, in which nitrogen and hydrogen are heated to 400-650°C using an iron catalyst at high
pressure. Ammonia production processes typically receive hydrogen feedstock from natural gas SMR. Using
these combined methods, the production of ammonia is generally energy and cost intensive and produces high
C02 emissions. Alternatively, ammonia produced using renewable energy coupled with water electrolysis
would make ammonia a more sustainable and cost-effective hydrogen source.
Hydrogen production from ammonia can be realized through ammonia cracking processes, which use
temperatures above 400°C and catalysts. Ammonia cracking technology can be applied in large-scale
centralized hydrogen plants or deployed at small commercial plants to produce hydrogen directly onsite for
fuel cell use. The latter affords the considerable benefits (energy density and costs) of ammonia as a hydrogen
carrier in delivering hydrogen to the fuel cell end use compared with the distribution and delivery of
compressed or cryogenic hydrogen. Furthermore, at smaller scales, ammonia cracking is more cost
competitive than steam methane reforming (Cheddie, 2012).
4.1.2 Hydrogen Production Process Feedstock, Water Requirements, and Emissions
Table 22 provides a summary of feedstock, energy use and water consumption requirements for various
hydrogen production processes (Mehmeti, 2018). Several of the hydrogen production processes have
significant water consumption requirements, especially the biomass-related processes. These water
requirements can impact hydrogen production plant location in the country, considering competing end-use
markets for water supplies for thermoelectric power, irrigation, public, industrial, domestic, livestock,
aquaculture, and mining. In terms of electricity consumption, the two electrolytic processes (E-PEM and E-
SOEC) far exceed the electricity use of the other hydrogen production processes.
Table 13. Summary of Hydrogen Production Process Characteristics
Type/Conversion
Pathway
Thermo-Chemical
Electrolysis
Steam
Methane
Reforming
(SMR)
Coal
Gasification
(CG)
Biomass
Gasification
(BMG)
Biomass
Reformation
(BDL-E)
Proton
Exchange
Membrane
(E-PEM)
Solid Oxide
Electrolysis
(E-SOEC)
Feedstock
Natural Gas
Coal
Corn Stover
Ethanol
Electricity
Electricity
Natural Gas (MJ/kg
Hz)
165
—
6.228
—
—
50.76
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Type/Conversion
Pathway
Thermo-Chemical
Electrolysis
Steam
Methane
Reforming
(SMR)
Coal
Gasification
(CG)
Biomass
Gasification
(BMG)
Biomass
Reformation
(BDL-E)
Proton
Exchange
Membrane
(E-PEM)
Solid Oxide
Electrolysis
(E-SOEC)
Coal (kg/kg H2)
—
7.8
—
—
—
—
Biomass (kg/kg H2)
—
—
13.5
6.54
—
—
Electricity (kWh/kg
Hz)
1.11
1.72
0.98
0.49
54.6
36.14
Water (kg/kg H2)
21.869
2.91
305.5
30.96
18.04
9.1
Table 23 lists emission values per kg hydrogen for the same hydrogen processes. Not surprisingly, heavy
reliance on coal in the coal gasification (CG) process, and grid electricity in the case of the two electrolytic
processes, results in considerably higher C02 equivalent emissions in comparison to the other production
processes. (Although the grid electricity generation mix was not specified in the study, the same electricity
generation mix was applied across each hydrogen production process (Mehmeti, 2018)). When using
renewable energy-generated electricity for the same two electrolytic processes (E-PEM-R and E-SOEC-R), these
processes produce some of the lowest C02 equivalent emissions. Between the two biomass-related hydrogen
production processes (BMG and BDL-E), biomass gasification produces the lowest C02 equivalent emissions.
Similarly, the coal gasification and two grid-based electrolysis processes produced the highest NOx and PM
emissions. The biomass reformation process (BDL-E) produced higher NOx and PM emissions than the biomass
gasification process (BMG). Both renewable energy-based electrolysis processes produce some of the lowest
concentrations of NOx and PM emissions. In terms of S02, the worst performing processes were coal
gasification, biomass reformation and grid-based electrolysis. Renewable energy-based electrolysis generated
notably low levels of S02 emissions. Overall, renewable energy-based electrolysis and biomass gasification
produced the lowest emissions, while coal gasification and grid-based electrolysis accounted for the highest
emission concentrations.
Table 23. Midlife Lifecycle Emission Values (per kg hydrogen) of Hydrogen Production Processes
Unit
SMR
CG
BMG
BDL-E
(Corn)
E-PEM
E-PEM-R
E-SOEC
E-SOEC-R
Kg C02eq
12.13
24.2
2.67
9.193
29.54
2.21
23.32
5.10
Kg NOx-eq
0.0089
0.055
0.00382
0.037
0.0492
0.0041
0.0353
0.0052
Kg PM2 5-eq
0.002
0.039
0.00284
0.007
0.0337
0.0041
0.0222
0.0025
Kg S02-eq
0.0087
0.139
0.03706
0.124
0.1087
0.0118
0.0724
0.0078
4.1.3 Hydrogen Storage and Transport Technologies
There is a variety of fuel transport and storage methods that can be employed for hydrogen production. For
example, fuel can be transported/stored as pressurized gas or liquefied product, as illustrated in Figure 12.
4.1.3.1 Bulk Storage
Prior to transport to regional or local end-use markets, hydrogen is typically stored in bulk storage tanks at
production facilities or terminals. Hydrogen can be stored in bulk as a gaseous product under pressure or as a
cryogenic liquid.
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High Pressure Hydrogen Gas
High-pressure hydrogen storage is typically accomplished using large cylindrical steel storage tanks. The tanks
can be manifolded together for loading and dispensing. The tanks are typically composed of all-steel or steel
fiber-wrapped steel. To increase the energy density of the stored hydrogen, hydrogen pressures typically range
between 2,500-5,000 psi. Compressors are used to pressurize hydrogen process feeds as necessary in
preparation for bulk storage.
Geologic storage is an alternative method of bulk hydrogen storage. Salt caverns, aquifers and hard rock
caverns are the three most commonly used geological bulk storage options today. Although geological bulk
storage provides opportunities for storing large volumes of hydrogen, additional research is necessary to
determine the efficacy of geological storage in relation to hydrogen product and fuel cells.
Cryogenic Hydrogen Liquid
Cryogenic tanks can also be used to store bulk quantities of hydrogen. Storing hydrogen as a cryogenic liquid
significantly increases its energy density, which makes it more favorable to pressurized storage for large
volumes (the energy density of liquid hydrogen is about twice that of high-pressure hydrogen). To liquefy
hydrogen, the hydrogen must be cooled below its boiling point (-253°C). The liquid hydrogen product is then
stored at low pressures in vacuum-insulated tanks and an outer carbon steel shell. To prevent the tank from
over-pressurizing, the tanks must be periodically vented to release "boil off" hydrogen vapor. Bulk tanks are
typically cylindrical; however, spherical tanks are also in use today. Tank sizes typically range from 1,500-
25,000 gallons.
The liquefaction process is very energy intensive and costly. Larger volume liquefaction reduces costs
compared to small-scale liquefaction so onsite processes are not very common.
4.1.3.2 Pipeline Transport
Over 1,600 miles of hydrogen pipeline are in place in the U.S. (U.S. Drive Partnership, November 2017). The
majority of this existing pipeline is located in California, Louisiana, and Texas for supporting large-scale
hydrogen production for the petroleum refining industry. The individual pipelines along this network range
from 1-597 miles.
Figure 3. Hydrogen Transport and Distribution Modes
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For a mature hydrogen fuel market, pipelines would be one of the most cost-effective means of transporting
large quantities of hydrogen from centralized hydrogen production plants to regional and local hydrogen
terminals, where it could then be distributed via smaller pipelines, by rail, or by tank truck. However, since
hydrogen gas has such low energy density, higher pipeline pressures would be required to achieve energy
flows comparable to natural gas pipelines. Multi-stage, positive displacement compressors are needed to
achieve pressures typically between 1,000-1,500 psi, which have higher capital and maintenance costs than
lower pressure compressors. These compressors are specially equipped for hydrogen use, including tight
tolerances and seals. Hydrogen compressor station spacing along pipelines would likely be similar to that of
comparable natural gas pipelines at 40-100 miles.
Typically, pipelines are made of carbon steel. Hydrogen has shown a propensity to embrittle steel and welds
over time, which can influence pipeline life. Previous research has characterized the extent of these effects to
inform codes and standards that guide pipeline design, and to enable the use of novel materials in pipeline
service. One such material is fiber reinforced polymer (FRP). FRP is widely used in upstream oil and gas
operations and was recently accepted into the ASME B31.12 Code for Hydrogen Piping and Pipelines for high-
pressure hydrogen service. FRP is about 20 percent cheaper to install than steel because FRP can be extruded
in longer lengths, thus requiring less welding for an equivalent length installed (U.S. Drive Partnership,
November 2017).
Since installing new hydrogen pipeline is capital intensive, another concept being researched is the
modification of the existing natural gas pipeline to transport pure hydrogen or a blend of natural gas and up to
15 percent hydrogen by volume. In the latter case the hydrogen could then be separated from the natural gas
downstream at the terminal or end-use location using separation and purification technologies. Necessary
pipeline modification in both cases are under research.
4.1.3.3 Truck/Rail/Barge/Ship/Pipeline Transport to End Use
Truck transport is typically employed to distribute hydrogen from production sites or storage terminals at the
regional and local level. Hydrogen can be transported in high pressure or liquid form via truck. Trailer-mounted
storage cylinders called tube trailers are used for high-pressure hydrogen. The cylinders are typically
comprised of steel, with high-pressure hydrogen stored between 2,500-7,250 psi (U.S. Drive Partnership,
November 2017). Steel, fiber-wrapped cylinders for lower weight and higher pressures (and thus greater
storage energy density) are also being developed. Although less common, gaseous hydrogen can also be
transported via local or regional pipeline to the end-use site. In the case of truck or pipeline transport, the
pressurized hydrogen gas is transferred to onsite storage cylinders for serving the onsite fuel cells. Another
option is for the tube trailers, either trailer-fixed or skid-mounted on the trailer, to be dropped on the site for
temporary storage and then swapped with a new load when the hydrogen gas is depleted.
Liquid hydrogen tank trailers are also used for truck transport. The tank trailers are vacuum-insulated tanks
with inner stainless steel and outer carbon steel, capable of holding about 18,000 gallons of liquid hydrogen.
Since tank trailers can hold a greater mass of hydrogen than high-pressure tube trailers, tank trailer transport
is typically used for longer distance deliveries. Although less common, liquid hydrogen can also be transported
long distances via rail car, ship, and barge.
4.1.3.4 Hydrogen Delivery to Fuel Cell Equipment
As explained above, pure hydrogen can be delivered to end-use sites in either gaseous or liquid form. In both
cases, however, final delivery of hydrogen to the fuel cell application is in gaseous form.
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Gaseous Hydrogen Delivery
For stationary power fuel cell applications, onsite storage cylinders are typically at sufficient pressure to
directly supply the equipment. The stored gas may need to be dropped in pressure through a series of
pressure regulators to match necessary hydrogen supply pressures for the stationary fuel cells.
In the case of mobile fuel cell equipment, the stored hydrogen gas would typically be boosted in pressure to
increase the stored hydrogen energy density onboard the mobile equipment application. Figure 13 illustrates a
typical high-pressure gaseous delivery station for mobile equipment applications. The gas delivery station
includes a hydrogen storage, compressor(s), a cascade storage cylinder system and a high-pressure dispenser.
The hydrogen compressor pressurizes hydrogen gas to higher pressures in the cascade system. Compressors
are typically non-lubricated to avoid possible contamination of the hydrogen gas and runoff of electric grid
power. The cascade storage is pressurized by the compressor to higher pressures than will eventually be
delivered to the equipment. Pressurized gas is delivered to the equipment via an electronic dispenser. The
dispenser controls gas delivery from the cascade system, preferentially accessing cylinders at different
pressures for faster dispensing for individual equipment storage pressure limitations and current pressure
status. Typically, most dispensers are configured to provide hydrogen gas at either 350 bar (5,000 psi) or 700
bar (10,000 psi) pressures to match equipment hydrogen storage system pressures. In some systems, the
compressor will be used to supplement the cascade storage in meeting the highest pressures the dispenser
Compressor
Heat
Exchanger Dispenser
H
H2 Site Storage
Figure 4. High-Pressure Gaseous Hydrogen Delivery System
demands. Other mobile applications may operate at lower pressures and thus appropriate dispensers would
need to be acquired for this equipment. Since heat is generated in the gas compression process, hydrogen
stations often incorporate heat exchangers to reduce the temperature of the gas entering the equipment
storage tank, as higher gas temperatures impact the amount of gas that can be stored in the tank at a given
pressure.
Liquid Hydrogen Delivery
For large-scale production of liquid hydrogen, liquefaction is performed upstream and then delivered to the
end-use site. The liquid hydrogen is pumped into onsite vacuum-insulated tanks for storage until ready for
delivery to onsite fuel cell equipment. Liquid hydrogen can also be delivered in vacuum-insulated tanks on
trailers or skids, which can then be connected to the fuel delivery system and replaced when empty.
Gaseous
1
h2
Transport
to Site
u
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Figure 14 shows a typical liquid hydrogen delivery system for mobile fuel cell applications. The system includes
onsite cryogenic storage, a high-pressure cryogenic pump, vaporizer, storage cascade system and dispenser
system. The cryogenic pump increases the liquid hydrogen pressure before the hydrogen is directed to the
vaporizer. The vaporizer acts as a heat exchanger, in which ambient air or warm water converts the liquid
hydrogen to gaseous hydrogen at pressure. The vaporizer outlet produces high-pressure hydrogen gas that can
be fed into the cascade storage system, or, if necessary, be boosted in pressure again with a hydrogen
compressor before entering the cascade system. The gaseous hydrogen dispenser then controls cascade
storage release in order to achieve necessary fast fill-up times at the fuel cell vehicle's required hydrogen gas
storage pressures.
Cryogenic Pump
Liquefied
1
h2
Transport
to Site
1
Cascade
Storage
Dispenser
Cryogenic H2 Site Storage
Figure 5. Liquid Hydrogen Delivery System
For stationary fuel cell applications, a dedicated vaporizer along with a pressure regulation system would be
necessary to provide inlet hydrogen gas matching the pressure and temperature requirements of the fuel cell.
4.1.3.5 Hydrogen Fuel Safety Considerations
All types of fuel energy carriers have inherent safety concerns. Since many of the fuel properties of hydrogen
are significantly different than conventional diesel, fuel safety considerations related to the storage, transport
and dispensing of the fuel vary according to fuel type. These differences can be addressed through preparation
and proper facility design. In generally considering fuel types and safety compared to diesel fuel, hydrogen gas
is more like compressed natural gas (CNG) and cryogenic hydrogen is more like liquid propane gas. Awareness
among field personnel is critical to safe operations and emergency response plans, and training programs
should be updated when introducing hydrogen fuel cell equipment. Ongoing research and development on
hydrogen and fuel cell technologies is informing co-des and standards associated with hydrogen use.
Diesel is generally considered a very stable and safe fuel at typical ambient conditions due to its low volatility
(low vapor pressures) and relatively high flash point14 (above 140°F). Diesel fuel also has a relatively narrow
flammability range of about 1-10 volume percent in air. When ignited, diesel fuel burns with a visible flame. In
comparison, hydrogen exists in gaseous form at typical ambient conditions, enabling hydrogen to readily mix
with air when released. Hydrogen is colorless and odorless. Unlike natural gas, odorants (sulfur-based
surfactants) are not typically added to hydrogen fuels, because odorants would be detrimental to fuel cell
14 The lowest temperature at which a flammable liquid gives off enough vapors to form an ignitable mixture with air.
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catalyst performance. Lastly, hydrogen has a very broad flammability range at 4-74 percent volume in air.
When ignited, hydrogen burns very fast and with a nearly invisible flame.
Enclosed areas for maintenance and indoor parking for hydrogen fuel cell equipment, specifically in relation to
hydrogen fuel releases, also require careful consideration. Many existing enclosed areas and garage/parking
facilities originally designed for diesel equipment are not necessarily equipped to address hydrogen fuel leaks.
As opposed to diesel fuel vapors, which are heavier than air and tend to pool nearthe floor, hydrogen is lighter
than air and will quickly rise to the ceiling. Many existing facilities have ventilation systems near the floor
instead of, near the ceiling. Additional ventilation and/or appropriate lighting and fixtures (i.e. designed to
avoid the possibility of sparks or heat that could ignite gas) may need to be installed before deploying
hydrogen fuel cell equipment in existing facilities. Facilities may also have hydrogen sensors installed at the
highest points of facilities to detect hydrogen leaks before hydrogen concentrations reach the lower
flammable limit. Overall, with necessary precautions and operational changes to accommodate fuel property
differences with hydrogen.
There are also additional considerations for liquid hydrogen fuel storage, transport, and handling. As a
cryogenic liquid maintained at temperatures below hydrogen's boiling point (-423°F), extreme care must be
taken to ensure the safe transfer and dispensing of the fuel. In addition, pumps, hoses, and nozzles exposed to
the fuel should be insulated to prevent severe frost bite for personnel exposed to these components. The
highly insulated liquid hydrogen storage tanks also tend to gain heat slowly over time, resulting in product
"boil-off vapor releases. Boil-off can occur in both stationary storage tanks as well as storage tanks on
vehicles. For this reason, care must be taken to ensure boil-off releases cannot collect in indoor spaces or near
active ignition sources.
4.2 Future Potential Hydrogen Production and Delivery Pathways
In terms of future hydrogen fuel use markets such as marine ports, there are likely to be two primary pathways
describing hydrogen production to end use delivery: Centralized and Distributed Pathways.
With regards to centralized hydrogen pathways, pure hydrogen is produced in large-scale plants (50,000-
500,000 kg/day) for serving regional or even national end-use markets. Centralized production site locations
may be selected for proximity to necessary process feedstocks or existing infrastructure. Once hydrogen is
produced in the centralized plants, the hydrogen is stored and transported to end-use sites via pipeline, truck
or rail for storage and later fuel cell use. New investments in this infrastructure may be necessary to reach
specific markets. Centralized plants will have higher capital costs but will benefit from economies of scale
operations.
Conversely, the distributed hydrogen pathway involves hydrogen production directly at or nearthe end use
site(s). In this case, hydrogen carrier feedstocks such as natural gas or hydrocarbon fuels may be transported
to end-use sites using existing transport infrastructure for these feedstocks, avoiding infrastructure investment
costs. Once at end-use sites, fuel feedstocks can be stored before later processing into hydrogen for fuel cell
applications. As discussed above, a variety of small plant processes (< 1,500 kg/day) are currently available for
producing hydrogen onsite, including natural gas SMR and water electrolysis.
It should be noted that hydrogen production pathways for facilities between 1,500 and 50,000 kg/day may also
evolve for serving intermediate-sized local or regional hydrogen markets (U.S. Drive Partnership, November
2017). These semi-central facilities may directly serve municipal or multiple municipal markets. Over time,
semi-central facilities may evolve and grow to central plants serving larger and geographically wider regions.
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The choice of centralized versus distributed hydrogen production will depend on a number of factors. These
include availability and proximity to feedstocks and process energy sources; size of regional or local markets;
hydrogen production process efficiency costs; and market, environmental and socioeconomic impacts.
Figure 15 presents a summary and timeline for current and projected hydrogen production technologies
according to typical plant capacities and centralized and distributed pathways (DOE Fuel Cell Technologies
Office, 2019). As noted, the near and mid-term hydrogen production candidates for centralized pathways
include natural gas reforming, biomass and coal gasification, and renewable energy supported electrolysis. For
distributed pathways, the most promising technologies include natural gas reforming, electric grid- and solar-
based electrolysis, bio-derived liquids, and microbial biomass conversion.
NEAR-TERM
MID-TERM
LONG-TERM
Natural Gas SM R [500K+ kg/day]
Coal Gasification with CCS [500K+ kg/day]
Biomass Gasification [100K kg/day]
Electrolysis (Wind) [50K kg/dayl
Electrolysis (Solar) [100K kg/day]
Natural
Gas SMR
Solar
Electrolysis
BTL Fuels
Microbial
Biomass
Conversion
Grid
Electrolysis
Figure 6. Current and Future Potential Centralized and Distributed Hydrogen Production Technologies
4.2.1 Centralized Hydrogen Pathways
As noted in Figure 15, there are four primary hydrogen production technologies for centralized pathways, all of
which are likely to be viable in the near to mid-term, including natural gas SMR, coal gasification, biomass
gasification and electrolysis using renewable energy. While each has significant potential for serving future
hydrogen markets, some of these options will likely be more regionally than nationally significant for
centralized hydrogen production.
As discussed previously, natural gas SMR is currently the most prevalent means of producing hydrogen today,
accounting for more than 95 percent of annual U.S. hydrogen production. Future SMR hydrogen production
would benefit from the expansive natural gas pipeline network across the country, allowing for easy access to
natural gas feedstocks for local and regional hydrogen product markets. A recent analysis by the NREL
identified SMR centralized hydrogen production potential in the U.S. using natural gas well data from the EIA
(U.S. DOE Hydrogen and Fuel Cell Technologies Office, 2020). Due to competing markets for natural gas, the
analysis assumed that that only 30 percent of the current natural gas production capacity would be available
for hydrogen production. The results indicated that there is strong potential for centralized natural gas SMR
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hydrogen production in Colorado, Louisiana, New Mexico, Oklahoma, Texas, Utah, and Wyoming. (Of course,
the water use constraints in Colorado and Texas may mitigate some of this potential). These centralized
hydrogen production facilities could generally serve coastal ports on the Western and Southern coasts, as well
as inland ports along the Mississippi River and Great Lakes regions.
The same NREL study analyzed the centralized hydrogen production potential for coal gasification by state
based on EIA coal production data (Milbrandt & Mann, 2009). The analysis indicated that the states of Arizona,
Colorado, Kentucky, New Mexico, Pennsylvania, West Virginia, and Wyoming all offer significant potential for
hydrogen production from coal gasification based on ready access to railroad infrastructure for coal feedstock
transport and finished hydrogen product delivery to regional markets. Centralized hydrogen production
facilities located in these states would support west and east coast port locations, as well as inland ports along
the Mississippi River and the Great Lakes. Existing railroad infrastructure could serve hydrogen product
transport to these markets.
In a separate study, the NREL assessed hydrogen production potential from national biomass gasification and
electrolysis using wind and solar resources (Melaina, Penev, & Heimiller, 2013). The NREL determined that the
highest potential for hydrogen production from biomass resources exists in the Midwestern states of Iowa,
Illinois, Indiana, Nebraska, and Ohio, as well as states along the Mississippi River, including Alabama and
Arkansas. There is additional regional potential in the Northwestern states of Washington and Oregon and in
the Mid-Atlantic and Southeastern states. Biomass feedstock transport for these locations could be achieved
via barge and rail given available waterways and existing rail infrastructure, and gaseous or liquefied hydrogen
product could be transported using the same infrastructure depending on proximity to regional liquefaction
plants.
In the case of hydrogen electrolysis using large-scale wind and solar energy resources, the NREL determined
that solar energy is the predominant resource, with strong potential in the upper and central Midwest
(Indiana, Iowa, Illinois, Minnesota, Ohio, North Dakota and South Dakota); along the Mississippi River
(Alabama, Arkansas and Louisiana); and in many of the southern state regions (Arizona, New Mexico, Florida,
Georgia and Texas). There is significant offshore wind resource potential along the east and west coasts, as
well as along some of the Gulf coast states (Louisiana and Texas). Both solar and wind resources could serve
centralized gaseous and liquefied hydrogen production in many areas of the country, including regions that
could support future hydrogen use at inland and coastal port locations. Table 24 provides an overall summary
of regional centralized hydrogen production potential based on the NREL's analyses.
Table 24. States with High Potential for Centralized Hydrogen Production
State
SMR
Coal Gasification
Biomass
Gasification
Electrolysis with
Solar
Electrolysis with
Wind
Alabama
V
V
Arizona
V
V
Arkansas
V
V
Colorado
V
V
V
Florida
V
Georgia
V
V
Illinois
V
V
Indiana
V
V
Iowa
V
V
V
Kentucky
V
Louisiana
V
V
V
Minnesota
V
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State
SMR
Coal Gasification
Biomass
Gasification
Electrolysis with
Solar
Electrolysis with
Wind
Nebraska
V
V
New Mexico
V
V
V
V
North Dakota
V
V
Ohio
V
V
Oklahoma
V
V
Pennsylvania
V
South Dakota
V
Texas
V
V
V
West Virginia
V
Wyoming
V
V
V
4.2.2 Distributed Hydrogen Pathways
Three viable distributed hydrogen production technologies include onsite natural gas SMR, onsite ethanol
stream reforming (ESR) and onsite electrolysis using the electric grid. In each of these cases, the hydrogen
produced onsite with these small plant processes is pressurized and stored in cylinders until directed to the
gaseous hydrogen delivery system.
The expansive U.S. natural gas pipeline system supports the use of natural gas as a viable hydrogen carrier
source for distributed hydrogen production. Natural gas feedstock can support both onsite SMR to produce
pure hydrogen and direct use as a fuel through internal fuel cell reforming depending on the fuel cell type.
Biomass-derived fuels such as ethanol are also viable hydrogen fuel carrier candidates for distributed hydrogen
production. Biomass-derived ethanol is already mass produced across the country. Most of the ethanol
produced today is derived from corn or sorghum feedstocks, although research continues to explore ethanol
production from cellulosic biomass feedstocks (such as switchgrass). Ethanol is advantageous as a liquid fuel,
as ethanol has a higher energy density than natural gas and can be transported much more efficiently and
cost-effectively. Due to its use in chemical markets and as a gasoline additive, ethanol is already widely
transported in large quantities by barge, rail, and tank truck.
Of course, water is a common feedstock among the distributed hydrogen production processes. Although
water volume requirements are much lower as compared to large-scale centralized production plants, water
usage for small-scale distributed plants could be a concern for ports located in heavy water usage areas such
as Texas and California. Water use is also important considering competitive water-use markets, or if port
locations already operate under water restrictions as a significant local water consumer. While the water
distribution system in the U.S. is ubiquitous and port locations are therefore well-served, water use for small-
scale electrolysis is higher than other distributed production processes. For example, in a recent Argonne
National Laboratory (ANL) study it was estimated that the water consumption for distributed hydrogen
electrolysis was about 17 percent higher than distributed hydrogen SMR processes for the same hydrogen
production yield (Elgowainy, 2016).
