Hydrogen Pathways 

Updated Cost, Well-to-Wheels Energy 

Use, and Emissions for the Current 

Technology Status of Ten Hydrogen 

Production, Delivery, and Distribution 

Scenarios 

T. Ramsden, M. Ruth, V. Diakov 

National Renewable Energy Laboratory

M. Laffen, T.A. Timbario

Alliance Technical Services, Inc.

Technical Report

NREL/TP-6A10-60528

March 2013

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308
Hydrogen Pathways 

Updated Cost, Well-to-Wheels Energy 

Use, and Emissions for the Current 

Technology Status of 10 Hydrogen 

Production, Delivery, and Distribution 

Scenarios 

T. Ramsden, M. Ruth, V. Diakov 

National Renewable Energy Laboratory

M. Laffen, T.A. Timbario

Alliance Technical Services, Inc.

Prepared under Task No. HS07.1002

Technical Report

NREL/TP-6A10-60528

March 2013

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov
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Acknowledgements 

The authors would like to acknowledge the following people for their assistance and support 

during this analysis. 

The U.S. Driving Research and Innovation for Vehicle efficiency and Energy sustainability’s 

(U.S. DRIVE’s) Fuel Pathway Integration Technical Team identified the need to examine 

concurrently the cost and well-to-wheels energy use and emissions of various hydrogen 

production, delivery, and use pathways and to carefully document the key parameters of the 

analysis. They reviewed the results of the study both for content and for presentation and 

provided many helpful pointers. In addition, they participated in the gap analysis that identified 

issues reported in Section 9.0. Current and past members of the team include Matt Watkins and 

Eric Bunnelle (ExxonMobil Corporation); Laura Verduzco (Chevron Corporation); Garry Gunter 

(Phillips 66 Company); Herie Soto (Shell Oil Products US); Brian Bonner (Air Products and 

Chemicals, Inc.), and Fred Joseck (U.S. Department of Energy [DOE]). 

Model developers assisted in the use of their models and understanding of underlying 

assumptions. Neil Popovich (National Renewable Energy Laboratory [NREL]) performed many 

delivery scenario simulations to identify and explain anomalies. Macro-System Model 

developers include Victor Diakov (NREL) and Tim Sa and Mike Goldsby (Sandia National 

Laboratories). 

Funding for this analysis was provided through the Fuel Cell Technologies Office within the 

Department of Energy’s Office of Energy Efficiency and Renewable Energy. Fred Joseck (DOE) 

provided leadership and guidance throughout this project, for which we are grateful, and this 

analysis would not have been possible without him. 

iv
List of Abbreviations and Acronyms

°C degrees Celsius

°F degrees Fahrenheit

atm atmosphere 

Btu British thermal unit

CCS carbon capture and sequestration 

CO carbon monoxide 

CO2 carbon dioxide 

CO2-eq. carbon dioxide-equivalent

CPM cost-per-mile

CSD compression, storage, and dispensing 

DOE U.S. Department of Energy 

FCEV fuel cell electric vehicle

FCTO Fuel Cell Technologies Office

gge gallon gasoline equivalent 

GHG greenhouse gas 

GREET Greenhouse Gases, Regulated Emissions, and Energy Use in 

Transportation 

H2, H2 diatomic hydrogen 

H2A Hydrogen Analysis

HDSAM H2A Delivery Scenario Analysis Model 

h hour 

ICE internal combustion engine 

kg kilogram 

kWh kilowatt-hour 

L liter

v 
lb pound 

LHV lower heating value

mi mile

mpgge miles per gallon gasoline equivalent 

MSM Macro-System Model 

MSRP manufacturer’s suggested retail price

NOx oxides of nitrogen 

NREL National Renewable Energy Laboratory

O&M operations and maintenance 

PM particulate matter

PSA pressure swing adsorption 

psi pounds per square inch

psia pounds per square inch absolute 

psig pounds per square inch gauge 

RPE retail price equivalent

SMR steam methane reforming

TBW tire and brake wear

U.S. United States 

VOC volatile organic compound 

WGS water-gas shift 

WTP well-to-pump 

WTW well-to-wheels 

vi 
Executive Summary

The United States (U.S.) Department of Energy’s (DOE’s) Hydrogen and Fuel Cells Program—

which is coordinated across the Department and includes activities in the Offices of Energy 

Efficiency and Renewable Energy (EERE), Science, Nuclear Energy, and Fossil Energy—has 

identified a need to understand the cost, energy use, and emissions tradeoffs of various hydrogen 

production, delivery, distribution and use options under consideration for fuel cell vehicles. The 

Fuel Cell Technologies Office (FCTO) within EERE has been researching and developing 

hydrogen and fuel cell technologies because they have the potential to reduce U.S. dependence 

on foreign crude oil, diversify energy sources, decrease greenhouse gas (GHG) emissions, and 

provide domestic economic growth. 

This report describes a life-cycle assessment conducted by the National Renewable Energy 

Laboratory (NREL) of 10 hydrogen production, delivery, dispensing, and use pathways that were 

evaluated for cost, energy use, and GHG emissions (see Table ES.1). This evaluation updates 

and expands on a previous assessment of seven pathways conducted in 2009 (Ruth, Laffen and

Timbario 2009). The evaluation takes a life-cycle approach, addressing both the “well-towheels” (WTW) transportation fuel cycle and also the portion of the vehicle cycle that considers 

the manufacturing of a fuel cell electric vehicle (FCEV) and the decommissioning and 

disposal/recycling of the FCEV. This study summarizes key results, parameters, and sensitivities 

to those parameters for the 10 hydrogen pathways, reporting on the levelized cost of hydrogen in 

2007 U.S. dollars as well as life-cycle energy use and GHG emissions associated with the 

pathways.1 The results from this assessment aid in understanding and evaluating technology 

needs and progress, potential environmental impacts, and the energy-related economic benefits 

of various hydrogen production, delivery, and dispensing options. 

Table ES.1. Ten Hydrogen Production, Delivery, and Distribution Pathways

Feedstock Central or

Distributed

Production

Carbon

Capture and

Sequestration

Delivery

Method

Hydrogen

Distribution

1 Natural Gas Distributed No Not applicable 700 bar, gaseous 

2a Ethanol Distributed No Not applicable 700 bar, gaseous

3 Grid Electricity Distributed No Not applicable 700 bar, gaseous

4 Biomass Central No Gaseous H2 in 

pipelines

700 bar, gaseous

5a Biomass Central No Gaseous H2 truck 700 bar, gaseous

6 Biomass Central No Liquid H2 truck 700 bar, gaseous

7a Biomass Central No Liquid H2 truck Cryo-compressed

8 Natural Gas Central No Gaseous H2 in 

pipelines

700 bar, gaseous

9 Wind 

Electricity

Central No Gaseous H2 in 

pipelines

700 bar, gaseous

10 Coal Central Yes Gaseous H2 in 

pipelines

700 bar, gaseous

a Newly analyzed pathways

1 This analysis does not attempt to evaluate the selling price of hydrogen, which will depend on market factors. 

Instead, results are discussed in terms of levelized cost, which is the resulting break-even cost of hydrogen 

calculated on a net present value basis to cover all capital, operating, and maintenance costs including a set internal 

rate of return on expenditures.

vii 

 
The pathways evaluated in this study represent currently available hydrogen production, 

delivery, and dispensing technologies, projected to a commercialized scale. Plausible production 

scenarios for mature hydrogen transportation-fuel markets combined with market penetration of 

hydrogen fuel cell vehicles were used in this analysis. This study does not evaluate transition 

scenarios where equipment may not be fully utilized. The assumptions used in the analysis 

reflect current technology: technology that has been developed to the bench scale (at a minimum) 

but has not necessarily been demonstrated at commercial scales. All the technology options have 

potential for research and development (R&D) improvements. 

For the evaluation, FCEVs were assumed to have an on-road fuel economy of 48 miles per 

gallon gasoline equivalent (mpgge). The 48 mpgge assumption is consistent with NREL’s 

analysis of on-road FCEV fuel economy data from the Hydrogen Fleet and Infrastructure 

Demonstration and Validation Project (Wipke et al. 2012) and also reflects modeling of FCEV 

fuel economy by Argonne using its Autonomie model, based on Argonne’s modeling 

assumptions and information from original equipment manufacturers (Rousseau 2012). Because 

fuel economy is likely to improve with fuel cell research and development advances, a sensitivity 

analysis was also performed for an assumed fuel economy of 68 mpgge. This higher end fuel 

economy was chosen as it represents the average fuel economy of a Toyota fuel cell vehicle in 

on-road testing conducted in California in 2009 (Wipke, Anton and Sprik 2009). 

The hydrogen Macro-System Model (MSM) was used to analyze the pathways by linking the 

H2A Production models, the Hydrogen Delivery Scenario Analysis Model (HDSAM), the 

Greenhouse Gas, Regulated Emission, and Energy for Transportation (GREET) Model, and the 

Cost-per-Mile (CPM) Tool.

2 The MSM links those models so they can be executed concurrently, 

utilizing the capabilities of each and ensuring consistency among them. Also, the MSM is 

available to the public and enables users to analyze pathways and complete sensitivity analyses 

that are not reported in this document. Consistent with the standard employed by the H2A 

Production model and HDSAM, costs are presented in 2007 U.S. dollars. 

The analysis has been reviewed by the U.S. DRIVE Partnership’s Fuel Pathway Integration 

Technical Team, which includes members from DOE, national laboratories, and energy 

companies (Phillips 66, Chevron Corporation, Shell, and ExxonMobil Corporation). 

Figure ES.1 depicts the performance of the 10 hydrogen fuel pathways, comparing pathway 

hydrogen fuel cost on a $/mile basis to fuel-cycle WTW GHG emissions on a gram CO2-

equivalent per mile basis. As seen in the figure, the levelized cost of hydrogen on a per mile 

basis (assuming a 48 mpgge fuel economy) ranges from $0.10/mile for the distributed natural gas 

production pathway to $0.18/mile for the distributed ethanol-reforming pathway (compared to 

gasoline costs of about $0.13/mile for a conventional gasoline vehicle). Figure ES.2 provides 

more detail on the WTW greenhouse gas emissions, showing total GHG emissions on a gram 

CO2-equivalent per mile basis for the 48 to 68 mpgge fuel economy range. The figure illustrates 

that all of the pathways except for the distributed electrolysis pathway result in GHG emissions 

2 This analysis uses a version of the MSM that incorporates H2A Version 3 (2012), HDSAM Version 2.3 (2012), 

GREET 1 (2011, rev. 1) and GREET 2 (version 2.7). The versions of H2A, HDSAM, and GREET used were current 

at the time this life-cycle evaluation began. As of the publication of this report, H2A Version 3 and HDSAM 

Version 2.3 are still current, but more recent updates of the GREET 1 and GREET 2 models were made available in 

late 2012.

viii

 
ix 

lower than 400 g/mile, based on a fuel economy of 48 mpgge. When a higher fuel economy of 68 

mpgge is considered, all of the pathways except distributed electrolysis result in GHG emissions 

lower than 250 g/mile. 

Figure ES.1. Comparison of pathways’ levelized costs and GHG emissions 

Distributed electrolysis has high GHG emissions when compared to the other hydrogen pathways 

because of the assumed electricity grid mix (the U.S. average grid mix is assumed, with coal 

production accounting for 44% of electricity generation). The pathways that use natural gas as a 

feedstock use little petroleum but have high GHG emissions compared to most of the other 

pathways due to the GHG emissions associated with producing hydrogen from natural gas. The 

coal pathway has slightly lower GHG emissions than the natural gas pathways do because of the 

efficient carbon-sequestration system that is assumed; no other pathways assume the use of a 

carbon sequestration system. The biomass and ethanol pathways have higher petroleum use than 

all but the distributed electrolysis pathway because the biomass and ethanol feedstocks are 

delivered using trucks. 

Of the four options for delivering hydrogen from a centralized production plant, pipeline delivery 

has the lowest GHG emissions and lowest petroleum use. The two liquid truck delivery options 

have higher GHG emissions because of the high electricity consumption of the liquefaction 

process (the U.S. average grid mix is assumed). The GHG emissions for hydrogen dispensed as a 

cryo-compressed liquid are slightly lower than those for hydrogen dispensed as a gas because the 

liquid pump requires less electricity than the compressor necessary for delivering 700 bar 

gaseous hydrogen. Hydrogen delivered in a gas truck has low GHG emissions but a high 

petroleum use because each truckload only carries 520 kg of hydrogen. 

Central Biomass - 

Liquid Trucks 

Central Biomass - 

Pipelines 

Central Biomass - 

Gas Trucks 

Central Biomass - 

Cryocompressed 

Central Coal Gasification 

w/CCS- Pipeline 

Distributed Electrolysis 

(U.S. Grid mix, 44% Coal) 

Distributed Natural Gas 

Central Natural Gas - 

Pipeline 

Wind Electricity 

Electrolysis - Pipeline 

Distributed 

Ethanol 

Conventional 

Gasoline Vehicle 

Gasoline Hybrid 

Electric Vehicle 

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

1,000 

$0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.12 $0.14 $0.16 $0.18 $0.20 

WTW Greenhouse Gas Emissions (g / mile) 

Levelized Cost of Hydrogen ($ / mile without fuel taxes) 

Biomass 

Coal 

Grid Electricity 

Natural Gas 

Wind Electricity 

Ethanol 
x 

Figure ES.2. WTW GHG emissions for 10 hydrogen pathways 

Figure ES.3 shows the levelized cost of hydrogen for the 10 pathways, breaking out hydrogen 

production costs, delivery costs, dispensing station costs (also known as CSD costs—station 

compression, storage, and dispensing costs), and the share of hydrogen levelized cost associated 

with pathway hydrogen losses. As seen in the figure, hydrogen production, delivery, and 

dispensing costs range from $4.60/kg H2 to almost $9.00/kg H2. Hydrogen production costs are 

at or near DOE’s $2.00/kg target for four of the production pathways (representing 7 of the total 

10 overall pathways evaluated). Station CSD costs range from about $1.00/kg to $2.50/kg, 

showing the need for R&D advancements to lower the cost of dispensed hydrogen. 

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

WTW GHG Emissions (g CO2-eq / mile) 

GHG emission range 

based on 48 to 68 

mpgge fuel economy 
xi 

Figure ES.3. Hydrogen production levelized costs for 10 pathways 

$0.00 

$1.00 

$2.00 

$3.00 

$4.00 

$5.00 

$6.00 

$7.00 

$8.00 

$9.00 

$10.00 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Levelized Cost($/kg) 

CSD Share ($/GGE) 

Pathway Losses Share ($/GGE) 

Delivery Share ($/GGE) 

Production Share ($/GGE) 
Table of Contents

List of Figures ........................................................................................................................................... xv

List of Tables ........................................................................................................................................... xxii

1 Introduction........................................................................................................................................... 1

1.1 Document’s Intent ............................................................................................................................ 1

1.2 Hypothetical Market State and Technology Development Assumptions ........................................ 2

1.3 Analysis Boundaries ........................................................................................................................ 3

1.4 Pathways .......................................................................................................................................... 3

1.4.1 Pathway 1: Distributed Natural Gas .................................................................................. 4

1.4.2 Pathway 2: Distributed Ethanol ........................................................................................ 4

1.4.3 Pathway 3: Distributed Electricity .................................................................................... 5

1.4.4 Pathway 4: Central Biomass—Pipeline Delivery ............................................................. 5

1.4.5 Pathway 5: Central Biomass—Gaseous H2 Truck Delivery ............................................. 6

1.4.6 Pathway 6: Central Biomass—Liquid Truck Delivery and Gaseous Dispensing ............. 7

1.4.7 Pathway 7: Central Biomass—Liquid Truck Delivery and Cryo-Compressed 

Dispensing ................................................................................................................................. 8

1.4.8 Pathway 8: Central Natural Gas—Pipeline Delivery ........................................................ 9

1.4.9 Pathway 9: Central Wind Electricity—Pipeline Delivery................................................. 9

1.4.10 Pathway 10: Central Coal with Carbon Capture and Sequestration—Pipeline Delivery 10

1.5 Models Used in the Pathway Analyses .......................................................................................... 11

2 Production Technology Descriptions and Assumptions ............................................................... 13

2.1 Distributed Natural Gas Reforming ............................................................................................... 13

2.2 Distributed Ethanol Reforming ...................................................................................................... 13

2.3 Distributed Electrolysis .................................................................................................................. 14

2.4 Central Biomass Gasification ........................................................................................................ 14

2.5 Central Natural Gas Reforming ..................................................................................................... 14

2.6 Central Electrolysis with Renewable Power .................................................................................. 15

2.7 Central Coal with Carbon Capture and Sequestration ................................................................... 15

3 Delivery and Dispensing Technology Descriptions and Assumptions ........................................ 16

3.1 Gaseous Hydrogen via Pipeline ..................................................................................................... 16

3.1.1 Pipeline ........................................................................................................................... 16

3.1.2 Compressor ..................................................................................................................... 16

3.2 Gaseous Hydrogen via Trucks ....................................................................................................... 17

3.2.1 Gaseous Hydrogen Truck ................................................................................................ 18

3.3 Compression, Storage, and Dispensing of Gaseous Hydrogen ...................................................... 19

3.4 Liquid Hydrogen via Trucks with Gaseous Hydrogen Dispensing ............................................... 19

3.4.1 Liquid Hydrogen Truck .................................................................................................. 20

3.4.2 Liquefier .......................................................................................................................... 20

3.5 Liquid Hydrogen via Trucks with Dispensing of Cryo-Compressed Liquid Hydrogen ................ 21

4 Vehicle Assumptions ......................................................................................................................... 23

4.1 Vehicle Fuel Economy ................................................................................................................... 23

4.2 Vehicle Criteria Pollutant Emissions ............................................................................................. 24

4.3 Vehicle Cost ................................................................................................................................... 24

4.4 Vehicle-Cycle Energy Use and Emissions ..................................................................................... 26

5 Financial Assumptions ...................................................................................................................... 27

6 Pathway Results ................................................................................................................................. 29

6.1 Distributed Natural Gas ................................................................................................................. 29

6.1.1 Cost Breakdown .............................................................................................................. 30

6.1.2 Energy Use and Emissions Breakdown .......................................................................... 35

6.1.3 Sensitivities ..................................................................................................................... 38

6.2 Distributed Ethanol ........................................................................................................................ 39

xii
6.2.1 Cost Breakdown .............................................................................................................. 40

6.2.2 Energy Use and Emissions Breakdown .......................................................................... 45

6.2.3 Sensitivities ..................................................................................................................... 47

6.3 Distributed Electricity .................................................................................................................... 49

6.3.1 Cost Breakdown .............................................................................................................. 49

6.3.2 Energy Use and Emissions Breakdown .......................................................................... 53

6.3.3 Sensitivities ..................................................................................................................... 55

6.4 Central Biomass—Pipeline Delivery ............................................................................................. 57

6.4.1 Cost Breakdown .............................................................................................................. 57

6.4.2 Energy Use and Emissions Breakdown .......................................................................... 61

6.4.3 Sensitivities ..................................................................................................................... 63

6.5 Central Biomass—Gaseous H2 Truck Delivery ............................................................................. 75

6.5.1 Cost Breakdown .............................................................................................................. 75

6.5.2 Energy Use and Emissions Breakdown .......................................................................... 79

6.5.3 Sensitivities ..................................................................................................................... 82

6.6 Central Biomass—Liquid Truck Delivery and Gaseous Dispensing ............................................. 93

6.6.1 Cost Breakdown .............................................................................................................. 93

6.6.2 Energy Use and Emissions Breakdown .......................................................................... 97

6.6.3 Sensitivities ................................................................................................................... 100

6.7 Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing ........................... 114

6.7.1 Cost Breakdown ............................................................................................................ 114

6.7.2 Energy Use and Emissions Breakdown ........................................................................ 118

6.7.3 Sensitivities ................................................................................................................... 121

6.8 Central Natural Gas—Pipeline Delivery...................................................................................... 135

6.8.1 Cost Breakdown ............................................................................................................ 135