Small-scale natural gas SMR plants are commercially available for providing onsite hydrogen production. These
systems are less efficient and more costly to operate per unit volume of hydrogen production than large-scale
SMR plants, but they have been used to directly support fuel cell power systems and refueling stations. In the
case of ethanol as a hydrogen fuel carrier, ethanol can be stored in aboveground or underground tanks before
being pumped to a small-scale hydrogen production ESR plant. ESR is similarto SMR in terms of operating
temperatures, hydrogen yields, energy efficiency and production cost (Tayade, 2012).
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Water electrolysis is the second most commonly used hydrogen production process behind SMR. Today's
commercially available electrolyzers utilize polymer electrolyte membrane and alkaline electrolytes. Although
electric grid power is most common for small-scale electrolyzers, research is exploring wind or solar power
potential, with the aim of improving small-scale economics and lifecycle emissions.
4.3 Non-Hydrogen Fuel Supplies for Direct Fuel Cell Use
Several non-hydrogen fuel sources offer potential for direct fueling of fuel cells at ports. These include natural
gas, ammonia, and methanol. Each is discussed below.
4.3.1 Natural Gas
The abundance of natural gas resources in the U.S. ensures its wide availability and use across a variety of
demand sectors in the future. As discussed above, natural gas will be a key fuel source for supporting onsite
production of hydrogen under distributed hydrogen pathways. Natural gas can also be used directly as a fuel
source for some types of fuel cells such as MCFCs and SOFCs. These high temperature fuel cells require less
catalytic electrode materials and allow for less fuel processing due to internal fuel reforming. The general
availability of natural gas supplies for most U.S. port locations offers significant potential for direct natural gas
use in stationary fuel cell applications using MCFC and SOFC technologies. Natural gas is extensively pipelined
across the U.S. with local pipeline networks serving municipal jurisdictions and/or large demand centers such
as ports. Natural gas can also be delivered onsite in bulk cryogenic liquid form where is can be stored for later
gaseous pipeline distribution to stationary fuel cell application.
Pipeline natural gas typically contains sulfur compounds (e.g., mercaptans) for producing an odor in the
gaseous product. (The odor affords easier detection of pipeline gas leaks.) Depending on gas sulfur levels,
additional fuel processing may be necessary to reduce sulfur compounds in the fuel prior to fuel cell use. SOFC
fuel cells tend to have higher fuel sulfur tolerance due to their high temperature operation and typically lower
catalytic materials (FuelCellToday, 2019).
4.3.2 Methanol
Methanol, or methyl alcohol, is a commonly used feedstock supporting a variety of market sectors in the U.S.
including the chemical, petroleum and refined product, and plastics industry. The global methanol market in
2019 was about 98 million metric tons according to the Methanol Institute (Methanol Institute, 2020).
Methanol is produced from syngas created from natural gas production. As a liquid fuel, methanol's energy
content is higher than natural gas but lower than ethanol or gasoline on an equivalent volume basis. Methanol
is transported as a liquid via tanker ship, barge, pipeline, rail, and truck ( Methanol Institute, 2013). Methanol
is flammable and burns with a nearly invisible flame. Methanol is toxic to humans, but when released it readily
biodegrades and is miscible with water.
Direct methanol fuel cells (DMFCs) were developed in the U.S. in the 1990s. A DMFC is essentially a specialized
form of PEMFC that utilizes an aqueous methanol mixture as its fuel source. DMFCs incorporate polymer
membranes for their electrolyte. However, platinum-ruthenium catalysts are used at their anodes which
breaks down the methanol molecules into hydrogen ions and C02. This eliminates the need for an external fuel
reformer to produce hydrogen. The hydrogen ions then pass through the electrolyte and combine with oxygen
at the cathode to form water. To date, DMFCs have primarily been used for small portable power applications
for cell phones and laptop computers as well as military power applications for the battlefield. According to
the Methanol Institute, global methanol demand for DMFC applications was about 12,000 metric tons.
4.3.3 Ammonia
As mentioned above, the current ammonia market is about 100 million tons per year for serving agriculture,
pharmaceutical, petroleum, and plastic industries in the U.S. As a result, existing supply infrastructure is
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already in place across the U.S. for potentially serving fuel cell end users. Ammonia is typically liquified and
stored in large refrigerated storage tanks as ammonia's boiling point is only -33°C. Thus, ammonia is
transported as a refrigerated bulk liquid product via ship or barge and can be transported to local markets as a
low-pressure liquid (like propane) via pipeline, barge, tank car, and tank truck. Ammonia has comparable
energy density to methanol and about twice that of liquid hydrogen on an equivalent volume basis. In terms of
safe handling and distribution, ammonia has a narrower flammability range than hydrogen and burns with a
visible flame as opposed to hydrogen's invisible flame. Ammonia releases from infrastructure are a significant
challenge for human exposure scenarios, but releases are detectable at less than 1 ppm in air and generally
dissipate quickly in gaseous form.
Ammonia can be utilized as a direct fuel for some fuel cell types. PEMFCs are not good candidates for direct
ammonia use due to their low operating temperatures (lower ammonia conversion potential) and subsequent
ammonia crossover issues, and potential poisoning of anode electrode catalysts. Recent research on direct
ammonia AFC, AMFC, and SOFC applications is progressing but still in pre-commercial development. The higher
temperatures of SOFCs hold promise for achieving similar efficiencies and power densities as hydrogen-fueled
SOFCs, but challenges with long-term durability persist.
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5. Port Fuel Cell Equipment, Infrastructure, and Fuel Costs
5.1 Hydrogen Infrastructure and Delivery Costs
The methods for producing, transporting, and dispensing hydrogen vary considerably. Regionally specific
refueling solutions involving most cost-effective delivery of hydrogen product to individual port locations will
ultimately determine which delivery pathways are most successful. A breadth of hydrogen refueling solutions
and their associated cost is presented and discussed in this section. The discussion includes estimated
hydrogen refueling station capital and operating costs according to station capacity and type of hydrogen
product delivered. In addition, the section presents a methodology for estimating overall delivered hydrogen
costs, accounting for hydrogen production process, transport and distribution type, and station/dispensing
type.
5.1.1 Refueling Station Capital and Operating Costs
In recent work on hydrogen refueling costs (Melaina & Penev, Hydrogen Station Cost Estimates: Comparing
Hydrogen Station Cost Calculator Results with Other Recent Estimates, 2013) (Hecht & Pratt, 2017) (McKinney,
2015), researchers reported on a variety of results, including refueling station capital and operating costs
developed by the University of California-Davis based on California station installations. Station capital costs
were estimated according to station capacity (kg hydrogen dispensed per day) as well as station type and
hydrogen delivery method. Researchers also provided estimates for natural gas and electricity consumption as
well as annual maintenance associated with hydrogen station types, including onsite SMR and electrolysis
processes. Using this information and reported average industrial prices (U.S. Energy Information
Administration, 2020) for natural gas ($4.17/1000ft3) and electricity ($0.0688/kwh) in 2018, estimates of
levelized hydrogen refueling station capital and operating costs are shown in Table 25 for a variety of hydrogen
delivery and station types. Gaseous hydrogen (GH2) and liquid hydrogen (LH2) delivery shown in the Table
represent delivery by truck. Conventional hydrogen stations represent those stations customized and
assembled onsite, while modular stations describe stations assembled by manufacturers offsite and then
delivered to the site on a skid or trailer. In general, the station cost Figures of Table 25include a single
dispenser capable of dispensing both 350 and 700 bar hydrogen (Melaina & Penev, Hydrogen Station Cost
Estimates: Comparing Hydrogen Station Cost Calculator Results with Other Recent Estimates, 2013) (Hecht &
Pratt, 2017) (McKinney, 2015).
It should be noted that station capital costs on per kg dispensed basis in Table 25 are inversely proportional to
station capacity. Stated another way, station capital costs on a per kg dispensed basis are higher for smaller
capacity stations than for larger stations. Further, there is a difference in station capital costs on a per kg
dispensed basis between the centralized delivery stations and the distributed delivery stations. This is due to
the additional costs associated with onsite SMR and electrolysis production. However, as will be addressed
below, the overall cost of delivered hydrogen from these distributed production stations becomes competitive
with those of centralized production when accounting for centralized production and transport costs.
From a station operating cost standpoint, centralized production served stations generally had lower costs
than distributed served stations for the same hydrogen dispensed capacity. The onsite electrolysis stations
exhibited the highest operating costs due primarily to their intensive electricity usage in producing hydrogen
from water.
California is leading the charge to develop hydrogen refueling infrastructure in the U.S. The California Energy
Commission is expanding California's network of hydrogen refueling stations throughout the state. Hydrogen
fuel cell electric vehicles are expected to play a key role in achieving the state's goal of getting 1.5 million zero-
emission vehicles on California roads by 2025. To support the fuel cell electric cars and increase deployment,
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the Commission is investing in a network of 100 public hydrogen stations.15 Efforts are also underway to
expand hydrogen fueling locations in Hawaii and across the East coast, with other markets expected to
develop as consumer demand increases. Hydrogen infrastructure is also developing for buses, medium-duty
fleets, and material handling equipment. 16
5.1.2 Dispensed Hydrogen Price
The ultimate cost for dispensed hydrogen ($/kg) must account for all production and delivery pathway
elements. This is especially important for centralized production pathways that include costs for production
and transport to the site on top of amortized costs for station capital cost recovery and operations. This also
affords the ability to assess differences in hydrogen delivered costs from regional production and delivery
sources, and to allow for apples-to-apples comparisons of total dispensed costs for centralized and distributed
production.
To estimate these pathways costs, several studies on specific hydrogen pathway cost elements were reviewed
(Lipman, 2011) (DOE Hydrogen and Fuel Cell Technical Advisory Committee, 2013) (DOE Fuel Cell Technologies
Office, 2019). Table 26 lists final estimated levelized cost figures on a per kg hydrogen produced and
transported basis for centralized production and transport pathways. The total delivered hydrogen cost in the
Table represents the summation of the production and transport costs for each delivery type. Thus, central
NG-SMR production ($1.47/kg) with tube trailer delivery ($1.50/kg) equates to a $2.97/kg delivered cost to the
station/site. Based on these figures and placing the previously determined refueling station capital and
operating costs of Table 25 on annualized per kg dispensed bases, final estimated dispensed hydrogen costs
were determined for both centralized and distributed production pathways. While hydrogen station lifetimes
can vary, a conservative station lifetime often years was selected for representing the lower end of this
lifetime range (Melaina & Penev, Hydrogen Station Cost Estimates: Comparing Hydrogen Station Cost
Calculator Results with Other Recent Estimates, 2013).
The dispensed hydrogen cost results are provided in Table 27 and represent estimates of levelized hydrogen
costs for dispensing the fuel to end use equipment. Note that centralized station dispensed hydrogen costs
ranged from $4.98-9.84/kg depending on the hydrogen production type, delivered product type (gaseous or
liquid), and the station type and capacity. Onsite dispensed hydrogen costs ranged from $5.43-12.28/kg. For
centralized pathways, delivered hydrogen costs were lowest with SMR produced gaseous product delivered to
conventional stations. For distributed pathways, onsite SMR produced the lowest delivered hydrogen costs. In
general, these estimates align with DOE projections for hydrogen costs in year 2025 of about $5-10/kg and
longer-term hydrogen costs of less than $4/kg (Satyapal, 2018). While the delivered hdyrogen cost estimates
of Table 27 represent sations capable of dispensing either 350- or700-bar pressures, it should be noted that
refueling at 350-bar pressures are reported to be up to $2/kg lower due to less required compressor operation
at these the lower pressure (McKinney, 2015).
15 California Energy Commission. Hydrogen Vehicles and Refueling Infrastructure, https://www.energy.ca.gov/programs-
and-topics/programs/clean-transportation-program/clean-transportation-funding-areas-1
16 U.S. Department of Energy. Alternative Fuels Data Center. Hydrogen Fueling Stations.
https://afdc.energy.gov/fuels/hvdrogen stations.html
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Table 14. Estimated Hydrogen Refueling Station Capital and Operating Costs by Hydrogen Delivery Method
Estimated Annual Station Costs
Assume H2
10-Year
Station
Station
Station Cost Per
Average Station
Average Station
Average Industrial
Average
Annualized
Annual
Annual
Annual
Hydrogen Refueling by Site
Capacity
Capital Cost
Capacity
Natural Gas Use
Electricity Use
Natural Gas Price
Electricity
Station Cost
Natural Gas
Electricity Cost
Maintenance
Total Annual Costs
Delivery Type
(kg/day)
($)
[$/(kg/day)]
(MMBtu/kg H2)
(kWh/kg H2)
($/1000ft3)
Price ($/kWh)
($)
Cost ($)
($)
Cost ($)
($)
Centralized Hydrogen Production and Delivery
Conventional, GH2 delivered
100
1,510,000
15,100
—
1.25
...
0.0688
151,000
...
3,139
19,630
173,769
Conventional, GH2 delivered
200
1,690,000
8,450
—
1.25
...
0.0688
169,000
...
6,278
21,970
197,248
Conventional, GH2 delivered
300
1,860,000
6,200
...
1.25
...
0.0688
186,000
...
9,417
24,180
219,597
Modular, GH2 delivered
100
1,860,000
18,600
...
1.25
...
0.0688
186,000
...
3,139
24,180
213,319
Modular, GH2 delivered
200
2,740,000
13,700
...
1.25
...
0.0688
274,000
...
6,278
35,620
315,898
Conventional, LH2 delivered
350
2,780,000
7,943
...
0.81
...
0.0688
278,000
...
7,119
30,580
315,699
Distributed Hydrogen Production and Delivery
Conventional, Onsite SMR
100
2,740,000
27,400
0.156
3.08
4.17
0.0688
274,000
23,744
7,734
35,620
341,098
Conventional, Onsite SMR
200
3,830,000
19,150
0.156
3.08
4.17
0.0688
383,000
47,488
15,469
49,790
495,747
Conventional, Onsite SMR
300
4,430,000
14,767
0.156
3.08
4.17
0.0688
443,000
71,232
23,203
57,590
595,025
Conventional, Onsite Electrolysis
100
2,380,000
23,800
...
55.2
...
0.0688
238,000
...
138,618
30,940
407,558
Conventional, Onsite Electrolysis
200
2,980,000
14,900
...
55.2
...
0.0688
298,000
...
277,236
38,740
613,976
Conventional, Onsite Electrolysis
300
3,450,000
11,500
...
55.2
...
0.0688
345,000
...
415,855
44,850
805,705
Modular, Onsite Electrolysis
100
2,740,000
27,400
...
55.2
...
0.0688
274,000
...
138,618
35,620
448,238
Modular, Onsite Electrolysis
200
3,140,000
15,700
...
55.2
...
0.0688
314,000
...
277,236
40,820
632,056
Modular, Onsite Electrolysis
300
3,450,000
11,500
...
55.2
...
0.0688
345,000
...
415,855
44,850
805,705
*ERG
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Table 15. Estimated Hydrogen Production and Transport Costs
Production Costs
Transport Costs
Total Delivered Hydrogen Cost to Station
Central
Central
Coal
Central
Tube Trailer
Liquid Tanker
Total NG-SMR
Total Coal H2
Total Biomass
NG-SMR
w/CCS
Biomass
Delivery to
Delivery to
H2 Delivered
Delivered Cost
H2 Cost
Hydrogen Refueling by Site Delivery Type
($/kg)
($/kg)
($/kg)
Station ($/kg)
Station ($/kg)
Cost ($/kg)
($/kg)
($/kg)
Mobile Refueler (100 kg/day)
$1.47
$1.82
$2.50
$1.50
—
$2.97
$3.32
$4.00
GH2 delivery via truck (100 kg/day)
$1.47
$1.82
$2.50
$1.50
—
$2.97
$3.32
$4.00
GH2 delivery via truck (180 kg/day)
$1.47
$1.82
$2.50
$1.50
—
$2.97
$3.32
$4.00
LH2 delivery via truck (100 kg/day)
$2.94
$3.64
$5.00
—
$0.75
$3.69
$4.39
$5.75
LH2 delivery via truck (400 kg/day)
$2.94
$3.64
$5.00
—
$0.75
$3.69
$4.39
$5.75
LH2 delivery via truck (1000 kg/day)
$2.94
$3.64
$5.00
—
$0.75
$3.69
$4.39
$5.75
Table 27. Final Estimated Dispensed Hydrogen Costs by Production and Delivery Type
Annualized Station Cost Estimates
Total
Total NG-SMR
Total Coal
Biomass
Total On-site
Assumed Station
Produced/
Produced/D
Produced/D
Produced/
H2 Capacity
Dispensed Cost
ispensed
ispensed
Dispensed Cost
Hydrogen Refueling by Site Delivery Type
(kg/day)
(S/kg)
Cost ($/kg)
Cost ($/kg)
(S/kg)
Centralized Production Pathways
Conventional, GH2 delivered
100
$7.73
$8.08
$8.76
—
Conventional, GH2 delivered
200
$5.67
$6.02
$6.70
—
Conventional, GH2 delivered
300
$4.98
$5.33
$6.01
—
Modular, GH2 delivered
100
$8.81
$9.16
$9.84
—
Modular, GH2 delivered
200
$7.30
$7.65
$8.33
—
Conventional, LH2 delivered
350
$6.16
$6.86
$8.22
—
Distributed Production Pathways
Conventional, Onsite SMR
100
—
—
—
$9.35
Conventional, Onsite SMR
200
—
—
—
$6.79
Conventional, Onsite SMR
300
—
—
—
$5.43
Conventional, Onsite Electrolysis
100
—
—
—
$11.17
Conventional, Onsite Electrolysis
200
—
—
—
$8.41
Conventional, Onsite Electrolysis
300
—
—
—
$7.36
Modular, Onsite Electrolysis
100
—
—
—
$12.28
Modular, Onsite Electrolysis
200
—
—
—
$8.66
Modular, Onsite Electrolysis
300
—
—
—
$7.36
5.2 Port Fuel Cell Equipment Costs by Port Application
This section presents a cost review of diesel-fueled and hydrogen fuel cell-powered port-related equipment.
The port equipment applications include nonroad materials handling equipment, switcher locomotives, marine
craft, and stationary power generation equipment. The diesel-fueled and hydrogen fuel cell-powered
equipment and associated operational data covered in this section are based on those previously identified in
Section 3 ("Fuel Cell Applications and Characteristics for Ports") of this report.
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5.2.1 Forklift Costs
Based on the port inventory data previously presented in Section 3 of this report, the following average
characteristics were assumed for a port forklift for costing purposes:
• Age range between 8-13 years old; assume 10-year useful life.
• Rated power range between 75-175 hp; assume 75 hp
• Annual utilization range between 500-2,200 hours; assume 1,500 hours
• Average load factor 0.30-0.59; assume 0.39
In order to derive representative costs for both conventional diesel and fuel cell forklifts, a recent study by
NREL was referenced which evaluated fuel cell forklift equipment implemented under hundreds of federally
funded demonstration projects (Ramsden, 2013). For purposes of the forklift analysis, Class V diesel forklift
costs were derived based on online vendor quotes. Fuel cell forklift capital costs were estimated based on
NREL report Figures but adjusted upward for the larger Class V forklifts assumed for ERG's analysis.
Both the Class V diesel and fuel cell forklifts are operated 1,500 hours annually and have ten-year lifetimes. In
order to assess annual fuel costs, gaseous hydrogen fuel prices based on DOE current and long-term estimates
was assumed (Satyapal, 2018). Diesel fuel pricing reflected EIA forecasted Figures for average low sulfur diesel
fuel (U.S. Energy Information Administration, 2020).
The cost analysis results are provided in Table 28 for calendar years 2020 and 2030. The year 2020 capital and
annual maintenance costs represent today's market costs. Year 2030 costs included applied average annual
inflation (two percent per year). In addition, year 2030 fuel cell equipment costs were derived by applying DOE
fuel cell system cost reduction projections for near- and long-term high-volume production to the year 2020
forklift cost estimate (Satyapal, 2018).
As shown for year 2020, the fuel cell forklift upfront cost was almost twice that of a comparable diesel-fueled
version. Year 2020 annual operating costs for forklifts were almost twice those of diesel units due mainly to
higher hydrogen fuel prices. In year 2030, as fuel cell technology evolves and assumed manufacturing volumes
increase, capital costs were only about 25 percent higher for fuel cell forklifts. Annual operating costs in 2030
were 18 percent lower as lower hydrogen fuel prices prevail in the marketplace due to high-volume
production.
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Table 28. Estimated Cost Comparison of Diesel and Fuel Cell Forklifts
Diesel Forklift Cost Elements
Fuel Cell Forklift Cost Elements
Assume 10-yr Lifetime
Assume 10-yr Lifetime
Calendar Year 2020
Diesel Fuel Price ($/gal)
$3.33
Hydrogen Fuel Price ($/kg)
$13.00
Total Capital Investment
$45,000
Total Capital Investment
$84,194
Total Annual Operating Costs
Annual Forklift Fuel Cost
Annual Forklift Maintenance Cost
$11,242
$7,992
$3,250
Total Annual Operating Costs
Annual Forklift Fuel Cost
Annual Forklift Maintenance Cost
$19,736
$13,736
$6,000
Calendar Year 2030
Diesel Fuel Price ($/gal)
$3.76
Hydrogen Fuel Price ($/kg)
$5.00
Total Capital Investment
$54,855
Total Capital Investment
$71,068
Total Annual Operating Costs
Annual Forklift Fuel Cost
Annual Forklift Maintenance Cost
$12,996
$9,034
$3,962
Total Annual Operating Costs
Annual Forklift Fuel Cost
Annual Forklift Maintenance Cost
$10,768
$5,283
$5,485
5.2.2 Yard Tractor Costs
Based on the port inventory data previously presented in Section 3 of this report, the following average
characteristics were assumed for a port yard tractor for costing purposes:
• Age range between 5-12 years old; assume 12-year useful life
• Rated power range between 175-200 hp; assume 175 hp
• Annual utilization range between 1,200-4,600 hours; assume 1,600 hours
• Average load factor 0.39; assume 0.39
Based on available information for both conventional diesel-fueled and fuel cell hybrid range extender yard
tractors, staff estimated typical capital and operational costs for comparison. In both cases, assumptions
include 12-year lifetimes and 1,600 annual hours of operation. The diesel yard tractor incorporated a diesel
engine meeting federal Tier 4 emission standards, while the fuel cell platform incorporated a system similar to
the pre-commercial Ballard/BAE Systems fuel cell yard tractor. The Ballard Power System couples a FCveloCity-
HD 85-kW PEMFC with a BAE System's HDS200 HybriDrive series propulsion system on a Capacity TJ9000 yard
tractor platform (maximum 242,000 GCWR). The system includes 31.8-kWh of lithium ion battery storage, and
20 kg of hydrogen storage at 350-bar ( Green Car Congress, 2018). The yard tractor analyses also assumed the
same hydrogen fuel and diesel fuel pricing as for the forklift analysis above.
Table 29 displays the cost comparison results for the yard tractor. Note that the 2020 incremental capital cost
for the fuel cell yard tractor was about $115,000 compared to a conventional diesel version. Based on the
assumption of the fuel cell top loader evolving to commercial, high-volume status, and using associated DOE
cost projections (Satyapal, 2018), the incremental capital cost relative to diesel units reduced to about $48,000
in 2030. Annual maintenance cost with the fuel cell yard tractor was higher in 2020 based on assumed one-
time lifetime replacement of the fuel cell and battery pack (compared with one engine repower with the diesel
unit). More robust fuel cell platform designs and associated lower replacement costs in 2030 placed fuel cell
yard truck annual maintenance cost at only slightly higher than for its diesel counterpart. While fuel cell fuel
*ERG
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costs were much higherthan for diesel in 2020, in 2030 fuel cell fuel costs were estimated to be over 40
percent lower assuming the high-volume hydrogen price of $5/kg.
Table 29. Estimated Cost Comparison of Diesel and Fuel Cell Yard Tractors
Diesel Yard Tractor Cost Elements
Fuel Cell Yard Tractor Cost Elements
Assume 12-yr Lifetime
Assume 12-yr Lifetime
Calendar Year 2020
Diesel Fuel Price ($/gal)
$3.33
Hydrogen Fuel Price ($/kg)
$13.00
Total Capital Investment
$110,000
Total Capital Investment
$225,000
Total Annual Operating Costs
Annual Yard Tractor Fuel Cost
Annual Yard Tractor Maintenance Cost
$22,981
$19,181
$3,800
Total Annual Operating Costs
Annual Yard Tractor Fuel Cost
Annual Yard Tractor Maintenance Cost
$38,464
$32,966
$5,498
Calendar Year 2030
Diesel Fuel Price ($/gal)
$3.76
Hydrogen Fuel Price ($/kg)
$5.00
Total Capital Investment
$134,089
Total Capital Investment
$182,704
Total Annual Operating Costs
Annual Yard Tractor Fuel Cost
Annual Yard Tractor Maintenance Cost
$26,314
$21,681
$4,632
Total Annual Operating Costs
Annual Yard Tractor Fuel Cost
Annual Yard Tractor Maintenance Cost
$17,799
$12,679
$5,120
As noted above, the fuel cell yard tractor capital cost in Table 29 is based on the pre-commercial Ballard/BAE
Systems/Capacity system which incorporated 20 kg of onboard hydrogen storage at 350-bar pressure. Higher
energy density storage systems like 700-bar pressure tanks or cryogenic liquid hydrogen tanks could also be
incorporated in this platform in the future to increase onboard storage volumes or reduce storage system
weight/volume footprints for the original hydrogen storage mass (20 kg). To assess the cost impacts of these
alternative hydrogen storage systems, low production volume storage system costs were first estimated based
on recent hydrogen storage cost research (Rivard, 219) (Law, 2011) and then applied to the fuel cell yard
tractor application. The analysis indicated that the use of 700-bar pressure tanks for the same 20 kg of
hydrogen storage would increase the cost of the fuel cell yard tractor by about $4,469 over the use of the
original 350-bar pressure tanks. If liquid hydrogen tanks were utilized, it was estimated that the fuel cell yard
tractor cost would decrease by about $5,276 compared with the original 350-bar pressure tanks.
5.2.3 Cargo Handlers (Top Loaders) Costs
A top loader was assumed to represent port cargo handler equipment. Based on the port equipment inventory
data discussed previously in Section 3 of this report, the following average characteristics were assumed for a
port top loader for costing purposes:
• Age range between 6-12 years old; assume 12-year useful life
• Rated power range between 300-375 hp; assume 350 hp
• Annual utilization range between 1,400-2,300 hours; assume 2,000 hours
• Load factor range of 0.43-0.59; assume average of 0.59
Based on available information for both conventional diesel-fueled and fuel cell hybrid range extender yard
trucks, staff derived typical capital and operational costs. In both cases, assumptions included 12-year lifetimes
and 2,000 annual hours of operation. The diesel top loader incorporated a federal Tier 4 compliant engine. The
pre-commercial Hyster/Nuvera fuel cell platform, which incorporates a 90-kW Nuvera PEMFC range extender
*ERG
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with 20 kg hydrogen storage (350 bar) and 200-kWh lithium ion battery pack (Nuvera, 2019), was the basis for
the fuel cell top loader. The analysis assumed similar hydrogen and diesel fuel prices as for forklifts and yard
tractors.
Table 30 provides an estimated cost comparison between the diesel and fuel cell hybrid top loader. The 2020
incremental capital cost for the fuel cell top loader (about $142,000) reflected its current pre-commercial
status. Using DOE cost projections, the 2030 incremental cost estimate reduced to about $77,000. Estimated
2020 annual maintenance costs for the fuel cell top loader were higher due to assumed one-time fuel cell and
battery pack replacement compared with one diesel engine repower over the 12-year lifetime. As with yard
trucks, 2030 annual maintenance costs improved relative to diesel units due to lower associated fuel cell and
battery replacement costs. While 2020 fuel costs for the fuel cell top loader were significantly higher than for
diesel, the assumed high-volume hydrogen pricing in 2030 reduced fuel cell fuel costs to 42 percent lower
compared with diesel.
Table 30. Estimated Cost Comparison of Diesel and Fuel Cell Cargo Handlers
Diesel Cargo Handler (Top Loader) Cost Elements
Fuel Cell Cargo Handler (Top Loader) Cost Elements
Assume 12-yr Lifetime
Assume 12-yr Lifetime
Calendar Year 2020
Diesel Fuel Price ($/gal)
$3.33
Hydrogen Fuel Price ($/kg)
$13.00
Total Capital Investment
$584,500
Total Capital Investment
$727,078
Total Annual Operating Costs
Annual Top Loader Fuel Cost
Annual Top Loader Maintenance Cost
$77,717
$72,594
$5,123
Total Annual Operating Costs
Annual Top Loader Fuel Cost
Annual Top Loader Maintenance Cost
$131,534
$124,767
$6,767
Calendar Year 2030
Diesel Fuel Price ($/gal)
$3.76
Hydrogen Fuel Price ($/kg)
$5.00
Total Capital Investment
$712,502
Total Capital Investment
$789,997
Total Annual Operating Costs
Annual Top Loader Fuel Cost
Annual Top Loader Maintenance Cost
$88,302
$82,058
$6,244
Total Annual Operating Costs
Annual Top Loader Fuel Cost
Annual Top Loader Maintenance Cost
$54,498
$47,987
$6,511
As noted, the pre-commercial Hyster/Nuvera fuel cell top loader design is the basis of the capital cost shown in
Table 30. The Hyster/Nuvera system utilized an onboard hydrogen storage system comprising 20 kg at 350-bar
pressure. The cost impacts of using 700-bar pressure and liquid hydrogen storage systems were also
estimated. Low production volume storage system costs were first estimated based on recent hydrogen
storage cost research (Rivard, 219) (Law, 2011) and then applied to the top loader application. The use of 700-
bar pressure tanks would increase the cost of the fuel cell top loader by about $4,469 compared to the original
350-bar pressure tanks for the same 20 kg hydrogen storage. For liquid hydrogen tanks, results indicated a
decrease of $5,276 compared to the original 350-bar pressure tanks for the same 20 kg hydrogen storage.
5.2.4 Switcher Locomotive Costs
For analysis purposes, the pre-commercial BNSF 1205 fuel cell switcher locomotive formed the basis for cost
comparisons of a fuel cell and a conventional diesel switcher locomotive. BNSF Railway developed the BNSF
1205 fuel cell switcher in 2009 retrofitted from an original diesel EMD GP9 switcher locomotive. The BNSF
1205 had a 500-kW PEMFC and 1-MW battery pack (California Air Resources Board, 2016). Back in 2010, CARB
estimated that the BNSF 1205 prototype cost about $3.5 million to develop. A comparable Tier 4 diesel
switcher locomotive (about 2,000 hp) was estimated to cost around $1.1 million. In order to develop a more
contemporary (that is, present day) cost for a fuel cell hybrid switcher, adjustments to the 2009 costs were
*ERG
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made to account for cost reductions in both lithium ion batteries and PEMFCs (Howell) (Wilson, 2017).
Adjustments were also made assuming market-based production volumes and U.S. Bureau of Labor Statistics
rail industry producer price indices. Staff also assumed a 20-year useful life for both switchers, assuming each
locomotive was used in line haul service for 20 years prior to being transferred to switcher service.
Table 31 lists the results for the cost comparison of the fuel cell hybrid switcher locomotive and a Tier 4 diesel
multi-genset locomotive. An average diesel fuel cost of $2.07/gallon was assumed for 2020 based on 2019
Class I railroad financial reports filed with the Surface Transportation Board (STB) (Surface Transportation
Board, 2019). A diesel fuel cost of $2.34/gallon was assumed for 2030 based on EIA forecasting for low sulfur
diesel fuel (U.S. Energy Information Administration, 2020). Gaseous hydrogen fuel costs were assumed similar
to those for forklifts, yard tractors, and top loaders. Note that the estimated incremental capital cost of the
pre-commercial fuel cell switcher in 2020 was about $1.9 million. Average diesel switcher annual maintenance
was assumed based on STB Class I railroad financial reports filed in 2019 (Surface Transportation Board, 2019).
Due to fuel cell and battery replacement costs approximately halfway (assuming 10-year lifetimes for the
original fuel cell stack and battery pack) through its 20-year lifetime, annual maintenance costs were higher
than those of the diesel switcher which included one engine repower over its lifetime. While fuel cell switcher
annual operating costs in 2020 were over twice those of the diesel switcher, fuel cell annual operating costs
were only about 16 percent higher in 2030.
Table 16. Estimated Cost Comparison of Diesel and Fuel Cell Switcher Locomotive
Diesel Switcher Cost Elements
Fuel Cell Switcher Cost Elements
Assume 20-yr Lifetime
Assume 20-yr Lifetime
Calendar Year 2020
Diesel Fuel Price ($/gal)
$2.07
Hydrogen Fuel Price ($/kg)
$13.00
Total Capital Investment
$1,544,000
Total Capital Investment
$3,466,543
Total Annual Operating Costs
Annual Switcher Fuel Cost
Annual Switcher Maintenance Cost
$188,439
$98,739
$89,700
Total Annual Operating Costs
Annual Switcher Fuel Cost
Annual Switcher Maintenance Cost
$504,700
$390,000
$114,700
Calendar Year 2030
Diesel Fuel Price ($/gal)
$2.34
Hydrogen Fuel Price ($/kg)
$5.00
Total Capital Investment
$1,882,127
Total Capital Investment
$3,804,663
Total Annual Operating Costs
Annual Switcher Fuel Cost
Annual Switcher Maintenance Cost
$220,955
$111,612
$109,344
Total Annual Operating Costs
Annual Switcher Fuel Cost
Annual Switcher Maintenance Cost
$274,120
$150,000
$124,120
The fuel cell switcher locomotive capital cost of Table 31 assumed 70 kg hydrogen storage at 350-bar pressure.
Both 700-bar pressure storage as well as liquid hydrogen storage are viable alternatives for the switcher
application. Based on recent hydrogen storage cost research results (Rivard, 219) (Law, 2011), a higher
incremental capital cost of $16,271 was estimated for using a 700-bar pressure storage system over the
original 350-bar pressure system for the same 20 kg of hydrogen storage. In the case of liquid hydrogen
storage, a lower incremental capital cost of $18,465 was estimated relative to the original 350-bar pressure
system for the same 20 kg.
5.2.5 Marine Propulsion and Auxiliary Power System Costs
Limited information was available in the literature regarding fuel cell vessel and harbor craft capital costs.
However, a SNL 2016 report detailing the costs for a high-speed, fuel cell-powered passenger ferry concept
vessel (Pratt & Klebanoff, Feasibility of the SF-BREEZE: A Zero-Emission, Hydrogen Fuel Cell, High-Speed
*ERG
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Passenger Ferry, 2016) versus a comparable diesel vessel was used. Under funding by the U.S. Maritime
Administration, SNL conducted a feasibility and design study of the vessel, called the SF-BREEZE concept. The
ferry as specified would be capable of carrying 150 passengers and travel two 50-mile roundtrips at a top
speed of 35 knots before needing refueling. The vessel would incorporate 41120-kW PEM fuel cell racks and
1,200 kg (4,500 gallons) of liquid hydrogen.
Based on selected SNL report cost Figures for the SF BREEZE, comparative costs were derived for a fuel cell and
comparable diesel propulsion ferry boat. The cost results are presented in Table 32. A 20-year lifetime was
assumed for both applications. Both vessels included a 120-kW auxiliary load supported by a single fuel cell on
the fuel cell vessel and by an auxiliary engine in the diesel vessel. Note that the analysis assumed liquid
hydrogen fuel prices which typically incurs higher costs due to liquefaction processes. The difference between
gaseous hydrogen and liquid hydrogen fuel prices was about 28 percent based on the previous hydrogen
station analysis results of this section; however, since a larger fuel dispensing system was needed for the ferry
application (about 1,500 kg/day), lower associated fueling station costs were assumed, resulting in liquid
hydrogen fuel prices of $11.69/kg and $4.40/kg for 2020 and 2030, respectively (Connelly, 2019).
The total capital cost of the fuel cell vessel was about 50 percent higher than that of the diesel vessel in 2020
due in part to the fuel cell power plants and onboard liquid hydrogen storage tanks. Assumed improvements
for fuel cell and vessel designs reduced the incremental cost to about 8 percent higher in 2030. In 2020, the
fuel cell vessel's annual operating costs were about four times that of its diesel counterpart. The fuel cell
vessel's 2020 annual operating cost included the requirement for three fuel cell powerplant replacements
during the 20-year life. The 2020 fuel energy requirement for the fuel cell boat was also about 28 percent
higher than that of the diesel boat due to higher weight from hydrogen storage system and a slightly less
efficient hull design. Based on assumed improved fuel cell platform and vessel design to achieve weight parity
with comparable diesel vessels, resulting in reduced fuel costs, fuel cell operating costs were about 45 percent
higher than diesel.
Table 17. Cost Comparison of Diesel and Fuel Cell Ferry Boat
Diesel Ferry Cost Elements
Fuel Cell Ferry Cost Elements
Assume 20-yr Lifetime
Assume 20-yr Lifetime
Calendar Year 2020
Diesel Fuel Price ($/gal)
$3.33
Hydrogen (Liquid) Fuel Price ($/kg)
$11.64
Total Capital Investment
$11,600,000
Total Capital Investment
$17,166,000
Total Annual Operating Costs
Annual Ferry Fuel Cost
Annual Ferry Maintenance Cost
$1,713,086
$1,313,086
$400,000
Total Annual Operating Costs
Annual Ferry Fuel Cost
Annual Ferry Maintenance Cost
$6,751,790
$5,751,790
$1,000,000
Calendar Year 2030
Diesel Fuel Price ($/gal)
$3.76
Hydrogen (Liquid) Fuel Price ($/kg)
$4.40
Total Capital Investment
$14,140,335
Total Capital Investment
$15,258,100
Total Annual Operating Costs
Annual Ferry Fuel Cost
Annual Ferry Maintenance Cost
$1,971,870
$1,484,272
$487,598
Total Annual Operating Costs
Annual Ferry Fuel Cost
Annual Ferry Maintenance Cost
$2,858,896
$1,927,787
$931,110
5.2.6 Stationary Power Generator Costs
For purposes of determining a detailed cost comparison of diesel-fueled and fuel cell-powered stationary
power generators, staff referenced elements of an SNL study of a containerized fuel cell generator (Pratt &
Chan, Maritime Fuel Cell Generator Project, 2017). The fuel cell generator design provided primary power to
*ERG
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up to ten refrigerated containers. The Hydrogenics fuel cell generator incorporated a 100-kW PEMFC rack with
72 kg of hydrogen at 350 bar and had a rated power of 100-kW, 240 VAC 3-phase. The analysis assumed a ten-
year lifetime for the fuel cell generator and one required fuel cell replacement over its lifetime. It was also
assumed that the diesel generator would require one engine rebuild over its ten-year lifetime.
The results of the cost comparison are shown in Table 33 for 3,000 hours per year of operation. The cost for
the diesel genset represents a unit with a Tier 4 diesel engine. As shown in year 2020, the capital cost of the
low volume production fuel cell generator was several times higher than that of the diesel generator. With
assumed higher manufacturing volumes, the 2030 capital cost of the fuel cell generator was about 50 percent
more than the cost of the diesel generator. Annual operating costs for the fuel cell generator in 2020 were
about twice those of the diesel generator due primarily to higher fuel costs. However, 2030 fuel cell generator
operating costs were about 28 percent lower resulting from much lower fuel prices and assumed annual
maintenance costs.
Table 33. Estimated Cost Comparison of Diesel and Fuel Cell Power Generator
Diesel Generator (100 kW) Cost Elements
Fuel Cell Generator (100 kW) Cost Elements
Assumed 10-yr Lifetine
Assumed 10-yr Lifetine
Calendar Year 2020
Diesel Fuel Price ($/gal)
$3.33
Hydrogen Fuel Price ($/kg)
$13.00
Total Capital Investment
$100,000
Total Capital Investment
$312,000
Total Annual Operating Costs
Annual Generator Fuel Cost
Annual Generator Maintenance Cost
$31,553
$26,453
$5,100
Total Annual Operating Costs
Annual Generator Fuel Cost
Annual Generator Maintenance Cost
$64,528
$56,365
$8,163
Calendar Year 2030
Diesel Fuel Price ($/gal)
$3.76
Hydrogen Fuel Price ($/kg)
$5.00
Total Capital Investment
$121,899
Total Capital Investment
$174,124
Total Annual Operating Costs
Annual Generator Fuel Cost
Annual Generator Maintenance Cost
$36,118
$29,901
$6,217
Total Annual Operating Costs
Annual Generator Fuel Cost
Annual Generator Maintenance Cost
$29,279
$21,679
$7,601
5.3 Port Fuel Cell Equipment Annual Savings and Capital Cost Recovery
Based on the port fuel cell equipment cost analysis results above, the lifecycle savings for fuel cell equipment
relative to comparable diesel fuel equipment was estimated. In addition, simple capital payback estimates
based on capital cost investments and annual savings were derived. This analysis only quantified results for
2020 and 2030 cost assumptions. Results for both are discussed below.
5.3.1 Lifecycle Savings and Payback
Table 34 lists the incremental cost results for each port equipment type along with assumptions regarding
average lifetime, annual utilization, and fuel prices. As indicated, none of the fuel cell equipment provided
annual operational savings in 2020 relative to their diesel counterparts, shown as negative savings in the Table.
This is due primarily from a high hydrogen fuel price in 2020 based on low-volume hydrogen production and
truck delivery.
*ERG
5-11
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Table 34. Estimated Port Fuel Cell Equipment Payback by Calendar Year
Comparative Cost Parameter
Forklift
Yard
Cargo
Switcher
Ferry Boat
Generator
Assumed Useful Lifetime
10
12
12
20
20
10
Assumed Utilization (Hr/yr)
1,500
1,600
2,000
1,500
2,800
3,000
Year 2020
Assumed Hydrogen Price ($/kg)
13.00
13.00
13.00
13.00
11.64
13.00
Assumed Diesel Price ($/gal)
3.33
3.33
3.33
2.07
3.33
3.33
Incremental Capital Cost ($)
39,194
115,000
142,578
1,922,543
5,566,000
212,000
Annual Operating Savings ($)
-8,494
-15,484
-53,817
-316,261
-5,038,704
-32,975
Estimated Simple Payback (Yrs)
None
None
None
None
None
None
Year 2030
Assumed Hydrogen Price ($/kg)
5.00
5.00
5.00
5.00
4.40
5.00
Assumed Diesel Price ($/gal)
3.76
3.76
3.76
2.34
3.76
3.76
Incremental Capital Cost ($)
16,214
48,614
77,494
1,922,536
1,117,764
52,225
Annual Operating Savings ($)
2,227
8,515
33,804
-53,165
-887,027
6,839
Estimated Simple Payback (Yrs)
7.3
5.7
2.3
None
None
7.6
In 2030, a much lower hydrogen fuel price resulting from higher-volume production begins to support the fuel
cell market. As a result, forklift, yard tractor, cargo handler (top Loader), and generator applications provided
payback potential within the assumed lifetimes of the equipment. Of course, these payback results reflect the
specific assumptions made for this equipment for purposes of this analysis. Higher equipment annual
utilization, higher load factors, or a larger differential fuel price between hydrogen and diesel fuel, would
improve the payback potential of the fuel cell equipment. For example, if a fuel cell yard tractor is operated for
4,600 hours versus the originally assumed 1,600 hours annually, simple payback duration as shown in Table 34
decreases from the 5.7 years to 1.9 years. Similarly, if the hydrogen fuel price in 2030 was $4/kg rather than
the originally assumed $5/kg, the fuel cell yard tractor payback is reduced to 4.4 years. Thus, port equipment
with higher annual utilization will exhibit faster capital payback than similar equipment with low annual
utilization. Further, as hydrogen fuel price decreases in the future due to production volume increases and fuel
delivery technology improvements, equipment payback potential relative to diesel fuel equipment will
increase commensurately and this estimate done for 2040 or 2050 would yield different results.
*ERG
5-12
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6. Hydrogen Fuel Cell Lifecycle Emissions
This section outlines one basic framework for estimating fuel cell equipment lifecycle emissions for port
applications. The framework can be used to identify hydrogen fuel-to-end use and fuel cell-to-end use
pathways associated with fuel cell equipment in port applications for subsequent lifecycle emissions
quantification relative to comparable diesel-fueled equipment.
6.1 Hydrogen Fuel Cycle and Fuel Cell Equipment Cycle
The proposed framework for fuel cell lifecycle emissions assessment relies on the total energy analysis
methodology employed by ANL and other lifecycle assessment researchers. Total energy analysis for
vehicle/equipment fuel usage encompasses energy use and emissions associated with the Fuel Cycle and the
Vehicle/Equipment Cycle (Wang, 2012). The Fuel Cycle encompasses all energy- and emissions-related
processes and activities of fuel feedstock extraction, fuel production, fuel product transport, distribution, and
dispensing, and fuel usage by end use vehicles and equipment. The Vehicle/Equipment Cycle includes the
energy- and emissions-related processes and activities of raw material extraction and transport, component
production and assembly, vehicle and equipment transport to end use, and vehicle/equipment post-life
disposal and/or recycling.
Using total energy analysis guidance, these same lifecycle elements can be organized for characterizing a
Hydrogen Fuel Cycle and a Fuel Cell Equipment Cycle, as depicted in Figure 16. The Hydrogen Fuel Cycle in the
Figure (shown in red) captures energy and emission expenditures for necessary feedstock exploration and
extraction, hydrogen fuel production, hydrogen fuel product storage, transport, and dispensing, and onsite
hydrogen fuel usage in fuel cell vehicles or equipment. The Fuel Cell Equipment Cycle (shown in blue) includes
raw material recovery, processing, and fabrication, fuel cell equipment component production and assembly,
and fuel cell equipment transport to end use, and post-life disposal or recycling. Note that while onsite
equipment utilization is a component of both the Fuel Cycle and Equipment Cycle (resulting in a purple
designation in the Figure), its energy and associated emissions contributions are typically attributed to the Fuel
Cycle. As such, the Fuel Cycle is often labeled as the "Well-to-Wheels" (WTW) contribution of overall pathway
scenario. With these generalized cycles defined, unique cycles for describing the likely near- and mid-term
options for hydrogen production, hydrogen product transport, and fuel cell use at ports were derived.
6.2 Hydrogen Fuel Cycle Pathways
As previously discussed, two hydrogen pathways from production to end use delivery have evolved:
Centralized Hydrogen Production and Distributed Hydrogen Production. In the case of centralized production,
pure hydrogen is produced in large scale plants (50,000 to 500,000 kg/day) for serving regional or even
national end use markets (DOE Fuel Cell Technologies Office, 2019). Hydrogen product from centralized plants
is stored and then transported to end use sites. For distributed production, hydrogen fuel carriers such as
natural gas are produced and transported using existing infrastructure to end use sites where hydrogen is then
produced in small volumes (< 1,500 kg/day) on site and used by fuel cell equipment.
For purposes of this analysis, the hydrogen fuel cycle pathways involving centralized and distributed hydrogen
production pathways were considered separately.
*ERG
6-1
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Fuel Cell
Equipment Cycle
Figure 7. General Hydrogen Fuel Cycle and Fuel Cell Equipment Cycle Pathways
6.2.1 Centralized Hydrogen Production Scenarios
Figure 17 shows three potential hydrogen fuel cycle pathways for centralized hydrogen production scenarios
(highlighted in red). These include Natural Gas SMR, Biomass Gasification, and Electrolysis Using Renewable
Energy. Each of the three centralized production pathways have different fuel feedstock extraction, feedstock
transport, and hydrogen production processes (as highlighted in green). These centralized hydrogen
production pathways can support both high-pressure and liquefied hydrogen product transport and delivery
(as shown in yellow in the Figure). Following centralized plant production, the hydrogen gas product is
pressurized and transported either via long distance pipeline or sent to near-by terminal storage for eventual
transport to market. In the case of liquefied hydrogen product transport, plant production feeds gaseous
hydrogen to a liquefaction plant (typically via pipeline) where it is cooled under pressure to produce liquid
hydrogen product. Liquefied hydrogen is then transferred via cryogenic pump to insulated tanker trucks for
delivery.
Due to the higher energy intensity of hydrogen delivery via pressurized tube trailers, hydrogen transport and
delivery via truck is generally relegated to 150 miles or less. Liquefied tank trailer transport is typically used for
delivery distances up to 1,000 miles. Although not as common, liquid hydrogen can also be transported long
distances via rail car, ship, and barge. In a recent study on hydrogen transport mode and distance impacts on
greenhouse gas emissions, NREL found that gaseous hydrogen transport by truck produces lower WTW
greenhouse gas emissions than liquified hydrogen truck transport at distances less than 400 miles for hydrogen
produced via natural gas SMR (Melaina M., 2017). The liquid hydrogen pathway requires the highest
electricity use, and thus is very sensitive to regional electricity generation mix. The NREL results represented an
average U.S. grid mix, but in U.S. locations with higher renewable energy-produced electricity, liquid product
truck transport may have lower WTW greenhouse emissions than gaseous product truck transport. At a
transport distance of 100 miles, both gaseous and liquified hydrogen truck transport produce substantially
lower GHG emissions and water usage than pipeline transport for hydrogen production from natural gas SMR.
*ERG
6-2
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(fl
Hydrogen Production
Feedstock
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Biomass
Gasification
Electrolysis
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Hydrogen Storage,
Transport
Storage: Terminal
Compressed
storage, geologic
Gaseous Hydrogen
storage
Transport: Pipeline,
tube trailer
Storage: Liquid
terminal storage
Liquefied
Hydrogen
Transport: tank truck,
tube trailer
On-site Hydrogen Storage
and Dispensing
Storage: cylinder, tube
trailer
Dispensing: Site pipeline,
dispensing station
Storage: liquid storage
tank
Dispensing:
Va porizer/com pressed
product station
Fuel Cell Type
On-site Fuel Cell Equipment Use
PEMFC
Forklift, yard tractor, top loader,
switcher locomotive, marine
propulsion, stationary power
AFC/AM FC
Forklift, marine shorepower,
stationary power
PAFC
Marine shorepower, stationary
power
MCFC
Marine shorepower, stationary
power
SOFC
Marine shorepower, stationary
power
Figure 8. Centralized Hydrogen Fuel Cycle Pathways
*ERG
6-3
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Hydrogen from centralized hydrogen production can then be delivered and stored on site as pressurized
gaseous product or as liquefied product (as shown in yellow in Figure 17). Pressurized hydrogen is delivered to
the site via tube trailer or distribution pipeline where it is transferred to onsite storage cylinders for serving
fuel cell equipment. For stationary fuel cell applications, the onsite storage cylinders are typically at sufficient
pressure to directly supply the equipment. In the case of mobile fuel cell equipment, hydrogen gas is further
compressed to increase the stored hydrogen energy density onboard the vehicle application.
For liquefied hydrogen, the liquid product that is delivered to the site is pumped into onsite vacuum-insulated
tanks for storage until ready for delivery to onsite fuel cell equipment. Liquid hydrogen can also be delivered in
vacuum-insulated tanks on trailers or skids which can then connected to the fuel delivery system and replaced
when empty.
As noted previously in the report, potential port fuel cell equipment applications include both mobile and
stationary applications. Table 35 lists the assumed near- to mid-term port-related fuel cell equipment for
centralized hydrogen production scenarios based on manufacturer research efforts and actual commercial
developments to date. For those equipment applications that are still in the pre-commercial stage of
development, the fuel cell type allocations are assumed to be the most likely candidates in the future once
commercialized. Note that PEMFCs are the predominant fuel cell type for the equipment applications listed.
Table 18. Assumed Near- and Mid-Term Port Fuel Cell Equipment Applications
Typical Port
Equipment Type
Hydrogen Dispenser
Delivery
Assumed Fuel Cell Type by Application
PEMFC
AFC/
AMFC
PAFC
MCFC
SOFC
Forklift
Yes
S
Yard Tractor
Yes
y
Top Loader
Yes
y
Switcher Locomotive
Yes
y
Marine Propulsion and
Auxiliary Power
Yes
y
Marine Shore Power
No - hydrogen gas direct
line fed
S
S
S
Stationary Power
No - hydrogen gas direct
line fed
y
S
y
y
y
6.2.2 Distributed Hydrogen Production Scenarios
Figure 18 illustrates three potential hydrogen fuel cycle pathways for distributed hydrogen production
scenarios (highlighted in red). These include Onsite SMR, Onsite Electrolysis Using Solar Power, and Onsite
Electrolysis Using Electric Grid.