6.8.2 Energy Use and Emissions Breakdown ........................................................................ 139

6.8.3 Sensitivities ................................................................................................................... 142

6.9 Central Wind Electricity—Pipeline Delivery .............................................................................. 143

6.9.1 Cost Breakdown ............................................................................................................ 143

6.9.2 Energy Use and Emissions Breakdown ........................................................................ 148

6.9.3 Sensitivities ................................................................................................................... 151

6.10 Central Coal with Carbon Capture and Storage—Pipeline Delivery .................................... 152

6.10.1 Cost Breakdown ............................................................................................................ 152

6.10.2 Energy Use and Emissions Breakdown ........................................................................ 157

6.10.3 Sensitivities ................................................................................................................... 159

7 Pathway Results Comparison......................................................................................................... 161

8 Analysis Gaps................................................................................................................................... 175

8.1 Production .................................................................................................................................... 175

8.2 Delivery and Dispensing .............................................................................................................. 176

8.3 Vehicle Costing ............................................................................................................................ 178

8.4 Pathway Analysis ......................................................................................................................... 178

9 References ........................................................................................................................................ 179

Appendix A: Distributed Natural Gas Supporting Tables and Figures ............................................. 182

Appendix B: Distributed Ethanol Supporting Tables and Figures .................................................... 188

Appendix C: Distributed Electricity Supporting Tables and Figures ................................................ 194

Appendix D: Central Biomass—Pipeline Delivery Supporting Tables and Figures......................... 200

Appendix E: Central Biomass—Gaseous H2 Truck Delivery Supporting Tables and Figures........ 207

Appendix F: Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Supporting Tables 

and Figures ....................................................................................................................................... 214

Appendix G: Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing 

Supporting Tables and Figures....................................................................................................... 221

Appendix H: Central Natural Gas—Pipeline Delivery Supporting Tables and Figures ................... 228

xiii
Appendix I: Central Wind Electricity—Pipeline Delivery Supporting Tables and Figures .............. 234

Appendix J: Central Coal with Carbon Capture and Storage—Pipeline Delivery Supporting Tables 

and Figures ....................................................................................................................................... 240

xiv
List of Figures

Figure ES.1. Comparison of pathways’ levelized costs and GHG emissions ..................................... ix

Figure ES.2. WTW GHG emissions for 10 hydrogen pathways.............................................................. x

Figure ES.3. Hydrogen production levelized costs for 10 pathways.................................................... xi

Figure 1.4.1. Flow diagram and energy balance of distributed natural gas pathway .......................... 4

Figure 1.4.2. Flow diagram and energy balance of distributed ethanol pathway................................. 5

Figure 1.4.3. Flow diagram and energy balance of distributed electricity pathway............................. 5

Figure 1.4.4. Flow diagram and energy balance of central biomass—pipeline delivery pathway...... 6

Figure 1.4.5. Flow diagram and energy balance of central biomass—gaseous truck delivery 

pathway ................................................................................................................................................. 7

Figure 1.4.6. Flow diagram and energy balance of central biomass—liquid truck delivery pathway 7

Figure 1.4.7. Flow diagram and energy balance of central biomass—liquid truck delivery and cryocompressed dispensing pathway....................................................................................................... 8

Figure 1.4.8. Flow diagram and energy balance of central natural gas—pipeline delivery pathway . 9

Figure 1.4.9. Flow diagram and energy balance of central wind electricity—pipeline delivery 

pathway ............................................................................................................................................... 10

Figure 1.4.10. Flow diagram and energy balance of central coal with CCS—pipeline delivery 

pathway ............................................................................................................................................... 11

Figure 3.1.1. Compressor cost as a function of motor rating .............................................................. 17

Figure 3.2.1. Hydrogen daily average demand for a peak dispensing day ......................................... 18

Figure 3.4.1. Liquefier energy requirement versus hydrogen flow rate .............................................. 20

Figure 3.4.2. Liquefier cost versus design capacity.............................................................................. 21

Figure 3.4.3. Refueling station electrical cost versus rated motor power.......................................... 21

Figure 4.1.1. NREL hydrogen fleet and infrastructure demonstration and validation project fuel 

economy.............................................................................................................................................. 23

Figure 5.0.1. Post-tax and pre-tax IRRs that result in the same levelized cost for multiple 

combinations of equity and debt financing (central production of hydrogen from coal with 

CCS pathway)...................................................................................................................................... 28

Figure 6.1.1. Summary of major inputs, assumptions, and outputs by subsystem for the 

distributed natural gas pathway ....................................................................................................... 31

Figure 6.1.2. Cost analysis inputs and high-level results for the distributed natural gas pathway . 32

Figure 6.1.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed natural gas pathway.......................................................................... 33

Figure 6.1.4. Breakdown of levelized costs for the distributed natural gas pathway........................ 33

Figure 6.1.6. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the distributed 

natural gas pathway ........................................................................................................................... 35

Figure 6.1.7. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the distributed natural gas pathway................................................................................................. 36

Figure 6.1.8. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed natural gas pathway ....................................................................................................... 36

Figure 6.1.9. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the distributed natural gas pathway ................................................................. 37

Figure 6.1.10. WTW petroleum, natural gas, and coal inputs for both the distributed natural gas 

pathway and the vehicle cycle .......................................................................................................... 37

Figure 6.1.11. WTW CO2, CH4, and N2O emissions for both the distributed natural gas pathway and 

the vehicle cycle ................................................................................................................................. 38

Figure 6.1.12. Production sensitivities for the distributed natural gas pathway................................ 39

Figure 6.2.1. Summary of major inputs, assumptions, and outputs by subsystem for the 

distributed ethanol pathway.............................................................................................................. 41

Figure 6.2.2. Cost analysis inputs and high-level results for the distributed ethanol pathway ....... 42

Figure 6.2.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed ethanol pathway................................................................................ 43

Figure 6.2.4. Breakdown of levelized costs for the distributed ethanol pathway .............................. 44

Figure 6.2.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the distributed 

ethanol pathway.................................................................................................................................. 45

xv
Figure 6.2.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the distributed ethanol pathway ....................................................................................................... 46

Figure 6.2.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed ethanol pathway.............................................................................................................. 46

Figure 6.2.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the distributed ethanol pathway........................................................................ 47

Figure 6.2.9. Production sensitivities for the distributed ethanol pathway........................................ 48

Figure 6.3.1. Summary of major inputs, assumptions, and outputs by subsystem for the 

distributed grid electricity pathway.................................................................................................. 50

Figure 6.3.2. Cost analysis inputs and high-level results for the distributed grid electricity pathway51

Figure 6.3.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed grid electricity pathway .................................................................... 52

Figure 6.3.4. Breakdown of levelized costs for the distributed grid electricity pathway .................. 52

Figure 6.3.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the distributed 

grid electricity pathway...................................................................................................................... 53

Figure 6.3.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the distributed grid electricity pathway ........................................................................................... 54

Figure 6.3.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed grid electricity pathway.................................................................................................. 54

Figure 6.3.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the distributed grid electricity pathway ............................................................ 55

Figure 6.3.9. Production sensitivities for the distributed grid electrolysis pathway ......................... 56

Figure 6.4.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

biomass—pipeline delivery pathway................................................................................................ 58

Figure 6.4.2. Cost analysis inputs and high-level results for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 59

Figure 6.4.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—pipeline delivery pathway..................................................... 60

Figure 6.4.4. Breakdown of levelized costs for the central biomass—pipeline delivery pathway ... 60

Figure 6.4.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—pipeline delivery pathway................................................................................................ 62

Figure 6.4.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—pipeline delivery pathway ............................................................................ 62

Figure 6.4.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—pipeline delivery pathway................................................................................................ 63

Figure 6.4.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—pipeline delivery pathway............................................. 63

Figure 6.4.9. Production sensitivities for the central biomass—pipeline delivery pathway............. 64

Figure 6.4.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—pipeline delivery pathway................................................................................................ 65

Figure 6.4.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—pipeline delivery pathway............... 66

Figure 6.4.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—pipeline delivery pathway............... 66

Figure 6.4.13. WTW GHG emissions versus penetration for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 67

Figure 6.4.14. WTW petroleum use versus penetration for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 68

Figure 6.4.15. WTW fossil energy use versus penetration for the central biomass—pipeline 

delivery pathway................................................................................................................................. 68

Figure 6.4.16. Levelized cost versus city population for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 70

Figure 6.4.17. GHG emissions versus city population for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 70

Figure 6.4.18. Petroleum energy use versus city population for the central biomass—pipeline 

delivery pathway................................................................................................................................. 71

xvi 
Figure 6.4.19. Levelized cost versus fuel economy for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 71

Figure 6.4.20. City hydrogen use versus fuel economy for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 72

Figure 6.4.21. GHG emissions versus fuel economy for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 72

Figure 6.4.22. Petroleum use versus fuel economy for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 73

Figure 6.4.23. Levelized cost versus forecourt size for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 73

Figure 6.4.24. GHG emissions versus forecourt size for the central biomass—pipeline delivery 

pathway ............................................................................................................................................... 74

Figure 6.4.25. Petroleum energy use versus forecourt size for the central biomass—pipeline 

delivery pathway................................................................................................................................. 74

Figure 6.5.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

biomass—gaseous H2 truck delivery pathway................................................................................ 76

Figure 6.5.2. Cost analysis inputs and high-level results for the central biomass—gaseous H2

truck delivery pathway....................................................................................................................... 77

Figure 6.5.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—gaseous H2 truck delivery pathway ..................................... 78

Figure 6.5.4. Breakdown of levelized costs for the central biomass—gaseous H2 truck delivery 

pathway ............................................................................................................................................... 78

Figure 6.5.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—gaseous H2 truck delivery pathway................................................................................ 80

Figure 6.5.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—gaseous H2 truck delivery pathway............................................................. 80

Figure 6.5.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—gaseous H2 truck delivery pathway................................................................................ 81

Figure 6.5.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—gaseous H2 truck delivery pathway ............................. 81

Figure 6.5.9. Production sensitivities for the central biomass—gaseous H2 truck delivery pathway82

Figure 6.5.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—gaseous H2 truck delivery pathway................................................................................ 83

Figure 6.5.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—gaseous H2 truck delivery pathway84

Figure 6.5.12. Levelized cost versus hydrogen vehicle penetration and distance between

production facility and city gate for the central biomass—gaseous H2 truck delivery pathway85

Figure 6.5.13. WTW GHG emissions versus penetration for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 86

Figure 6.5.14. WTW petroleum use versus penetration for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 86

Figure 6.5.15. WTW fossil energy use versus penetration for the central biomass—gaseous H2

truck delivery pathway....................................................................................................................... 87

Figure 6.5.16. Levelized cost versus city population for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 88

Figure 6.5.17. GHG emissions versus city population for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 88

Figure 6.5.18. Petroleum energy use versus city population for the central biomass—gaseous H2

truck delivery pathway....................................................................................................................... 89

Figure 6.5.19. Levelized cost versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 89

Figure 6.5.20. City hydrogen use versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 90

Figure 6.5.21. GHG emissions versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 90

Figure 6.5.22. Petroleum use versus fuel economy for the central biomass—gaseous H2 truck 

xvii 
delivery pathway................................................................................................................................. 91

Figure 6.5.23. Levelized cost versus forecourt size for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 91

Figure 6.5.24. GHG emissions versus forecourt size for the central biomass—gaseous H2 truck 

delivery pathway................................................................................................................................. 92

Figure 6.5.25. Petroleum energy use versus forecourt size for the central biomass—gaseous H2

truck delivery pathway....................................................................................................................... 92

Figure 6.6.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

biomass—liquid truck delivery and gaseous dispensing pathway............................................... 94

Figure 6.6.2. Cost analysis inputs and high-level results for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ..................................................................................... 95

Figure 6.6.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—liquid truck delivery and gaseous dispensing pathway.... 96

Figure 6.6.4. Breakdown of levelized costs for the central biomass—liquid truck delivery and 

gaseous dispensing pathway............................................................................................................ 96

Figure 6.6.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—liquid truck delivery and gaseous dispensing pathway............................................... 98

Figure 6.6.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—liquid truck delivery and gaseous dispensing pathway ........................... 98

Figure 6.6.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—liquid truck delivery and gaseous dispensing pathway............................................... 99

Figure 6.6.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—liquid truck delivery and gaseous dispensing pathway99

Figure 6.6.9. Production sensitivities for the central biomass—liquid truck delivery and gaseous 

dispensing pathway ......................................................................................................................... 100

Figure 6.6.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—liquid truck delivery and gaseous dispensing pathway............................................. 101

Figure 6.6.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and gaseous 

dispensing pathway ......................................................................................................................... 102

Figure 6.6.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and gaseous 

dispensing pathway ......................................................................................................................... 103

Figure 6.6.13. Truck levelized cost versus distance between production facility and city gate for 

the central biomass—liquid truck delivery and gaseous dispensing pathway ......................... 104

Figure 6.6.14. Liquefaction system levelized cost versus penetration for the central biomass—

liquid truck delivery and gaseous dispensing pathway............................................................... 105

Figure 6.6.15. Liquefaction system capital cost (levelized) versus penetration for the central 

biomass—liquid truck delivery and gaseous dispensing pathway............................................. 105

Figure 6.6.16. Liquefaction system efficiency versus penetration for the central biomass—liquid 

truck delivery and gaseous dispensing pathway.......................................................................... 106

Figure 6.6.17. WTW GHG emissions versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 107

Figure 6.6.18. WTW petroleum use versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 107

Figure 6.6.19. WTW fossil energy use versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 108

Figure 6.6.20. Levelized cost versus city population for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 109

Figure 6.6.21. GHG emissions versus city population for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 109

Figure 6.6.22. Petroleum energy versus city population for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 110

Figure 6.6.23. Levelized cost versus fuel economy for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 110

Figure 6.6.24. City hydrogen use versus fuel economy for the central biomass—liquid truck 

xviii
delivery and gaseous dispensing pathway ................................................................................... 111

Figure 6.6.25. GHG emissions versus fuel economy for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 111

Figure 6.6.26. Petroleum energy use versus fuel economy for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 112

Figure 6.6.27. Levelized cost versus forecourt size for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 112

Figure 6.6.28. GHG emissions versus forecourt size for the central biomass—liquid truck delivery 

and gaseous dispensing pathway .................................................................................................. 113

Figure 6.6.29. Petroleum energy use versus forecourt size for the central biomass—liquid truck 

delivery and gaseous dispensing pathway ................................................................................... 113

Figure 6.7.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway ............................. 115

Figure 6.7.2. Cost analysis inputs and high-level results for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway.................................................................... 116

Figure 6.7.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—liquid truck delivery and cryo-compressed dispensing 

pathway ............................................................................................................................................. 117

Figure 6.7.4. Breakdown of levelized costs for the central biomass—liquid truck delivery and cryocompressed dispensing pathway................................................................................................... 117

Figure 6.7.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway ............................. 119

Figure 6.7.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—liquid truck delivery and cryo-compressed dispensing pathway.......... 119

Figure 6.7.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway ............................. 120

Figure 6.7.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—liquid truck delivery and cryo-compressed dispensing 

pathway ............................................................................................................................................. 120

Figure 6.7.9. Production sensitivities for the central biomass—liquid truck delivery and cryocompressed dispensing pathway................................................................................................... 121

Figure 6.7.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway ............................. 122

Figure 6.7.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and cryocompressed dispensing pathway................................................................................................... 123

Figure 6.7.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and cryocompressed dispensing pathway................................................................................................... 124

Figure 6.7.13. Truck levelized cost versus distance between production facility and city gate for 

the central biomass—liquid truck delivery and cryo-compressed dispensing pathway.......... 125

Figure 6.7.14. Liquefaction system levelized cost versus penetration for the central biomass—

liquid truck delivery and cryo-compressed dispensing pathway ............................................... 126

Figure 6.7.15. Liquefaction system capital cost (levelized) versus penetration for the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway ............................. 126

Figure 6.7.16. Liquefaction system efficiency versus penetration for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway.......................................................... 127

Figure 6.7.17. WTW greenhouse gas emissions versus penetration for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway.......................................................... 128

Figure 6.7.18. WTW petroleum use versus penetration for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway.................................................................... 128

Figure 6.7.19. WTW fossil energy use versus penetration for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway.................................................................... 129

Figure 6.7.20. Levelized cost versus city population for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 130

Figure 6.7.21. GHG emissions versus city population for the central biomass—liquid truck delivery 

xix
and cryo-compressed dispensing pathway................................................................................... 131

Figure 6.7.22. Petroleum use versus city population for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 131

Figure 6.7.23. Levelized cost versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 132

Figure 6.7.24. City hydrogen use versus fuel economy for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway.................................................................... 132

Figure 6.7.25. GHG emissions versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 133

Figure 6.7.26. Petroleum use versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 133

Figure 6.7.27. Levelized cost versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 134

Figure 6.7.28. GHG emission versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 134

Figure 6.7.29. Petroleum use versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway................................................................................... 135

Figure 6.8.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

natural gas—pipeline delivery pathway ......................................................................................... 136

Figure 6.8.2. Cost analysis inputs and high-level results for the central natural gas—pipeline 

delivery pathway............................................................................................................................... 137

Figure 6.8.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen from the central natural gas—pipeline delivery pathway ........................................... 138

Figure 6.8.4. Breakdown of levelized costs for the central natural gas—pipeline delivery pathway138

Figure 6.8.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

natural gas—pipeline delivery pathway ......................................................................................... 140

Figure 6.8.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central natural gas—pipeline delivery pathway...................................................................... 140

Figure 6.8.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

natural gas—pipeline delivery pathway ......................................................................................... 141

Figure 6.8.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central natural gas—pipeline delivery pathway ...................................... 141

Figure 6.8.9. Production sensitivities for central natural gas–pipeline delivery pathway .............. 142

Figure 6.9.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

wind electricity—pipeline delivery pathway .................................................................................. 144

Figure 6.9.2. Cost analysis inputs and high-level results for the central wind electricity—pipeline 

delivery pathway............................................................................................................................... 145

Figure 6.9.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen from the central wind electricity—pipeline delivery pathway .................................... 146

Figure 6.9.4. Breakdown of levelized costs for the central wind electricity—pipeline delivery 

pathway ............................................................................................................................................. 147

Figure 6.9.6. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

wind electricity—pipeline delivery pathway .................................................................................. 149

Figure 6.9.7. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central wind electricity—pipeline delivery pathway............................................................... 149

Figure 6.9.8. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

wind electricity—pipeline delivery pathway .................................................................................. 150

Figure 6.9.9. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central wind electricity—pipeline delivery pathway ............................... 150

Figure 6.9.10. Life-cycle petroleum, natural gas, and coal inputs for both the central wind 

electricity—pipeline delivery pathway and the vehicle cycle ...................................................... 151

Figure 6.9.11. Life-cycle CO2, CH4, and N2O emissions for both the central wind electricity—

pipeline delivery pathway and the vehicle cycle........................................................................... 151

Figure 6.9.12. Production sensitivities for the central wind electricity—pipeline delivery pathway152

Figure 6.10.1. Summary of major inputs, assumptions, and outputs by subsystem for the central 

coal with CCS—pipeline delivery pathway .................................................................................... 154

xx 
Figure 6.10.2. Cost analysis inputs and high-level results for the central coal with CCS—pipeline 

delivery pathway............................................................................................................................... 155

Figure 6.10.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central coal with CCS—pipeline delivery pathway.......................................... 156

Figure 6.10.4. Breakdown of levelized costs for the central coal with CCS—pipeline delivery 

pathway ............................................................................................................................................. 156

Figure 6.10.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

coal with CCS—pipeline delivery pathway .................................................................................... 158

Figure 6.10.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central coal with CCS—pipeline delivery pathway................................................................. 158

Figure 6.10.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

coal with CCS—pipeline delivery pathway .................................................................................... 159

Figure 6.10.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central coal with CCS—pipeline delivery pathway.................................. 159

Figure 6.10.9. Production sensitivities for the central coal with CCS—pipeline delivery pathway 160

Figure 7.0.1. Levelized cost of hydrogen for all pathways, based on 48 mpgge fuel economy..... 162

Figure 7.0.2. Levelized cost of hydrogen for all pathways for both 48 and 68 mpgge fuel economy162

Figure 7.0.3. Production levelized costs for 10 pathways .................................................................. 164

Figure 7.0.4. Normalized capital costs for 10 pathways ..................................................................... 165

Figure 7.0.5. Pathway energy use for 10 pathways ............................................................................. 166

Figure 7.0.6. WTW, pathway, and production efficiencies for 10 hydrogen pathways.................... 167

Figure 7.0.7. WTW petroleum energy use for 10 hydrogen pathways............................................... 168

Figure 7.0.8. WTW natural gas energy use for 10 hydrogen pathways............................................. 169

Figure 7.0.9. WTW GHG emissions for 10 hydrogen pathways ......................................................... 170

Figure 7.0.10. Comparison of pathways’ petroleum use and GHG emissions (48 mpgge)............. 171

Figure 7.0.11a. Comparison of pathways’ levelized costs per mile and GHG emissions (based on 

48 mpgge fuel economy) ................................................................................................................. 172

Figure 7.0.11b. Comparison of pathways’ levelized costs per mile and GHG emissions (based on 

68 mpgge fuel economy) ................................................................................................................. 173

Figure 7.0.12. Per-mile levelized hydrogen costs for 10 hydrogen pathways .................................. 174

Figure 7.0.13. Levelized hydrogen costs with possible cost of carbon for 10 hydrogen pathways 

(based on 48 mpgge fuel economy) ............................................................................................... 174

xxi 
List of Tables

Table ES.1. Ten Hydrogen Production, Delivery, and Distribution Pathways .................................... vii

Table 1.4.1. Ten Hydrogen Production, Delivery, and Distribution Pathways...................................... 3

Table 4.2.1. Change in Exhaust as Compared to a Gasoline Vehicle.................................................. 24

Table 4.3.1. FCEV Subsystem Costs....................................................................................................... 25

Table 4.3.2. ICE Vehicle Subsystem Costs............................................................................................. 25

Table 4.4.1. FCEV Subsystem Mass Percentages ................................................................................. 26

Table 5.0.1. H2A Key Economic Parameters.......................................................................................... 27

Table 6.0.1. Ten Hydrogen Production, Delivery, and Distribution Pathways.................................... 29

Table 6.1.1. WTP and WTW Results for the Distributed Natural Gas Pathway................................... 32

Table 6.1.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost for the 

Distributed Natural Gas Pathway...................................................................................................... 34

Table 6.1.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Distributed Natural Gas Pathway ...................................................................................... 39

Table 6.1.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Distributed Natural Gas Pathway ...................................................................................... 39

Table 6.2.1. WTP and WTW Results for the Distributed Ethanol Pathway.......................................... 42

Table 6.2.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost for the 

Distributed Ethanol Pathway............................................................................................................. 45

Table 6.2.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Distributed Ethanol Pathway ............................................................................................. 48

Table 6.2.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Distributed Ethanol Pathway ............................................................................................. 48

Table 6.3.1. WTP and WTW Results for the Distributed Grid Electricity Pathway ............................. 51

Table 6.3.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost for the 

Distributed Grid Electricity Pathway ................................................................................................ 53

Table 6.3.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Distributed Grid Electrolysis Pathway.............................................................................. 56

Table 6.3.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Distributed Grid Electrolysis Pathway.............................................................................. 56

Table 6.4.1. WTP and WTW Results for the Central Biomass—Pipeline Delivery Pathway.............. 59

Table 6.4.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Pipeline Delivery Pathway................................................................................. 61

Table 6.4.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Pipeline Delivery Pathway ................................................................. 64

Table 6.4.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Pipeline Delivery Pathway ................................................................. 64

Table 6.5.1. WTP and WTW Results for the Central Biomass—Gaseous H2 Truck Delivery Pathway77

Table 6.5.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Gaseous H2 Truck Delivery Pathway................................................................ 79

Table 6.5.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Gaseous H2 Truck Delivery Pathway ................................................ 82

Table 6.5.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Gaseous H2 Truck Delivery Pathway ................................................ 83

Table 6.6.1. WTP and WTW Results for the Central Biomass—Liquid Truck Delivery and Gaseous 

Dispensing Pathway........................................................................................................................... 95

Table 6.6.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway............................. 97

Table 6.6.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway ........... 100

Table 6.6.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway ........... 101

Table 6.7.1. WTP and WTW Results for the Central Biomass—Liquid Truck Delivery and CryoCompressed Dispensing Pathway.................................................................................................. 116

Table 6.7.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

xxii 
Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway........... 118

Table 6.7.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway121

Table 6.7.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway122

Table 6.8.1. WTP and WTW Results for the Central Natural Gas—Pipeline Delivery Pathway....... 137

Table 6.8.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Natural Gas—Pipeline Delivery Pathway.......................................................................... 139

Table 6.8.3. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Natural Gas—Pipeline Delivery Pathway .......................................................... 142

Table 6.9.1. WTP and WTW Results for the Central Wind Electricity—Pipeline Delivery Pathway 145

Table 6.9.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost from 

the Central Wind Electricity—Pipeline Delivery Pathway ............................................................ 148

Table 6.10.1. WTP and WTW Results for the Central Coal with CCS—Pipeline Delivery Pathway 155

Table 6.10.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost from 

the Central Coal with CCS—Pipeline Delivery Pathway............................................................... 157

Table 6.10.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Coal with CCS—Pipeline Delivery Pathway...................................................... 160

Table 6.10.4. The Effects of Grid Mix on Use of Primary Energy and Emissions from the Central 

Coal with CCS—Pipeline Delivery Pathway................................................................................... 160

Table 7.0.1. Key Analysis Parameters................................................................................................... 161

xxiii
1 Introduction

1.1 Document’s Intent

The United States (U.S.) Department of Energy (DOE) has identified a need to understand the 

life-cycle cost, energy use, and emissions tradeoffs of various hydrogen production, delivery, and 

use pathways under consideration to enable a transition from a hydrocarbon-based economy to a 

hydrogen-and-electricity-based economy. In 2009 the National Renewable Energy Laboratory

(NREL) addressed this need by analyzing and reporting on a life-cycle cost, energy use, and 

emissions evaluation of seven hydrogen production, delivery, and use pathways (Ruth, Laffen

and Timbario 2009). The present analysis updates and expands on the 2009 evaluation, assessing 

life-cycle costs, energy use, and emissions of a set of hydrogen pathways using updated costs 

and technology assumptions. This report contains the results of the updated life-cycle evaluation, 

including the updated cost of delivered hydrogen for the seven hydrogen production, delivery, 

and use pathways previously studied using the Macro-System Model (MSM), as well as three 

additional potential hydrogen production, delivery, and use pathways. The report also provides 

the results of sensitivity evaluations of the cost of delivered hydrogen to varying assumptions 

regarding feedstock cost, capital cost, plant capacity, and utility cost. 

This analysis will aid in understanding and assessing technology needs and progress, potential 

environmental impacts, and the energy-related economic benefits of various hydrogen supply 

and demand pathways. 

The MSM was used to analyze the pathways by linking the H2A Production Model, the 

Hydrogen Delivery Scenario Analysis Model (HDSAM), the Greenhouse Gas, Regulated 

Emission, and Energy for Transportation (GREET) Model, and the Cost-per-Mile (CPM) Tool. 

The MSM links those models so they can be executed concurrently, utilizing the capabilities of 

each and ensuring consistency among them. Also, the MSM is available to the public and 

enables users to analyze pathways and complete sensitivity analyses that are not reported in this 

document. Consistent with the standard employed by the H2A Production model and HDSAM, 

costs are presented in 2007 U.S. dollars. 

The primary differences between the 2009 report and this report are that the current study: 

• Analyzed three additional pathways: distributed ethanol reforming, central biomass 

reforming with delivery in gaseous hydrogen trucks, and central biomass reforming with 

delivery in liquid hydrogen trucks with cryo-compressed dispensing. 

• Added vehicle costs and vehicle-cycle energy use and emissions to calculate overall 

ownership costs and fuel-plus-vehicle-cycle energy use and emissions. The vehicle is 

assumed to be owned for 5 years and be driven 15,000 miles per year and sold in good 

condition at the end of that period. Energy use and emissions are averaged over a vehicle 

lifetime of 160,000 miles. 

1 
• Used H2A Version 3, HDSAM Version 2.3, GREET 1 2011, GREET 2.7, and the CPM 

Tool within the MSM.3 (The central coal with carbon-capture and sequestration [CCS] 

case still uses H2A Version 2.1.1, which is the most recent H2A version of this case.) 

• Updated energy prices from the Energy Information Administration’s Annual Energy 

Outlook 2009. 

• Updated cost of delivered hydrogen in 2007 dollars from 2005 dollars (except for the 

central coal with CCS pathway). 

• Reduced vehicle penetration rate from 50% to 15%. 

• Increased vehicle fuel economy from 45 to 48 miles per gallon gasoline equivalent 

(mpgge). Additional sensitivity analyses using 68 mpgge were also performed. 

• Increased hydrogen dispensing pressure from 5,000 psi (350 bar) to 10,000 psi (700 bar). 

This document reports a greater level of detail than analyses that show only the full pathway 

results (or maybe have a single break-point in the pathway), but it reports little information at the 

unit-operation level. Parameters that are expected to have major effects on the results are 

reported at the unit-operation level. 

1.2 Hypothetical Market State and Technology Development 

Assumptions

The pathways analyzed are intended to be plausible production scenarios for mature technologies 

with full deployment of a regional hydrogen fueling network. They are not transition scenarios 

where equipment may not be utilized fully, nor are they technology validation activities where 

production, delivery, and vehicle costs are higher due to first-of-a-kind plants and low 

production levels of vehicles. Specifically, today’s technical status is extrapolated to a scenario 

where 15% of the vehicles are fueled by hydrogen in a city with the area (553 mi2) and 

population (1,247,364) of Indianapolis, Indiana, and all equipment is fully utilized for its 

lifetime. Production facilities are not scaled to meet demand; instead, necessary demand from 

other nearby communities is assumed available so the facilities are kept at the H2A-defined 

natural scale.

Costs, energy use, and emissions estimates in this study are based on current technologies, and 

costs are reported in 2007 U.S. dollars (except where noted). In this analysis, “current 

technology” refers to technology that is available currently at the bench scale—not necessarily 

technology that has been demonstrated at production scales. Thus, assumptions about largerscale performance and equipment requirements and costs are necessary. 

Designs and costs in this analysis do not include additional requirements of first-of-a-kind or 

one-of-a-kind technologies. In many cases, first-of-a-kind technologies require safety factors, 

instrumentation, and contingencies that are not necessary later in the development process. Those 

additional costs are not included in this analysis because they are difficult to account for and 

because they are not well understood. Instead, technology designs and costs are based on “nth

3 The versions of H2A, HDSAM, and GREET used were current at the time this life-cycle evaluation began. As of 

the publication of this report, H2A Version 3 and HDSAM Version 2.3 are still current, but more recent updates of 

the GREET 1 and GREET 2 models were made available in late 2012.

2 

 
plant” techniques (techniques that inherently assume that the technology is mature and do not 

include additional contingency, capital costs, and yield loss necessary for first-of-a-kind plant 

cost estimation). 

1.3 Analysis Boundaries

The “well-to-wheels” (WTW) energy use and emissions are assessed for each pathway using the 

GREET 1 fuel-cycle model. Included in the assessment are feedstock recovery, transportation, 

and storage; fuel production, transportation, storage, and distribution; and vehicle production, 

maintenance, operation, and disposal. The reported energy use includes both direct and indirect 

use of raw materials (natural gas, coal, and petroleum). For feedstock recovery, direct use of raw 

materials involves those used to recover and refine the feedstock, and indirect use of raw 

materials involves those needed to produce electricity and materials that are used directly. In 

addition to WTW analyses, life-cycle energy use and emissions are assessed for each pathway by 

combining the fuel-cycle WTW assessment from GREET 1 with the vehicle-cycle assessment 

from GREET 2.

Energy used and emissions generated to produce the equipment required to recover the 

feedstock, produce the fuel, produce the vehicles, and so on, are not included. 

1.4 Pathways 

The 10 pathways included in this analysis are shown in Table 1.4.1. 

Table 1.4.1. Ten Hydrogen Production, Delivery, and Distribution Pathways

Feedstock Central or

Distributed

Production

Carbon

Capture and

Sequestration

Delivery

Method

Hydrogen

Distribution

1 Natural Gas Distributed No Not applicable 700 bar, gaseous

2a Ethanol Distributed No Not applicable 700 bar, gaseous

3 Grid Electricity Distributed No Not applicable 700 bar, gaseous

4 Biomass Central No Gaseous H2 in 

pipelines

700 bar, gaseous

5a Biomass Central No Gaseous H2 truck 700 bar, gaseous

6 Biomass Central No Liquid H2 truck 700 bar, gaseous

7a Biomass Central No Liquid H2 truck Cryo-compressed

8 Natural Gas Central No Gaseous H2 in 

pipelines

700 bar, gaseous

9 Wind 

Electricity

Central No Gaseous H2 in 

pipelines

700 bar, gaseous

10 Coal Central Yes Gaseous H2 in 

pipelines

700 bar, gaseous

a Newly analyzed pathways

For convenience, the pathways are identified throughout this report using the feedstock and the 

delivery method; for example: Pathway 1 is referred to as the distributed natural gas pathway, 

Pathway 2 is referred to as the distributed ethanol pathway, Pathway 3 is the distributed 

electrolysis pathway, and Pathway 4 is the central biomass with pipeline delivery pathway.

Each pathway description below includes a flowchart showing the major subsystems of the 

hydrogen production and delivery pathway and the amount of energy required for each. Not 

3 
4 

included in these flowcharts are the energy requirements to supply the feedstock for hydrogen 

production; the energy use for feedstock production and delivery is included in the full WTW 

results presented in Section 6.0. 

1.4.1 Pathway 1: Distributed Natural Gas 

In the distributed natural gas pathway, hydrogen is produced from natural gas at the hydrogen 

refueling site using a 1,500 kg H2/day steam methane reformer (SMR) with water-gas shift 

(WGS). Pressure swing adsorption (PSA) is used to obtain the required hydrogen purity. The 

hydrogen is then compressed to 12,687 psi (875 bar) and stored on-site prior to dispensing as a 

gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The flow diagram in Figure 1.4.1 

shows the fuel production and delivery components of the distributed natural gas pathway and 

the energy balance for the major hydrogen-related subsystems, on a 1-gallon gasoline equivalent 

(gge) basis. The production and forecourt technologies are detailed in Ruth, Laffen and Timbario 

(2009). 

Figure 1.4.1. Flow diagram and energy balance of distributed natural gas pathway 

Values may not sum to zero due to rounding.

This pathway is considered among the least costly in the near term to establish early market 

refueling capability (Greene et al. 2008). 

1.4.2 Pathway 2: Distributed Ethanol 

In the distributed ethanol pathway, hydrogen is produced from corn stover-based ethanol at the 

hydrogen refueling site using a 1,500 kg H2/day steam reformer with a WGS reactor. PSA is 

used to obtain the required hydrogen purity. The hydrogen is then compressed to 12,687 psi (875 

bar) and stored on-site prior to dispensing as a gaseous fuel to the 10,000 psi (700 bar) vehicle 

fuel tank. The flow diagram in Figure 1.4.2 shows the fuel production and delivery components 

of the distributed ethanol pathway and the energy balance for the major hydrogen-related 

subsystems, on a 1-gge basis. The production technologies are detailed in Section 2.2, and the 

delivery technologies are detailed in Ruth, Laffen and Timbario (2009). 
5 

Figure 1.4.2. Flow diagram and energy balance of distributed ethanol pathway 

Values may not sum to zero due to rounding.

1.4.3 Pathway 3: Distributed Electricity 

In the distributed electricity pathway, hydrogen is produced from water at the hydrogen refueling 

site using a 1,500 kg H2/day grid-powered electrolyzer. A scrubber is used to obtain the required 

hydrogen purity. The hydrogen is then compressed to 12,687 psi (875 bar) and stored on-site 

prior to dispensing as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The flow 

diagram in Figure 1.4.3 shows the fuel production and delivery components of the distributed 

electricity pathway and the energy balance for the major hydrogen-related subsystems, on a 1-

gge basis. The production and forecourt technologies are detailed in Ruth, Laffen and Timbario 

(2009). 

This pathway offers an alternative to distributed natural gas, particularly in areas where clean, 

inexpensive electricity is available. 

Figure 1.4.3. Flow diagram and energy balance of distributed electricity pathway 

Values may not sum to zero due to rounding.

1.4.4 Pathway 4: Central Biomass—Pipeline Delivery 

In the central biomass—pipeline delivery pathway, woody biomass (poplar) within a 50-mile 

radius is transported via truck to a central hydrogen production facility with a design capacity of 
6 

2,000 bone dry metric ton/day biomass (~155,000 kg H2/day). An indirectly heated biomass 

gasifier converts the biomass to a biogas, which is then converted to hydrogen using a catalytic 

SMR with WGS. PSA is used to obtain the required hydrogen purity. The hydrogen is 

compressed to 1,000 psi (69 bar) and injected into a pipeline, through which it is transported to a 

1,000 kg/day forecourt hydrogen refueling station. There the hydrogen is compressed to 12,687 

psi (875 bar) and dispensed as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The 

flow diagram in Figure 1.4.4 shows the fuel production and delivery components of the central 

biomass—pipeline delivery pathway and the energy balance for the major hydrogen-related 

subsystems, on a 1-gge basis. The production, delivery, and forecourt technologies are detailed 

in Ruth, Laffen and Timbario (2009). 

Figure 1.4.4. Flow diagram and energy balance of central biomass—pipeline delivery pathway 

Values may not sum to zero due to rounding.

1.4.5 Pathway 5: Central Biomass—Gaseous H2 Truck Delivery 

In the central biomass—gaseous truck delivery pathway, woody biomass (poplar) within a 50-

mile radius is transported via truck to a central hydrogen production facility with a design 

capacity of 2,000 bone dry metric ton/day biomass (~155,000 kg H2/day). An indirectly heated 

biomass gasifier converts the biomass to a biogas, which is then converted to hydrogen using a 

catalytic SMR with WGS. PSA is used to obtain the required hydrogen purity. The hydrogen is 

then transported via pipeline to a cavern for geologic storage. The cavern is designed to satisfy a 

surge in demand during the summer period and to provide storage during the annual shutdown of 

the hydrogen production facility. The usable capacity of the geologic storage is >1.3 million kg 

H2. The hydrogen is then transported from the geologic storage facility to a terminal, where it is 

compressed to 3,777 psi and loaded into tube trailers. The tube trailers are transported via truck 

to a 800 kg/day forecourt hydrogen refueling station. There the hydrogen is compressed to 

12,687 psi (875 bar) and dispensed as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel 

tank. The flow diagram in Figure 1.4.5 shows the fuel production and delivery components of the 

central biomass—gaseous truck delivery pathway and the energy balance for the major 

hydrogen-related subsystems, on a 1-gge basis. The production and forecourt technologies are 

detailed in Ruth, Laffen and Timbario (2009). 
Figure 1.4.5. Flow diagram and energy balance of central biomass—gaseous truck delivery 

pathway

Values may not sum to zero due to rounding.

1.4.6 Pathway 6: Central Biomass—Liquid Truck Delivery and Gaseous 

Dispensing

In the central biomass—liquid truck delivery pathway, woody biomass (poplar) within a 50-mile 

radius is transported via truck to a central hydrogen production facility with a design capacity of 

2,000 bone dry metric ton/day biomass (~155,000 kg H2/day). An indirectly heated biomass 

gasifier converts the biomass to a biogas, which is then converted to hydrogen using a catalytic 

SMR with WGS. PSA is used to obtain the required hydrogen purity. The hydrogen is liquefied, 

stored as necessary, loaded into tube trailers, and delivered via truck to a 1,000 kg/day forecourt 

hydrogen refueling station, where it is vaporized, compressed to 12,687 psi (875 bar), and 

dispensed as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The flow diagram in 

Figure 1.4.6 shows the fuel production and delivery components of the central biomass—liquid 

truck delivery pathway and the energy balance for the major hydrogen-related subsystems, on a 

1-gge basis. The production and forecourt technologies are detailed in Ruth, Laffen and

Timbario (2009). 