As provided in Figure 18, the distributed production pathways have a variety of fuel feedstock extraction,
feedstock transport, and hydrogen production processes (as highlighted in green). The expansive natural gas
pipeline system across the U.S. supports the use of natural gas as a viable hydrogen carrier source for
distributed hydrogen production. Small-scale SMR plants are commercially available for providing onsite
hydrogen production. These systems are less efficient and more costly to operate per unit volume of hydrogen
production than large-scale SMR plants, but they have been used to directly support fuel cell power systems
and hydrogen refueling stations. Today's commercially available electrolyzers utilize polymer electrolyte
membrane and alkaline electrolytes. Although electric grid power is most common for small-scale
*ERG
6-4
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Hydrogen Production
Cycle Option
Feedstock
Recovery
Feedstock
Transport
Hydrogen Fuel
Carrier Production
Hydrogen Fuel
Carrier Product
Hydrogen Fuel
Carrier Storage,
Transport
On-site Hydrogen Fuel
Carrier Storage
On-site Hydrogen
Production, Storage, and
Dispensing
Fuel Cell Type
On-site Fuel Cell Equipment Use
Onsite Natural GasSMR
Natural Gas,
Water
>
Pipeline/Ship
>
Natural Gas
Processing
>
Gaseous Natural
Gas
Transport: pipeline,
tube trailer
>
Storage: Pressurized
cylinder, tube trailer
>
Production: On-site SMR
with cylinder storage
PEMFC
Forklift, yard tractor, top loader,
switcher locomotive, marine
propulsion, stationary power
Liquefied Natural
Transport: tank truck,
Storage: cyrogenic
Dispensing: Site pipeline,
AFC/AM FC
Forklift, marine shorepower,
Gas
tube trailer
cylinder, tube trailer
dispensing station
stationary power
Storage: Regional
Production: On-site
PAFC
Marine shorepower, stationary
Onsite Electrolysis with
Water
Pipeline
W ate r/W a ste wate r
Treatment and
Processing
Water
storage
electrolysis (Solar-based)
>
power
Solar Power
Transport: Pipeline
Dispensing: Site pipeline,
dispensing station
MCFC
Marine shorepower, stationary
power
Storage: Regional
Production: On-site
Onsite Electrolysis with
Electrical Grid
Water
>
Pipeline
>
W ate r/W a ste wate r
Treatment and
Processing
>
Water
storage
Transport: Pipeline
>
>
electrolysis (grid-based)
Dispensing: Site pipeline,
dispensing station
SOFC
Marine shorepower, stationary
power
Figure 9. Distributed Hydrogen Fuel Cycle Pathways
*ERG
6-5
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electrolyzers, research is being conducted on wind or solar power to improve small-scale economics and
lifecycle emissions.
The assumed near- to mid-term port-related fuel cell equipment of Table 35 above also apply for distributed
hydrogen production scenarios. Mobile equipment will be fueled using a high-pressure hydrogen dispensing
system fed by the onsite production plant and/or onsite storage. Depending on the fuel cell type, marine shore
power and stationary power systems will be fueled directly by a hydrogen line from onsite production or
storage.
6.3 Fuel Cell Equipment Cycle Pathways
The assumed Fuel Cell Equipment Cycle pathways for purposes of this analysis are presented in Figure 19. As
listed in the Figure, the fuel cell equipment cycle pathways (shown in blue) related to ports are many. They
represent the matrix of individual port equipment applications and fuel cell types assumed for this analysis, as
well as their associated development pathways from material recovery, to assembly, to use at the ports, and
finally disposal and recycling. Further discussion of these pathways follows below.
6.3.1 Raw Material Recovery and Processing
The primary differences in the individual fuel cell equipment pathways are associated with variances in fuel cell
materials and processing (shown in Figure 19 in green), fuel cell type component production and assembly
(shown in orange), and the material compositions and assembly for port equipment applications (shown in
orange). Each fuel cell type/application combination has unique material composition and processing
requirements, which is the reason separate pathways are shown for these combinations. Once identified, the
energy use and emissions associated with the recovery and processing of individual materials must be assessed
and compiled for each specific fuel cell/equipment combination.
Materials can be characterized according to fuel cell functionality which include electrode/membrane
assembly, current flow hardware, catalysts, and ancillary systems for storing and/or supplying and controlling
fuel, air, cooling, and water to the fuel cell assembly. In many cases, fuel cell materials are not domestically
produced and must be sourced internationally, increasing energy use and emissions. This is especially evident
for specialized catalyst materials which are often mined and processed outside the U.S. Depending on material
origins, transport methods may include ship, rail, and/or truck.
6.3.2 Equipment Component Production and System Assembly
Fuel cell systems vary depending on fuel cell type, but have the following basic components in common:
• Fuel Cell Stack
• Fuel Processor
• Power Conditioners
• Air Compressors
• Humidifiers
Similar to material supplies, many fuel cell components and full system assemblies are sourced internationally
and then shipped to the final equipment assembly point.
*ERG
6-6
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c
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Fuel Cell Equipment
Option
Raw Material
Recovery and
Transport
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O
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Component and System
Production and Transport
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and EquipmentComponents
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FC and Equipment Components
FCartd Equipment Components
FC and Equipment Components
>
>
>
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Fuel Cell Equipment
Application Assembly
and Transport
Forklift
Forklift
Yard Tractor
Top Loader
Switcher Locmotive
Marine Propulsion
Marine Shore Power
Marine Shore Power
Marine Shore Power
Stationary Power
Stationary Power
Stationary Power
>
>
>
>
>
>
>
>
>
>
>
>
>
>
Fuel Cell Type
On site Fuel Cell
Equipment Use
PEMFC
Forklift
AFC/AMFC
Forklift
PEMFC
Yard Tractor
PEMFC
Top Loader |
PEMFC
Switcher Locmotive
PEMFC
Marine Propulsion
PSEF
MartfnHrhw"' """ii ii
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>
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>
>
>
>
>
Fuel Cell
Equipment
Application
Disposal and
Recycling and
Transport
Processing
Processing
Processing
Processing
Processing
Processing
Processing
Figure 19. Fuel Cell Equipment Cycle Pathways
*ERG
6-7
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In addition to fuel cell components and systems, the production of the balance of equipment components and
systems comprising each port application must also be accounted for. In the case of mobile equipment this
includes the interior and exterior body, chassis and suspension, powertrain, transmission, electric systems,
fluids, tires, and control systems. For components like batteries and fluids that will require replacement during
the equipment's lifetime, additional energy and emissions assessments will be required based on typical
replacement cycles.
6.3.3 Fuel Cell Equipment Application Assembly
Fuel cell equipment assembly consists of the unique component assembly requirements for the specific port
equipment applications, including the incorporation of the fuel cell power and propulsion systems. Final fuel
cell equipment assembled products can be transported via ship, rail, and/or truck.
6.3.4 Fuel Cell Equipment Application Disposal/Recycling
The final element of the Fuel Cell Equipment Cycle is equipment disposal and recycling. This accounts for the
energy and emissions associated with assembled equipment disposal and/or dismantling for material recycling,
Recycled materials used in original equipment production should be accounted for in the total fuel cell
equipment cycle energy use and emissions.
6.4 Lifecycle Emissions Estimation Methodology, Tools, and Resources for Port Equipment
Applications
The following section outlines one basic methodology, tools, and available resources for estimating the
lifecycle emissions associated with operating fuel cell equipment in key applications at U.S. port locations. The
methodology applies total lifecycle energy and emissions analysis for assessing lifecycle emissions for port fuel
cell equipment relative to their conventional diesel counterparts. Available estimation tools are also discussed
for supporting the methodology.
6.4.1 Proposed Lifecycle Emissions Estimation Framework
The near- and mid-term hydrogen fuel and fuel cell equipment cycle constructs discussed above in this section
form the basis from which lifecycle emissions analysis can be conducted for evaluating the multitude of
hydrogen production, distribution and delivery routes, and fuel cell equipment usage at U.S. ports. The
proposed methodology covers fuel cycle, onsite use of port equipment, and port equipment cycle
requirements separately, but assesses lifecycle emissions under each of these segments for both traditional
diesel fuel and hydrogen fuel so that comparisons can be made. Pollutant coverage in the framework includes
criteria pollutants, greenhouse gases, and MSATs. In all cases, pollutant coverage was dependent upon
available models, emission factors, and emissions research. As a result, consistent pollutant coverage across
lifecycle framework elements was not always possible. For example, MSAT pollutant coverage was only
possible for port equipment-related emissions; MSAT pollutants related to fuel production, storage, and
transport were not available given the scope of this initial assessment.
6.4.1.1 Fuel Cycle Well-to-Pump
For both the diesel fuel and hydrogen fuel cycle pathways, it is proposed that ANL's Greenhouse Gases,
Regulated Emissions, and Energy use in Transportation (GREET) model be utilized. The model is available as
GREET.Net with graphical interface or as GREET Excel which incorporates separate spreadsheet sub-models for
fuel cycle and vehicle/equipment cycle analyses (Argonne National Laboratory, 2019).
GREET incorporates internal databases for assessing a multitude of conventional and alternative fuel cycles.
For purposes of this analysis, the following fuel pathways were considered:
• U.S. Average Low Sulfur Diesel Fuel Production from Crude Oil
*ERG
6-8
-------
• Centralized Hydrogen Production: Natural Gas SMR, Biomass Gasification, and Electrolysis Using Solar
Power
• Distributed Hydrogen Production: Natural Gas SMR, Electrolysis Using Solar Power, and Electrolysis Using
Grid Electricity
The model can be used to derive energy consumption, GHG and criteria pollutant emissions, and water
consumption for the "Well-to-Pump (WTP)" portion of the fuel cycle, that is, fuel feedstock extraction and
transport, fuel production and transport, and fuel distribution and dispensing. The following WTP pollutants
are available from GREET:
• Volatile Organic Compounds (VOC)
• Carbon Monoxide (CO)
• Nitrogen Oxides (NOx)
• Particulate Matter 10 Microns and Smaller (PMi0)
• Particulate Matter 2.5 Microns and Smaller (PM25)
• Sulfur Oxides (represented as S02 in this analysis)
• Carbon Dioxide (C02)
• Methane (CH4)
• Nitrous Oxide (N20)
Table 36 lists calendar year 2020 WTP results using 2019 GREET.Net17 for conventional low sulfur diesel and
various selected centralized and distributed gaseous and liquid hydrogen production pathways. Results are
presented on a per diesel gallon18 basis for the low sulfur diesel fuel pathway, and on a per kg hydrogen19
produced basis for the hydrogen pathways. The following 2019 GREET.Net fuel pathways were utilized:
• Low Sulfur Diesel from Crude Oil
• Central Plants: Compressed G.H2 via Pipeline from Natural Gas (w/o C02 Sequestration)
• Central Plants: Compressed G.H2 via Pipeline from Solar Energy
• Central Plants: Compressed Gaseous Hydrogen via Pipeline from Biomass (H2A Model)
• Refueling Stations: Compressed G.H2 from Natural Gas (w/o C02 Sequestration)
• Refueling Stations: Compressed Gaseous Hydrogen from Electricity
• Central Plants: L.H2 from NA Natural Gas (w/o C02 Sequestration) (Simplified)
• Central Plants: Liquid Hydrogen from Biomass
• Central Plants: Liquid Hydrogen from Solar Power
• Refueling Stations: L.H2 from NA Natural Gas (w/o C02 Sequestration)
• Refueling Stations: Liquid Hydrogen from U.S. Electricity
17 2019 GREET.Net, accessed December 2019.
18 Low sulfur diesel lower heating value - 129,488 BTU/gal (Source: GREET.Net)
19 Hydrogen lower heating value - Gaseous H2 113,725 BTU/kg; Liquid H2 113,822 BTU/kg (Source: GREET.Net)
*ERG
6-9
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For each pathway, default GREET.Net model assumptions were assumed except for the following year 2020
electricity generation mix based on the ElA's Annual Energy Outlook 2020:
Assumed 2020 U.S. Average Electricity Generation Mix (Percent)
Coal
Oil
Natural
Gas
Nuclear
Hydro-
electric
Biomass
Wind
Solar
Geothermal
Biogenic
Waste
22.0
0.6
40.3
19.0
7.0
1.6
6.5
1.5
0.5
0.5
In general, the Table 36 WTP results for the hydrogen production pathways are much more energy and water
use intensive than diesel fuel production on a per unit fuel production basis. Centralized processes exhibited
lower water consumption rates than distributed processes in general. Solar-based electrolysis (both
centralized and distributed) displayed the lowest water consumption rates among the hydrogen pathways.
Those hydrogen production pathways with lower fossil energy inputs such as centralized biomass gasification,
solar-based electrolysis, and distributed solar-based electrolysis, exhibited the lowest criteria pollutants and
GHG emissions in general. Further, liquid hydrogen production pathways tended to have higher energy use
requirements due primarily to hydrogen liquefaction processes, and this higher energy use generally
correlated with higher emissions. However, in the case of Iquid hydrogen produced from centralized biomass
gasification, the assumed use of biomass-generated electricity through integrated gasification combined cycle
(IGCC) power for the liquefaction process resulted in lower net C02 emissions (process C02 minus biogenic
C02) than gaseous hydrogen production from centralized biomass gasification. In addition, emissions from
liquid hydrogen produced from centralized solar-based electrolysis were generally lower than those from
gaseous hydrogen in Table 36 since the liquefied pathway assumed the liquefaction process was powered by
solar power.
Since regional electricity generation can vary considerably across the U.S., several results for distributed, grid-
based electrolysis were analyzed using 2019 GREET.Net. In addition to the previously described U.S. average
mix, two additional grid electricity generation mixes were assumed for distributed, grid-based electrolysis as
shown in Table 37: High Coal and Low Renewables Generation Mix and Low Coal and High Renewables
Generation Mix. These assumed 2020 electricity resource mixes were as follows:
Additional
Electricity
Mix Types
Assumed 2020 Electricity Generation Mixes (Percent)
Coal
Oil
Natural
Gas
Nuclear
Hydro-
electric
Biomass
Wind
Solar
Geothermal
Biogenic
Waste
High
Coal/Low
Renewables
92.0
0.0
2.1
0.0
3.0
0.0
2.9
0.0
0.0
0.0
Low
Coal/High
Renewables
0.0
0.2
0.3
4.0
60.0
5.0
17.0
13.5
0.0
0.0
The High Coal/Low Renewables and Low Coal/High Renewables cases were derived based on the range of
electricity generation mixes reported by EIA at the state levels. Note that grid-based electrolysis with the U.S.
Average Generation Mix required more energy and produced higher emissions than other hydrogen pathways
on a per kg basis. Grid-based electrolysis with the High Coal/Low Renewables mix required even higher energy
use and produced higher emissions than the U.S. Average mix resulting from its very high fossil energy input
(94.1 percent). The Low Coal/High Renewables mix, conversely, generally produced the lowest emissions of
the three electricity mix cases for distributed grid-based electrolysis due to its heavy reliance on renewable
energy. These results indicate that distributed grid-based electrolysis in areas of the country served by
electrical grids with high renewable energy input will have better lifecycle emissions than those with high fossil
energy fractions.
*ERG
6-10
-------
Table 36. 2019 GREET WTP Results for Gaseous and Liquid Hydrogen Production
Hydrogen WTP Pathway
Total
Energy
(BTU)
Fossil
Energy
Fraction
Water
Use (gal)
Pollutant Emissions (grams)
VOC
CO
NOx
PM10
PM2.5
sox
C02
ch4
N20
Diesel Fuel Production [per Gallon]
Low Sulfur Diesel
23,149
0.99
2.9
0.97
1.54
2.61
0.20
0.16
0.88
1,640.00
14.04
0.03
Centralized Hydrogen Production (Gaseous Product) [per kg]
Natural Gas SMR
63,511
0.96
5.6
1.37
2.71
3.35
0.54
0.38
3.36
10,550.00
26.65
0.09
Biomass Gasification
174,888
0.15
7.6
0.92
2.79
3.64
0.55
0.33
7.54
3,170.00
6.79
0.00
Electrolysis Solar
69,375
0.12
5.7
0.21
0.93
1.04
0.22
0.08
1.86
1,750.00
3.71
0.03
Distributed Hydrogen Production (Gaseous Product) [per kg]
On-site Natural Gas SMR
79,618
0.97
5.4
1.94
6.29
7.43
0.43
0.29
3.34
11,470.00
40.30
0.26
On-site Electrolysis Solar
62,663
0.00
14.2
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
On-site Electrolysis Grid (US Avg)
207,958
0.77
38.2
2.28
10.11
11.41
2.43
0.84
20.29
19,070.00
40.47
0.30
On-site Electrolysis Grid (High
Coal/Low Renewable)
341,742
0.98
35.8
3.28
2.54
10.75
4.39
1.03
75.30
44,060.00
65.11
0.70
On-site Electrolysis Grid (Low
Coal/High Renewable)
91,501
0.01
148.3
0.35
10.68
2.76
3.50
1.04
1.55
200.00
0.41
0.04
Centralized Hydrogen Production (Liquid Product) [per kg]
Natural Gas SMR
110,666
0.92
9.9
1.71
4.21
5.23
0.89
0.51
6.22
13,360.00
32.62
0.14
Biomass Gasification1
257,339
0.07
5.3
1.94
3.37
5.22
0.74
0.50
21.88
1,770.00
4.25
0.96
Electrolysis Solar2
86,760
0.00
4.5
0.02
0.07
0.26
0.01
0.01
0.00
46.86
0.06
0.00
Distributed Hydrogen Production (Liquid Product) [per kg]
On-site Natural Gas SMR
151,994
0.92
12.2
2.45
8.57
10.00
0.98
0.48
7.89
15,760.00
49.45
0.33
On-site Electrolysis Solar
94,841
0.00
15.3
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
On-site Electrolysis Grid (US Avg)
265,628
0.77
42.3
2.69
11.92
13.45
2.87
0.99
23.92
22,490.00
47.71
0.35
On-site Electrolysis Grid (High
Coal/Low Renewable)
423,312
0.98
40.8
3.86
2.99
12.67
5.18
1.22
88.77
51,940.00
76.76
0.82
On-site Electrolysis Grid (Low
Coal/High Renewable)
128,200
0.01
174.4
0.42
12.59
3.25
4.12
1.22
1.82
240.00
0.48
0.05
1 Pathway includes hydrogen liquefaction process supported by electricity generated from switchgrass integrated gasification combined cycle (IGCC) power plant.
2 Pathway includes hydrogen liquefaction process supported by electricity generated from solar power.
*ERG
6-11
-------
6.4.1.2 Fuel Cycle Onsite Use (Pump-to-Wheels) of Port-related Equipment
The lifecycle results for equipment use are the remaining component of the full fuel cycle and are referred to
as the "Pump-to-Wheels (PTW)" component. (Combining the WTP results with the PTW results provides the
full fuel cycle, or "Well-to-Wheels (WTW)", results.) The GREET model does provide lifecycle results for
equipment use but only for on-road vehicles and their typical duty cycles. Thus, for the port-related
equipment, it is proposed that other models or sources are utilized for generating equipment use lifecycle
emissions.
Table 37 provides a listing of recommended models and sources for estimating PTW lifecycle emissions. For
port-related nonroad mobile diesel-powered equipment such as forklifts, yard tractors, and top loaders, the
Nonroad module of EPA's MOtor Vehicle Emission Simulator (MOVES) should be used (U.S. EPA, 2019). MOVES
is an emission modeling system that estimates emissions for mobile sources at the national, county, and
project level for criteria air pollutants, greenhouse gases, and air toxics. MOVES-Nonroad can provide fuel
consumption, exhaust emission, and evaporative emission estimates.
Table 37. Recommended Emission Estimation Models/Sources by Port Equipment Application
Port Equipment Application
Emissions Estimation Model/Source
Diesel Forklift
EPA MOVES-Nonroad model
Diesel Yard Tractor
EPA MOVES-Nonroad model
Diesel Top Loader
EPA MOVES-Nonroad model
Diesel Switcher Locomotive
EPA Locomotive Emission Factor Guidance, National Port Strategy
Assessment
Marine Propulsion
EPA MOVES-Nonroad model, National Port Strategy Assessment
Stationary Power
EPA eGRID model, EPA AP-42 Emission Factors for Electric Power Generation,
EPA Potential to Emit Calculator for CI Engines
For switcher locomotives, the analysis utilized EPA locomotive emission factors (U.S. EPA, Office of
Transportation and Air Quality, 2019) and EPA's National Port Strategy Assessment methodologies (U.S. EPA,
Office of Transportation and Air Quality, 2016). For marine propulsion, the National Port Strategy Assessment
provides a comprehensive methodology for estimating emissions for various vessel types and sizes. Similarly,
the National Port Strategy Assessment, along with EPA's Shore Power Emissions Calculator, can used for
estimating vessel shore power emissions. Finally, for stationary power sources EPA's Emissions & Generation
Resource Integrated Database (eGRID) model was used for estimating electric generation emissions. The
eGRID model can estimate regional emission rates based on electric power sources across the country. For
estimating diesel standby power generator emissions, appropriate emission factors from EPA's AP-42 can and
were employed. In the case of stationary power fuel cells using direct natural gas internal reforming
manufacturer information was used as available to estimate emissions.
Based on these sources, PTW lifecycle factors for a variety of diesel-powered port equipment were identified
and are presented in Table 38. The pollutants covered include the following: VOC, CO, NOx, PMio, PM25, S02,
C02, CH4, N20, Benzene, Formaldehyde, Acetaldehyde, and Acrolein.
The PTW factors for diesel equipment in Table 38 are listed on a per gallon diesel basis. The average
equipment model years and power levels assumed for purposes of the analysis in this report were based on
the actual port equipment inventory information presented earlier in the report. Emission factors for port
equipment representing different model years and/or power levels should be obtained from the previously
mentioned sources in deriving port specific PTW estimates. To estimate equipment fuel use rates for this
report, an average brake specific fuel consumption rate of 0.367 lb/hp-hr20 was utilized from the EPA Nonroad
20 This value is from MOVES, based on MY 1988-1995 engines. It may not represent the latest in the literature.
*ERG
6-12
-------
model documentation dated July 2018 for each of the diesel port-related equipment (U.S. EPA, Office of
Transportation and Air Quality, 2018). This documentation was also referenced for nonroad emission factors.
An average fuel sulfur content of 15 ppm was assumed for all port equipment diesel fuel. Average fuel use
rates of gallon per hour were derived by applying the assumed rated horsepower and load factor for each
equipment type and an average diesel fuel density of 6.93 lb/gallon. Average fuel rates could also be obtained
from diesel equipment manufacturers for specific models as available.
There are no PTW emissions for comparable hydrogen fuel cell port equipment since hydrogen fuel cells emit
only water vapor and heat.
6.4.1.3 Fuel Cycle Well-to-Wheels
As noted above, full fuel cycle (WTW) energy and emission estimates for fuel cell port equipment applications
can be derived by compiling WTP and PTW estimates. Table 39 provides the incremental WTW emission
results21 for port fuel cell equipment versus comparable diesel equipment for the gaseous hydrogen fuel
delivery pathways listed in Table 36. Note that the results of Table 39 are presented on a hp-hr equivalent and
efficiency adjusted basis22. That is, the results consider the energy content difference between hydrogen and
diesel fuel as well as the increased energy efficiency of hydrogen fuel cells compared to diesel engines. Fuel
cell equipment energy efficiencies for each port application were estimated based on fuel cell efficiencies
(assuming PEMFCs), current fuel cell equipment drivetrain configurations, and estimated duty cycle efficiencies
(Ahluwalia, 2020). Similar estimations were made for the baseline diesel equipment the fuel cell equipment
would replace. Based on this analysis, the following relative energy efficiencies of each port equipment type
was applied23 to the WTP emission estimates of Table 36:
Estimated H2 Fuel Cell to Diesel Energy Efficiency Ratio
Forklift
Yard
Tractor
Top
Loader
Marine
Vessel
Switcher
Locomotive
Stationary
Generator
2.52
2.52
2.52
1.35
1.77
2.04
21 WTW estimates for air toxic pollutants were not possible due to a lack of WTP estimates for these pollutants.
22 Based on LHVs: 129,488 BTU/gal low sulfur diesel, 113,725 BTU/kg gaseous hydrogen, and 113,822 BTU/kg liquid hydrogen.
23 WTP estimates were divided by the H2 Fuel Cell to Diesel Energy Efficiency Ratios to obtain efficiency adjusted values.
*ERG
6-13
-------
Table 38. PTW Factors for Diesel-Fueled Port Equipment per Gallon Diesel Fuel
Diesel Port Equipment Type
Typical
Propulsion
Power
Pollutant Emissions (gm/gallon)
VOC
CO
NO„
PM10
PM2.5
so2
co2
ch4
n2o
Benz
Form
Acet
Aero
Forklift
100
5.10
70.40
63.26
0.57
0.56
0.09
10,023
0.35
...
0.26
1.45
0.52
0.09
Yard Tractor
200
2.84
1.47
22.03
0.22
0.22
0.07
10,029
0.25
...
0.15
0.83
0.30
0.05
Top Loader
310
2.84
1.68
26.32
0.24
0.23
0.07
10,029
0.25
...
0.15
0.83
0.30
0.05
Assist Tugboat
1,908
3.81
35.25
138.17
3.64
3.53
0.09
9,729
0.14
0.44
0.09
0.85
0.30
0.06
Ferry
1,718
2.82
70.50
98.70
2.43
2.35
0.09
9,729
0.14
0.44
0.15
0.82
0.29
0.05
Harbor Tugboat
711
2.82
70.50
98.70
2.43
2.35
0.09
9,729
0.14
0.44
0.15
0.82
0.29
0.05
Switcher Locomotive
2,000
11.06
27.82
187.00
4.10
3.98
0.09
10,208
...
...
0.02
0.29
0.12
...
Power Generator
135
21.18
70.50
56.40
4.23
4.10
0.09
10,210
0.41
0.08
0.06
0.07
0.05
0.01
*ERG
6-14
-------
Table 39. Summary of WTW Emission Reductions for Fuel Cell Equipment/Gaseous Hydrogen Fuel Pathways Relative to Comparable Diesel-
Fueled Equipment
Fuel Cell
Equipment
Type
Hydrogen Fuel Pathway
WTW Emission Reductions Relative to Diesel-Fueled Equipment (g/hp-hr) [Efficiency Ad
usted]
VOC
CO
NOx
PMio
PM2.5
SOz
COz
CH4
NzO
Yard Tractor
Centralized NG SMR
0.063
0.035
0.458
0.004
0.004
-0.011
136.668
0.045
0.000
Centralized Biomass Gasification
0.067
0.035
0.455
0.003
0.005
-0.049
202.697
0.222
0.001
Centralized Electrolysis Solar
0.073
0.051
0.479
0.006
0.007
0.002
215.402
0.250
0.000
Distributed NG SMR
0.058
0.003
0.421
0.005
0.005
-0.011
128.437
-0.078
-0.002
Distributed Electrolysis Solar
0.075
0.060
0.488
0.008
0.007
0.019
231.060
0.283
0.001
Distributed Electrolysis Grid (US Avg)
0.055
-0.031
0.386
-0.013
0.000
-0.163
60.440
-0.079
-0.002
Distributed Electrolysis Grid (Hi Coal)
0.046
0.037
0.392
-0.031
-0.002
-0.655
-163.147
-0.300
-0.006
Distributed Electrolysis Grid (Lo Coal)
0.072
-0.036
0.463
-0.023
-0.002
0.005
229.270
0.279
0.000
Forklift
Centralized NG SMR
0.108
1.400
1.274
0.011
0.011
-0.011
136.549
0.047
0.000
Centralized Biomass Gasification
0.112
1.400
1.272
0.010
0.011
-0.048
202.578
0.224
0.001
Centralized Electrolysis Solar
0.118
1.416
1.295
0.013
0.014
0.003
215.283
0.252
0.000
Distributed NG SMR
0.103
1.368
1.238
0.011
0.012
-0.011
128.318
-0.076
-0.002
Distributed Electrolysis Solar
0.120
1.425
1.304
0.015
0.014
0.019
230.940
0.285
0.001
Distributed Electrolysis Grid (US Avg)
0.100
1.334
1.202
-0.006
0.007
-0.162
60.320
0.285
0.001
Distributed Electrolysis Grid (Hi Coal)
0.091
1.402
1.208
-0.024
0.005
-0.654
-163.266
-0.298
-0.006
Distributed Electrolysis Grid (Lo Coal)
0.117
1.329
1.280
-0.016
0.005
0.005
229.151
0.281
0.000
Cargo Handler
(Top Loader)
Centralized NG SMR
0.063
0.040
0.543
0.004
0.004
-0.011
136.668
0.045
0.000
Centralized Biomass Gasification
0.067
0.039
0.540
0.004
0.005
-0.049
202.697
0.222
0.001
Centralized Electrolysis Solar
0.073
0.055
0.563
0.007
0.007
0.002
215.402
0.250
0.000
Distributed NG SMR
0.058
0.008
0.506
0.005
0.005
-0.011
128.437
-0.078
-0.002
Distributed Electrolysis Solar
0.075
0.064
0.573
0.009
0.008
0.019
231.060
0.283
0.001
Distributed Electrolysis Grid (US Avg)
0.055
-0.027
0.471
-0.013
0.000
-0.163
60.440
-0.079
-0.002
Distributed Electrolysis Grid (Hi Coal)
0.046
0.041
0.477
-0.031
-0.001
-0.655
-163.147
-0.300
-0.006
Distributed Electrolysis Grid (Lo Coal)
0.072
-0.032
0.548
-0.023
-0.002
0.005
229.270
0.279
0.000
Assist Tugboat
Centralized NG SMR
0.072
0.683
2.732
0.067
0.067
-0.037
48.922
-0.164
0.008
Centralized Biomass Gasification
0.079
0.682
2.727
0.067
0.068
-0.107
172.177
0.167
0.009
*ERG
6-15
-------
Fuel Cell
Equipment
Type
Hydrogen Fuel Pathway
WTW Emission Reductions Relative to Diesel-Fueled Equipment (g/hp-hr) [Efficiency Ad
usted]
VOC
CO
NOx
PMio
PM2.5
SOz
COz
CH4
NzO
Centralized Electrolysis Solar
0.091
0.713
2.770
0.072
0.072
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.062
0.623
2.664
0.069
0.068
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.095
0.728
2.788
0.076
0.073
0.019
225.119
0.281
0.009
Distributed Electrolysis Grid (US Avg)
0.057
0.560
2.597
0.035
0.059
-0.320
-93.371
-0.395
0.004
Distributed Electrolysis Grid (Hi Coal)
0.040
0.686
2.608
0.003
0.056
-1.238
-510.732
-0.807
-0.002
Distributed Electrolysis Grid (Lo Coal)
0.089
0.550
2.742
0.018
0.056
-0.007
221.779
0.274
0.009
Ferry
Centralized NG SMR
0.052
1.381
1.950
0.043
0.043
-0.037
48.922
-0.164
0.008
Centralized Biomass Gasification
0.060
1.380
1.945
0.043
0.044
-0.107
172.177
0.167
0.009
Centralized Electrolysis Solar
0.072
1.411
1.989
0.048
0.048
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.043
1.321
1.882
0.045
0.045
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.075
1.426
2.006
0.052
0.050
0.019
225.119
0.281
0.009
Distributed Electrolysis Grid (US Avg)
0.037
1.258
1.815
0.011
0.036
-0.320
-93.371
-0.395
0.004
Distributed Electrolysis Grid (Hi Coal)
0.020
1.384
1.827
-0.021
0.033
-1.238
-510.732
-0.807
-0.002
Distributed Electrolysis Grid (Lo Coal)
0.069
1.248
1.960
-0.006
0.032
-0.007
221.779
0.274
0.009
Harbor
Tugboat
Centralized NG SMR
0.052
1.381
1.950
0.043
0.043
-0.037
48.922
-0.164
0.008
Centralized Biomass Gasification
0.060
1.380
1.945
0.043
0.044
-0.107
172.177
0.167
0.009
Centralized Electrolysis Solar
0.072
1.411
1.989
0.048
0.048
-0.012
195.892
0.219
0.009
Distributed NG SMR
0.043
1.321
1.882
0.045
0.045
-0.037
33.557
-0.392
0.005
Distributed Electrolysis Solar
0.075
1.426
2.006
0.052
0.050
0.019
225.119
0.281
0.009
Distributed Electrolysis Grid (US Avg)
0.037
1.258
1.815
0.011
0.036
-0.320
-93.371
-0.395
0.004
Distributed Electrolysis Grid (Hi Coal)
0.020
1.384
1.827
-0.021
0.033
-1.238
-510.732
-0.807
-0.002
Distributed Electrolysis Grid (Lo Coal)
0.069
1.248
1.960
-0.006
0.032
-0.007
221.779
0.274
0.009
Switcher
Locomotive
Centralized NG SMR
0.221
0.547
3.712
0.078
0.077
-0.024
100.225
-0.061
0.000
Centralized Biomass Gasification
0.226
0.546
3.708
0.078
0.078
-0.077
194.232
0.192
0.001
Centralized Electrolysis Solar
0.235
0.569
3.741
0.082
0.081
-0.004
212.321
0.231
0.000
Distributed NG SMR
0.213
0.501
3.660
0.080
0.078
-0.023
88.506
-0.235
-0.003
Distributed Electrolysis Solar
0.238
0.581
3.755
0.085
0.082
0.019
234.612
0.278
0.001
Distributed Electrolysis Grid (US Avg)
0.209
0.453
3.609
0.054
0.071
-0.239
-8.304
-0.237
-0.003
*ERG
6-16
-------
Fuel Cell
Equipment
Type
Hydrogen Fuel Pathway
WTW Emission Reductions Relative to Diesel-Fueled Equipment (g/hp-hr) [Efficiency Ad
usted]
VOC
CO
NOx
PMio
PM2.5
SOz
COz
CH4
NzO
Distributed Electrolysis Grid (Hi Coal)
0.196
0.549
3.618
0.029
0.069
-0.940
-326.630
-0.551
-0.008
Distributed Electrolysis Grid (Lo Coal)
0.234
0.445
3.719
0.041
0.069
0.000
232.065
0.273
0.000
Stationary
Generator
Centralized NG SMR
0.424
1.397
1.131
0.082
0.080
-0.018
118.051
-0.008
0.001
Centralized Biomass Gasification
0.429
1.396
1.128
0.082
0.081
-0.064
199.616
0.211
0.002
Centralized Electrolysis Solar
0.436
1.416
1.157
0.085
0.084
-0.001
215.311
0.245
0.002
Distributed NG SMR
0.417
1.357
1.086
0.083
0.081
-0.018
107.883
-0.159
-0.001
Distributed Electrolysis Solar
0.439
1.426
1.168
0.088
0.084
0.019
234.652
0.286
0.002
Distributed Electrolysis Grid (US Avg)
0.413
1.315
1.042
0.061
0.075
-0.205
23.886
-0.161
-0.001
Distributed Electrolysis Grid (Hi Coal)
0.402
1.398
1.050
0.039
0.073
-0.813
-252.309
-0.433
-0.006
Distributed Electrolysis Grid (Lo Coal)
0.435
1.308
1.138
0.049
0.073
0.002
232.442
0.282
0.002
*ERG
6-17
-------
Positive emissions reductions in Table 39 are highlighted in green, indicating that gaseous hydrogen fuel cell
equipment WTW emissions are lower than those of diesel equipment per kg equivalent consumed, while
negative values shown in red signify gaseous hydrogen fuel cell WTW emission reductions are higher than
diesel. Similar WTW results can be obtained for the liquid hydrogen fuel pathways listed in Table 36 using the
same methodology.
The WTW results show that hydrogen fuel cell-powered equipment in various port applications can achieve
significant lifecycle emission reductions. Reductions in VOC and NOx emissions were achieved across all port
equipment types for each of the gaseous hydrogen fuel delivery pathways. CO emissions were generally lower
for the majority of fuel cell equipment and gaseous hydrogen pathways, except for yard tractors and top
loaders under the U.S. Average and Low Coal/High Renewables grid-based electrolysis pathway. Lower PMio
were determined for fuel cell equipment applications and gaseous hydrogen fuel pathways, except for yard
tractors, forklifts, top loaders, ferries, and harbor tugboats under the grid electrolysis pathways. PM25
emissions were lower for all port equipment applications and gaseous hydrogen fuel pathways except for yard
tractors and top loaders under some grid-based electrolysis pathways. All fuel cell equipment produced higher
S02 emissions for all gaseous hydrogen fuel pathways except for some solar-based electrolysis and low
coal/high renewables grid-based electrolysis pathways. The increased S02 emissions result from higher levels
created from gaseous hydrogen fuel feedstock processes, fuel production, and fuel compression. S02 levels
were significantly higher for the U.S. average and high coal mix grid-electrolysis processes resulting from their
intensive electricity use and high fossil fuel resources. WTW C02 emissions were significantly lower for fuel cell
equipment for all gaseous hydrogen fuel pathways, apart from high coal/low renewables generation grid-
based electrolysis and for some equipment applications, U.S. average grid-based electrolysis. Mixed results
were observed for WTW CH4 emissions across applications with generally higher values for natural gas SMR
pathways, U.S. average grid electrolysis, and high coal/low renewables electrolysis, and lower values for
biomass gasification, solar-based electrolysis, and low coal/high renewables electrolysis. Similarly, WTW
results for N20 emissions varied with higher levels from for natural gas SMR, U.S. average grid electrolysis, and
high coal/low renewables electrolysis pathways, and lower values for biomass gasification, solar-based
electrolysis, and low coal/high renewables electrolysis pathways, depending on the equipment application.
Upon review of individual pathway WTW results, all gaseous hydrogen fuel pathways provided significant
emission reductions for most port equipment applications, although higher S02 emissions did occur in many
cases. Again, these higher levels of S02 emissions were attributed to WTP hydrogen feedstock, production,
transport (for centralized pathways), and gaseous hydrogen compression processes, not the fuel cell
equipment PTW segment. Thus, the hydrogen WTP S02 emissions surpassed those of the diesel WTW (both
WTP and PTW segments) pathway. Overall, the solar-based electrolysis pathway emerged as the highest
performing hydrogen fuel pathway for both centralized and distributed cases. The performance of distributed
grid-based electrolysis is highly dependent on the electricity generation mix. Regions of the country with high
coal and low renewable resource electricity generation can be expected to produce significantly less favorable
grid-based electrolysis pathway WTW emission results as compared to regions with low coal and high
renewable resource generation mixes. Further, the WTW emission results presented here were dictated by
specific assumptions for both WTP and PTW estimates. WTW results may vary depending on hydrogen
production scenarios, feedstock and fuel transport modes, and port equipment types and sizes. As such, local
and regional analysis can facilitate emissions assessments associated with hydrogen fuel cell equipment use at
port locations.
6.4.1.4 Port-related Equipment Cycle
As a reminder, the equipment cycle includes the resources and energy necessary to produce, dispose of, and
recycle equipment. The individual components of the equipment cycle include materials recovery, processing
and transport, component fabrication and transport, equipment assembly and transport, and equipment
disposal and recycling.
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The GREET model provides both diesel and hydrogen fuel cell equipment cycle results, but only for on-highway
vehicle types including light duty vehicles such passenger cars, sport utilities, and pickup trucks. While these
results cannot be applied directly for the nonroad port-related equipment such as forklifts, yard tractors, and
top loaders, this functionality could be modified for application to the nonroad equipment assuming similar
manufacturing processes and energy intensities albeit for different material types and compositions.
To determine equipment cycle results, the GREET model assesses raw material recovery and processing,
vehicle component production and vehicle assembly, and vehicle disposal and recycling (Burnham, Wang, &
Wu, 2006). The model first estimates vehicle component weight for the major components of the vehicle
including the body, chassis, batteries, fluids, powertrain (engine or fuel cell stack and auxiliaries), and
transmission or gearbox. The component categories are comprised of systems and subsystems, and not every
vehicle type has all the systems or subsystems. For all vehicle types within a category including fuel cell
vehicles, the weights of the engine or fuel cell and transmission are scaled for equivalent performance
requirements. Next, the model assigns a material composition to each major component and includes
replacement schedules for component materia Is that are replaced over the vehicle's lifetime. For vehicle
disposal and recycling, the model estimates energy and emissions associated with scrap material recycling and
fabrication for reuse. Based on the materials specified, the model also estimates energy use from material
recovery to vehicle assembly.
The weight of each vehicle component is aggregated with the weights of other corresponding components and
then divided by the total weight of all vehicle components to obtain component specific fractional weights.
When the total vehicle weight is changed in the GREET model by the user, these fractional Figures along with
material composition Figures are used to determine the weight of each material in a component category.
In order to estimate equipment cycle results for forklifts, yard tractors, and top loaders, for future assessments
it is recommended that the fractional weight and material composition inputs in the GREET model be modified
for representing these port equipment applications. This will require additional research to identify port
equipment components, systems, and materials for inclusion in the model. These updated Figures can then be
inputted appropriately into the model to assess equipment cycle results for the forklift, yard, tractor, and top
loader categories. As a caveat to this approach, the GREET model currently only supports analysis on PEMFCs.
Therefore, analysis on AFC/AMFC-powered forklifts for example would not be directly possibly, but
extrapolation of the PEMFC-powered forklift results may be possible.
For the remaining port equipment types considered in this task, switcher locomotive, marine propulsion, and
stationary power, the determination of an approach for equipment cycle estimation was not possible due to
current limits on scope and budget. Significant additional lifecycle assessment research on these port
equipment applications is recommended to fully assess their equipment cycle energy and emission
contributions.
6.5 Port Locations and Regional Analysis Results
Regional analysis is important in assessing the energy use, greenhouse gas emissions, and costs associated
with hydrogen fuel cell equipment use at port locations since the type of hydrogen production and the
distances and modes for transporting hydrogen to the port site can greatly impact the results. Based on a
port's location, an assessment can be made regarding the most viable near- and mid-term hydrogen product
pathways for delivery to the site. For example, a port located in Louisiana would have higher potential for
hydrogen fuel service from a centralized natural gas SMR plant rather than a centralized coal gasification plant
based on its geographical location.
The regional results can also assist in assessing hydrogen fuel product transport distances from viable
production regions or from existing infrastructure networks to actual port locations. Hydrogen fuel and
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hydrogen fuel carrier transport-related energy use and emissions can be significant when considered long
distances for site delivery. Additionally, in assessing gaseous versus liquefied hydrogen product delivery,
gaseous hydrogen transport via truck or rail generally only makes economic sense for transport distances of
less than 200 miles. For distances over 200 miles but less than 1,000 miles, liquefied hydrogen transport is
more economically favorable.
Furthermore, port location in relation to available electricity generation source mix is also important. For port
sites with regional electricity more reliant on fossil fuel-powered generation, the lifecycle emission reduction
potential for hydrogen fuel cell use is lower given the high electricity requirements of some hydrogen
production processes. For these sites, distributed hydrogen production using renewable energy sources may
have higher emissions reduction potential.
6.6 Additional Analytical Sources
The U.S. Department of Energy's Hydrogen and Fuel Cell Program established the Hydrogen Analysis (H2A)
Project to establish a repository of information and analytical results for the hydrogen and fuel cell research
community (DOE Hydrogen Program, 2019). The project's website maintains the latest information on DOE
programs and links to DOE-sponsored research including hydrogen production and delivery models and case
studies. Relevant lifecycle model results and case studies for this task work include the following:
• Centralized Hydrogen Production (greater than 50,000 kg/day hydrogen production)
o Coal Gasification
o Natural Gas SMR
o Biomass Gasification
• Distributed Hydrogen Production (100-1,500 kg/day hydrogen production)
o Natural Gas SMR
o Water Electrolysis (Grid)
o Ethanal (Corn) ESR
• Hydrogen Delivery Methods
o Hydrogen Pathways: gaseous hydrogen via pipeline, gaseous hydrogen via tube trailer and
liquefied hydrogen via tank truck
o Components Model: pipelines, compressors, tube trailers, liquefied tank trucks, liquefaction
plants, gaseous tube storage, geologic storage gaseous terminals, and liquefied hydrogen
terminals
o Scenario model: geographic-specific scenarios for delivery infrastructure
The information contained under the H2A project can be used to directly inform the proposed lifecycle
emissions analytical framework established in this report.
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7. Future Hydrogen and Fuel Cell Market Penetration
7.1 Primary Factors for Future Fuel Cell Commercial Viability and Competitiveness
Fuel cell technology promises significant benefits for sustainable energy use into the future for a broad array of
port applications. Among these benefits include lower criteria pollutants, greenhouse gas, and noise emissions,
high energy efficiency and lower petroleum use, diverse fueling capability, and potentially lower maintenance
requirements. While the benefits are many, a variety of key factors impact future fuel cell commercial viability
and market competitiveness in ports and other sectors. These factors are equipment capital cost, equipment
durability/reliability, equipment power/duty cycle performance, equipment operational hours/range,
equipment maintenance/serviceability, and hydrogen fuel price. Each is discussed below.
7.1.1 Equipment Capital Cost
One of the key factors for future fuel cell technology competitiveness is capital cost. Fuel cell system costs are
currently much higher than those for traditional diesel fuel technologies at comparable power levels. This cost
disparity results from high-cost system designs and low-volume manufacturing. Table 40 displays DOE fuel cell
system cost estimates for various applications and manufacturing volumes on a per kW basis (Satyapal, 2018).
The Table also identifies DOE's program cost targets for each application which represent fuel cell system costs
that would be market competitive on a lifecycle basis. None of the current high production volume fuel cell
system costs currently achieve the DOE target values indicating that per unit costs need further reduction.
Table 19. Estimated Fuel Cell System Costs by Application and Production Volume
Cost/Production Metric
Forklifts
(5 kW)
Back-up Power Systems
(5 kW)
Stationary Power
Systems (25 kW)
Low Volume Production
Estimate ($/kW)
6,100 (100 units/yr)
7,400 (lOOunits/yr)
3,000 (100 units/yr)
High Volume Production
Estimate ($/kW)
2,800 (10,000 units/yr)
2,400 (50,000 units/yr)
3,200 (10,000 units/yr)
2,800 (50,000 units/yr)
2,000 (10,000 units/yr)
1,900 (50,000 units/yr)
DOE Target ($/kW)
NA
1,000
1,500
One element of current fuel cell research is on reducing costs for both fuel cell stack systems and balance of
plant (BOP) components (compressors, pumps, etc.) that support overall fuel cell system operation. Fuel cell
stack research is aimed at lowering fuel cell membrane and catalyst costs. Researchers are developing fuel cell
catalysts with very low or no platinum group metal (PGM) content to lower stack system costs ( DOE Fuel Cell
Technologies Office, 2017). PGM catalysts are expensive but are important for durability and fuel impurity
tolerance especially in high temperature fuel cell types that operate on syngas or mixed reformate fuels. In
automotive applications, researchers have identified catalyst costs as the single highest cost element for high-
volume production PEMFC fuel cell stacks. Researchers are also investigating cost reductions and
improvements in BOP components. BOP costs for automotive fuel cell systems make up about half of their
costs. Research is focused on lower cost external fuel processor reactors and sorbent bed systems for
reforming syngas fuels and removing fuel impurities (e.g., sulfur). Current fuel clean-up technologies are
effective at removing impurities but are very costly. Current practice is to customize fuel processors and clean-
up technologies to match individual fuel and fuel cell applications which limits the ability for high-volume
production and associated cost savings. This could potentially cause issues with fuel cell equipment inventories
with varying fuel quality requirements depending on the fuel cell type and equipment application. Common
fuel processor and clean-up systems capable of handling a variety of fuels will allow mass production and
lower costs and support broader fuel cell deployment. For high temperature fuel cell types like SOFCs, MCFCs,
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and PAFCs, more temperature tolerance catalyst structures and subsystems are under development for better
supporting high temperature operations and associated higher efficiencies.
7.1.2 Equipment Durability/Reliability
According to a recent DOE assessment, "fuel cells have not yet demonstrated a level of durability comparable
to the incumbent technologies in the main application areas of transportation and stationary power
generation" ( DOE Fuel Cell Technologies Office, 2017). This assessment is based on long-term testing
programs and on current fuel cell technology's ability to meet real-world operational conditions and duty
cycles over expected equipment application lifetimes including fuel impurities, cold weather starting and
operation, humidity, and load cycles. Of course, it should be stated that in these cases fuel cell technologies
are being compared with mature and market-proven technologies such as diesel engines. Ultimately, for fuel
cell applications at ports, extended in-use testing may be necessary in actual port operations with rapidly
changing duty cycles, humid-salty air, and ambient industrial air pollution to fully demonstrate fuel cell
reliability and potential performance detrioration.
In a recent study NREL presented long-term durability data based on laboratory testing of fuel cells from 23
domestic and international fuel cell developers across multiple applications including forklifts and stationary
prime and back-up power (Blenkey, 2019). On average, none of the systems met DOE's target metric for
accumulated operational hours before 10 percent voltage degradation. DOE uses the 10 percent voltage
degradation metric as an indicator of service life degradation, although it is not necessarily an end of useful life
indicator. For example, DOE estimates that the 5,000-hour durability target with less than 10 percent
degradation for automotive fuel cells is equivalent to about 150,000 miles of actual driving ( DOE Fuel Cell
Technologies Office, 2017). (It should be noted that DOE ultimately established an 8,000-hour durability target
associated with 150,000 miles of driving under a lower average speed drive cycle.) While the average NREL
operational data for each application did not meet the DOE targets, it should be pointed out that some
individual back-up power units did meet the target.
For applications with rapid cycling and frequent starts and stops such as nonroad vehicle applications, meeting
durability requirements is typically challenging. Higher fuel cell catalyst loadings can improve long-term
durability but at the expense of higher capital costs. BOP components are also a source of fuel cell durability
issues in PEMFCs. For example, about 90 percent of automotive fuel cell systems failures and forced outages
are due to BOP-related issues, including air blowers, compressors, and hydrogen fuel leaks ( DOE Fuel Cell
Technologies Office, 2017) (Eudy & Post, 2018). For low temperature fuel cells like PEMFCs, additional
research is needed for improving designs for more effective water management and operation below freezing
temperatures.
Fuel cells for stationary power systems must meet durability limits upwards of 60,000 hours to be competitive
with traditional diesel-fueled stationary power systems in some markets ( DOE Fuel Cell Technologies Office,
2017). SOFCs have demonstrated durability levels over 25,000 hours. As discussed above, the high operating
temperatures and thermal cycling of high temperature fuel cells (SOFC, MCFC, and PAFC) in stationary power
applications place additional long-term stress on a variety of fuel cell stack components. About 90 percent of
CHP fuel cell system failures and forced outages are due to BOP-related issues. Start-up and shutdown
durations and energy use under varied ambient conditions require improvement for high temperature fuel cell
types.
7.1.3 Equipment Power and Duty Cycle Performance
The power and duty cycle requirements of some port-related equipment applications are significant in terms
of maximum torque and power levels and durations spent at these levels. Fuel cell power plants must be
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capable of meeting these duty cycle demands to be viable alternatives to their diesel-fueled counterparts in
these applications.
The modularity and scalability of fuel cells enables their broad application in equipment ranging from kW to
MW power requirements. Necessary equipment power levels are achieved by combining multiples of the same
module. This is beneficial to manufacturers as well in terms of increasing production volumes of the same
module in order to lower per unit costs. Toyota is a good example of a manufacturer taking advantage of this
modularity. Toyota is currently producing the Mirai light duty fuel cell-powered sedan which utilizes a 114-kW
PEMFC stack. Toyota is also using multiple Mirai fuel cell stacks in parallel for other applications including a
pre-commercial drayage truck developed with Kenworth for a demonstration in California as well as its Sora
transit bus in Japan (Tajitsu & Shiraki, 2018). Further, Toyota bases its forklift fuel cell powerplant on the Mirai
sedan's powerplant, using the same fuel cells but different stack structure (370 total cells for the Mirai and 82
total cells for the forklift) (Schreffler, 2019).
For high power, heavy duty vehicle manufacturers are developing pre-commercial hybrid systems ranging from
fuel cell dominant to fuel cell range extender platforms. Similar modular approaches are being taken for
meeting the power demands in these applications. Table 41 illustrates the average power requirements and
fuel cell power system approach for one manufacturer of fuel cell hybrid container handlers for three types of
duty cycles (Nieuwland, 2017).
Table 41. Typical Fuel Cell Power Requirements and Range Extender Design for Various Container
Handler Duty Cycles
Duty Cycle*
Average Power Requirement (kW)
Fuel Cell Range Extender Power
#1
55-70
1x50 kW/2x30kW
#2
70-85
2x30kW/3x30kW
#3
85-110
3x30kW/2x50kW
*Duty cycle based on load monitoring at Port of LA
7.1.4 Equipment Operational Hours/Range
For effective utilization in port applications, fuel cell-powered equipment should have equivalent or greater
operational capacity (hours) or driving range compared with diesel-fueled equipment. For port applications
such as forklifts, yard tractors, and container handlers, operational capacity or driving range is important for
port operational efficiency and productivity so that equipment does not have to be frequently
refueled/recharged during shift work.
One of the benefits of fuel cell systems is that they are on average two times more energy efficient than diesel
engines. However, while hydrogen has excellent gravimetric (mass) energy density compared with diesel fuel,
as a gas under ambient conditions it exhibits poor volumetric energy density. To improve its volumetric energy
density in storage systems, hydrogen is compressed to high pressures (typically 350-700 barfor
vehicles/equipment storage) or liquefied at temperatures below its boiling point of-423°F (-253°C). Hydrogen
has a gravimetric energy density of about 120 MJ/kg compared to diesel fuel with about 43 MJ/kg (U.S.