Figure 1.4.6. Flow diagram and energy balance of central biomass—liquid truck delivery pathway

Values may not sum to zero due to rounding.

7 
8 

1.4.7 Pathway 7: Central Biomass—Liquid Truck Delivery and Cryo-Compressed 

Dispensing 

In the central biomass—liquid truck delivery and cryo-compressed dispensing pathway, woody 

biomass (poplar) within a 50-mile radius is transported via truck to a central hydrogen 

production facility with a design capacity of 2,000 bone dry metric ton/day biomass (~155,000 

kg H2/day). An indirectly heated biomass gasifier converts the biomass to a biogas, which is then 

converted to hydrogen using a catalytic SMR with WGS. PSA is used to obtain the required 

hydrogen purity. The hydrogen is liquefied, stored as necessary, loaded into tube trailers, and 

delivered via truck to a 1,000 kg/day forecourt hydrogen refueling station, where it is dispensed 

via a cryogenic pump as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The flow 

diagram in Figure 1.4.7 shows the fuel production and delivery components of the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway and the energy balance 

for the major hydrogen-related subsystems, on a 1-gge basis. The production and delivery 

technologies are detailed in Ruth, Laffen and Timbario (2009). 

The biomass pathways were selected for this study because of their potential to provide hydrogen 

with low or zero net carbon dioxide (CO2) emissions and because there are feedstock 

availability, delivery, and handling issues that are unique to biomass. These pathways are also 

more dependent on regional resource availability and costs than other pathways are; while 

sensitivity studies to regionality are outside the scope of this study, they may be conducted as 

more data become available. 

Figure 1.4.7. Flow diagram and energy balance of central biomass—liquid truck delivery and cryocompressed dispensing pathway 

Values may not sum to zero due to rounding. 

These are the only pathways studied that utilize liquid hydrogen delivery. Comparison of the 

liquid hydrogen delivery pathways with the central biomass—pipeline delivery pathway offers 

insights to the advantages, disadvantages, and issues associated with liquid hydrogen delivery. It 

also offers the opportunity to examine the sensitivity of delivery options (gaseous or liquid truck 

and gaseous pipeline) to parameters such as delivery distance and degree of hydrogen 

penetration in the vehicular fuel market. 
9 

1.4.8 Pathway 8: Central Natural Gas—Pipeline Delivery 

In the central natural gas—pipeline delivery pathway, natural gas is carried via pipeline to a 

central hydrogen production facility with a design capacity of ~379,000 kg H2/day, where an 

SMR with WGS is used to reform the natural gas to hydrogen. PSA is used to obtain the required 

hydrogen purity. The hydrogen is compressed to 1,000 psi (69 bar) and injected into a pipeline, 

through which it is transported to a 1,000 kg/day forecourt hydrogen refueling station. There the 

hydrogen is compressed to 12,687 psi (875 bar) and dispensed as a gaseous fuel to the 10,000 psi 

(700 bar) vehicle fuel tank. The flow diagram in Figure 1.4.8 shows the fuel production and 

delivery components of the central natural gas—pipeline delivery pathway and the energy 

balance for the major hydrogen-related subsystems, on a 1-gge basis. The production, delivery, 

and forecourt technologies are detailed in Ruth, Laffen and Timbario (2009). 

Figure 1.4.8. Flow diagram and energy balance of central natural gas—pipeline delivery pathway 

Values may not sum to zero due to rounding.

The central natural gas—pipeline delivery pathway was selected as a benchmark case for this 

study. Large-scale natural gas reforming is a mature process being used to produce hydrogen for 

industrial applications such as merchant hydrogen sales, chemical production, and oil refining. It 

is expected to result in the lowest cost of hydrogen when pipeline delivery is employed. 

1.4.9 Pathway 9: Central Wind Electricity—Pipeline Delivery 

In the central wind electricity—pipeline delivery pathway, hydrogen is produced from water at a 

central production facility using a grid-powered electrolyzer with a design capacity of ~52,300 

kg H2/day. It is assumed that the facility buys wind-power credits for all of the electricity 

purchased. (From an emission perspective, solar photovoltaic or other forms of zero-emission 

electricity could be assumed, though the costs presented assume the purchase of wind power.) A 

scrubber is used to obtain the required hydrogen purity. The hydrogen is compressed to 1,000 psi 

(69 bar) and injected into a pipeline, through which it is transported to a 1,000 kg/day forecourt 

hydrogen refueling station. There the hydrogen is compressed to 12,687 psi (875 bar) and 

dispensed as a gaseous fuel to the 10,000 psi (700 bar) vehicle fuel tank. The flow diagram in 

Figure 1.4.9 shows the fuel production and delivery components of the central wind electricity—

pipeline delivery pathway and the energy balance for the major hydrogen-related subsystems, on 
10 

a 1-gge basis. The production and forecourt technologies are detailed in Ruth, Laffen and 

Timbario (2009). 

Figure 1.4.9. Flow diagram and energy balance of central wind electricity—pipeline delivery 

pathway 

Values may not sum to zero due to rounding.

The central wind electricity—pipeline delivery pathway represents a low-carbon, renewable 

energy-based option for providing hydrogen as a transportation fuel. Unlike the biomass 

pathways, which have potential geographic limitations, the wind electricity pathway can be 

implemented anywhere that wind-power credits are available for purchase. 

1.4.10 Pathway 10: Central Coal with Carbon Capture and Sequestration—Pipeline 

Delivery 

In the central coal with carbon capture and sequestration (CCS)—pipeline delivery pathway, coal 

is delivered via rail to a central hydrogen production facility with a design capacity of ~308,000 

kg H2/day, where it is gasified. A shift converter is used to convert the syngas to a hydrogen-rich 

gas, which undergoes acid gas cleanup and removes hydrogen sulfide prior to entering a PSA 

unit to obtain the required hydrogen purity. Carbon dioxide is captured using a Selexol process 

and is compressed to 2,200 psi (152 bar) for injection to a pipeline. It is transported via pipeline 

to a sequestration site. The hydrogen is compressed to 1,000 psi (69 bar) and injected into a 

pipeline, through which it is transported to a 1,000 kg/day forecourt hydrogen refueling station. 

There the hydrogen is compressed to 12,687 psi (875 bar) and dispensed as a gaseous fuel to the 

10,000 psi (700 bar) vehicle fuel tank. The flow diagram in Figure 1.4.10 shows the fuel 

production and delivery components of the central coal with CCS—pipeline delivery pathway 

and the energy balance for the major hydrogen-related subsystems, on a 1-gge basis. The 

production and forecourt technologies are detailed in Ruth, Laffen and Timbario (2009). 
11 

Figure 1.4.10. Flow diagram and energy balance of central coal with CCS—pipeline delivery 

pathway 

Values may not sum to zero due to rounding.

Coal is an abundant fossil fuel in the United States, typically available at a relatively low cost. 

The central coal with CCS—pipeline delivery pathway was selected for this study to enable 

comparisons between coal and other fossil and renewable options for providing hydrogen 

transportation fuel. It is the only pathway studied that includes carbon capture and sequestration, 

thus offering opportunities for better understanding the effects of CCS on hydrogen costs, energy 

use, and emissions. 

1.5 Models Used in the Pathway Analyses 

The H2A Production Model Version 3.0 (Steward, Ramsden and Zuboy 2012) applies a standard 

discounted cash flow rate of return methodology to determine the minimum hydrogen selling 

price for central and forecourt hydrogen production technologies, including a specified after-tax 

internal rate of return. The H2A Production Model performs carbon sequestration calculations 

for centralized hydrogen production pathways and refueling station compression, storage, and 

dispensing calculations for distributed hydrogen production pathways. 

HDSAM Version 2.3 (Mintz, Elgowainy and Gillette 2010) calculates the cost of hydrogen 

delivery using an engineering economics approach via a single or mixed mode for transmission 

and distribution (cryogenic tank truck, compressed gas truck, or pipeline) for a scenario defined 

by type and size of market, penetration rate, and refueling station capacity. Delivery in Version 

2.3 includes all transport, storage, and conditioning activities from the outlets of a centralized 

hydrogen production facility to and including a fuel station that stores, in some cases further 

conditions, and dispenses the hydrogen to vehicles; this version does not model distributed 

production scenarios. Discounted cash flow is used to calculate the cost contribution of each 

component in the delivery chain. 

The GREET models (Argonne National Laboratory, 2012) calculate the full fuel-cycle (GREET 

1) and vehicle-cycle (GREET 2) emissions and energy use associated with various transportation

fuels for light-duty vehicles. Emissions included are the five criteria pollutants (volatile organic 

compounds, carbon monoxide, oxides of nitrogen, oxides of sulfur, and particulate matter) and 
three greenhouse gases (carbon dioxide, methane, and nitrous oxide). Additionally, total fuelcycle and vehicle-cycle energy consumption, fossil fuel consumption, and petroleum 

consumption are calculated. More than 100 fuel production pathways and more than 70 

vehicle/fuel systems are available in the current version of GREET. For this hydrogen pathways 

report, the GREET 1 2011 and GREET 2.7 versions were utilized for GREET 1 and GREET 2, 

respectively. 

The CPM Tool (Timbario et al. 2011) calculates the cost of vehicle ownership by estimating 

acquisition and operating costs for consumers and fleets. Operating costs include fuel, 

maintenance, tires, and repairs; ownership costs include insurance, registration, taxes and fees, 

depreciation, financing, and tax credits. The CPM Tool was developed to allow simultaneous 

comparisons of conventional light-duty internal combustion engine (ICE) vehicles, mild and full 

hybrid electric vehicles, and fuel cell electric vehicles (FCEVs). The tool assumes that the 

vehicle is kept for five years and is driven 15,000 miles per year. At the end of the ownership 

period, the vehicle is assumed to be sold in a clean, reconditioned state. All operating and 

ownership costs in 2007 dollars for the 5-year period are summed and divided by the annual 

vehicle miles traveled to obtain the annual cost per mile.

The MSM (Ruth et al. 2011) links the H2A Production Model, HDSAM, GREET, and the CPM 

Tool to perform WTW analysis of the energy use, emissions, and economics of hydrogen 

production and delivery pathways from feedstock extraction through end use of hydrogen in 

vehicles. The primary inputs to the MSM are technology year, city size and hydrogen fuel 

penetration, production and delivery technology, and vehicle fuel economy. H2A and HDSAM 

results are used for many of GREET’s input parameters in each MSM run. Primary energy 

source requirements and emissions are analyzed. Outputs of the model include the amount and 

type of feedstock used to produce hydrogen, efficiency values of different technologies, energy 

use and emissions of various pathways, hydrogen production capacity to meet demand, and 

levelized cost of hydrogen at the pump achievable under different scenarios. 

The MSM provides a Web-based interface that allows users to perform hydrogen pathway 

analyses following their own interests. It also allows for extensive single-parameter and multiparameter sensitivity studies. The MSM will be updated with future versions of the H2A 

Production Model, HDSAM, GREET, and the CPM Tool as they are made public.4

4 For access to the MSM, please contact Victor Diakov at victor.diakov@nrel.gov. 

12 

 
2 Production Technology Descriptions and

Assumptions

The hydrogen production technologies used in each of the 10 pathways examined in this study 

are summarized below. Full details for each production technology except ethanol reforming can 

be found in Ruth, Laffen and Timbario (2009). Note that this study assumes that energy used in 

the production facility for lighting, control systems, and other ancillary systems is small relative 

to the energy used directly in the production process; these items are therefore not included in the 

cost, energy use, and emissions calculations. 

2.1 Distributed Natural Gas Reforming

The H2A distributed natural gas model (James 2012) determines a baseline delivered cost of 

hydrogen for the forecourt production of hydrogen from natural gas steam reforming. The natural 

gas reforming process is based on an ASPEN simulation of a 20-atm conventional SMR process, 

with an accompanying hydro-desulfurization pretreatment and PSA gas cleanup. The PSA is 

based on a four-bed Batta cycle achieving 75% hydrogen recovery (single pass). Multiple passes 

are used to increase recovery. The unit is assumed to be factory built (as opposed to on-site 

construction) and skid-mounted for easy and rapid installation. 

A single 1,500 kg/day unit is assumed. The system is assumed to be air-cooled (and thus requires 

no cooling water flow). The product hydrogen exits the PSA at 300 psi and is compressed for 

storage in metal cylinder storage tanks (2,500 psi max pressures). The hydrogen is next 

compressed to 12,700 psi (maximum) for transfer into a four-bed, high-pressure cascade system 

to allow rapid filling of 10,000-psi onboard hydrogen vehicular tanks. A process flow diagram is 

shown in Ruth, Laffen and Timbario (2009). 

2.2 Distributed Ethanol Reforming

The H2A distributed ethanol model (James 2012) determines a baseline delivered cost of 

hydrogen for the forecourt production of hydrogen from ethanol reforming. The ethanol 

reforming process is based on an ASPEN simulation of a 20-atm conventional tube-in-shell 

steam reactor with PSA gas cleanup. Precious metal catalyst is assumed. The catalyzed 

conversion of ethanol to methane occurs rapidly to near-full ethanol conversion in a compact 

adiabatic pre-reformer. Because methane is the primary component of the pre-reformer effluent, 

the remainder of the system is nearly identical to that of a natural gas reformer system. Ethanol is 

the sole feedstock and is also used as a supplemental fuel to the burner. An adiabatic flame 

temperature of 950°C is assumed for the burner, and the reformer temperature is assumed to be 

850°C. Flue gas is exhausted at 110°C. The PSA is based on a four-bed Batta cycle achieving 

75% hydrogen recovery. The unit is assumed to be factory built (as opposed to on-site 

construction) and is skid-mounted for easy and rapid installation. 

A single 1,500 kg/day unit is assumed. The system is assumed to be air-cooled (and thus requires 

no cooling water flow). The product hydrogen exits the PSA at 300 psi and is compressed for 

storage in metal cylinder storage tanks (2,500 psi max pressures). The hydrogen is next 

compressed to 12,700 psi (maximum) for transfer into a four-bed high-pressure cascade system 

to allow rapid filling of 10,000-psi onboard hydrogen vehicular tanks. A process flow diagram is 

shown in Ruth, Laffen and Timbario (2009). 

13 
2.3 Distributed Electrolysis

The system modeled in the H2A distributed electrolysis model (Ruth and Ramsden 2012) is a 

standalone, grid-powered electrolyzer system with a total hydrogen production capacity of 1,500 

kg/day. The system is based on the NEL Hydrogen (formerly Norsk Hydro) bi-polar alkaline 

electrolyzer system (Atmospheric Type No. 5040–5150 amp direct current). The electrolyzer 

system modeled is a skid-mounted unit, including the electrolyzer system and necessary 

auxiliary subsystems. The electrolyzer units use process water for electrolysis and cooling water.

Potassium hydroxide is the electrolyte in the system. The system includes the following 

equipment: transformer, thyristor, electrolyzer unit, lye tank, feed water demineralizer, hydrogen 

scrubber, gas holder, two compressor units to 30 bar (435 psig), deoxidizer, and twin tower 

dryer. 

As with the distributed natural gas and ethanol reforming pathways, the produced hydrogen is 

compressed to 12,700 psi to allow rapid filling of 10,000-psi onboard hydrogen vehicular tanks. 

A process flow chart and a mass balance diagram are shown in Ruth, Laffen and Timbario

(2009). 

2.4 Central Biomass Gasification

The systems examined in the H2A central biomass gasification model (Mann and Steward 2012) 

are based on the Battelle/FERCO indirectly heated biomass gasifier, conventional catalytic steam 

reforming, WGS, and PSA purification. The indirectly heated biomass gasifier uses hot sand 

circulating between the char combustor and the gasifier to provide the heat necessary for 

gasification. Steam is used as the fluidizing gas; no oxygen (as pure oxygen or air) is fed to the 

gasifier. The biomass feedstock is assumed to be a woody biomass, represented as hybrid poplar. 

A process flow chart is shown in Ruth, Laffen and Timbario (2009). 

2.5 Central Natural Gas Reforming

Steam reforming of natural gas continues to be the most efficient, economical, and widely used 

process for production of hydrogen. The H2A central natural gas reforming model (Rutkowski 

2012) assesses the economics of production of hydrogen by steam reforming of natural gas.

A process flow diagram and stream summaries for the central natural gas reforming process are 

shown in Ruth, Laffen and Timbario (2009). Natural gas is fed to the plant from a pipeline at a 

pressure of 450 psia. The gas is generally sulfur-free, but mercaptans (odorizers) must be cleaned 

from the gas to prevent contamination of the reformer catalyst. The desulfurized natural gas 

feedstock is mixed with process steam to be reacted over a nickel-based catalyst contained inside 

a system of high alloy steel tubes. The reforming reaction, which converts the methane to a 

mixture of carbon monoxide (CO) and H2, is strongly endothermic, and the metallurgy of the 

tubes usually limits the reaction temperature to 760°–930°C. 

The flue gas path of the fired reformer is integrated with additional boiler tubes to produce about 

700,000 lb/h steam. Of this, about 450,000 lb/h is superheated to 450 psia and 750°F to be added 

to the incoming natural gas. Excess steam from the boiler is sent off-site; however, revenue from 

the steam is not factored into the economic assessment. After the reformer, the process gas 

mixture of CO and H2 passes through a heat recovery step and is fed into a WGS reactor to 

produce additional H2. 

14 
2.6 Central Electrolysis with Renewable Power

The system modeled in the H2A central electrolysis model (Ramsden and Ruth 2011) is a 

standalone grid-powered electrolyzer system with a total hydrogen production capacity of 52,300 

kg/day. The technology is identical to that used for distributed electrolysis even though it is 35 

times larger, which provides economies of scale for the auxiliary components. Thus, the process 

description for distributed electrolysis in Section 2.3 applies to this production process as well. 

The H2A central electrolysis model is not based on wind power, so this analysis assumes that a 

single facility is buying electricity from the grid and wind-power credits for all of the electricity 

purchased. Because the facility is using grid power, the operating capacity factor is 97%. If the 

facility were co-located with the wind turbines, it would likely have a lower operating capacity 

because the turbines would not be generating electricity all of the time. The optimal location and 

the capacity factor are not studied in this analysis.

2.7 Central Coal with Carbon Capture and Sequestration

The H2A central coal with carbon capture and sequestration model (Rutkowski 2008) uses

capital and operating cost data to determine a plant-gate cost for hydrogen produced from coal 

gasification. The plant design for hydrogen production is based on commercially available 

process technologies with modifications to meet current permitting regulations for environmental 

compliance. The coal gasification production plant is designed to capture and sequester CO2

emissions resulting from the shift conversion process. 

The plant utilizes a Wabash River-scale ConocoPhillips (EGas) gasifier, conventional gas 

cooling, commercial shift conversion and acid gas cleanup, commercial sulfuric acid technology, 

and commercial PSA. A steam turbine supplies the electricity needed for the process except that 

required to compress the CO2. A two-stage Selexol process is used to remove CO2. Carbon 

dioxide is compressed to 2,200 psi for sequestration using electricity purchased from the grid 

(U.S. grid mix). The EGas gasifier is the gasifier of choice for this study because it has been 

operated on both bituminous and subbituminous coals. H2A simulations of hydrogen from coal 

in central plants are based on the use of Pittsburgh No. 8 bituminous coal, while GREET 

simulations are based on generic coal. The properties of Pittsburgh No. 8 coal used in the H2A 

analysis, a process flow chart, and the energy efficiencies are shown in Ruth, Laffen and

Timbario (2009). 

15 
3 Delivery and Dispensing Technology Descriptions 

and Assumptions The hydrogen delivery and distribution technologies used in each of the 10 pathways examined 

in this study are summarized below. Full details for each delivery and distribution technology 

used in the previous study can be found in Ruth, Laffen and Timbario (2009). Note that this 

study assumes that energy used in the hydrogen refueling station for items such as lighting, 

cryogenic pumping, and security cameras is small relative to the total delivery and distribution 

energy use; these items are therefore not included in the cost, energy use, and emissions 

calculations.

3.1 Gaseous Hydrogen via Pipeline

The pathways with delivery of gaseous hydrogen via pipeline include the following components: 

central production → compressor → geologic storage for plant outages → transmission and 

distribution pipeline → and gaseous hydrogen fuel station. 

The largest diameter pipe of those in each scenario is the transmission pipeline. It extends from 

the production facility to the city gate. The diameter of the transmission pipeline is a function of 

its length, peak hydrogen demand, and the pressure differential between the pipeline inlet at the 

production end and the pipeline outlet at the city gate. An intermediate diameter pipe (trunk line) 

creates one or more rings within an area and is used to carry hydrogen from the transmission line 

to the individual service pipelines that connect to each individual hydrogen fuel station. HDSAM 

finds the least-cost combination of trunk and service lines and in doing so determines the number 

of trunk lines and their location, lengths, and diameters. The pipeline system requires a 

compressor to increase hydrogen pressure from its production level to the pressure at the 

terminus of the transmission line. 

3.1.1 Pipeline

Pipeline diameter is calculated using the Panhandle B pipeline equation (see Ruth, Laffen and

Timbario 2009) and is used to simulate compressible flow. HDSAM uses a cost curve to estimate 

the capital cost of a hydrogen pipeline system. Data from the curve are broken down into four 

parts: pipeline material cost, labor cost, miscellaneous cost, and right-of-way cost. It is assumed 

that the cost of a hydrogen pipeline will be 10% higher than that of a natural gas pipeline given 

that materials and weld-types may be different. 

3.1.2 Compressor

Storage for production plant outages and demand surges is provided in geologic formations, 

which are assumed to be immediately adjacent to the production facility. A compressor is 

required to charge the hydrogen produced at a central facility into the geologic storage cavern. 

The same compressor is used to extract hydrogen from the cavern and push it into the pipeline at 

the operating pressure of the pipeline. HDSAM is designed to calculate the cost of a centralized 

compressor that can raise the pressure of a defined flow rate from one pressure to another. Spare 

compressor units are included in the model to ensure a high level of operational availability. It is 

assumed that there are no pressure drops in the after-cooler or interstage coolers. An electricpowered compressor is assumed. 

16 
A cost curve has been developed to estimate the uninstalled capital cost of transmission and 

terminal compressors. Figure 3.1.1 shows the cost of a compressor (2- and 3-stage) versus motor 

rating. 

Transmission and Terminal Compressors

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

10,000,000

0 4,000 8,000 12,000 16,000

Motor Rating, kW

Uninstalled Cost, $

2-Stage

3-Stage

Figure 3.1.1. Compressor cost as a function of motor rating 

Source: Elgowainy, Mintz and Gillette 2010 (costs are in 2007$)

The capital cost of the compressor needs to be based on a unit that is capable of processing the 

peak hydrogen flow rate. During a typical operating year, however, the feed flow rate will 

fluctuate. Therefore, an average hydrogen flow rate is used as a basis to calculate the annual 

energy requirement and follows the compressor power equation in Ruth, Laffen and Timbario

(2009). 

3.2 Gaseous Hydrogen via Trucks

The pathways with delivery of gaseous hydrogen via trucks include the following components: 

central production → compressor → geologic storage for plant outages → gaseous hydrogen 

terminal → gaseous hydrogen truck transmission and distribution → and gaseous hydrogen fuel 

station. 

As described above for pathways with gaseous hydrogen delivery via pipeline, storage for 

production plant outages and demand surges is provided in geologic formations, which are 

assumed to be immediately adjacent to the production facility. From the geologic storage facility, 

the hydrogen is transported to a terminal or depot, where it is stored, compressed, and loaded 

onto trailers for delivery to stations. The terminal’s storage requirement is determined by the 

following factors: peak daily demand, days of summer peak demand, and expected days per year 

that the production plant is off-line. The amount of required storage determines the number of 

truck-filling bays required at the terminal, the capacities of storage tanks, and the resulting 

capital and operating costs associated with the terminal.

17 
For gaseous hydrogen truck transmission and distribution, tube trailers provide the primary onsite storage at the gaseous hydrogen fuel station. Because the compressor and cascade charging 

system operate at a constant rate, on-site storage is used to accommodate peak demand. Peak 

demand occurs on Fridays between 4:00 p.m. and 6:00 p.m. (Nexant 2008). Figure 3.2.1 shows 

the hourly Friday demand profile at a refueling station over 24 hours. The area under the curve 

above the daily average hourly demand represents the minimum storage requirement to satisfy 

the station demand during peak hours (approximately 30% of daily demand). 

Figure 3.2.1. Hydrogen daily average demand for a peak dispensing day

Source: Nexant 2008

Capital and operating costs for dispensers, ancillary equipment, storage/cascade charging system, 

and forecourt compressors are calculated in HDSAM. The number of trucks and trailers and the 

distance traveled are used to calculate the capital and operating costs of delivery trucks as well as 

the amount of diesel fuel required. 

3.2.1 Gaseous Hydrogen Truck

To maximize the usage of each truck, HDSAM assumes that a single tractor can serve multiple 

forecourt stations. The number of trailers (therefore the number of stations served) is optimized 

to maximize the use of the tractor. Because a trailer is assumed to be left at the fuel station and 

used as on-site storage, a single truck can move several trailers to any of the stations that it 

serves. HDSAM assumes that each trailer is refilled at the same terminal facility. The number of 

trailers for each tractor is calculated by considering the time required to empty the trailer at the 

forecourt station and the time required to deliver a full trailer and to return an empty one. The 

number of trailers required for each truck is typically more than the number of stations served by 

18 
that truck because there needs to be a full trailer ready to be delivered when the truck returns 

with an empty trailer.

The capital, labor, fuel, and other operating and maintenance costs for the truck and trailers are 

calculated and added together. 

3.3 Compression, Storage, and Dispensing of Gaseous Hydrogen

Hydrogen distribution requires compression, storage, and dispensing at the fueling station to 

transfer hydrogen at 12,700 psi to vehicles in the required fill-up time.

Much like gasoline stations, hydrogen stations will experience seasonal demand (see Ruth, 

Laffen and Timbario 2009). In addition to seasonal demand, demand variation occurs daily 

during the week as well as hourly during the day as shown in Figure 3.2.1. 

Daily and hourly fluctuations in demand are further described in Ruth, Laffen and Timbario

(2009). 

Refueling stations include a cascade charging system with at least one bank of three pressure 

vessels operating under different pressures (4,000, 8,000, and 11,000 psi) to satisfy vehicle 

refueling requirements. Each vessel holds 17 ft3

 of hydrogen at a maximum pressure of 14,200 

psi. 

The calculation for the number of dispensers is described in Ruth, Laffen and Timbario (2009). 

3.4 Liquid Hydrogen via Trucks with Gaseous Hydrogen Dispensing

The pathways with delivery of liquid hydrogen via trucks and dispensing of gaseous hydrogen 

include the following components: central production → liquefier → liquid hydrogen terminal 

(including liquid storage for plant outages) → liquid hydrogen truck transmission and 

distribution → and gaseous hydrogen fuel station. 

For liquid hydrogen truck transmission and distribution, HDSAM calculates the number and cost 

of the trucks and trailers required to deliver the fuel to fueling stations as well as the distances 

traveled. The capital and operating costs of the delivery trucks, including the amount of diesel 

fuel required, are computed. Additionally, the costs of appropriately sized liquefiers, terminal 

storage, liquid pumps, and vaporizers are calculated. 

Peak demand is used to determine the design capacity of the terminal or depot where hydrogen is 

stored and loaded onto trailers for delivery to stations. Cryogenic storage tanks are used to 

mitigate production outages and demand surges and are assumed to be sited immediately 

adjacent to the production facility. The terminal’s storage requirement is determined by the 

following factors: peak daily demand, days of summer peak demand, and expected days per year 

that the production plant is off-line. The amount of required storage determines the number of 

truck-filling bays required at the terminal, the capacities of storage tanks, and the resulting 

capital and operating costs associated with the terminal. Liquefier design is also linked to peak 

demand. 

19 
3.4.1 Liquid Hydrogen Truck

HDSAM calculates the amount of hydrogen that is loaded on a trailer when it leaves the terminal 

as well as the amount of boil-off losses during delivery to a station (see Ruth, Laffen and

Timbario 2009). 

HDSAM assumes there are only combinations of one tractor and one trailer. Additionally, it 

assumes that the stations are the same distance from the terminal and that the same amount of 

hydrogen is delivered to each station. 

3.4.2 Liquefier

For the pathways analysis, HDSAM is able to cost a single liquefier unit based on an idealized 

liquefier power equation and an energy requirement based on literature data. The actual power 

requirement is calculated using the curve in Figure 3.4.1. 

0

2

4

6

8

10

12

14

0 50 100 150 200

kWh/kg Hydrogen

Plant Capacity, Tonne/Day

Near-Term Liquefier Performance 

Figure 3.4.1. Liquefier energy requirement versus hydrogen flow rate

Source: Elgowainy, Mintz and Gillette 2010

The liquefier efficiency is calculated by dividing the theoretical power by the actual power 

requirement as described in Ruth, Laffen and Timbario (2009). 

It is assumed that the inlet and outlet pressures for the liquefier are both 1 atm and that the feed 

to the system is pure hydrogen. 

A cost curve has been developed based on several literature sources that estimate the capital cost 

of a liquefier. Figure 3.4.2 displays the costs for an installed liquefier. For the purposes of this 

analysis, a conventional liquefier is assumed. 

20 
Liquefiers

0

20

40

60

80

100

120

140

160

180

200

0 50 100 150 200 250

Capacity, Metric Ton H2/Day

Installed Cost, $ million

Conventional

Magnetic

Figure 3.4.2. Liquefier cost versus design capacity 

Source: Elgowainy, Mintz and Gillette 2010 (costs are in 2007$)

Refueling station electricity supply costs, assuming 480 V service, are shown in Figure 3.4.3. 

Refueling Station Electrical (480V Service)

0

10000

20000

30000

40000

50000

60000

0 100 200 300 400 500 600 700

Station Motor Power, bhp

Uninstalled Cost, $

Figure 3.4.3. Refueling station electrical cost versus rated motor power 

Source: Elgowainy, Mintz and Gillette 2010 (costs are in 2007$)

3.5 Liquid Hydrogen via Trucks with Dispensing of Cryo-Compressed 

Liquid Hydrogen

The liquid hydrogen pathway includes the following components: central production → liquefier 

→ liquid hydrogen (including liquid storage for plant outages) → liquid hydrogen truck 

transmission and distribution → and liquid hydrogen fuel station. 

21 
For liquid hydrogen via trucks with dispensing of cryo-compressed liquid hydrogen, HDSAM 

calculates the number and cost of the trucks and trailers required to deliver the fuel to fueling 

stations and the distances traveled in the same way that it calculates this information for liquid 

hydrogen via trucks with gaseous hydrogen dispensing. The only subsystem in this pathway that 

differs from the liquid hydrogen via trucks with gaseous hydrogen dispensing pathway is the 

cryo-compressed dispensing, which comprises a cryogenic pump and a cryogenic dispenser. 

22 
4 Vehicle Assumptions

4.1 Vehicle Fuel Economy

Vehicle fuel economy is a primary parameter for these analyses because it has an inversely 

proportional effect on cost per mile as well as energy use and emissions per mile. For this study, 

the estimated fuel economy for the fuel cell vehicle is 48 mpgge, representing the expected 

actual on-road fuel economy of the vehicle (not “window sticker” reported fuel economy). As 

this study investigates current technology, the fuel cell vehicle is presumed to reflect a 

conventional vehicle, including a fuel cell-based powertrain and regenerative braking, but 

without significant light-weighting, advanced aerodynamics, low-rolling-resistance tires, or other 

advanced vehicle platform improvements to improve fuel economy. For this analysis, 48 mpgge 

is used as the base fuel economy, but a sensitivity analysis of all hydrogen pathways was 

conducted using 68 mpgge. This higher end fuel economy represents the average fuel economy 

of a Toyota fuel cell vehicle in on-road testing conducted in California in 2009 (Wipke, Anton 

and Sprik 2009). 

Selection of the 48 mpgge fuel economy parameter is based on a consideration of NRELanalyzed FCEV data as well as modeling results from Argonne National Laboratory. NREL has 

collected fuel economy data under the Controlled Hydrogen Fleet and Infrastructure 

Demonstration and Validation Project (Wipke et al. 2012). Final fuel economy results for that 

project are displayed in Figure 4.1.1, which shows an on-road range of 36–52 mpgge for a 

second-generation FCEV. This range includes the 48 mppge fuel economy that was used in this 

analysis. The 48 mpgge value also reflects modeling of FCEV fuel economy by Argonne using 

its Autonomie model, based on Argonne’s modeling assumptions and information from original 

equipment manufacturers (Rousseau 2012). 

Figure 4.1.1. NREL hydrogen fleet and infrastructure demonstration and validation project fuel 

economy 

Source: Wipke et al. 2012

23 
4.2 Vehicle Criteria Pollutant Emissions

Table 4.2.1 presents the default values of emission change rates used in the GREET model for a 

hydrogen fuel cell vehicle as compared to the modeled gasoline vehicle. Those values are used 

for this study. 

Hydrogen FCEVs run on hydrogen instead of combustible carbon compounds, so there are no 

volatile organic carbon compounds (VOC) to either evaporate or be exhausted due to incomplete 

emissions. Likewise, there are no CO or methane (CH4) emissions. Because these vehicles run 

on fuel cells instead of combustion engines, combustion-caused pollutants are also avoided; 

therefore, there are no PM10, NOx, or N2O emissions. 

Vehicles within the same class (mid-size passenger car), whether powered by a gasoline internal 

combustion engine or a hydrogen fuel cell, are assumed to have similar tire- and brake-wear 

(TBW) particulate matter (PM) emissions (Wang, 1999).

Table 4.2.1. Change in Exhaust as Compared to a Gasoline Vehicle

Vehicle Exhaust 

VOC

Evap. 

VOC

CO NOx Exhaust 

PM

CH4 N2O TBW PM

H2 FCEV -100% -100% -100% -100% -100% -100% -100% 0%

4.3 Vehicle Cost

Vehicle ownership costs are based on purchasing a new vehicle, driving it 15,000 miles/year 

over a 5-year period, and selling it in good condition at the end of that timeframe. 

To estimate the purchase cost, original equipment manufacturer data beginning with model year 

1993 (when available) were obtained for six conventional ICE mid-size-class sedans: the 

Chevrolet Malibu, Ford Fusion, Honda Accord, Nissan Altima, Saturn Aura, and Toyota Camry. 

In addition, manufacturer’s data for the Ford Taurus (which was discontinued in 2006 and 

subsequently reintroduced in 2008) were also collected to help fill in early 1990s data because 

vehicles like the Fusion and Aura are both relatively new models. Manufacturer’s suggested 

retail price (MSRP) data were collected for each of the seven models through model year 2010. 

MSRP data were then averaged together for each model year. For example, MSRP data for a 

2002 Chevrolet Malibu, Honda Accord, Nissan Altima, and Toyota Camry were averaged 

together to get a generic 2002 mid-size sedan MSRP. Not all seven models were used in the 

averaging due to class change or vehicle model availability in that model year. The process was 

repeated for model years 1993–2010. The resulting averaged MSRP was used to define a generic 

mid-size conventional ICE cost for each model year. 

Both MSRP and invoice price, which were provided in current dollars for 1993–2010, were 

converted to 2007 constant dollars using the Consumer Price Index for All Urban Consumers for 

New Cars. MSRP and invoice were plotted in 2007 constant dollars and projected using a best-fit 

curve to obtain future vehicle pricing. 

To determine the MSRP of an FCEV, the FCEV subsystem costs were calculated relative to a 

conventional ICE vehicle. Cost estimates and DOE cost goals were taken from Plotkin et al. 

(2009). Revised hydrogen storage system costs for 700 bar compressed gas storage were based 

on cost analyses conducted by Strategic Analysis, Inc. (James 2012). Table 4.3.1 and Table 4.3.2 

24 
list those subsystem components and accompanying costs for the model-year 2015 FCEV and 

conventional ICE vehicles. The conventional ICE vehicle subsystem costs were then subtracted 

from the FCEV subsystem costs to obtain the incremental subsystem costs of the FCEV. As 

outlined in Plotkin et al. (2009), the costs in Table 4.3.1 and Table 4.3.2 are manufacturing costs 

and are not representative of MSRP. Therefore, Plotkin et al. (2009) multiplied these 

manufacturing costs by 1.5 to obtain the retail price equivalent (RPE). The incremental RPE of 

the FCEV over the conventional ICE vehicle was obtained by summing the incremental 

subsystem costs and multiplying by 1.5. This increment was then added to the conventional ICE 

vehicle MSRP to obtain the FCEV MSRP. 

Table 4.3.1. FCEV Subsystem Costs

2015

Fuel cell system $4,500

Hydrogen storage $2,400

Motor $700

Battery $1,000

Transmission $100

Electronics $500

Exhaust $0

Table 4.3.2. ICE Vehicle Subsystem Costs

2015

Engine $1,800

Hydrogen storage $0

Motor $0

Battery $0

Transmission $100

Electronics $0

Maintenance costs for ICEs were estimated by extrapolating the maintenance cost history of four 

sedans. Those were adjusted by a maintenance cost ratio range used by the National Energy 

Modeling System to estimate maintenance costs for FCEVs. The ratio’s value is 1.08 in 2015 

and goes down to 1.04 in 2019. 

Tire and repair costs for FCEVs were assumed to be the same as those for ICEs. Expenses for 

registration, taxes, and fees were estimated using the same tax rate as for ICEs.

Insurance premiums for ICEs were estimated by extrapolating the national averages of combined 

(collision, liability, and comprehensive) insurance premiums for sedans. Those costs were 

multiplied by a ratio of 1.11 to estimate insurance premiums for FCEVs. The ratio was set to the 

premium ratio of a natural gas Honda Civic to a conventional ICE Honda Civic. 

Vehicle depreciation was based on NADA resale values for five sedans. The percentage of 

retained MSRP for each sedan was averaged to develop a common percentage applied to all 

ICEs in each ownership year. That percentage was then adjusted by the difference between the 

conventional ICE Honda Civic and the natural gas Honda Civic to estimate the depreciation of 

the FCEVs.

25 
Standard financing at a loan rate of 7.51% over a 5-year period with 8.23% down was used to 

calculate financing costs.

4.4 Vehicle-Cycle Energy Use and Emissions

Energy use and emissions for the vehicle cycle are estimated using GREET 2 as described above. 

They include energy use and emissions for creating vehicle materials, vehicle assembly, vehicle 

maintenance, and disposal/recycling including all upstream energy and emissions requirements. 

GREET 2 default values are used for all vehicle parameters.

The GREET 2 default FCEV is defined as a 3,020 lb vehicle with a 70 kW fuel cell stack. The 

fuel cell stack is estimated to weigh 226 lb and require 546 lb of auxiliary systems. The vehicle 

is assumed to have a 30 kW nickel-metal hydride (NiMH) battery for hybridization. The battery 

weighs 110 lb and needs to be replaced twice over the vehicle lifetime. 

The component mass of the vehicle (i.e., the mass without batteries or fluids) is estimated at 

2,832 lb, and the percentage of mass in each subsystem is shown in Table 4.4.1. 

Table 4.4.1. FCEV Subsystem Mass Percentages

Powertrain system 8.0%

Transmission system 2.6%

Chassis (without battery) 23.0%

Traction motor 3.8%

Generator 0.0%

Electronic controller 3.4%

Fuel cell auxiliary system 19.3%

Body: including body-in-white, interior, exterior, and glass 39.9%

26 
5 Financial Assumptions

DOE’s hydrogen cost analysis models (the H2A Production Model and HDSAM) use a common 

set of economic assumptions to allow for consistent and comparable results across technology 

options. Table 5.0.1 provides a set of key economic parameters selected by H2A analysts and 

discussed with industry collaborators who participated in the H2A effort. 