Department of Energy, 2019). However, the volumetric energy density of hydrogen ranges from about 3MJ/L
as a gas at 350 bar pressure to 4 MJ/L as a gas at 700 bar, and 9 MJ/L as a liquid. This compares with diesel fuel
at about 38 MJ/L. Thus, on an equivalent volume basis, diesel fuel provides 4-12 times more energy depending
on how the hydrogen is stored on a vehicle or piece of equipment. For this reason, hydrogen fuel cell vehicles
and equipment require larger volume storage systems than comparable diesel vehicles and equipment even
with their increased energy efficiencies. For stationary power applications, hydrogen storage volume and
weight concerns are generally less of an issue for most sites.
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The issue of hydrogen storage volume can be exacerbated in heavy-duty vehicles and equipment such as used
at ports which have high fuel consumption, payload weight requirements, and limited space for hydrogen fuel
storage. Hydrogen stored at high pressures require high pressure storage cylinders that add to the overall
weight of the vehicles or equipment potentially limiting viable payload and increasing fuel consumption. The
fuel storage volume and weight issue become even more challenging for fuel cell hybrid platforms that
incorporate both fuel cells and large battery packs for meeting peak power and onboard energy storage
specifications.
As a near-term solution, manufacturers are developing higher pressure hydrogen fuel dispensing and onboard
storage systems. However, these systems have higher capital costs, and compressing hydrogen to higher
pressures increases dispensing station operating costs. Further, higher storage pressures increase fuel
temperatures during refueling resulting in lower refueling volume efficiency and lower final tank storage
pressures (and thus energy densities) once the fuel tanks cool down. As a longer-term solution (U.S.
Department of Energy, 2019), researchers are investigating cryo-compressed hydrogen dispensing and storage.
Cryo-compressed hydrogen involves the generation of compressed hydrogen gas from liquid hydrogen using a
cryogenic compressor. The cryo-compressed hydrogen gas is stored in heaviliy insulated pressure vessels. The
cryo-compressed gas has much higher densities at lower storage pressures than compressed hydrogen gas.
Cryo-compressed hydrogen storage offers potential improved performance compared to traditional high
pressure hydrogen storage both in terms of vehicle storage volume and weight, especially for larger vehicles.
In summary, most hydrogen fuel cell vehicles and equipment have comparable to slightly less operational
range than their diesel-fueled counterparts. This is accomplished by employing larger volume tanks, increasing
gaseous hydrogen storage pressures or liquid hydrogen product tanks, and/or using hybrid range extender
platforms that incorporate battery packs in addition to hydrogen storage. Cryo-compressed hydrogen storage
holds promise for higher hydrogen storage densities and corresponding improved operational range, but these
systems are still in the research phase.
7.1.5 Equipment Maintenance/Serviceability
Another factor in the commercial viability of fuel cell-powered port equipment is their ability to be reasonably
maintained and serviced. In theory, the maintenance for fuel cell-based drivetrains should be equivalent or
even less than that of comparable diesel engine drivetrains since the former are less mechanically complex and
rely on low-maintenance electric propulsion components such as electric motors. While this has generally
been born out for scheduled maintenance protocols for limited commercial and pre-commercial fuel cell
vehicles and equipment, the generally pre-commercial status of fuel cell systems has resulted in higher vehicle
and equipment downtimes due to unscheduled maintenance. These occurrences result not only from fuel cell
stack-related issues but also BOP failures, indicating further development work is necessary for comparable
reliability to diesel-powered versions. In addition, many fuel cell platforms are hybrid systems incorporating
advanced batteries and power electronics for meeting duty cycle requirements. Spare parts and supplies for
low production volume fuel cell vehicles and equipment has been challenging for some applications. To
counter this in the fuel cell transit bus application, North American manufacturers are incorporating fuel cell
platforms into traditional bus platforms (Eudy & Post, 2018). This approach allows greater availability of parts
and lower fuel cell bus part costs, as well as affords fleet mechanics with greater bus serviceability. This
approach is likely to be followed for other fuel cell applications as well. However, additional training on fuel
cell system maintenance, diagnostics, and repair is required for fleet applications. Also, new maintenance and
diagnostic equipment for fuel cell systems may need to be purchased by fleets.
7.1.6 Hydrogen Fuel Price
Hydrogen fuel price remains a limiting market factor for fuel cell-powered equipment. Currently, hydrogen fuel
can be obtained in most areas of the country from established hydrogen production facilities and gas supply
companies that currently serve U.S. petroleum product refineries and fertilizer industries.
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California by far has the most established infrastructure for supporting hydrogen fuel use in fuel cell vehicles
and equipment. According to CARB's 2019 Annual Hydrogen Evaluation (California Air Resources Board, 2019),
the state has 41 existing retail hydrogen refueling stations and an additional 24 planned stations to serve over
5,900 registered light duty fuel cell vehicles in the state. In a December 2015 study, the California Energy
Commission (CEC) reported retail hydrogen prices of between $12.85-16.49/kg of hydrogen dispensed for 700
bar pressure refueling, with an average price of $13.99/kg. Refueling at 350 bar pressures were about $2/kg
lower due to less required compressor operation at these the lower pressure (McKinney, 2015).
The CEC also reported delivered hydrogen costs for gaseous and liquid hydrogen to multiple California-located
stations (McKinney, 2015). For gaseous hydrogen, the average delivered hydrogen cost via gaseous hydrogen
tube trailer to 180 kg/day stations was about $8/kg. For liquid hydrogen, the average delivered hydrogen cost
via liquid hydrogen tank truck or trailer to 350 kg/day stations was about $9-10/kg. Other sources have
reported similar delivered hydrogen costs to refueling sites. Sandia National Laboratories reported that
industrial gas companies could provide liquid hydrogen at $6.35-7.40/kg to support the SF BREEZE marine
vessel's 1,600 kg/day hydrogen consumption (Pratt & Klebanoff, Feasibility of the SF-BREEZE: A Zero-Emission,
Hydrogen Fuel Cell, High-Speed Passenger Ferry, 2016). NREL reported an average delivered gaseous hydrogen
cost of about $8/kg for a multitude of forklift fleets in its 2013 study, although the range of delivered hydrogen
costs reported was $5-22/kg (Ramsden, 2013).
The CEC also reported projected retail prices through year 2025 assuming production volume and economies
of scale improvements in the market (McKinney, 2015). Study results projected an average retail hydrogen
price of $ll.ll/kg in year 2025. The CEC study also predicted an average gaseous hydrogen delivered cost via
truck transport to retail stations of about $7.64/kg by year 2025 assuming increased production and greater
economies of scale for hydrogen production and transport/delivery.
The DOE's Fuel Cell Technologies Office estimates the current cost of hydrogen, delivery, and dispensing at
about $13-16/kg at today's low production volumes (Satyapal, 2018). Through additional research and
development to lower refueling station capital costs, increase station efficiency and outputs, and improve
hydrogen production and transport technologies, DOE targets a cost of hydrogen production, delivery, and
dispensing at $7/kg by 2025. DOE's long-term target for the cost of hydrogen production and delivery is less
than $4/kg for a fully mature hydrogen market; the target for hydrogen production costs is about $2/kg and
the target for the cost of hydrogen delivery and dispensing is $2/kg.
Table 42 below lists DOE's hydrogen cost estimates and targets for low-volume, high-volume, and long-term
timeframes. The Table also contextualizes these costs on the basis of DGE efficiency (Satyapal, 2018). The
hydrogen cost on a DGE basis places them on an equivalent energy basis with diesel fuel, while the efficiency
adjusted price basis further accounts for the energy efficiency improvement of fuel cells (assuming about twice
more efficient on average). The DGE efficiency adjusted cost values for hydrogen can be compared favorably
with the ElA's forecasted (as of the end of calendar year 2019) average retail low sulfur diesel price of
$3.33/gallon in 2020 and $3.76/gallon in 2030.
Table 20. DOE Estimated Retail Hydrogen Price Projections Compared with Retail Diesel Price
Hydrogen Cost
Hydrogen Cost -
DGE Basis
Efficiency Adjusted
Cost Basis
EIA Forecasted 2020
Average Diesel Fuel
Price
DOE Estimate - Current Low-Volume Production
$3.33/gal
$13 - 16/kg H2
$15.12- 18.60/DGE H2
$7.55-9.30/DGE Adj
DOE Estimate - Future High-Volume Production
$5 -10/kg H2
$5.81 - 11.62/DGE H2
$2.91 - 5.81/DGE Adj
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Hydrogen Cost
Hydrogen Cost -
DGE Basis
Efficiency Adjusted
Cost Basis
EIA Forecasted 2020
Average Diesel Fuel
Price
DOE Long-term Target
< $4/kg H2
$4.65/DGE H2
$2.32/DGE Adj
7.2 Future Potential Hydrogen Fuel Supply and Demand
The flexibility of hydrogen production across a variety of feedstocks and processes allows for opportunities in
ramping up production volumes quickly for meeting future hydrogen demand, including demand for fuel cell
vehicles and equipment. Similarly, the extensive networks of natural gas pipelines and electricity transmission
and distribution infrastructure in the U.S. may be able to support both centralized and distributed approaches
to hydrogen production using SMR and electrolysis processes. Furthermore, the projected lower long-term
costs of natural gas and electricity and the anticipated growth in renewable energy electricity generation
collectively support lower costs for hydrogen production at high-volume demand levels.
Figures 20 and 21 list EIA forecasts for both natural gas and electricity prices through 2050 (U.S. Energy
Information Administration, 2020) (Nieuwland, 2017). The projected reference case price of natural gas shows
a modest increase through 2050 depending on natural gas and oil resources available and future processing
technology assumptions, while the reference case electricity price is relatively flat through 2050 as lower
generation costs are offset by high distribution and transmission costs. Generation costs decrease in the
future due to lower investment costs resulting from lower cost installed capacity and lower operating costs
from more efficient generator technologies and renewable energy. Higher transmission and distribution costs
over that time result from the replacement of older infrastructure as well as upgrades necessary for
integrating renewable energy capacity. Figure 22 illustrates the impact of renewable energy electricity
generation in the future as traditional coal and nuclear generation capacity is retired in favor of solar and wind
generation and lower cost natural gas generation (U.S. Energy Information Administration, 2020).
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Dry natural gas production Natural gas spot price at Henry Hub
trillion cubic feet 2018 dollars per million British thermal unit
en 2018 ^ 2018
history
High Oil
Gas Reso
40 and Techno
30 i
projections
and 10
jrce ^•"''Reference,,
' 8
history projections
A . I
Low Oil and Gas
Resource and
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Low Oil and ^ \
Gas Resource N
and Technology 4
2
[a / Reference
\ A / "
\ I " —'—
High Oil and Gas
Resource and
Technology
2000 2010 2020 2030 2040 2050 2000
2010 2020 2030 2040 2050
Figure 10. Natural Gas Consumption and Price Projections
Electricity prices by service category
(Reference case)
2018 cents per kiiowatthours
12
10
8
6
4
2
Average electricity price
2018 cents per kilowatthour
distribution
jg transmission
generation
Tf
Low Oil and Gas
Resource and
Technology
High Economic
Growth
High Oil Price
Low Economic
Growth
Low Oil Price
Reference
High Oil and
Gas Resource
and Technology
2018 2020 2030 2040 2050
0 ,—
2010 2020 2030 2040 2050
2018
history
projections
Figure 11. Electricity Price Projections
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Annual electricity generating capacity additions and retirements (Reference case}
giga watts
50
40
30
20
10
0 \
-10
-20
-30
2018
history
projections
additions
solar
wind
oil and gas
nuclear
other
coal
retirements
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
Figure 12. Projected Annual Electricity Generation Capacity (GW) Additions/Retirements (Reference
Case)
Future hydrogen demand will be comprised of both existing capacity and emerging markets. Recent NREL24
and ANL research under DOE's H2@Scale initiative (Ruth, Jadun, & Elgowainy, 2019) (Elgowainy, Hydrogen
Demand Analysis for H2@Scale, 2019) has determined the total technical potential hydrogen demand25 at
about 166 million metric tons per year by 2050, as provided in Table 43. This is more than a sixteen-fold
increase over current annual market levels of around 10 million metric tons. Hydrogen demand for the U.S.
refinery and chemical industry is anticipated to grow to about eight million metric tons per year by 2030 and
remain at that level through 2050. Annual hydrogen demand for ammonia production could increase to four
million metric tons as domestic fertilizer production increases over time. Significant synthetic fuel and biofuel
markets are expected to develop, fed by increasing production from natural gas production wells, ethanol
plants, and ammonia plants. The increasing use of direct reduction iron (DRI) technology in electric arc furnace
steel production could require about 12 million metric tons per year, while hydrogen demand for natural gas
pipeline injection (5 -15 percent hydrogen by volume) is forecasted to increase to ten million metric tons
annually. NREL also estimated annual hydrogen demand for transportation at about 86 million metric tons, and
for seasonal electricity storage at 28 million metric tons.
NREL assessed the economic hydrogen demand potential26 for five separate future scenarios accounting for
hydrogen pricing impacts (Ruth, Jadun, & Elgowainy, 2019). The five scenarios, listed in Table 44, vary
according to natural gas price assumptions based on EIA Annual Energy Outlook forecasts, and use of natural
gas SMR, nuclear power for high temperature electrolysis, curtailed electricity for low temperature
electrolysis, and available biomass gasification (Ruth, Jadun, & Elgowainy, 2019).
24 A final report update for the cited NREL research is anticipated in year 2020.
25 Defined as market and resource potential that is constrained by existing end-uses, real-world geography, and system performance,
but not constrained by economics.
26 Subset of the technical demand potential where hydrogen is less expensive than other options that can supply the end use.
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Table 43. Future Technical Potential Hydrogen Demand by Market Sector
Future Hydrogen Market
Technical Potential Hydrogen Demand
(million metric ton/yr)
Refinery/Chemical Industries
8
Ammonia
4
Synthetic Fuels
14
Biofuels
4
Metal/Steel Production
12
Natural Gas Pipeline Injection
10
Light Duty Vehicles
57
Other Transport
29
Seasonal Electricity Storage
28
Total
166
Table 44. NREL Hydrogen Demand Economic Potential Scenarios
Scenario Element
Economic Potential Scenarios
Business
as Usual
Low NG
Resource
Improved Available Biomass
Electrolysis Resource
Low Cost
Electrolysis
Natural Gas Prices
AEO 2017
Reference
AEO 2017 Low Oil and Gas Resource/Technology
Availability of NG
SMR
Hydrogen from SMR for non-ammonia production capped at three times current levels (23
million metric ton/yr
Hydrogen production from SMR estimated future ammonia production capped at five million
metric ton/yr
Nuclear Hydrogen
20 percent of current nuclear plants available at $25/MWhe equivalent
LT-Electro lysis
Capital Costs
$400/kW
$200/Kw
$100/Kw
Curtailed Electricity
Available at Retail price
Available between retail and wholesale
prices
Available at
wholesale price
Biomass
Not available
Available
Not available
Metals Demand
Must compete with existing
technologies
Markets are willing to pay premium for metals refined using
hydrogen
For each scenario, NREL developed national hydrogen demand curves. Market acceptable hydrogen prices
ranges from over $3/kg for traditional refinery and ammonia production demand to about $l/kg for future
electricity storage. NREL then developed hydrogen supply curves for the five scenarios. The supply curves were
developed by aggregating supply curves from multiple production sources and estimating delivery and storage
costs. Supply curve pricing ranges from less than $l/kg to close to $3.50/kg across the five scenarios.
Each scenario's hydrogen demand curve was then compared to determine the economic equilibrium point for
each scenario, that is, the quantity in which the demand and supply prices are equal. Equilibrium is the natural
end point for market dynamics and thus predictive of future market response to these scenarios.
Table 45 lists the equilibrium point results for each scenario (Ruth, Jadun, & Elgowainy, 2019). Overall results
from NREL's work indicate future hydrogen market prices of $2.00-2.30/kg across the scenarios for the
production volumes indicated, all of which are lower than DOE's targeted hydrogen costof$4/kg. In general,
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natural gas SMR comprises a significant portion of hydrogen supply except in the Low-Cost Electrolysis
scenario in which low temperature electrolysis becomes economically dominant.
The current status of low and high temperature electrolytic systems for hydrogen production points to the
potential for heavy use of these technologies in the future. There are a number of alkaline-, proton exchange
membrane-, and high temperature-based electrolyzers either available today, soon to be available, or in
demonstration today (E4tech, 2018).
Table 45. Economic Potential Hydrogen Demand Equilibrium Point Results by Scenario
Scenario
Parameter
Business as
Usual
Low NG
Resource
Improved
Electrolysis
Available
Biomass
Resource
Low Cost
Electrolysis
Hydrogen
Equilibrium Price
($/kg)
2.20
2.30
2.30
2.20
2.00
Annual Hydrogen
Demand/Supply
(million MT)
31
14
17
36
48
Alkaline-based systems are most established in the marketplace, with a variety of manufacturer products,
including systems for central plant production.
NREL also analyzed the U.S. regional hydrogen demand and supply locations under the Low-Cost Electrolysis
scenario. NREL determined that hydrogen demand locations tended to be located along the coasts in major
population centers, while centralized hydrogen production centers were co-located with major wind and solar
resources in the middle of the country. This would necessitate the need for regional and long-distance
transport of hydrogen from the production centers to the end use locations. Since gaseous pipelines are the
lowest cost method for transporting quantities of hydrogen of over ten tons per day at distances greater than
60 miles, regional and interstate pipelines may prove economical in the long-term for serving mature hydrogen
markets (Penev & Hunter, 2018).
7.3 Future Fuel Cell Equipment Market Penetration
The following provides market penetration estimates for port fuel cell equipment applications for the 2020-
2050 timeframe. Estimates were derived according to various future market assumptions and employing an "S-
curve" market penetration methodology. In deriving market penetration estimates, it was assumed that
current research and development efforts would address fuel cell costs and durability issues as well as
decrease hydrogen fuel production, transport, and dispensing costs in the future. Estimates also accounted for
future market competitiveness and conditions. The following port equipment are addressed: forklifts, yard
tractors, cargo handlers, switcher locomotives, marine propulsion and auxiliary power, and stationary power
generators. Note: This effort is one way to do this analysis. The results, although detailed and specific, should
not be used to gleam any definitive relationships or conclusions.
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7.3.1 Fuel Cell Forklifts
The Occupational Safety and Health
Administration (OSHA) Class IV-V
forklift segments are generally
representative of the forklifts used at
ports. The majority of fuel cell forklift
sales to date are in the class l-lll
segment represent lighter weight
forklifts used primarily in
warehouses. The Class IV-V forklift
segment is comprised of heavier
forklift products powered by internal
combustion engines with cushion or
pneumatic tires. Forklift market sales
data was obtained for purposes of
this analysis from a report by the
Industrial Truck Association
(Industrial Truck Association, 2017).
Figure 23 provides the estimated market penetration for the Class IV-V forklifts which are more highly utilized
in port applications. Class IV-V fuel cell forklifts are still pre-commercial today, as opposed to Class l-lll fuel cell
forklifts. In addition, the Class IV-V market segment will remain very competitive in the future with diesel,
natural gas, liquified petroleum gas (LPG), and
emerging all-electric systems. A relatively stable
natural gas liquids market in the future should
support the economics of natural gas and LPG
forklifts. The Class IV-V fuel cell forklift market should
benefit from actions taken to grow the on-highway
light and medium duty fuel cell vehicle markets as it
develops both from fuel cell system cost reduction as
well as local and regional fuel supplies. For these
reasons, the Class IV-V fuel cell forklift market
penetration is estimated at about 45 percent in 2050,
or 56,000 units per year.
Annual Class IV-V Forklift Sales Projections
140,000
120,000
100,000
80,000
60,000
40,000
20,000
0
2020
I
2025 2030 2035 2040
¦ Fuel Cell ¦ Total
2045
2050
Figure 13. Estimated Annual Class IV-V Fuel Cell Forklift U.S.
Market Penetration
Primary Market Penetration Assumptions for Class IV-
V Fuel Cell Forklifts
• Competitive market with diesel, natural gas, propane,
and emerging electric forklifts.
• Assume forklift market share of one percent in 2020.
• Fuel cell forklifts will benefit from on-road light and
medium/heavy duty fuel cell vehicle market
development.
• Generally low future natural gas liquids prices will
help natural gas and propane markets.
• Class IV-V forklift market will develop more slowly, in
concert with on-road medium/heavy duty vehicle
market.
• Additional research and development work needed
for forklift applications.
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7.3.2 Fuel Cell Cargo Handling
Equipment
Cargo handling equipment
constitutes yard tractors, reach
stackers, and heavy-duty lift trucks.
Annual sales data from the Port
Equipment Manufacturers
Association was obtained for
estimating future sales forecasts
(Port Equipment Manufacturers,
2018). Figure 24 provides the
estimated annual fuel cell cargo
handling equipment market
penetrations.
Annual Cargo Handler Equipment Sales Projections
300
250
200
150
100
50
0
I
2020 2025 2030 2035 2040
¦ Fuel Cell ¦Total
2045
2050
Note that total fuel cell market
penetration in 2050 is estimated at
about 25 percent, or 66 units per
year. In general, fuel cell platforms for these
applications are in the early prototype stage and
still require further development. Average duty
cycles for this equipment require high power
and significant operational range. Most of the
fuel cell platforms to date are incorporate both
fuel cells and onboard batteries to meet power
demands, and hydrogen storage to meet range
requirements. Optimal platform development is
still ongoing, and thus pre-commercial
incremental capital costs are currently very high.
Fuel cell development and costs for these
applications should benefit from commercial
progress made in fuel cell transit bus and heavy
truck markets.
Figure 14. Estimated Annual Fuel Cell Cargo Handling Equipment
Market Penetration
Primary Market Penetration Assumptions for Fuel Cell Cargo
Handlers
• Competitive market with diesel and diesel hybrid cargo
handlers.
• Only limited prototype platforms produced as of 2020.
Assume fuel cell less than one percent in 2020.
• Fuel cell cargo handler equipment will benefit from on-road
and nonroad fuel cell heavy vehicles/equipment
development.
• Considerable research and development work needed for
cargo handler applications.
• Hybrid platforms likely to be developed including fuel cell
and battery systems.
• High incremental costs compared with diesel platforms will
impact market penetration.
• Battery technology continually improving resulting in the
development of competitive diesel hybrid platforms.
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400
350
300
250
200
150
100
50
0
7.3.3 Fuel Cell Switcher Locomotives
Figure 25 provides market
penetration estimates for fuel cell
switcher locomotives. A 2016 study
by the California Air Resource Board
on freight locomotives formed the
basis for annual sales predictions for
switcher locomotives (California Air
Resources Board, 2016). As provided
in the Figure, fuel cell market
penetration for switcher locomotives
is estimated at about 15 percent in
2050. However, more recently, there
has been increased development of
fuel cell switcher locomotives and
line haul locomotives. Costs for
previous prototypes were very high
but cost levels can be Expected to
lower as technology advances.
Recent developments may advance fuel
cell locomotive deployment well beyond
what is projected here.
High hydrogen fuel volumes are necessary
to support fuel cell switcher locomotives
which can be a limiting factor in some
regions of the country in the near-term.
The annual market for switcher
locomotives is also limited, and so cost
improvements due to economies of scale
are not likely. However, some benefits
from commercial fuel cell production for
other markets could assist in this regard.
Government funding assistance may be
warranted to offset the high incremental
cost of fuel cell switcher locomotives to
jumpstart the market for port applications
and others.
Annual Switcher Sales Projections
2020
2025
2030
2035
iFuelCell ¦ Total
2040
2045
2050
Figure 15. Estimated Annual Fuel Cell Switcher Locomotive Market
Penetration
Primary Market Penetration Assumptions for Fuel Cell Switcher
Locomotives
• Recent fuel cell switcher research and development
• Primary market competitor are diesel hybrid platforms.
• Hybrid platforms likely incorporating fuel cells and battery
systems.
• Necessary hydrogen fuel volumes likely limiting early market
development.
• cost of fuel cell switcher prototypes will slow market penetration
until hydrogen fuel markets developed and hydrogen prices come
down.
• Future market penetration at ports may benefits from other fuel
cell port equipment introduction.
• I limited annual market for new switcher locomotives will slow
fuel cell switcher market penetration without economies of scale
cost benefits for high volume production.
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7.3.4 Fuel Cell Marine
Propulsion and Power
For purposes of this report, fuel cell
marine propulsion applications are
defined as harbor craft such as
passenger cruise boats, ferry boats,
tugboats, and push boats. Data from
the Institute for Water Resources U.S.
Army Corps of Engineers were used
for representing U.S. sales for these
applications (U.S. Army Corps of
Engineers, 2017). Figure 26 provides
the estimated market penetration for
fuel cell harbor craft of this type.
Market penetration is estimated at
about 25 percent in 2050, or about 26
vessels per year.
There has been recent fuel cell propulsion
prototype development in harbor craft
applications both in the U.S. and Europe,
and prototypes are expected to be in
service in the next couple of years. In
terms of power and energy use
requirements in these applications, the
primary competitor is likely to be diesel
and diesel hybrids, although natural gas
engines and biofuels might be competitive
in certain markets. Limiting factors for
market penetration include very high
incremental costs and large fuel volumes
that could be problematic to supply in
certain regions in early markets. Again,
early government funding assistance for marine vessel fuel cell applciations may be warranted to create
momentum in the marketplace.
Annual Harbor Craft Sales Projections
120
100
80
50
40
20
0
2019
2024 2029 2034 2039
¦ FuelCell ¦ Total
II
2044
2049
Figure 16. Estimated Annual Fuel Cell Harbor Craft Market
Penetration
Primary Market Penetration Assumptions for Fuel Cell Harbor Craft
• Only the Sea Change ferry in California and European harbor craft
fuel cell vessel prototypes as of 2021.
• No significant market competition other than diesel and diesel
hybrid.
• Prototype costs are a limiting factor for early market penetration.
• Necessary hydrogen fuel volumes likely limiting early market
development.
• Overall limited annual market for new harbor craft will slow fuel
cell market penetration; no economies of scale cost benefits for
high volume production.
• Market penetration established once regional fuel supply
established.
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7.3.5 Fuel Cell Power Generator Systems
As noted above, stationary power
systems have been one of the more
successful applications for fuel cell
technology to date, with fuel cell
systems offered across a range of
power levels incorporating different
types of fuel cells (E4tech, 2018). As
a means of assessing fuel cell market
penetration in this segment,
representative diesel generator
sales data was obtained across the
10 to 6,000 kW power range (Pratt &
Chan, Maritime Fuel Cell Generator
Project, 2017). Fuel cell market
penetration estimates were then
derived for power generator sales F1Sure 17- Estimated Annual Fuel Cell Generator Market Penetration
segment and are shown in Figure 27.
Fuel cell market penetration in 2050 is
estimated at about 60 percent, or about
148,000 units per year. This assumed over
one percent market share currently, and
no significant future competition except
for diesel engines.
Fuel cell system costs for stationary power
systems have decreased significantly over
the last decade and should continue to decline as systems and balance of plant components are improved. The
fuel cell market will likely be slanted towards high power levels as they are cheaper on a per kW basis and the
ease of diesel fuel supplies for lower power units will probably be preferred unless hydrogen is being used for
other applications on site. Depending on the fuel cell type used, fuel cell generators can also run on hydrogen
or natural gas, providing flexibility to some facilities for using the cheapest available fuel.
300,000
250,000
200,000
150,000
100,000
50,000
0
Annual Power Generator Sales Projections
2020
2025
1
1
1
2030 2035
¦ Fuel Cell ¦ Total
2040
2045
2050
Primary Market Penetration Assumptions for Fuel Cell Power
Generators
• Fuel cell power generators about three percent share in 2019.
• No significant market competition other than diesel.
• Fuel cell generator costs on downward trend over last decade.
• Some fuel cell units could run on cheap natural gas or propane
until hydrogen is available or cheaper.
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8. Areas of Uncertainty
8.1 Uncertainty in the Economics and Emissions Analysis
An analysis of the costs and emissions associated with fuel cell equipment revealed several areas of
uncertainty:
8.1.1 Economics
• Current hydrogen fuel prices for fuel cell vehicles and equipment vary regionally, but generally range
between $13 to $16 per kg. However, these prices correspond with low-volume production, transport, and
dispensing. Applying these hydrogen prices in the economics analysis skews the results against fuel cell
competitiveness. However, using a Figure more representative of high-volume production poses additional
risk, as the high-volume price would be based on speculative market conditions. In response to fuel pricing
uncertainties, guidance from the DOE and the national laboratories on future market conditions and fuel
pricing promotes the use of more economically viable fuel pricing projections for forecasting fuel cell
implementation at ports and other sectors.
• There is some uncertainty in using regional hydrogen fuel feedstock resources as the basis for forecasting
centralized plant locations and resultant fuel transport distances to port locations. Additional analysis of
water restrictions, competing markets, economic conditions, plant siting restrictions, and other factors
would decrease uncertainty in this approach.
• Fuel cell system costing for some equipment applications are based on pre-commercial designs, making
comparisons between fuel cell and diesel markets more difficult. Pre-commercial costs are nearly always
higher than baseline equipment costs because of the low manufacturing volumes. However, this skews the
estimate, making capital costs appear higher than normal, and consequently reducing their applicability in
economic comparisons between equipment types. In addition, pre-commercial capital costs are difficult to
use in forward pricing scenarios.
• Similar to equipment capital costs, maintenance costs based on in-use performance of pre-commercial
designs provide potentially unrepresentative cost estimates at best, and erroneous cost estimates at
worst.
8.1.2 Emissions
• Portions of the emission analysis were completed using port equipment inventory information. There were
a limited number of inventories available for analysis, which limited this data's veracity in representing the
broader port equipment market.
• The use of models and equipment emission factors has inherent uncertainties for estimating emissions for
ports or other types of facilities.
8.2 Current Barriers to the Fuel Cell Implementation at Ports
• High fuel cell equipment costs and hydrogen fuel prices weaken the business case for fuel cells.
• Although fuel system costs have become more competitive with regards to reduced catalyst content and
improved design, estimated balance of plant (BOP) costs account for 50 percent of fuel cell costs.
• The lack of hydrogen production volume, long transport distances and high refueling station costs drive
hydrogen fuel prices upwards.
• The rapid growth of the electric vehicle market has usurped interest and curbed potential investment in
fuel cell equipment in many regions.
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• The durability/reliability, performance and operational range associated with some fuel cell port
equipment have not been fully realized in the marketplace. Demonstrating the advantages of fuel cell
technology is necessary to increase the industry's market share.
8.3 Potential Areas for Future Work
• Additional research should focus on lifecycle emission analysis on the various components of the
equipment cycle. Future collaborative efforts with ANL staff could support lifecycle emission research.
• Additional forecasts of hydrogen pricing for high-volume production, transport and dispensing through
2050 would benefit port analytical and decision-making efforts considering future implementation of fuel
cell equipment.
• Similarly, forecasts of fuel cell system and equipment costs at varying volumes of production are vital to
understanding the economic viability of fuel cell equipment in current and future market conditions.
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9. Summary and Conclusions
9.1 Study Overview and Scope
This study involved a comprehensive evaluation of fuel cell technology and its applications in port equipment
for replacing comparable diesel-fueled equipment. The study was intended to provide EPA with a more
thorough understanding of fuel cell applications within the port environment and their potential impacts on
equipment operation, performance, emissions, and cost.
The specific research areas covered in the study and presented in this report include:
• Fuel Cell Types and Characteristics
• Fuel Cell Market Status
• Fuel Cell Applications and Characteristics for Ports
• Fuel Cell Fuel Supply Infrastructure
• Port Fuel Cell Equipment, Infrastructure, and Fuel Costs
• Hydrogen Fuel Cell Lifecycle Emissions
• Future Hydrogen and Fuel Cell Market Penetration
A summary of key findings in these areas is provided below.
9.2 Summary of Key Findings
9.2.1 Fuel Cell Types and Characteristics
Fuel cells are characterized according to their electrolyte type. There are five primary types of fuel cells that
are currently on the market and/or under further development. These include:
• Polymer Electrolyte Membrane, or PEMFCs
• Alkaline, or AFCs
• Phosphoric Acid, or PAFCs
• Molten Carbonate, or MCFCs
• Solid Oxide, or SOFCs
Table 46 provides a summary of common characteristics for these fuel cell types. Low temperature fuel cells
include PEMFC and AFCs, while MCFCs and SOFCs are considered high temperature fuel cells (U.S. Department
of Energy Fuel Cell Technologies Office, 2019). The fuel cells with the highest efficiencies are PEMFCs, AFCs,
and SOFCs. The high temperature fuel cells tend to have greater tolerance for air and fuel impurities, but all
fuel cell types require high purity fuels to limit catalyst poisoning. Fuel quality is a key aspect of fuel cell
maintenance.
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Table 21. Common Fuel Cell Type Characteristics
Fuel
Cell
Type
Common Electrolyte
Operating Temp/
Electrical Efficiency
(LHV)
Common Applications
Current Challenges
PEMFC
Water- or mineral-
based acidic polymer
140 - 212°F/60%
On-road vehicles, mobile
nonroad equipment, mobile
power supplies, stationary
power sources
Expensive catalysts; CO
and sulfur poisoning
AFC
Aqueous solution
containing potassium
hydroxide in a porous
matrix
158 - 212°F/60%
Distributed generation and
remote stationary power
Electrolyte
management; C02
poisoning
PAFC
Phosphoric acid in a
porous matrix or
polymer membrane
302 - 392°F/40%
Stationary power and DG
generation including CHP
Expensive catalysts;
long-start up time; CO
and C02 poisoning
MCFC
Molten lithium,
sodium, and
potassium carbonates
in a porous matrix
1,112 - l,292°F/50%
Large stationary power
generation including CHP
High temperature
corrosion; long start-up
time; low power density
SOFC
Zirconium oxide
stabilized with yttrium
oxide
932 - l,832°F/60%
Stationary power including
CHP, small portable power,
CHP, automotive auxiliary
power systems
High temperature
corrosion; long start-up
time; limited number of
shutdowns
9.2.2 Fuel Cell Market Status
Worldwide fuel cell markets
have emerged for a variety of
stationary power and
transportation applications
(E4tech, 2018).
Transportation applications
and stationary power
applications made up a
combined total of about
69,000 fuel cell shipments in
2018 and over 800 MW
shipped capacity. As shown in
Figure 28, Asia is the largest
fuel cell market accounting
for almost 75 percent of total
worldwide fuel cell shipments
in 2018. Much of the Asian
market (over half of the fuel
cells shipped in 2018) can be
attributed to the fuel cell demand for residential CHP applications under the Japanese Ene-Farm program.
North America accounted for only about 13 percent of market shipments in 2018, but about 52 percent of
total MW capacity. PEMFCs are dominant in the marketplace with about 58 percent of total worldwide fuel cell
shipments, and SOFCs were second with about 36 percent. PEMFCs are being applied across both stationary
and transportation applications, while SOFCs have been relegated to stationary applications, including CHP.
Worldwide Fuel Cell Shipments (000's) by Region
2014 2015 2016 2017 2018
¦ N.America ¦ Europe BAsia ¦ Other
Figure 18. Worldwide Fuel Cell Market Status in 2018
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9.2.3 Fuel Cell Equipment Applications and Characteristics for Ports
There is considerable potential for the application of fuel cell technology in port applications including on-
highway vehicles, nonroad vehicles, rail, marine and stationary power applications. Many of these applications
are part of current or planned formal demonstrations of pre-commercial and commercial fuel cell equipment.
Table 47 lists typical port equipment applications, the most common fuel cell types for these applications and
their commercial status. As noted in the table, PEMFCs are the primary technology used in the port-related
equipment listed. Additional market details for each port fuel cell equipment application are listed below.
Table 47. Typical Diesel-Fueled Equipment Characteristics Used at Port Facilities and Common Fuel Cell
Replacements
Diesel
Equipment Type
Common
Estimated Fuel Cell
Fuel Cell
Types
Equipment
Commercial Status*
Application Summary
Forklift
PEMFC
TRL 7 Class IV, V and
higher
Commercially available for Classes 1, II and III; pre-
commercial demonstration for Classes IV, V and higher.
Yard Tractor
PEMFC
TRL 7
Pre-commercial demonstrations.
Cargo Handlers
PEMFC
TRL 7
Pre-commercial demonstrations.
Pre-commercial switcher and line haul demonstrations
Switcher
Locomotives
PEMFC
TRL 6-7
are on-going. Recent domestic and international pre-
commercial passenger train demonstrations are
advancing technology.
Harbor Craft
Propulsion
Auxiliary
PEMFC
PEMFC, SOFC
TRL 7
TRL 7
Both domestic and international pre-commercial
demonstrations for propulsion and onboard power.
Power
Generator
PEMFC, AFC,
PAFC, MCFC,
SOFC
TRL 9
Commercially available in 5 kilowatt (kW) -10 megawatt
(MW) capacities for stationary, back-up, and portable
power applications.
*Based on the DOE Technology Readiness Level (TRL) Scale
Forklifts
• As of early 2018, the DOE estimated that almost 22,000 Class I to III fuel cell forklifts have been deployed
in the U.S. In these classes, forklifts are successfully competing with all-electric forklifts (DOE Hydrogen and
Fuel Cells Program , 2018).
• For Class IV and higher forklifts, pre-commercial fuel cell versions are being demonstrated or planned for
development.
Yard Tractors and Cargo Handlers (e.g., Top Loaders)
• Pre-commercial fuel cell yard tractors have been developed and are being demonstrated at present.
• Platforms have typically been "hybrid" platforms, incorporating both fuel cells and battery packs on an
electric motor drivetrain. Depending on the platform, the fuel can be used as a range extender to charge
the battery pack or may provide primary propulsion power.
• Most platforms incorporate energy recovery systems that capture a portion of energy typically lost from
braking to recharge onboard battery packs and increase overall operational range. Some cargo handler
platform energy recovery systems capture normally lost energy from braking and lowering loads.
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Switcher Locomotives
• Pre-commercial fuel cell switcher and line haul locomotives are being developed and demonstrated in
service.
• "Hydrorail" developments, both internationally and in the U.S., involving hydrogen fuel cell passenger train
locomotives may stimulate new efforts in fuel cell locomotive applications, especially given their potential
to improve local air quality.
Marine Propulsion and Auxiliary Power
• A study by SNL determined that most marine vessel types can be viable applications for propulsion or
power, except for vessels requiring multi-MW power capacities and associated impractical, large hydrogen
storage volumes.
• Internationally, fuel cell system research has focused on lower power and shorter-range harbor craft
vessels such as passenger ferries, inland cruise boats and push/tow boats.
• In 2022, A U.S. industry consortium began conducting sea trails of a hydrogen fuel cell-powered passenger
ferry for deployment in the California Bay Area.
Power Generator
• A range of commercial fuel cell stationary power systems from kW to MW power levels are available.
• According to the HARC (Hydrogen Analysis Resource Center, 2019), 580 active stationary power
installations have been deployed across the country. As of September 2018, the vast majority (81 percent)
of installations were SOFCs.
9.2.4 Fuel Cell Fuel Supply Infrastructure
Current annual U.S. hydrogen production stands at about 10 million metric tons for supporting its primary
markets of petroleum refining and fertilizer production. While the supply infrastructure in terms of production
plants, regional pipelines, and terminal storage are well-established for serving these two current sectors, the
same cannot be stated for future hydrogen fuel cell markets. Currently, fuel cell equipment users must
generally work through equipment manufacturers to secure a local supply of high-quality hydrogen from an
industrial gas supply company. To meet future hydrogen demand for widescale fuel cell equipment use,
including port users, a significant expansion of existing production, storage, and distribution infrastructure is
necessary.
9.2.4.1 Hydrogen Production Processes
A vast variety of hydrogen production processes are currently available or under development. These include
SMR, partial oxidation of natural gas, gasification of biomass or coal feedstocks, water electrolysis using
electricity, biomass-to-liquids (ethanol) followed by reformation, microbial biomass conversion (or dark
fermentation), and ammonia cracking. SMR using natural gas feedstock is by far the most prominent hydrogen
production process and currently produces about 95 percent of hydrogen supplies today (Ogden, 2018). The
remaining 5 percent of current hydrogen production results from by-product production from refinery and
chemical plant processing such as hydrocracking plants and chemical plants. Smaller SMR plants are also
available for local or onsite hydrogen production. Water electrolysis is also a common hydrogen production
process. Electrolyzers typically incorporate polymer electrolyte membrane or alkaline electrolytes and are
available as small plants for onsite installation and have been demonstrated at port facilities.
Table 48 summarizes the feedstock, energy use, and water consumption requirements for various
thermochemical and electrolytic hydrogen production processes (Mehmeti, 2018). Several processes have
significant water consumption requirements, which may impact plant locations in the U.S. under water use
*ERG
9-4
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restrictions. In addition, high electricity consumption is required for many of the processes, especially the
electrolytic processes. Electrical power for the electrolysis process is generally grid-based, so the sources of
grid electricity can significantly affect both electrolyzer economics and its lifecycle emissions. For this reason,
current research is being conducted on electrolyzers principally powered by onsite renewable energy sources
such as wind and solar.
Table 48. Feedstock, Water, and Electricity Requirements for Hydrogen Production Processes
Type/Conversion
Pathway
Thermo-Chemical
Electrolysis
Steam
Methane
Reforming
Coal
Gasification
Biomass
Gasification
Biomass
Reformation
Proton
Exchange
Membrane
Solid Oxide
Electrolysis
Natural Gas (MJ/kg
Hz)
165
—
6.228
—
—
50.76
Coal (kg/kg H2)
—
7.8
—
—
—
—
Biomass (kg/kg H2)
—
—
13.5
6.54
—
—
Electricity (kWh/kg
Hz)
1.11
1.72
0.98
0.49
54.6
36.14
Water (kg/kg H2)
21.869
2.91
305.5
30.96
18.04
9.1
9.2.4.2 Hydrogen Storage and Transport Technologies
Following large-scale production, hydrogen is typically stored in bulk storage tanks before transport to regional
or local end use markets. Bulk hydrogen storage is either as a gaseous or liquid product. In gaseous form,
hydrogen storage is typically pressurized to 2,500-5,000 psi and stored in large cylindrical steel storage tanks.
In liquid form, hydrogen must be cooled to below its boiling point of-423°F using a liquefaction process, and
then stored in insulated, cryogenic storage cylinders.
In terms of transport, hydrogen can be moved via a variety of modes depending on distance and hydrogen
product type (gaseous or liquid). Currently, there is over 1,600 miles of hydrogen pipeline in the U.S. (U.S.
Drive Partnership, November 2017). Most of this existing pipeline is in California, Louisiana, and Texas for
supporting large-scale hydrogen production for the petroleum refining industry. Pipelines are the most
economical means of transporting gaseous hydrogen long distances (over 1,000 miles). Regional and local
hydrogen distribution from production to terminal storage and/or to the end use site via truck transport is very
common today for either as gaseous or liquid product. Although less common, liquid hydrogen can be
transported long distances via rail car, ship, and barge.
Once hydrogen product arrives onsite as gaseous or liquid product it can be stored locally until ready for use.
Stationary power fuel cell applications can typically be fed gaseous hydrogen directly. For mobile fuel cell
equipment, gaseous hydrogen would typically be boosted in pressure before dispensing to increase the stored
hydrogen energy density onboard the equipment. Most commercial dispensing systems can provide hydrogen
gas at either 350 bar (5,000 psi) or 700 bar (10,000 psi) pressures.
As with most fuel energy carriers, there are safety considerations for the storage, handling, and dispensing of
hydrogen fuel product. Hydrogen has significantly different fuel properties than diesel fuel and should be
handled differently to mitigate potential fire and exposure risks. While diesel fuel is a low volatility fuel at
ambient conditions, hydrogen is gas at ambient condition that can readily mix with air. Hydrogen has much
wider flammability limits and burns almost invisibly. Enclosed facilities that store or maintain hydrogen fuel cell
equipment must be properly designed for hydrogen gas releases and leaks. Liquid hydrogen product, which is
cryogenic, should be handled with care to prevent personal exposure to fuel spills or uninsulated dispensing
equipment which could result in severe frost bite.
*ERG
9-5
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9.2.4.3 Future Potential Hydrogen Production and Delivery Pathways
Future hydrogen delivery from production to end use will likely follow two pathways: Centralized and
Distributed Pathways. Centralized pathways involve large-scale hydrogen production (50,000-500,000 kg/day)
for serving regional or even national end use markets depending on plant location. Hydrogen product is
transported via pipeline, truck, or rail to end use markets. For distributed pathways, hydrogen is produced
locally or onsite to support specific end users. Hydrogen product carriers such as natural gas or water are
transported to the site to be used as feedstocks in small scale (less than 1,500 kg/day) SMR or electrolytic
hydrogen production processes. The choice between centralized and distributed hydrogen production will
depend on availability and proximity to feedstocks and process energy sources, size of regional or local
markets, and hydrogen production process efficiency, costs, and market, environmental, socioeconomic
impacts. While centralized and distributed plant sizes may be most common in early hydrogen market
development, production facilities between the 1,500 and 50,000 kg/day size may also arise for meeting
regional hydrogen markets (U.S. Drive Partnership, November 2017), potentially growing into centralized
plants serving broader geographical regions.
Table 49 provides an estimated implementation timeline for various centralized and distributed hydrogen
pathways based on DOE program information (DOE Fuel Cell Technologies Office, 2019). The near and mid-
term hydrogen production candidates for centralized pathways include natural gas reforming, biomass and
coal gasification, renewable energy supported electrolysis, and high temperature electrolysis using nuclear or
renewable energy. While hydrogen by-product production from hydrocracking and chlorine production plants
are also commercially available, these processes are more likely to support market demand rather than serve
as full-scale centralized plants. The most promising distributed pathways at this time include natural gas
reforming, electric grid-based electrolysis, bio-derived liquids reforming (ethanol), and microbial biomass
conversion.
Table 49. Implementation Timeframes for Centralized and Distributed Hydrogen Pathways
2020 - 2030 Timeframe
2030 - 2040 Timeframe
2040+ Timeframe
Centralized Pathways
NG SMR
(500,000 kg/day plants)
Biomass Gasification
(100,000 kg/day plants)
High Temperature Electrolysis
(500,000 kg/day plants)
Electrolysis - Wind/Solar
(50,000 -100,000 kg/day plants)
Coal Gasification
(500,000 kg/day plants)
Distributed Pathways
NG SMR
(1,500 kg/day plants)
Bio-derived Liquids Reforming
(1,500 kg/day plants)
Microbial Biomass Conversion
(1,500 kg/day plants)
Grid-based Electrolysis
(1,500 kg/day plants)
While each of the centralized pathways has significant potential for serving future hydrogen markets, some of
these options are more likely to be regionally rather than nationally significant. In terms of distributed
pathways, the existing natural gas pipeline system would support the use of natural gas as a viable hydrogen
carrier source for onsite hydrogen production, and small-scale SMR plants are already commercially available.
Water electrolysis is the second most used hydrogen production process behind SMR and small-scale water
electrolysis plants are commercially available now. While the water distribution system in the U.S. is
*ERG
9-6
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ubiquitous and port locations are thusly well-served, the water requirements for small-scale electrolysis are
higher than other distributed production processes which may be a limiting factor in some jurisdictions.
It should be noted too that there are non-hydrogen fuel sources that can be used directly by some types of
fuel cells. These fuels include natural gas, ammonia, and methanol. For example, natural gas, which can be
delivered onsite via pipeline, can be used in MCFCs and SOFCs in stationary power applications. Methanol, a
widely distributed chemical in the U.S., can be used in DMFCs which are specialized PEMFCs. DMFCs are
currently used extensively in portable power applications but could also be adapted to other stationary power
applications. Ammonia is also a widely used chemical in the U.S. and thus supported by an expansive
distribution system, especially in the agricultural and pharmaceutical industries. Ammonia can generally be
used directly in AFCs, AMFCs, and SOFCs, but further research is needed before these applications are
commercialized.
9.2.5 Port Fuel Cell Equipment, Infrastructure, and Fuel Costs
9.2.5.1 Refueling Station Capital and Operating Costs
A review of several recent studies of hydrogen station economics determined that station capital costs on a
per kg dispensed basis are higher for smaller capacity stations than for larger stations. In addition, there is a
large difference in station capital costs on a per kg dispensed basis between the stations associated with
centralized versus distributed delivery. From a station operating cost standpoint, centralized production served
stations generally have lower costs than distributed served stations for the same hydrogen dispensed capacity.
The onsite grid-electrolysis stations exhibited the highest operating costs due primarily to their intensive
electricity usage.
9.2.5.2 Dispensed Hydrogen Price
The final cost to the end user for dispensed hydrogen ($/kg) must account for all production and delivery
pathway elements. This is especially important for centralized production pathways that include costs for
production and transport to the site on top of amortized costs for station capital cost recovery and operations.
Levelized pathways costs were compiled from several studies and placed on a kg produced or transported
basis. Final dispensed hydrogen costs were then estimated by summing the pathway costs with the station
capital and operating costs on a kg delivered basis. Based on a ten-year station lifetime, centralized pathway
levelized dispensed fuel costs ranged from about $4.98-$9.84 per kg, while those for distributed pathways
ranged from $5.43-$12.28 per kg for station capacities ranging from 100-1,000 kg/day. These costs dovetail
well with DOE long-term projected hydrogen cost of less than $4/kg assuming high-volume production
(Satyapal, 2018).
9.2.6 Port Fuel Cell Equipment Costs by Port Application
Port fuel cell equipment cost estimates were derived for the following types of port equipment: forklifts, yard
tractors, cargo handlers (top loaders), switcher locomotives, marine vessels, and power generators.
Incremental pricing between fuel cell and comparable diesel-fueled equipment was based on available cost
information and projections and typical equipment operating characteristics and anticipated lifetimes. Results
for the assessment of capital and annual maintenance costs are provided in Table 50 for years 2020 and 2030.
Diesel fuel costs represent EIA projections (except for the switcher locomotive case, which is based on Surface
Transportation Board figures), while hydrogen pricing is based on DOE projected near-term and long-term cost
estimates. Note that the costs for all the port fuel cell equipment are higher than those of comparable diesel
equipment in 2020 and 2030. In 2030, annual operating savings are generated for some fuel cell equipment as
a result of its higher fuel efficiency and the lower hydrogen pricing. As a result of these savings, reasonable
capital payback is possible for fuel cell forklift, yard tractor, cargo handler, and generator applications in 2030.
Thus, ports could realize significant economic benefit from the implementation of fuel cell equipment as future
*ERG
9-7
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fuel cell costs decrease with improved designs and higher-volume manufacturing, and hydrogen fuel pricing
drops due to higher-volume production.
Table 50. Fuel Cell Equipment Capital and Operating Cost Results
Yard
Cargo
Switcher
Comparative Cost Parameter
Forklift
Tractor
Handler
Locomotive
Ferry Boat
Generator
Assumed Useful Lifetime
10
12
12
20
20
10
Assumed Utilization (Hr/yr)
1,500
1,600
2,000
1,500
2,800
3,000
Year 2020
Assumed Hydrogen Price ($/kg)
13.00
13.00
13.00
13.00
11.64
13.00
Assumed Diesel Price ($/gal)
3.33
3.33
3.33
2.07
3.33
3.33
Incremental Capital Cost ($)
39,194
115,000
142,578
1,922,543
5,566,000
212,000
Annual Operating Savings ($)
-8,494
-15,484
-53,817
-316,261
-5,038,704
-32,975
Estimated Simple Payback (Yrs)
None
None
None
None
None
None
Year 2030
Assumed Hydrogen Price ($/kg)
5.00
5.00
5.00
5.00
4.40
5.00
Assumed Diesel Price ($/gal)
3.76
3.76
3.76
2.34
3.76
3.76
Incremental Capital Cost ($)
16,214
48,614
77,494
1,922,536
1,117,764
52,225
Annual Operating Savings ($)
2,227
8,515
33,804
-53,165
-887,027
6,839
Estimated Simple Payback (Yrs)
7.3
5.7
2.3
None
None
7.6
9.2.7 Hydrogen Fuel Cell Lifecycle Emissions
A comprehensive illustrative lifecycle emissions assessment was completed for port fuel cell equipment by
estimating WTP and PTW emission components relative to low sulfur (15 ppm) diesel. WTP emissions analyses
were conducted using ANL's 2019 GREET model. In general, the analysis determined that hydrogen production
and transport pathways are more energy and water use intensive than that for diesel fuel. Criteria pollutant
and GHG emissions from the hydrogen pathways generally correlated with energy use and fossil energy
fractions. Thus, centralized and distributed SMR and grid-based electrolysis produced the highest criteria
pollutant and GHG emissions. The centralized and distributed solar-based electrolysis generally produced the
lowest criteria pollutant and GHG emissions. Further, an analysis of electricity generation sources for serving
the distributed grid-based electrolysis indicated that electricity mixes with high fossil energy (especially coal)
and low renewable energy produce much higher WTP emissions than electricity generated from low fossil
energy and high renewable energy mixes. This means that WTP results from grid-based electrolysis are very
dependent on the region of the country and its electricity generation sources.
In terms of PTW emissions, fuel cell equipment offers a distinct advantage over comparable diesel equipment
across all criteria pollutants, air toxics, and GHG emissions as fuel cell emit only water vapor and heat.