Table 5.0.1. H2A Key Economic Parameters

Parameter Value

Start-up year 2015

Reference year 2007 dollars

Percentage equity financing 100%

After-tax internal rate of return 10% real

Inflation rate 1.9%

Effective corporate income tax rate 38.9%

Depreciation schedule Modified Accelerated Cost Recovery System

Economic analysis period:

 Central plant production

 Forecourt production

40 years

20 years

In cases where the capital cost component is a large fraction of the levelized cost of producing 

hydrogen, the assumed after-tax internal rate of return (IRR) strongly affects the results 

calculated by H2A. As seen in Table 5.0.1, H2A uses an IRR of 10% real, after tax. The 10% 

real, after-tax value was derived from return on equity statistics (adjusted for inflation) for large 

company stocks over the period of 1926–2002. Because returns already account for corporate 

taxes, this value is an after-tax return. The use of a 10% real IRR is intended to reflect a steadystate situation in the future in which hydrogen is a familiar and publicly accepted fuel and in 

which a significant demand for hydrogen for transportation exists (Pacific Northwest National 

Laboratory 2004). 

This 10% after-tax IRR is linked to the H2A assumption of 100% equity financing. Actual 

projects would probably be financed with a combination of debt and equity, but H2A analysts 

have been told that firms typically assume 100% equity financing for paper studies and analyses. 

When debt financing is used, a higher after-tax IRR can be achieved with the same levelized 

cost. The increase is dependent upon the fraction of debt financing and the interest rate on that 

debt. Figure 5.0.1 shows the after-tax IRR for multiple combinations of equity and debt 

financing at three different interest rates for production of hydrogen from coal in central 

facilities; delivery costs are not included in the data shown. Technologies with different ratios of 

capital to operating cost will result in slightly different curves.

Figure 5.0.1 also shows the before-tax IRR for the same combinations of equity and debt 

financing. Corporate income tax can be considered a reduction in profits, so a pre-tax IRR is 

always greater than an after-tax IRR. Figure 5.0.1 shows pre-tax and after-tax IRR ranges for 

different debt interest rates and different percentages of equity financing.

27 
10

12

14

16

18

20

22

0 10 20 30 40 50 60 70 80 90 100

Equity (%)

IRR (%)

6% Interest - After Tax IRR

8% Interest - After Tax IRR

10% Interest - After Tax IRR

6% Interest - Before Tax IRR

8% Interest - Before Tax IRR

10% Interest - Before Tax

IRR

Pre-tax IRRs

Figure 5.0.1. Post-tax and pre-tax IRRs that result in the same levelized cost for multiple 

combinations of equity and debt financing (central production of hydrogen from coal with CCS

pathway) 

28 
6 Pathway Results

This study assessed the life-cycle cost, energy use, and greenhouse gas (GHG) emissions of each 

of the 10 pathways listed in Table 6.0.1 (see detailed descriptions of each pathway in Section 

1.4). 

Table 6.0.1. Ten Hydrogen Production, Delivery, and Distribution Pathways

Feedstock Central or

Distributed

Production

Carbon

Capture and

Sequestration

Delivery

Method

Hydrogen

Distribution

1 Natural Gas Distributed No Not applicable 700 bar, 

gaseous 

2a Ethanol Distributed No Not applicable 700 bar, 

gaseous

3 Grid Electricity Distributed No Not applicable 700 bar, 

gaseous

4 Biomass Central No Gaseous H2 in 

pipelines

700 bar, 

gaseous

5a Biomass Central No Gaseous H2 truck 700 bar, 

gaseous

6 Biomass Central No Liquid H2 truck 700 bar, 

gaseous

7a Biomass Central No Liquid H2 truck Cryocompressed

8 Natural Gas Central No Gaseous H2 in 

pipelines

700 bar, 

gaseous

9 Wind 

Electricity

Central No Gaseous H2 in 

pipelines

700 bar, 

gaseous

10 Coal Central Yes Gaseous H2 in 

pipelines

700 bar, 

gaseous a Newly analyzed pathways

The hydrogen production technologies are described in Section 2, and the delivery technologies 

are detailed in Section 3. Fuel cell vehicle assumptions and financial assumptions are discussed 

in Sections 4 and 5, respectively. This section presents the results of the life-cycle cost, energy 

use, and GHG emissions analysis for each pathway. As noted above, the base analysis is 

conducted using a fuel economy of 48 mpgge, with a sensitivity analysis conducted using a fuel 

economy of 68 mpgge. Results presented are for a fuel economy of 48 mpgge, except where 

noted. 

6.1 Distributed Natural Gas

Figure 6.1.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix A for more details on this pathway.) 

The well-to-pump (WTP) and WTW cost of hydrogen, energy use, and emissions for the 

distributed natural gas pathway are summarized in Table 6.1.1. 

29 
6.1.1 Cost Breakdown

Figure 6.1.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the distributed natural gas pathway. The financial assumptions 

used in this analysis are detailed in Section 5.0. 

Figure 6.1.3 shows the contributions of hydrogen production, distribution (compression, storage, 

and dispensing—CSD), and losses to the levelized cost of hydrogen shown in Figure 6.1.2. 

Figure 6.1.4 and Table 6.1.2 show the breakdown of levelized costs for the distributed natural 

gas pathway. 

30 
Figure 6.1.1. Summary of major inputs, assumptions, and outputs by subsystem for the distributed natural gas pathway

31 

NG Delivery Pressure

NG Quality at Delivery

Outputs

Average of gas companies

Average of gas companies

NG Recovery Efficiency 95.7%

NG emitted & combusted during recovery 399 g/MMbtu

NG processing energy efficiency 97.2%

NG Cost

NG Share of H2 Levelized Cost

$6.09 2007 $ / mmBTU

$1.28 2007$ / kg H2 dispensed

33 g/MMbtu

 199,400 g/MMbtu WTG CO2 Emissions

WTG CH4 Emissions

NG emitted & combusted during processing

NG emitted & combusted during transport

NG transport distance

Compression Req'ts. (stages & efficiency) WTG N2O Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

300 Btu / 116000Btu to Pump

127,200 Btu / 116000Btu to Pump

500 Btu / 116000Btu to Pump WTG GHG Emissions

650 g CO2 eq./ 116000 Btu

1,750 g CO2 eq./ 116000 Btu

3 g CO2 eq./ 116000 Btu

2,390 g CO2 eq./ 116000 Btu

300 psi

0.156 MMBtu/kg H2 produced

Hydrogen Output Pressure

Hydrogen Outlet Quality 99.9%

1,500 kg / day $1,150 2007$ / daily kg H2 (effective capacity)

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

1.11 kWh / kg H2 produced

5.77 gal / kg H2 produced

0.00 gal / kg H2 produced 89%

92

Total Capital Investment per station $1,530,000 2007$ 71.4%

US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.59 2007$ / kg H2 dispensed

$0.19 2007$ / kg H2 dispensed

$0.12 2007$ / kg H2 dispensed

$2.17 2007$ / kg H2 dispensed

10%

Distributed plant design capacity

Capacity factor

# of Plants Needed to Meet City Demand

Process energy efficiency

Electricity Mix

After-tax IRR

Coal Input (including upstream) Assumed Plant Life 20

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

5,600 Btu / 116000Btu to Pump

49,200 Btu / 116000Btu to Pump

400 Btu / 116000Btu to Pump

Production CO2 Emissions

Production CH4 Emissions

Production N2O Emissions

Production GHG Emissions

10,410 g CO2 eq./ 116000 Btu

690 g CO2 eq./ 116000 Btu

8 g CO2 eq./ 116000 Btu

11,100 g CO2 eq./ 116000 Btu

Electricity consumption 4.4 kWh / kg H2 produced Hydrogen outlet pressure

Basis -- Hydrogen Quantity

12,700 psi

116,000 Btu (116,000 Btu/gal non-oxygenated 

1,247,000 people conventional unleaded gasoline)

Total Capital Investment (per station) 15%

Total Capital Investment

$5,059,000 2007$ / station

$465,391,000 2007$ / all stations 121,100 kg / day $3,810 2007$ / daily kg H2 (effective capacity)

1,330 kg / day

92

5

1,450 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$1.49 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$0.54 2007$ / kg H2 dispensed

$2.43 2007$ / kg H2 dispensed

200 kg H2

100% % of design capacity CSD CO2 Emissions

3 CSD CH4 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

21,900 Btu / 116000Btu to Pump

9,700 Btu / 116000Btu to Pump

800 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station

Site storage

# of 2-hose Dispensers per Station

Hydrogen losses 0.50% CSD N2O Emissions

CSD GHG Emissions

3,020 g CO2 eq./ 116000 Btu

190 g CO2 eq./ 116000 Btu

12 g CO2 eq./ 116000 Btu

3,220 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.66 2007$ / mi

70 kW 48.0 mi / GGE $0.10 2007$ / mi

Vehicle Mass

Fuel cell size

Size of hybridization battery 30 kW 15,000 mi / yr $0.07 2007$ / mi

160,000 mi $0.12 2007$ / mi

2015 $0.27 2007$ / mi

$33,700 2007$

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$4,500 2007$

$2,400 2007$

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Vehicle Cycle CO2 Emissions

Vehicle Cycle CH4 Emissions

Vehicle Cycle N2O Emissions

Vehicle Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

170 g CO2 eq / gge fuel consumed

6 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

Inputs

Vehicle

NG Recovery, Processing, & Transport

Assumptions

Hydrogen Production

500 miles

Average of gas companies
Table 6.1.1. WTP and WTW Results for the Distributed Natural Gas Pathway

WTP WTW

Coal input (including upstream)a 27,700 Btu/116,000 Btu 580 Btu/mi

Natural gas input (including upstream)a 186,100 Btu/116,000 Btu 3,900 Btu/mi

Petroleum input (including upstream)a 1,700 Btu/116,000 Btu 40 Btu/mi

Fossil energy input (including upstream)a 215,500 Btu/116,000 Btu 4,500 Btu/mi

WTP CO2 emissionsb 14,100 g/116,000 Btu 290 g/mi

WTP CH4 emissions 100 g/116,000 Btu 2 g/mi

WTP N2O emissions 20 g/116,000 Btu 0 g/mi

WTP GHG emissions 16,700 g CO2-eq./

116,000 Btu

350 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $4.60 2007$/kg $0.10 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and 

delivery pathway as feedstocks and fuels; those used to produce electricity and other materials used in the 

pathway; and those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Natural Gas @ Total capital investment $1,152 2007$ / daily kg H2 (effective capacity)

$6.09/MMBtu Levelized Cost of Capital $0.59 2007$ / kg H2 dispensed

Fixed O&M Costs $0.19 2007$ / kg H2 dispensed

Variable O&M Costs $0.12 2007$ / kg H2 dispensed

Total Levelized Cost $2.17 2007$ / kg H2 dispensed

Total capital investment $3,806 2007$ / daily kg H2 (effective capacity)

Levelized Cost of Capital $1.49 2007$ / kg H2 dispensed

Energy & Fuel $0.40 2007$ / kg H2 dispensed

Other O&M Costs $0.54 2007$ / kg H2 dispensed

Levelized Cost of Dispensing $2.43 2007$ / kg H2 dispensed

Gaseous H2 Storage

Hydrogen @ $4.60/kg

Transport PSA

Processing WGS

Dispensing

Distribution:

Compressor

Recovery SMR

Forecourt 

and Delivery*: Desulfurizer

Electricity @ $0.0847/kWh

Natural Gas Production Hydrogen Production: 

Figure 6.1.2. Cost analysis inputs and high-level results for the distributed natural gas 

pathway

32 
33 

Figure 6.1.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed natural gas pathway 

Figure 6.1.4. Breakdown of levelized costs for the distributed natural gas pathway 

$2.17 

$2.43 

$0.00 

Distributed Reforming of Natural Gas 

Production 

CSD 

Losses 

PRODUCTION 

$2.17 
34 

Table 6.1.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost 

for the Distributed Natural Gas Pathway 

Cost Component Capital 

Other 

O&Ma

 Feedstock 

Energy/ 

Fuel Total 

Production $0.58 $0.32 $1.28 $2.17 

 Feed and desulfurization $0.06 

 Reformer $0.13 

 WGS $0.10 

 PSA $0.04 

 Cooling and condensing $0.04 

 Supports and controls $0.03 

 System assembly $0.12 

 Miscellaneous $0.05 

CSD $1.49 $0.54 $0.40 $2.43 

 Compressor (levelized) $1.04 

 Storage (levelized) $0.99 

 Dispenser (levelized) $0.10 

 Refrigeration (levelized) $0.16 

 Remainder of station (levelized) $0.14 

Losses $0.00 

Total $2.07 $0.86 $1.28 $0.40 $4.60 a

 O&M: operations and maintenance 

Figure 6.1.5. Breakdown of vehicle ownership costs for the distributed natural gas 

pathway 

Fuel costs are not the only costs of ownership of a vehicle. Vehicle ownership costs 

including fuel, maintenance, tires, repairs, insurance, registration, and vehicle 

depreciation and financing are shown in Figure 6.1.5. Note that the costs in the figure are 

$%$

$$( $$%

$$&

$$*

$$'

$&)

$%$


	
	



#
	
 



	





	


!

	

	

not discounted (i.e., a discount rate was not used to reduce future costs to their net present 

values). That methodology has the same effect as a discount rate of 0%.

6.1.2 Energy Use and Emissions Breakdown

Figures 6.1.6 and 6.1.7 show the WTW energy inputs and losses for the distributed 

natural gas pathway. The WTW energy inputs to natural gas production and delivery 

include those necessary to produce 116,000 Btu of natural gas for reforming. Additional 

WTW energy inputs for natural gas needed for heating and lost in reforming are reported 

as inputs to hydrogen production. 

5,600 Btu Coal

49,200 Btu Natural Gas (inc. heating fuel)

400 Btu Petroleum

300 Btu Coal

127,200 Btu Natural Gas 159,000 Btu

500 Btu Petroleum Natural Gas

21,900 Btu Coal

9,700 Btu Natural Gas

800 Btu Petroleum Distribution 

losses 0.00%

* This box represents the natural gas that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include natural gas used as a heating fuel or to produce electricity.

Forecourt 

Recovery SMR

Processing WGS

Pipeline Transport PSA

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 6.1.6. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the

distributed natural gas pathway

35 
36 

Figure 6.1.7. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using the distributed natural gas pathway 

Figures 6.1.8 and 6.1.9 show the WTW emissions resulting from the delivery of 116,000 

Btu hydrogen to a vehicle fuel tank using the distributed natural gas pathway. 

Figure 6.1.8. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed natural gas pathway 

0 

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

140,000 

NG Production & 

Delivery 

Hydrogen Production Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Distributed Natural Gas SMR) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 

CO2 Emissions 600 g CO2 Emissions 10,400 g

CH4 Emissions 100 g CH4 Emissions 28 g

N2O Emissions 0 g

N2O Emissions 0 g GHG Emissions 11,100 g

GHG Emissions 2,400 g

CO2 Emissions 3,000 g

Electricity CH4 Emissions 7 g

N2O Emissions 0 g

GHG Emissions 3,200 g

* This box represents the natural gas that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include natural gas used as a heating fuel or to produce electricity.

Forecourt 

Recovery SMR

Processing WGS

Pipeline Transport PSA

Electricity

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing
37 

Figure 6.1.9. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using the distributed natural gas pathway 

Figures 6.1.10 and 6.1.11 show the energy inputs and emissions, respectively, for the 

vehicle cycles in addition to those for the fuel production cycle. The fuel production 

cycle values are consistent with those reported in Figures 6.1.7 and 6.1.9. 

Figure 6.1.10. WTW petroleum, natural gas, and coal inputs for both the distributed natural 

gas pathway and the vehicle cycle 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

NG Production & Delivery Hydrogen Production Forecourt Storage & 

Dispensing 

g CO2 eq/GGE 

WTW Emissions (Distributed Natural Gas SMR) 

CO2 CH4 N2O 

0 

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

140,000 

NG Production & 

Delivery 

Hydrogen 

Production 

Forecourt Storage & 

Dispensing 

Vehicle Cycle 

Btu/GGE 

WTW Energy Input Including Vehicle Cycle (Distributed Natural Gas) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
38 

Figure 6.1.11. WTW CO2, CH4, and N2O emissions for both the distributed natural gas 

pathway and the vehicle cycle 

6.1.3 Sensitivities 

6.1.3.1 Production Sensitivities 

The parameters used for this analysis are not known absolutely, so sensitivity analyses 

were performed to better understand the potential effects of that lack of knowledge on the 

final results. Several sensitivities were run on this pathway. They focused primarily on 

cost factors; however, several sensitivities also affect energy use and emissions. Figure 

6.1.12 shows the effects of several production parameters on the pathway’s levelized 

cost, and Table 6.1.3 shows the effect of production energy efficiency on WTW energy 

use and emissions. 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.1.4 

shows the differences in energy use and GHG emissions between the U.S. average grid 

mix (which was used for all other sensitivities) and a hypothetical green grid mix that is 

100% renewable energy (solar and wind). 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

NG Production & 

Delivery 

Hydrogen 

Production 

Forecourt Storage & 

Dispensing 

Vehicle Cycle 

g CO2 eq/GGE 

WTW Emissions (Distributed Natural Gas SMR) 

CO2 CH4 N2O 
39 

Figure 6.1.12. Production sensitivities for the distributed natural gas pathway 

Table 6.1.3. The Effects of Production Energy Efficiency on Primary Energy Use and 

Emissions from the Distributed Natural Gas Pathway 

60% 

Efficiency 

71% 

Efficiency 

75% 

Efficiency 

WTW GHG emissions (g/mile) 400 350 340 

WTW fossil energy (Btu/mile) 5,200 4,500 4,300 

WTW petroleum energy (Btu/mile) 40 40 40 

WTW total energy (Btu/mile) 5,400 4,700 4,500 

Table 6.1.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and 

Emissions from the Distributed Natural Gas Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 350 250 270 

WTW fossil energy (Btu/mile) 4,500 3,200 3,600 

WTW petroleum energy (Btu/mile) 40 30 10 

WTW Total energy (Btu/mile) 4,700 3,300 4,100 

6.2 Distributed Ethanol 

Figure 6.2.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen 

dispensing. (See Appendix B for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the distributed 

ethanol pathway are summarized in Table 6.2.1. 
6.2.1 Cost Breakdown

Figure 6.2.2 shows the feedstock and energy price inputs and the resulting hydrogen 

production, delivery, and distribution costs for the distributed ethanol pathway. The 

financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.2.3 shows the contributions of hydrogen production, distribution (CSD), and 

losses to the levelized cost of hydrogen shown in Figure 6.2.2. 

Figure 6.2.4 and Table 6.2.2 show the breakdown of levelized costs for the distributed 

ethanol pathway. 