Final WTW emission results were derived by combining the respective WTP and PTW emission components of
fuel cell and diesel equipment, respectively. The increased fuel efficiencies of fuel cell equipment relative to
diesel equipment were considered in deriving the WTW results. (Port fuel cell equipment applications were
estimated to be 1.4-2.5 times more efficiency than comparable diesel equipment.) Table 51 lists directional
results for each of the port equipment and the hydrogen fuel pathways relative to low sulfur diesel. A green
"+" indicates an emission reduction, while a red signifies an emissions increase. Overall, WTW emissions
were seen across pollutants and hydrogen pathways. Significant reductions were seen for VOC and NOx
*ERG
9-8
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Table 22. WTP Emission Reduction Summary for Port Fuel Cell Equipment Relative to
Diesel Equipment
Equipment
Type
Hydrogen Fuel Pathway
WTW Emission Reductions Relative to Diesel-Fueled Equipment (g/kg H2
VOC
CO
NOx
PM10
PM2.5
so2
co2
CH4
N20
Yard Tractor
Centralized NG SMR
+
+
+
+
+
-
+
+
-
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
-
-
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
-
-
-
Distributed Electrolysis Grid (Lo Coal)
+
+
-
-
+
+
+
+
Forklift
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
-
+
-
+
+
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
-
+
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
-
+
+
+
+
+
Cargo Handler
(Top Loader)
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
-
+
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
-
-
-
Distributed Electrolysis Grid (Lo Coal)
+
+
-
-
+
+
+
+
Assist Tugboat
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
-
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
+
+
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
+
+
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
+
+
-
+
+
+
Ferry
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
-
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
+
+
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
-
+
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
-
+
-
+
+
+
Harbor
Tugboat
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
-
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
+
+
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
-
+
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
-
+
-
+
+
+
Switcher
Locomotive
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
-
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
+
+
-
Distributed Electrolysis Grid (Hi Coal)
+
+
+
+
+
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
+
+
-
+
+
+
Stationary
Generator
Centralized NG SMR
+
+
+
+
+
-
+
+
Centralized Biomass Gasification
+
+
+
+
+
-
+
+
+
Centralized Electrolysis Solar
+
+
+
+
+
-
+
+
+
Distributed NG SMR
+
+
+
+
+
-
+
Distributed Electrolysis Solar
+
+
+
+
+
+
+
+
+
Distributed Electrolysis Grid (US Avg)
+
+
+
+
+
-
+
Distributed Electrolysis Grid (Hi Coal)
+
+
+
+
+
-
-
Distributed Electrolysis Grid (Lo Coal)
+
+
+
+
+
+
+
+
+
*ERG
9-9
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emissions for all port equipment and hydrogen fuel pathways. CO, PMi0, and PM2.semission reductions were
achieved for most hydrogen pathways and equipment except for grid-based electrolysis. C02 emissions
reductions were observed for all hydrogen fuel pathways, with the exception of high coal/low renewables grid-
based electrolysis and U.S. average generation grid-based electrolysis for some equipment applications. CH4,
N20 emissions were mixed across pathways and port applications, with lower emissions generally being
achieved with biomass gasification, solar-based electrolysis, and low coal/high renewables electrolysis
pathways.
Only S02 emissions were higher for many port fuel equipment and hydrogen fuel pathways except for solar-
based electrolysis and low coal/high renewables generation grid-based electrolysis. Overall, the solar-based
electrolysis pathway achieved the best emissions among the centralized and distributed pathway cases. The
performance of distributed grid-based electrolysis is highly dependent on regional electricity generation mix.
Ports with electricity generated from fossil (especially) coal and low renewable resource generation will
produce higher WTW emissions for the grid-based electrolysis compared to regions with low fossil energy and
high renewable resources. Further, the WTW emission results were dictated by specific assumptions for both
WTP and PTW estimates.
9.2.8 Future Hydrogen and Fuel Cell Market Penetration
9.2.8.1 Primary Factors for Future Fuel Cell Commercial Viability and Competitiveness
Various factors were identified as impactful on the future market viability of fuel cells in ports and other sector
applications. These factors included:
• Equipment capital cost - Current fuel cell system costs are higher than comparable diesel powerplants.
Much of this cost variance is low-volume manufacturing. Fuel cell system costs are expected to decrease in
the near- to mid-term as fuel cell designs improve and manufacturing volumes increase.
• Required emission reductions - For ports with high future emission reduction targets, fuel cell equipment
can help meet future emission inventory goals.
• Equipment durability/reliability - Fuel cell durability and reliability across equipment applications have
improved considerably, including port equipment. The DOE expects fuel cell systems will meet targets
(that is, 5,000 hours for mobile applications and 80,000 hours for SOFC stationary applications) within the
next two to four years.
• Equipment power/duty cycle performance -The general scalability of fuel cells should allow fuel cell
systems to meet most demanding power and duty cycle requirements for port equipment.
• Equipment operational hours/range - For most port equipment, operational ranges for fuel cell-powered
equipment are like those of diesel-fueled equipment. For some port equipment such as top loaders and
marine propulsion, hybrid fuel cell battery systems and improved hydrogen storage systems are under
development to assist in meeting specific operational requirements.
• Equipment maintenance/serviceability-While scheduled maintenance for fuel cell systems is generally
less frequent than comparable diesel equipment, pre-commercial systems have exhibited higher rates of
unscheduled maintenance. As pre-commercial fuel cell systems continue to develop, unscheduled
maintenance episodes are anticipated to decrease.
• Hydrogen fuel price - Fuel price is a limiting factor for fuel cell equipment market growth. Dispensed
hydrogen market prices are currently about $13-16/kg in many areas of the country (or about $7.55-
9.30/DGE when adjusted for the energy content and higher fuel efficiency of hydrogen) (Satyapal, 2018).
*ERG
9-10
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DOE expects hydrogen costs to decrease to about $2.91-5.81/DGE efficiency adjusted in 2025, and to less
than $2.32/DGE efficiency adjusted in the long-term. These future hydrogen prices compare favorably with
EIA diesel fuel price forecast of $4.05/gallon in 2045 (U.S. Energy Information Administration, 2020).
9.2.8.2 Future Potential Hydrogen Fuel Supply and Demand
Future hydrogen demand will be comprised of both existing capacity and emerging markets. Recent NREL and
ANL research under DOE's H2@Scale initiative determined the total technical potential hydrogen demand at
about 166 million metric tons per year by 2050, a sixteen-fold increase over current annual hydrogen
productions levels.
9.2.8.3 Future Fuel Cell Equipment Market Penetration Estimates
Market penetration estimates for port fuel cell equipment applications were estimated for the 2020-2050
timeframe based on future market
assumptions and employing an S-
curve market penetration
methodology. As provided in Figure
29, high fuel cell market penetration
was estimated for new purchases of
generators and forklifts based on
their current status in the market
and anticipated competitiveness in
future markets.
Estimated U.S. Market Share by Year (%)
2020
2025
¦ Forklift
• Harbor Craft
¦Generator
2030
2035
2040
2045
2050
¦Yard Tractor/Cargo Handler
Switcher
Figure 29. Estimated Port Fuel Cell Equipment Market Penetration
(2020-2050)
*ERG
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Appendix A-
Summary of Recent Fuel Cell Equipment Demonstrations
and Deployments at U.S. Ports
%ERG
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Table A-1. Recent Fuel Cell Demonstrations and Deployments at U.S. Ports
Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
Alcatraz Island National
Park Ferry Boat
Embarkation Dock, San
Francisco, California
Portable fuel cell-
powered mobile
light tower for
ferry boat
embarkment dock
Plug Power/PEM
Fall 2016
The 1,100 W fuel cell in the Luxfer-GTM Technologies
Zero-Set Lite uses hydrogen fuel and provides up to 36
hours of continuous LED lighting. The Zero-Set Lite
provided critical working light for a scheduled
overnight barge exchange operation at Alcatraz Island
National Park. The project was undertaken by
Alcatraz Cruises, Alcatraz Island's official National Park
Service ferry service concessioner. Ferry boat
embarkment dock serves about 5,000 visitors per day.
Zero Emission Cargo
Transportation Program
(ZECTII program) (Ports
of Long Beach and Los
Angeles/San Pedro Bay
Ports)
Drayage truck
1. BAE/Ballard/Kenworth - Electric
with PEM FC range extended
drayage truck
2. Hydrogenics/Siemens - Electric
with PEM FC range extended
drayage truck
3.Transpower/Hydrogenics/Navistar
- Electric with PEM FC range
extended drayage truck
4.U.S. Hybrid/US
FuelCell/lnternational - Electric
with PEM FC range extended
drayage truck
The demonstration
phase of this
project is expected
to start by Q12018
with at least two
trucks, one each
from TransPower
and US Hybrid. The
project is set be
completed by Q3
2019 and the
commercialization
of these truck
technologies can
be expected after
2019.
BAE/CTE - Ballard Fuel cell range extended dravage
truck; 100 kWh Lithium technology batteries; Auxiliary
Power Unit (Range Extender) is 100 kW Fuel Cell
providing power to charge batteries; 30 kg Onboard
hydrogen fuel storage system. BAE plans to build and
install a FC APUs on one fully integrated truck systems
for drayage service demonstration. BAE anticipates
that the 30 kg of hydrogen (25 kg usable) will provide
approximately 110 to 120 miles of range between re-
fueling.
Hvdrogenics/Siemens - will develop a hvdrogen fuel
cell drayage truck powered by their latest advanced
fuel cell drive technology (Celerity Plus fuel cell power
system) and Siemens' ELFA electric drivetrain,
customized for heavy duty vehicle applications. The
proposed fuel cell drayage truck is designed to be
capable of delivering over 150 miles of zero emission
operation with 10-15 minutes fast refueling of
hydrogen.
TransPower - Plug-in electric Fuel cell range extended
drayage truck - Battery energy storage 120kWh;
gaseous storage, fuel cell; TransPower plans to build
and install FC APUs on two fully integrated truck
systems for drayage service demonstration. The
proposed project will result in the manufacturing and
deployment of two demonstration trucks, one with a
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
30-kW fuel cell and one with a 60-kW fuel cell,
enabling a direct comparison of both variants. The
higher power output of the 60 kW systems is expected
to be better suited for trucks carrying heavy loads
over longer distances that might exceed the average
power capacity of the 30 kW systems. The system will
store 25-30 kg of hydrogen onboard based on an
estimated 7.37 miles per kg fuel economy.
TransPower's system also includes a bi-directional
J1772-compliant charger that can recharge the vehicle
batteries or provide power export
U.S. Hvbrid - Plug-in electric Fuel cell range extended
drayage truck; UTC Pure Motion 80 (80kW) fuel cell;
26kWhr battery system; expected range 150-200
miles; 20kg @ 350bar; 6.6kW on-board charger; US
Hybrid plans to build and install FC APUs on two fully
integrated truck systems for drayage service
demonstration. The proposed technology will provide
a 150-200 mile range between refueling. Each truck
will carry approximately 20 kg of hydrogen storage at
350 bar with an estimated fueling time of less than 10
minutes.
These advanced technology trucks will operate along
major drayage truck corridors including the Terminal
Island Freeway, a primary corridor for port cargo
travelling between Port of Los Angeles and Port of
Long Beach terminals and the Intermodal Container
Transfer Facility, a near-dock rail facility.
FAST TRACK Fuel Cell
Truck Project (Ports of
Los Angeles and San
Diego)
Drayage truck
GTI/Loop
Energy/Transpower/Peterbilt -
Loop's FC-REX fuel cell
Loop fuel cell range
extenders will be
integrated by
TransPower into
two Peterbilt 579
truck gliders in
early 2019.
Following on-
highway testing by
Canada-based Loop Energy's heavy-duty fuel cell
range extender will power two new zero-emission
hybrid-electric Class 8 drayage trucks that will operate
for a one-year period as part of a FAST TRACK Fuel Cell
Truck Project in southern California.
The Loop-powered, long-haul trucks will work in
demanding road operations, towing up to 80,000
pounds of freight throughout the San Diego and Los
Angeles regions. The hybrid-configured trucks will
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
Peterbilt, the
trucks are
scheduled to enter
daily operational
service in California
in the second
quarter of 2019.
incorporate a range of technologies including Loop's
FC-REX fuel cell range extender, TransPower's latest
"T-NMC" energy storage technology that is built
around batteries provided by Nissan, and battery-
electric drive systems supplied by TransPower, to
extend the operating range of Peterbilt trucks beyond
200 miles without the need for refueling or
recharging.
Commercialization of
POLB Off-Road
Technology (C-PORT)
Demonstration Project
(Port of Long Beach)
Yard Tractor
KalmarTranspower/Loop Energy
2019
The POLB C-PORT project is to: 1) design, develop and
demonstrate three battery electric top handlers at the
Long Beach Container and SSA MarineTerminals; 2)
design, develop and demonstrate one battery electric
and one hydrogen fuel cell yard tractor at the Long
Beach Container Terminal; and 3) install electric
charging and hydrogen fueling infrastructure to
support operation of these vehicles in revenue service
for a minimum of six months at Long Beach Container
Terminal Pier E. It is anticipated that up to three
vehicle original equipment manufacturers and three
technology vendors will be involved in this project.
The project will also feature a unique, head-to-head
comparison of hydrogen fuel cell vs. battery-electric
technology in yard trucks.
Demonstration of Zero-
Emission Technologies
for Freight Operations
at Ports (Port of Los
Angeles)
Top Loader
Nuvera PEM Fuel Cell
Hyster Yale Group
The project team, led by the Center for Transportation
and the Environment, will build an electric top loader
with wireless inductive charging and a 90-kW fuel cell
range extender for demonstration at the Port of Los
Angeles. The electric top loader with a fuel cell range
extender will be developed, integrated, and built by
Hyster Yale Group, with the fuel cell engine provided
by Nuvera and wireless charging provided by WAVE.
The vertical integration of zero-emission equipment
by a major OEM provides a clear path towards
commercialization and represents the commitment of
the OEMs to develop and commercialize advanced
technologies that are necessary to meet California's
air quality and climate goals.
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
Hydrogen ics Advanced
Fuel Cell Vehicle
Technology
Demonstration for
Drayage Truck (Ports of
Los Angeles and Long
Beach)
Drayage truck
Hydrogen ics Corp CelerityPlus™
hydrogen PEM fuel cell
For the project, "Advanced Fuel Cell Vehicle
Technology Demonstration for Drayage Truck,"
Hydrogenics, with the technical support of Siemens,
will integrate its advanced CelerityPlus™ fuel cell
drive system into a Class 8 drayage truck. Total
Transportation Services, Inc. (TTSI) will demonstrate
the Hydrogen fuel cell-powered drayage trucks on the
Alameda Corridor as well as in the ports of Long Beach
and Los Angeles.
Hydrogen Fuel Cell
Passenger Ferry Boat
(Port of San Francisco)
Passenger Ferry
Boat
Hydrogenics PEM fuel cell
BAE Systems
Hexagon Composites
Mid-2020 planned
The catamaran ferry boat is powered by dual 300 kW
electric motors using independent electric drivetrains
from BAE Systems. Power is generated by three 120
kW of Hydrogenics proton exchange membrane fuel
cells and two 50 kWh Li-ion battery packs. Hydrogen
tanks from Hexagon Composites, will be installed on
the upper deck, and contain enough hydrogen to go
up to two days between refuelings. The ferry"s cruise
speed is estimated to be 21 knots. In 2022, All
American Marine, Inc. (AAM) and the vessel owner
SWITCH Maritime (SWITCH)began conducting sea
trials of the vessel "Sea Change", a 70-foot, 75-
passenger zero-emissions, hydrogen fuel cell-
powered, electric-drive ferry that will operate in the
California Bay Area.
Fuel Cell Drayage Truck
and Intelligent
Transportation Systems
Demonstration (Ports
of LA/Long Beach)
(ZECT 1)
SCAQMD Project ID:
VSS115
Drayage Trucks
Kenworth/General Motors, Toyota,
AirProducts
Project start date:
Oct. 2012
Project end date:
Sept. 2017
Project involving fuel cell electric vehicles (FCEVs) for
the drayage industry, supporting hydrogen
infrastructure, as well as the next iteration of
geofencing technologies that will maximize emissions
reductions from near-zero emission vehicle
technologies in disadvantaged communities (DACs).
These vehicles will support the Ports of LA and Long
Beach and include fuel cell electric (Kenworth-General
Motors and US Hybrid-Dongfeng) trucks, state-of-the-
art renewable hydrogen infrastructure (Toyota), and
plug-in diesel hybrid electric with ITS (Volvo Group
North America with University of California-Riverside).
Project includes a confirmed end-user fleet which has
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
routes in DACs within the state, as well as a
partnership with the National Renewable Energy
Laboratory for data collection. The goals of the fuel
cell and ITS technology development are to reduce
criteria and greenhouse gas emissions, protect public
health, and reduce dependence on fossil fuels.
"Project Portal"
Experiment (Port of
Long Beach/Los
Angeles)
"Project Portal" 2.0
(Port of Long Beach/Los
Angeles)
Drayage truck
Toyota/Kenworth
"Alpha" truck -
April 2017
"Beta" truck-Fall
2018
Since mid-2017, Toyota has been testing a prototype
Class 8 tractor powered by hydrogen fuel cell
technology, in drayage service. Toyota is using the
same proton exchange member fuel cell (PEMFC)
technology that it has already commercially deployed
in its Mirai fuel cell passenger cars. The Kenworth
Class 8 tractor used by Toyota in the project
incorporates two Mirai PEMFC stacks in parallel
(totaling about 230 kW of peak power output),
hybridized with a small battery pack (about 12 kWhr).
Under the initial Project Portal effort, Toyota has been
testing its first prototype PEMFC truck in local drayage
service, from Toyota's Port of Long Beach facility. The
Toyota Alpha truck has logged more than 10,000
miles. In mid-2018, Toyota launched a second "Beta"
model, which reportedly offers longer range
(increased from 200 to 300 miles), and other
improvements. Notably, Toyota's apparent ultimate
plan is to sell this heavy-duty PEMFC drive system to
Class 8 truck OEMs (rather than to become a Class 8
OEM itself).
Zero-Emission Freight
"Shore to Store" Project
(Port of Los Angeles)
Drayage truck
Toyota, Kenworth, Ballard Power
Systems, and Shell
ZANZEFF projects
must be completed
by April 2021
ZANZEFF funds are supporting the development of
hydrogen fuel cell technology. The Zero-Emission
Freight "Shore to Store" project involves a hydrogen
fuel-cell-electric technology framework for freight
facilities to structure operations for goods movement.
As part of the plan, the partners will collaborate to
develop and deploy 10 hydrogen fuel cell Class 8
trucks, develop two hydrogen fueling stations, and
increase zero-emission technology use in off-road
applications.
*ERG
A-5
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
• Ten new zero-emissions hydrogen fuel-cell-electric
Class 8 on-highway trucks on the Kenworth T680
platform will be developed through a collaboration
between Kenworth and Toyota to move cargo from
the Los Angeles ports throughout the Los Angeles
basin, as well as ultimately to inland locations such
as Riverside County, the Port of Hueneme, and
eventually to Merced. The trucks will be operated
by Toyota Logistics Services (4), United Parcel
Services (3), Total Transportation Services Inc. (2),
and Southern Counties Express (1).
• Two new large capacity heavy-duty hydrogen
fueling stations will be developed by Shell in
Wilmington and Ontario, California. The new
stations will join three additional stations located at
Toyota facilities around Los Angeles to form an
integrated, five-station heavy-duty hydrogen
fueling network. Together, they will provide
multiple sources of hydrogen throughout the
region, including over 1 ton of 100% renewable
hydrogen per day at the heavy-duty station to be
operated by Shell, enabling zero-emissions freight
transport. Stations supplied by Air Liquide at Toyota
Logistics Services in Long Beach and Toyota
Technical Center in Gardena will serve as important
research and development locations.
Renewable H2
Production & Fueling
Station (Joint Base
Pearl Harbor-Hickam)
Refueling for
ground fuel cell
vehicles
First installed in
2006 as mobile
storage and
refueling unit, with
more established
station in 2013
JBPHH H2Station Capacity Upgrades:
• 65 kg/day PEM Electrolyzer
• 270 kg H2 storage
• Dual compressors and dispensers for 350 bar and
700 bar vehicle refueling
Naval Submarine Base
New London Fuel Cell
Stationary power
generation
FuelCell Energy Inc. molten
carbonate fuel cell
July 2018
The project involves the installation of two FuelCell
Energy SureSource 4000™ power plants at the U.S.
Navy Submarine Base in Groton, CT for the long-term
supply of 7.4 megawatts of power. The highly
efficient fuel cell power generation project minimizes
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
carbon output while providing continuous power to
the strategic military base. The U.S. Navy continues to
purchase power from CMEEC and Groton Utilities,
who in turn purchases the power from FuelCell Energy
under a 20-year power purchase agreement. This
pay-as-you-go structure enables CMEEC and the Navy
to avoid a direct investment in owning the power
plant which will be operated and maintained by FCE.
By generating 7.4 MW of clean, efficient power, the
fuel cell park will meet a majority of the average daily
energy needs of Submarine Base New London. Any
excess power will be exported to the Groton Utilities
distribution system.
Maritime Hydrogen
Fuel Cell Project (Port
of Honolulu)
Portable power
generation
Hydrogenics Corp proton exchange
membrane fuel cell
August 2015
Hydrogenics Corp. designed and manufactured a
containerized 100-kilowatt hydrogen fuel cell unit,
which includes the fuel cell engine, a hydrogen
storage system, and power-conversion equipment.
The unit fits inside a 20-foot shipping container and
consist of four 30 kW fuel cells, a hydrogen storage
system, and power-conversion equipment. The unit
has an outward appearance and functionality similar
to maritime diesel generators that are currently in
use. The system contains 72 kg of hydrogen at 350 bar
and has a rated power of 100 kW, 240 VAC 3-phase,
which can be divided among 10 plugs to power up to
10 reefer containers at a time. The design of the
generator was reviewed by the US Coast Guard,
American Bureau of Shipping, and the Hydrogen
Safety Panel to ensure safety and compliance with
regulations.
Integrated Algal Flow-
Way, Digester,
and Fuel Cell
Demonstration Project
(Port of Baltimore)
Onsite process
power
Atrex Energy solid oxide fuel cell
2017
A 500 W-fuel cell (Atrex Energy ARP500) was
purchased for the demonstration project. The biogas
being converted to electricity by the fuel cell was
constrained by the algal flow-way size and the biogas
production rate from site-grown algae. The lowest
wattage of a commercially available fuel cell was 500
W at the time of the RFPs in spring 2017; therefore, a
*ERG
A-7
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
greater percentage of supplemental gas was needed
to continuously power the fuel cell than anticipated.
As an operational adjustment, the demonstration
project team decided to collect and store biogas in the
external biogas storage bags until enough biogas was
available to run the fuel cell for at least 5 to 7 days at
a time, allowing for the testing of up to 35% biogas in
the fuel mix to the fuel cell. This demonstration
project successfully validated the ability to couple an
algal flow-way, digester, biogas conditioning and
compression unit, and fuel cell into an integrated
system producing electricity from algae grown on site.
The demonstration project team designed and
operated an integrated system to convert algae—
already being grown on an algal flow-way to remove
nutrients from a nutrient-rich surface water—into
biogas for fuel to a fuel cell. This demonstration
project showed that electricity could be produced
using a non-fossil fuel energy source and, thereby,
could reduce air emissions. With financial support and
project oversight from MARAD and MDOT MPA, the
demonstration project answered many questions on
the feasibility and success potential of coupling
independent units into a system that could produce
electricity from site-grown algae. Several design and
operational uncertainties were answered, and others
identified during the design, start-up, and operations
of the system.
Naval Submarine Base
New London Fuel Cell
Combined Heat
and Power
FuelCell Energy Inc. molten
carbonate fuel cell
2010
Two 300-kilowatt DFC300 fuel-cell plants were
installed next to the existing power plant on the base
to provide reliable electricity.
LOGANEnergy installed and operated two power
plants. These units will provide base load electricity,
with byproduct heat being used to preheat boiler
water.
*ERG
A-8
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
Zero Emissions for
California Ports (ZECAP)
(Port of Los Angeles)
Yard Tractors
Ballard Power Systems PEM fuel
cell
Installation in 2019
and a 12-month
operating period is
planned for the
project, beginning
in March 2020.
85kW FCveloCity HD PEM fuel cell modules. BAE
Systems electric drive integrated within its HDS200
HybriDrive Propulsion System.
Toyota Renewable
Energy Fuel-cell Power
Plant and Hydrogen
Fueling Station (Port of
Long Beach)
Combined heat
and power and
hydrogen
refueling station
Toyota and FuelCell Energy
Construction
anticipated to start
late 2018 and be
completed in 18
months.
The Tri-Gen facility will be the first megawatt-sized
molten carbonate fuel cell power generation plant in
the world. Using 100 percent renewables, the plant
will utilize agricultural waste to generate the water
and hydrogen required to support the logistics of the
project trucks and electricity for use in the Port of
Long Beach.
The 2.3 MW powerplant will provide the following
benefits:
1. Electricity- enough to power the terminal - and sell
power back to the grid
2. Water- a byproduct of the power plant- will be used
to wash cars at the terminal
3. Heat-another by-product- will generate necessary
heat for the facility.
4. Hydrogen- fueling the power plant - will also be
used to fuel the Toyota Mirai as well as trucks
operating at the terminal.
Comparison of Battery
Electric and FC Electric
Yard Trucks (Port of
Long Beach)
Yard trucks
LOOP Energy
National Heavy-Duty Truck Group
August 2017
Two main elements: First, demonstrate three battery-
electric top handlers with collaboration between BYD
and Taylor Machine Works. Second, perform a head-
to-head comparison of a battery electric yard truck
and a fuel cell yard. The battery electric yard truck
will be developed by TransPower and Kalmar, and the
fuel cell yard truck will be developed by LOOP Energy
and China National Heavy-Duty Truck Group. All the
equipment will be demonstrated at the Port of Long
Beach at two different terminals.
Toyota "Tri-Gen"
Facility for Logistics
Stationary power
generation EV
charging, and
FuelCell Energy
2020
2.35 MW power plant, with power and hydrogen
production produced from agri-bio-waste conversion
(manure).
*ERG
A-9
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Project Name
(Port Location)
Port Application
Fuel Cell Manufacturer/Type
Installation Date/
Planned Date
FC Design and Operational Information
Operations (Port of Los
Angeles)
onsite production
of hydrogen
refueling station
Hydrogen refueling station, producing 1.2 tons of
hydrogen per day.
The electricity will be used to powerToyota Logistic
Services' (TLS) operations at the Long Beach Port,
making it the first Toyota facility in North America
source all its power from renewable sources.
*ERG
A-10
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