40 
Figure 6.2.1. Summary of major inputs, assumptions, and outputs by subsystem for the distributed ethanol pathway

41 

100% Ethanol Cost

Ethanol Share of H2 Cost

$3.04 2007 $ / gal

$5.29 2007$ / kg H2 dispensed

Percent from Corn Stover

Corn Stover Production

Ethanol Yield from Corn Stover

Elec. Co-Prod. from Corn Stover Conversion

2.21 dry ton / acre

90.0 gal / dry ton

2.28 kWh / gal ethanol WTG CO2 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

-21,100 Btu / 116000Btu to Pump

400 Btu / 116000Btu to Pump

12,700 Btu / 116000Btu to Pump WTG CH4 Emissions

WTG N2O Emissions

Energy use and emissions calcs include electricity displaced by ethanol production WTG GHG Emissions

-14,010 g CO2 eq./ 116000 Btu

-20 g CO2 eq./ 116000 Btu

1,140 g CO2 eq./ 116000 Btu

-12,900 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

Hydrogen Outlet Quality 99.9%

1,500 kg / day $1,430 2007$ / daily kg H2 (effective capacity)

Ethanol Consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

2.19 gal / kg H2 produced

0.49 kWh / kg H2 produced

8.18 gal / kg H2 produced

0.00 gal / kg H2 produced 89%

92

Total Capital Investment per station $1,907,000 2007$ 67.4%

US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.83 2007$ / kg H2 dispensed

$0.24 2007$ / kg H2 dispensed

$0.07 2007$ / kg H2 dispensed

$6.42 2007$ / kg H2 dispensed

10%

Distributed plant design capacity

Capacity factor

# of Plants Needed to Meet City Demand

Process energy efficiency

Electricity Mix

After-tax IRR

Assumed Plant Life 20 SMR CO2 Emissions

SMR CH4 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,400 Btu / 116000Btu to Pump

1,100 Btu / 116000Btu to Pump

100 Btu / 116000Btu to Pump SMR N2O Emissions

SMR GHG Emissions

13,080 g CO2 eq./ 116000 Btu

20 g CO2 eq./ 116000 Btu

1 g CO2 eq./ 116000 Btu

14,010 g CO2 eq./ 116000 Btu

Electricity consumption 4.4 kWh / kg H2 Hydrogen outlet pressure

Basis -- Hydrogen Quantity

12,700 psi

116,000 Btu (116,000 Btu/gal non-oxygenated 

1,247,000 people

15%

conventional unleaded gasoline)

Total Capital Investment (per station) $3,810 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$5,059,000 2007$ / station

$465,390,000 2007$ / all stations 121,100 kg / day

1,329 kg / day

92

5

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$1.49 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$0.54 2007$ / kg H2 dispensed

$2.43 2007$ / kg H2 dispensed

1450 kg H2

200 kg H2 CSD CO2 Emissions

100% % of design capacity CSD CH4 Emissions

3 CSD N2O Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

21,900 Btu / 116000Btu to Pump

9,700 Btu / 116000Btu to Pump

800 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station

Site storage

# of 2-hose Dispensers per Station

Hydrogen losses 0.50% CSD GHG Emissions

3,020 g CO2 eq./ 116000 Btu

190 g CO2 eq./ 116000 Btu

12 g CO2 eq./ 116000 Btu

11,320 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.75 2007$ / mi

70 kW 48.0 mi / GGE $0.18 2007$ / mi

Vehicle Mass

Fuel cell size

Size of hybridization battery 30 kW 15,000 mi / yr $0.07 2007$ / mi

160,000 mi $0.12 2007$ / mi

2015 $0.27 2007$ / mi

$33,700 2007$

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$4,500 2007$

$2,400 2007$

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Veh. Cycle CO2 Emissions

Veh. Cycle CH4 Emissions

Veh. Cycle N2O Emissions

Veh. Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

170 g CO2 eq / gge fuel consumed

6 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

Inputs Outputs

Vehicle

Assumptions

Ethanol Production

Hydrogen Production

Displacement method used for estimating effects 

of co-produced electricity on LCA results
Table 6.2.1. WTP and WTW Results for the Distributed Ethanol Pathway

WTP WTW

Coal input (including upstream)a 3,200 Btu/116,000 Btu 70 Btu/mi

Natural gas input (including upstream)a 11,200 Btu/116,000 Btu 200 Btu/mi

Petroleum input (including upstream)a 13,600 Btu/116,000 Btu 300 Btu/mi

Fossil energy input (including upstream)a 28,000 Btu/116,000 Btu 600 Btu/mi

WTP CO2 emissionsb 2,100 g/116,000 Btu 45 g/mi

WTP CH4 emissions 7 g/116,000 Btu 0 g/mi

WTP N2O emissions 4 g/116,000 Btu 0 g/mi

WTP GHG emissions 3,400 g CO2-eq./

116,000 Btu

70 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $8.84 2007$/kg $0.18 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and 

delivery pathway as feedstocks and fuels; those used to produce electricity and other materials used in the 

pathway; and those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Figure 6.2.2. Cost analysis inputs and high-level results for the distributed ethanol

pathway

42 
43 

Figure 6.2.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed ethanol pathway 

$6.42 

$2.43 

$0.00 

Distributed Reforming of Ethanol 

Production 

CSD 

Losses 
44 

Figure 6.2.4. Breakdown of levelized costs for the distributed ethanol pathway 
Table 6.2.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost

for the Distributed Ethanol Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.82 $0.31 $5.29 $6.42

 Feed and desulfurization $0.06

 Reformer $0.20

 WGS $0.13

 PSA $0.05

 Cooling and condensing $0.05

 Supports and controls $0.04

 System assembly $0.14

 Miscellaneous $0.16

CSD $1.49 $0.54 $0.40 $2.43

 Compressor (levelized) $1.04

 Storage (levelized) $0.99

 Dispenser (levelized) $0.10

 Refrigeration (levelized) $0.16

 Remainder of station (levelized) $0.14

Losses $0.00

Total $2.31 $0.86 $5.29 $0.40 $8.85

6.2.2 Energy Use and Emissions Breakdown

Figures 6.2.5 and 6.2.6 show the WTW energy inputs and losses for the distributed 

ethanol pathway. The WTW energy inputs to ethanol production and delivery include 

those necessary to produce 116,000 Btu of ethanol for reforming. Additional WTW 

energy inputs for natural gas needed for heating and lost in reforming are reported as 

inputs to hydrogen production. 

Figure 6.2.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the 

distributed ethanol pathway

45 
46 

Figure 6.2.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using the distributed ethanol pathway 

Figures 6.2.7 and 6.2.8 show the WTW emissions resulting from the delivery of 116,000 

Btu hydrogen to a vehicle fuel tank using the distributed ethanol pathway. 

Figure 6.2.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed ethanol pathway 

-30,000 

-20,000 

-10,000 

0 

10,000 

20,000 

30,000 

40,000 

Ethanol Production & 

Delivery 

Hydrogen Production Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Distributed Ethanol Reforming) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 

CO2 Emissions -14,000 g CO2 Emissions 13,100 g

CH4 Emissions -1 g CH4 Emissions 1 g

N2O Emissions 0 g

N2O Emissions 4 g GHG Emissions 13,100 g

GHG Emissions -12,900 g

CO2 Emissions 3,000 g

Electricity CH4 Emissions 7 g

N2O Emissions 0 g

GHG Emissions 3,200 g

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Electricity

Ethanol Production: Hydrogen Production: 

Corn Stover Production Steam Reforming

Forecourt 

Corn Stover Delivery WGS

Ethanol Production PSA

Ethanol Transport
47 

Figure 6.2.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using the distributed ethanol pathway 

6.2.3 Sensitivities 

6.2.3.1 Production Sensitivities 

The parameters used for this analysis are not known absolutely, so sensitivity analyses 

were performed to better understand the potential effects of that lack of knowledge on the 

final results. Several sensitivities were run on this pathway. They focused primarily on 

cost factors; however, several sensitivities also affect energy use and emissions. Figure 

6.2.9 shows the effects of several production parameters on the pathway’s levelized cost, 

and Table 6.2.3 shows the effect of production energy efficiency on WTW energy use 

and emissions. 

-20,000 

-15,000 

-10,000 

-5,000 

0 

5,000 

10,000 

15,000 

Ethanol Production & 

Delivery 

Hydrogen Production Forecourt Storage & 

Dispensing 

g CO2 eq/GGE 

WTW Emissions (Distributed Ethanol Reforming) 

CO2 CH4 N2O 
48 

Figure 6.2.9. Production sensitivities for the distributed ethanol pathway 

Table 6.2.3. The Effects of Production Energy Efficiency on Primary Energy Use and 

Emissions from the Distributed Ethanol Pathway 

56% 

Efficiency 

67% 

Efficiency 

70% 

Efficiency 

WTW GHG emissions (g/mile) 70 70 70 

WTW fossil energy (Btu/mile) 550 590 590 

WTW petroleum energy (Btu/mile) 340 280 270 

WTW total energy (Btu/mile) 9,300 7,900 7,500 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.2.4 

shows the differences in energy use and GHG emissions between the U.S. average grid 

mix (which was used for all other sensitivities) and a hypothetical green grid mix that is 

100% renewable energy (solar and wind). 

Table 6.2.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and 

Emissions from the Distributed Ethanol Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid Mix

(48 mpgge) 

WTW GHG emissions (g/mile) 70 50 60 

WTW fossil energy (Btu/mile) 590 410 490 

WTW petroleum energy (Btu/mile) 280 200 280 

WTW total energy (Btu/mile) 7,900 5,600 7,800 
6.3 Distributed Electricity

Figure 6.3.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen 

dispensing. (See Appendix C for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the distributed 

electricity pathway are summarized in Table 6.3.1. 

6.3.1 Cost Breakdown

Figure 6.3.2 shows the feedstock and energy price inputs and the resulting hydrogen 

production, delivery, and distribution costs for the distributed electricity pathway. The 

financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.3.3 shows the contributions of hydrogen production, distribution (CSD), and 

losses to the levelized cost of hydrogen shown in Figure 6.3.2. 

Figure 6.3.4 and Table 6.3.2 show the breakdown of levelized costs for the distributed 

electricity pathway. 

49 
Figure 6.3.1. Summary of major inputs, assumptions, and outputs by subsystem for the distributed grid electricity pathway

50 

U.S. Grid Mix Electricity price at H2 production 0.0574 2007$ / kWh

1% Electricity Share of H2 Cost $3.22 2007$ / kg H2 dispensed

44%

21% WTG CO2 Emissions

21% WTG CH4 Emissions

1% WTG N2O Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

159,600 Btu / 116000Btu to Pump

70,800 Btu / 116000Btu to Pump

6,100 Btu / 116000Btu to Pump

Biomass Fraction

Coal Fraction

Natural Gas Fraction

Nuclear Fraction

Residual Oil Fraction

Others (Carbon Neutral) 12% WTG GHG Emissions

36,930 g CO2 eq./ 116000 Btu

2,280 g CO2 eq./ 116000 Btu

150 g CO2 eq./ 116000 Btu

39,360 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

Electricity consumption Hydrogen Outlet Quality 100.0%

Process Water Consumption

Cooling Water Consumption

50.0 kWh / kg H2 produced

2.94 gal / kg H2 produced

0.11 gal / kg H2 produced 1,500 kg / day $1,700 2007$ / daily kg H2 (effective capacity)

89%

91

Total Capital Investment per station $2,258,000 2007$ 66.8%

US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.77 2007$ / kg H2 dispensed

$0.28 2007$ / kg H2 dispensed

$0.06 2007$ / kg H2 dispensed

$4.32 2007$ / kg H2 dispensed

10%

Distributed plant design capacity

Capacity factor

# of Plants Needed to Meet City Demand

Process energy efficiency

Electricity Mix

After-tax IRR

Coal Input (including upstream) Assumed Plant Life 20 years

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

86,400 Btu / 116000Btu to Pump

38,300 Btu / 116000Btu to Pump

3,300 Btu / 116000Btu to Pump

Production CO2 Emissions

Production CH4 Emissions

Production N2O Emissions

Production GHG Emissions

0 g CO2 eq./ 116000 Btu

0 g CO2 eq./ 116000 Btu

0 g CO2 eq./ 116000 Btu

0 g CO2 eq./ 116000 Btu

Electricity consumption 4.4 kWh / kg H2

Electricity price $0.088 2007$ / kWh

Hydrogen outlet pressure

Basis -- Hydrogen Quantity

12,700 psi

116,000 Btu (116,000 Btu/gal non-oxygenated 

1,247,000 people conventional unleaded gasoline)

15%

Total Capital Investment (per station) 121,100 kg / day $3,810 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$5,059,000 2007$ / station

$465,391,000 2007$ / all stations 1,330 kg / day

92

0

1,450 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$1.49 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$0.54 2007$ / kg H2 dispensed

$2.43 2007$ / kg H2 dispensed

200 kg H2

100% % of design capacity CSD CO2 Emissions

3 CSD CH4 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

21,900 Btu / 116000Btu to Pump

9,700 Btu / 116000Btu to Pump

800 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station

Site storage

# of 2-hose Dispensers per Station

Hydrogen losses 0.50% CSD N2O Emissions

CSD GHG Emissions

3,020 g CO2 eq./ 116000 Btu

190 g CO2 eq./ 116000 Btu

12 g CO2 eq./ 116000 Btu

3,220 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.71 2007$ / mi

70 kW 48.0 mi / gge $0.14 2007$ / mi

Vehicle Mass

Fuel cell size

Size of hybridization battery 30 kW 15,000 mi / yr $0.07 2007$ / mi

160,000 mi $0.12 2007$ / mi

2015 $0.27 2007$ / mi

$33,700 2007$

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$4,500 2007$

$2,400 2007$

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Vehicle Cycle CO2 Emissions

Vehicle Cycle CH4 Emissions

Vehicle Cycle N2O Emissions

Vehicle Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

7 g CO2 eq / gge fuel consumed

0 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

Inputs Outputs

Vehicle

Electricity Generation & Transmission

Assumptions

Hydrogen Production
Table 6.3.1. WTP and WTW Results for the Distributed Grid Electricity Pathway

WTP WTW

Coal input (including upstream)a 267,900 Btu/116,000 Btu 5,590 Btu/mi

Natural gas input (including upstream)a 118,800 Btu/116,000 Btu 2,480 Btu/mi

Petroleum input (including upstream)

a 10,200 Btu/116,000 Btu 210 Btu/mi

Fossil energy input (including upstream)a 396,900 Btu/116,000 Btu 8,280 Btu/mi

WTP CO2 emissionsb 40,000 g/116,000 Btu 770 g/mi

WTP CH4 emissions 100 g/116,000 Btu 2 g/mi

WTP N2O emissions 1 g/116,000 Btu 0 g/mi

WTP GHG emissions 42,600 g CO2-eq./

116,000 Btu

820 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $6.75 2007$/kg $0.14 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Electricity @ Total capital investment $1,699 2007$ / daily kg H2 (effective capacity)

$0.0574/kWh Levelized Cost of Capital $0.77 2007$ / kg H2 dispensed

Fixed O&M Costs $0.28 2007$ / kg H2 dispensed

Variable O&M Costs $0.06 2007$ / kg H2 dispensed

Total Levelized Cost $4.32 2007$ / kg H2 dispensed

Total capital investment $3,806 2007$ / daily kg H2 (effective capacity)

Electricity @ $0.0574/kWh Levelized Cost of Capital $1.49 2007$ / kg H2 dispensed

Energy & Fuel $0.40 2007$ / kg H2 dispensed

Other O&M Costs $0.54 2007$ / kg H2 dispensed

Levelized Cost of Dispensing $2.43 2007$ / kg H2 dispensed

Processing & Delivery Electrolyzer

Transmission & Distribution

Dispensing

Distribution:

Compressor

Gaseous H2 Storage

and Transmission: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Forecourt 

Hydrogen @ $6.75/kg

Electricity Generation, Scrubber

Water @

$1.81/thousand gal

Electricity Generation Hydrogen Production: 

Figure 6.3.2. Cost analysis inputs and high-level results for the distributed grid electricity pathway

51 
52 

Figure 6.3.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for the distributed grid electricity pathway 

Figure 6.3.4. Breakdown of levelized costs for the distributed grid electricity pathway 

$4.32 

$2.43 

$0.00 

Distributed Electrolysis Using Grid Electricity 

Production 

CSD 

Losses 
Table 6.3.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost for the

Distributed Grid Electricity Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.76 $0.35 $3.22 $4.23

 Electrolyzer stack $0.42

 H2 gas management system $0.14

 Electrolyte management system $0.09

 Power electronics $0.09

 Balance of plant $0.02

CSD $1.49 $0.54 $0.40 $2.43

 Compressor (levelized) $1.04

 Storage (levelized) $0.99

 Dispenser (levelized) $0.10

 Refrigeration (levelized) $0.16

 Remainder of Station (levelized) $0.14

Losses $0.00

Total $2.24 $0.89 $3.22 $0.40 $6.75

6.3.2 Energy Use and Emissions Breakdown

Figures 6.3.5 and 6.3.6 show the WTW energy inputs and losses for the distributed electricity 

pathway. 

Figure 6.3.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the distributed 

grid electricity pathway

53 
54 

Figure 6.3.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the distributed grid electricity pathway 

Figures 6.3.7 and 6.3.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the distributed electricity pathway. 

Figure 6.3.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the 

distributed grid electricity pathway 

0 

50,000 

100,000 

150,000 

200,000 

250,000 

Electricity Production & 

Delivery 

Hydrogen Production Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Distributed Grid Electrolysis) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 

CO2 Emissions 37,000 g CO2 Emissions 0 g

CH4 Emissions 91 g CH4 Emissions 0 g

N2O Emissions 0 g

N2O Emissions 1 g GHG Emissions 0 g

GHG Emissions 39,400 g

CO2 Emissions 3,000 g

Electricity CH4 Emissions 7 g

N2O Emissions 0 g

GHG Emissions 3,200 g

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Forecourt 

Transmission & Distribution

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer
55 

Figure 6.3.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the distributed grid electricity pathway 

6.3.3 Sensitivities 

6.3.3.1 Production Sensitivities 

The parameters used for this analysis are not known absolutely, so sensitivity analyses were 

performed to better understand the potential effects of that lack of knowledge on the final results. 

Several sensitivities were run on this pathway. They focused primarily on cost factors; however, 

several sensitivities also affect energy use and emissions. Figure 6.3.9 shows the effects of 

several production parameters on the pathway’s levelized cost, and Table 6.3.3 shows the effect 

of production energy efficiency on WTW energy use and emissions. 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

40,000 

45,000 

Electricity Production & 

Delivery 

Hydrogen Production Forecourt Storage & 

Dispensing 

g CO2 eq / GGE 

WTW Emissions Distributed Grid Electrolysis) 

CO2 CH4 N2O 
56 

Figure 6.3.9. Production sensitivities for the distributed grid electrolysis pathway 

Table 6.3.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Distributed Grid Electrolysis Pathway 

61% 

Efficiency 

67% 

Efficiency 

72% 

Efficiency 

WTW GHG Emissions (g/mile) 900 820 760 

WTW Fossil Energy (Btu/mile) 9,000 8,300 7,700 

WTW Petroleum Energy (Btu/mile) 230 210 200 

WTW Total Energy (Btu/mile) 10,700 9,800 9,100 

The assumed electrical grid mix also affects the energy use and emissions. If a hypothetical 

green grid mix that is 100% renewable energy (solar and wind) is used instead of the average 

grid mix (which was used for all other sensitivities), no fossil energy is used, nor are there any 

GHG emissions (Table 6.3.4). 

Table 6.3.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Distributed Grid Electrolysis Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid Mix

(48 mpgge) 

WTW GHG emissions (g/mile) 820 580 10 

WTW fossil energy (Btu/mile) 8,300 5,800 0 

WTW petroleum energy (Btu/mile) 210 150 0 

WTW total energy (Btu/mile) 9,800 6,800 4,300 
6.4 Central Biomass—Pipeline Delivery 

Figure 6.4.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix D for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central biomass—

pipeline delivery pathway are summarized in Table 6.4.1. 

Net GHG emissions include carbon dioxide uptake occurring during growth of the biomass. The 

analysis assumes that 100% of the carbon in the biomass is provided by atmospheric carbon 

dioxide. No other carbon uptake is assumed (e.g., carbon utilized to produce roots is assumed to 

be returned to the atmosphere through decomposition). Likewise, land use change is assumed to 

have neither positive nor negative effects on emissions. 

6.4.1 Cost Breakdown

Figure 6.4.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central biomass—pipeline delivery pathway. The financial 

assumptions used in this analysis are detailed in Section 5. 

Figure 6.4.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.4.2. 

Figure 6.4.4 and Table 6.4.2 show the breakdown of levelized costs for the central biomass—

pipeline delivery pathway. 

57 
Figure 6.4.1. Summary of major inputs, assumptions, and outputs by subsystem for the central biomass—pipeline delivery pathway

58 

Energy Use for Farming Trees 235,000 Btu / dry ton

25%

16,013,200 Btu / dry ton

100%

Biomass moisture content

Woody biomass LHV

Biomass price at H2 production

Biomass Share of Levelized Cos

$75 2007 $ / dry ton

Fraction of Woody Biomass $0.97 2007$ / kg H2 dispensed

LUC GHG changes ='Params - U g / dry ton

Average dist from farm to H2 production pstream'!E15 miles -24,830 g CO2 eq./ 116000 Btu

13 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

200 Btu / 116000Btu to Pump

600 Btu / 116000Btu to Pump

2,900 Btu / 116000Btu to Pump

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

WTG GHG Emissions

35 g CO2 eq./ 116000 Btu

-24,780 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

Biomass consumption 13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

155,200 kg / day $1,300 2007$ / daily kg H2 (effective capacity)

90%

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 produced

1.32 gal / kg H2 produced

79.3 gal / kg H2 produced 0.87

46.0%

Total Capital Investment $181,080,000 2007$ US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.64 2007$ / kg H2 dispensed

$0.23 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.24 2007$ / kg H2 dispensed

10%

Central plant design capacity

Capacity factor

Number of production facilities necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Coal Input (including upstream) Assumed Plant Life 40

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

5,100 Btu / 116000Btu to Pump

9,500 Btu / 116000Btu to Pump

3,400 Btu / 116000Btu to Pump

Production CO2 Emissions

Production CH4 Emissions

Production N2O Emissions

Production GHG Emissions

26,510 g CO2 eq./ 116000 Btu

140 g CO2 eq./ 116000 Btu

43 g CO2 eq./ 116000 Btu

26,690 g CO2 eq./ 116000 Btu

Electricity consumption for compressor Total capital investment $3,300 2007$ / daily kg H2 (effective capacity)

Electricity consumption for geo storage

Total electricity consumption

0.56 kWh / kg H2 dispensed

0.01 kWh / kg H2 dispensed

0.57 kWh / kg H2 dispensed 1,247,000 people

15%

121,100 kg / day

Total Capital Investment $404,341,000 2007$ 62 miles

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Delivery

$1.71 2007$ / kg H2 dispensed

$0.04 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.15 2007$ / kg H2 dispensed

1,325,000 kg H2

3

1.5 miles / line

122

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,800 Btu / 116000Btu to Pump

1,300 Btu / 116000Btu to Pump

100 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Distance from City to Production Facility

Geologic storage capacity

Number of trunk pipelines

Service-line length

Number of service lines

Hydrogen losses 0.80%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

390 g CO2 eq./ 116000 Btu

24 g CO2 eq./ 116000 Btu

2 g CO2 eq./ 116000 Btu

420 g CO2 eq./ 116000 Btu

12,700 psi

Electricity consumption 4.4 kWh / kg H2 dispensed

Hydrogen outlet pressure

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated

1,000 kg/day

 conventional unleaded gasoline)

Total Capital Investment per Station $2,650 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$2,629,000 2007$ / station

$320,679,000 2007$ / all stations 122

5

Inlet pressure of hydrogen at stations 300 psi 370 kg H2

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station 130 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$1.08 2007$ / kg H2 dispensed

$0.41 2007$ / kg H2 dispensed

$0.43 2007$ / kg H2 dispensed

$1.93 2007$ / kg H2 dispensed

42% % of design capacity 3,370 g CO2 eq./ 116000 Btu

2

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

24,400 Btu / 116000 Btu to Pump

10,800 Btu / 116000 Btu to Pump

900 Btu / 116000 Btu to Pump

Site storage

# of 2-hose Dispensers per Station

Hydrogen Losses 0.50%

210 g CO2 eq./ 116000 Btu

14 g CO2 eq./ 116000 Btu

3,590 g CO2 eq./ 116000 Btu

CSD CO2 Emissions

CSD CH4 Emissions

CSD N2O Emissions

CSD GHG Emissions

Cost Per Mile

3,020 lb

70 kW 48.0 mi / gge

Vehicle Mass

Fuel cell size

Hybridization battery (peak power) 30 kW 15,000 mi / yr

160,000 mi

2015

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing

$0.70 2007$ / mi

$0.13 2007$ / mi

$0.07 2007$ / mi

$0.12 2007$ / mi

$0.27 2007$ / mi

$0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Veh. Cycle CO2 Emissions

Veh. Cycle CH4 Emissions

Veh. Cycle N2O Emissions

Veh. Cycle GHG Emissions

1,670 g CO2 eq/ gge fuel consumed

7 g CO2 eq/ gge fuel consumed

0 g CO2 eq/ gge fuel consumed

1,850 g CO2 eq/ gge fuel consumed

Inputs Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Dispensing
Table 6.4.1. WTP and WTW Results for the Central Biomass—Pipeline Delivery Pathway

WTP WTW

Coal input (including upstream)a 32,600 Btu/116,000 Btu 680 Btu/mi

Natural gas input (including upstream)a 22,600 Btu/116,000 Btu 460 Btu/mi

Petroleum input (including upstream)

a 7,300 Btu/116,000 Btu 150 Btu/mi

Fossil energy input (including upstream)a 62,100 Btu/116,000 Btu 1,300 Btu/mi

WTP CO2 emissionsb 5,400 g/116,000 Btu 110 g/mi

WTP CH4 emissions 15 g/116,000 Btu 0 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 5,900 g CO2-eq./

116,000 Btu

120 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $6.32 2007$/kg $0.13 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and 

delivery pathway as feedstocks and fuels; those used to produce electricity and other materials used in the 

pathway; and those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Electricity @ Natural Gas @ 

$0.0847/kWh $10.49/MMBtu

Biomass @ Total capital investment $1,296 2007$ / daily kg H2 (effective capacity)

$75.02/dry short ton Levelized Cost of Capital $0.64 2007$ / kg H2 dispensed

Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Variable O&M Costs $0.40 2007$ / kg H2 dispensed

Total Levelized Cost $2.24 2007$ / kg H2 dispensed

Total capital investment $3,339 2007$ / daily kg H2 (effective capacity)

Electricity for compressor @ $0.0587/kWh Levelized Cost of Capital $1.71 2007$ / kg H2 dispensed

Energy & Fuel $0.04 2007$ / kg H2 dispensed

Electricity for geologic storage Other O&M Costs $0.40 2007$ / kg H2 dispensed

@ $0.0634/kWh Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Total capital investment $2,648 2007$ / daily kg H2 (effective capacity)

Electricity @ $0.0955/kWh Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Energy & Fuel $0.41 2007$ / kg H2 dispensed

Other O&M Costs $0.43 2007$ / kg H2 dispensed

Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting PSA

Truck Transport

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Dispensing

Hydrogen @ $6.32/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Figure 6.4.2. Cost analysis inputs and high-level results for the central biomass—pipeline delivery 

pathway

59 
60 

Figure 6.4.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—pipeline delivery pathway 

Figure 6.4.4. Breakdown of levelized costs for the central biomass—pipeline delivery pathway 

$2.21 

$4.08 

$0.03 

Biomass Gasification - Delivery of Gaseous 

Hydrogen in Pipelines 

Production 

Delivery 

Losses 
Table 6.4.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.64 $0.62 $0.96 $2.21

 Feed handling and drying $0.11

 Gasification, tar reforming, and quench $0.10

 Compression and sulfur removal $0.09

 SMR, WGS, and PSA $0.18

 Steam system and power generation $0.09

 Cooling water and other utilities $0.02

 Buildings and structures $0.04

Delivery $2.80 $0.83 $0.45 $4.08

 Central compressor $0.12

 Transmission pipeline $0.30

 Distribution pipeline $1.64

 Geologic storage $0.09

 Gaseous refueling station $1.08 $0.43 $0.41 $1.93

 Refrigeration $0.12

 Compressor $0.41

 Cascade storage $0.12

 Low pressure storage $0.30

 Dispenser and accessories $0.13

Losses $0.03

Total $3.44 $1.45 $0.96 $0.45 $6.32

6.4.2 Energy Use and Emissions Breakdown

Figures 6.4.5 and 6.4.6 show the WTW energy inputs and losses for the central biomass—

pipeline delivery pathway. 

Figures 6.4.7 and 6.4.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central biomass—pipeline delivery pathway. 

61 
62 

Figure 6.4.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—pipeline delivery pathway 

Figure 6.4.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—pipeline delivery pathway 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

40,000 

Biomass Production 

& Delivery 

H2 Production Pipeline Transport Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Biomass Gasification with Pipeline H2 Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
63 

Figure 6.4.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—pipeline delivery pathway 

Figure 6.4.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—pipeline delivery pathway 

6.4.3 Sensitivities 

6.4.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central biomass—pipeline delivery 

pathway. These sensitivities focused primarily on cost factors; however, several sensitivities also 

affect energy use and emissions. Figure 6.4.9 shows the effects of several production parameters 

-30,000 

-20,000 

-10,000 

0 

10,000 

20,000 

30,000 

Biomass Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

g CO2 eq / GGE 

Dispensing 

WTW Emissions (Biomass Gasification with Pipeline H2 Delivery) 

CO2 CH4 N2O 
64 

on the pathway’s levelized cost, and Table 6.4.3 shows the effects of varying production energy 

efficiency on WTW energy use and emissions. 

Figure 6.4.9. Production sensitivities for the central biomass—pipeline delivery pathway 

Table 6.4.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Pipeline Delivery Pathway 

44% 

Efficiency 

46% 

Efficiency 

48% 

Efficiency 

WTW GHG emissions (g/mile) 120 120 120 

WTW fossil energy (Btu/mile) 1,300 1,300 1,300 

WTW petroleum energy (Btu/mile) 160 150 150 

WTW total energy (Btu/mile) 6,900 6,600 6,300 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.4.4 shows the 

differences in energy use and GHG emissions between the U.S. average grid mix (which was 

used for all other sensitivities) and a hypothetical green grid mix that is 100% renewable energy 

(solar and wind). 

Table 6.4.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Pipeline Delivery Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 120 90 20 

WTW fossil energy (Btu/mile) 1,300 900 300 

WTW petroleum energy (Btu/mile) 150 110 130 

WTW total energy (Btu/mile) 6,600 4,700 5,900 
65 

6.4.3.2 Delivery Sensitivities 

Delivery cost, energy use, and emissions are strongly dependent upon daily consumption of 

hydrogen within a city and delivery distance from the central facility to the city gate. 

Sensitivities were run to show some of those effects. Daily consumption was varied by keeping 

the city size constant and adjusting the penetration of hydrogen vehicles from the base case of 

15%. The resulting consumption is shown in Figure 6.4.10. 

Figure 6.4.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—pipeline delivery pathway 

As expected there are economies of scale for higher vehicle penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to the city 

gate is shortened. Figures 6.4.11 and 6.4.12 show those economic effects (the figures show 

identical data but are organized differently). 

As Figure 6.4.12 shows, the cost increase due to distance from the city is more gradual with 

higher penetration because the cost of the transmission pipeline is shared more fully with 

increased demand. 













          





	



	



	




	


66 

Figure 6.4.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—pipeline delivery pathway 

Figure 6.4.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—pipeline delivery pathway 













          


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67 

The effects of penetration and distance between the production facility and city gate on WTW 

GHG emissions, WTW petroleum use, and WTW fossil energy use are shown in Figures 6.4.13, 

6.4.14, and 6.4.15. The overall emissions change little with penetration because the additional 

energy required for distance is minimal. That additional electricity requirement is for 

compression over the distance. The total energy required for compression varies little with 

increased penetration because the total electricity required to compress each kilogram of 

hydrogen is nearly constant for all penetrations. That is the case because only a small portion of 

the total energy is needed for compression for the pipelines (see Figure 6.4.1), and much of the 

pressure drop is in the service pipelines instead of the transmission or trunk pipelines. 

Figure 6.4.13. WTW GHG emissions versus penetration for the central biomass—pipeline delivery 

pathway 




























 
 
 
 
 
 
 
 
 
 





	



			



	

	


	
68 

Figure 6.4.14. WTW petroleum use versus penetration for the central biomass—pipeline delivery 

pathway 

Figure 6.4.15. WTW fossil energy use versus penetration for the central biomass—pipeline 

delivery pathway 

























 
 
 
 
 
 
 
 
 
 



		








		


	

	


	



















 
         





	
 
!

"




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The effects of city population on levelized cost of hydrogen, GHG emissions, and petroleum 

energy use are shown in Figures 6.4.16, 6.4.17, and 6.4.18. Levelized hydrogen cost, GHG

emissions, and petroleum energy use decrease only gradually with population increases for cities 

with populations of 5,000 or greater. The increase in cost between 500,000 people and 1,250,000 

people shown in Figure 6.4.16 is caused by increased installed pipeline costs per kg hydrogen 

dispensed. In both cases, there are two trunk pipeline rings; however, because population density 

is essentially constant, the larger population results in a larger city area and thus longer rings in 

the trunk pipelines. Those longer rings result in higher pipeline capital costs per kg dispensed. 

Additional people result in HDSAM-calculated optimums with more than two rings, thus 

reducing the pipeline capital costs per kg dispensed. 

Figure 6.4.19 shows the effect of fuel economy on the levelized cost of hydrogen. The hydrogen 

cost increases with increasing fuel economy, with the greatest increase in hydrogen cost 

occurring when fuel economy is increased from 40 mpgge to 50 mpgge. Lower demand for 

hydrogen resulting from higher fuel economy, as shown in Figure 6.4.20, is the reason for the 

increasing hydrogen costs. HDSAM optimization calculations calculated an optimum of two 

rings for all fuel economies except 48 mpgge. In that case it calculated three rings, resulting in a 

large jump in levelized cost between 40 mpgge and 48 mpgge. 

Figures 6.4.21 and 6.4.22 show that GHG emissions and petroleum energy use decrease with 

increasing fuel economy, as one might expect.

Figures 6.4.23, 6.4.24, and 6.4.25 show the effects of forecourt size on levelized cost of 

hydrogen, GHG emissions, and petroleum energy use for the central biomass—pipeline delivery 

pathway. Cost, emissions, and petroleum energy use decrease with increasing forecourt size. The 

apparent inconsistent result at 1,000 kg/day forecourt size in Figure 6.4.23 is due to a stepchange in distribution pipeline capital cost. At 750 kg/day, the diameter is 0.75 in. and at 1,000 

kg/day the diameter is 1.0 in. Because discrete diameters are chosen, a jump between them is 

required and the larger pipeline is not as fully utilized as the smaller one is. 

69 
70 

Figure 6.4.16. Levelized cost versus city population for the central biomass—pipeline delivery 

pathway 

Figure 6.4.17. GHG emissions versus city population for the central biomass—pipeline delivery 

pathway 

	










  	 
  




	

	
	
	







	











     

 	
!


 



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71 

Figure 6.4.18. Petroleum energy use versus city population for the central biomass—pipeline 

delivery pathway 

Figure 6.4.19. Levelized cost versus fuel economy for the central biomass—pipeline delivery 

pathway 







	

	

     

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!



	

			



	

		





	



	  		  	










72 

Figure 6.4.20. City hydrogen use versus fuel economy for the central biomass—pipeline delivery 

pathway 

Figure 6.4.21. GHG emissions versus fuel economy for the central biomass—pipeline delivery 

pathway 

	














    	

	























    	







	






	
	
73 

Figure 6.4.22. Petroleum use versus fuel economy for the central biomass—pipeline delivery 

pathway 

Figure 6.4.23. Levelized cost versus forecourt size for the central biomass—pipeline delivery 

pathway 











    	

				
	

	
		

	
					

		














   	 
 

	






74 

Figure 6.4.24. GHG emissions versus forecourt size for the central biomass—pipeline delivery 

pathway 

Figure 6.4.25. Petroleum energy use versus forecourt size for the central biomass—pipeline 

delivery pathway 



	



	



 
    

	




















	

 	   
 




	





6.5 Central Biomass—Gaseous H2 Truck Delivery

Figure 6.5.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix E for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central biomass—

gaseous H2 truck delivery pathway are summarized in Table 6.5.1. 

Net GHG emissions include carbon dioxide uptake occurring during growth of the biomass. As 

noted above, the analysis assumes that 100% of the carbon in the biomass is provided by 

atmospheric carbon dioxide and that land use change is assumed to have neither positive nor 

negative effects on emissions. 

6.5.1 Cost Breakdown

Figure 6.5.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central biomass—gaseous H2 truck delivery pathway. The 

financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.5.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.5.2. 

Figure 6.5.4 and Table 6.5.2 show the breakdown of levelized costs for the central biomass—

gaseous H2 truck delivery pathway. 

75 
Figure 6.5.1. Summary of major inputs, assumptions, and outputs by subsystem for the central biomass—gaseous H2 truck delivery pathway

76 

25%

16,013,000 Btu / dry ton

Energy Use for Farming Trees 235,000 Btu / dry ton $75.02 2007 $ / dry ton

100%

Biomass moisture content

Woody biomass LHV

Biomass price at H2 production

Biomass Share of Levelized Cos $0.97 2007$ / kg H2 dispensed

0 g / dry ton

Fraction of Woody Biomass 

LUC GHG changes

Average distance from farm to H2 prod. 40 miles -24,850 g CO2 eq./ 116000 Btu

15 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

300 Btu / 116000Btu to Pump

800 Btu / 116000Btu to Pump

3,200 Btu / 116000Btu to Pump

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

WTG GHG Emissions

35 g CO2 eq./ 116000 Btu

-24,800 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

Biomass consumption 13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

155,200 kg / day $1,300 2007$ / daily kg H2 (effective capacity)

90%

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.98 kWh / kg H2 produced

1.32 gal / kg H2 produced

79.3 gal / kg H2 produced 0.87

46.0%

Total Capital Investment $181,080,000 2007$ US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.65 2007$ / kg H2 dispensed

$0.23 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.25 2007$ / kg H2 dispensed

10%

Central plant design capacity

Capacity factor

Number of production facilities necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Coal Input (including upstream) Assumed Plant Life 40 26,620 g CO2 eq./ 116000 Btu

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

5,200 Btu / 116000Btu to Pump

9,700 Btu / 116000Btu to Pump

3,700 Btu / 116000Btu to Pump

140 g CO2 eq./ 116000 Btu

43 g CO2 eq./ 116000 Btu

26,800 g CO2 eq./ 116000 Btu

Production CO2 Emissions

Production CH4 Emissions

Production N2O Emissions

Production GHG Emissions

Total capital investment $2,100 2007$ / daily kg delivered

Electricity consumption at terminal 1.31 kWh / kg H2 dispensed Levelized Electricity cost $0.09 2007$ / kg H2 delivered

1,247,000 people

Electricity consumption for geo storage

Total electricity consumption

Diesel consumption

0.01 kWh / kg H2 dispensed

1.32 kWh / kg H2 dispensed

58.9 gal / 1000 kg H2 15%

Levelized Diesel cost

Levelized Labor cost

Levelized Other operating costs

$0.20 2007$ / kg H2 delivered

$0.41 2007$ / kg H2 delivered

$0.34 2007$ / kg H2 delivered

121,100 kg / day

Levelized Cost of Delivery $1.88 2007$ / kg H2 delivered

Total Capital Investment $254,858,000 2007$

62 miles

1,470,000 kg H2

79,700 per year

560 kg / truckload

88.0%

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

400 Btu / 116000Btu to Pump

1,400 Btu / 116000Btu to Pump

9,800 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

One-way distance for delivery

Storage capacity (geologic + terminal)

Number of truck-trips required

Truck hydrogen capacity

Efficiency of truck loading compressors

Hydrogen losses 1.0%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

910 g CO2 eq./ 116000 Btu

32 g CO2 eq./ 116000 Btu

7 g CO2 eq./ 116000 Btu

950 g CO2 eq./ 116000 Btu

12,700 psi

2.1 kWh / kg H2

Hydrogen outlet pressure

Electricity consumption Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

Electricity price $0.096 2007$ / kWh

800 kg / day Total capital investment

conventional unleaded gasoline)

$2,190 2007$ / daily kg

Total Capital Investment per Station 152 Levelized Cost of Capital

Total Capital Investment

$1,744,000 2007$ / station

$265,136,000 2007$ / all stations 5 Energy & Fuel

N/A (storage on trucks) Other O&M Costs

Minimum inlet pressure from tube trailer 220 psi

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compressor Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing

$0.95 2007$ / kg H2 dispensed

$0.20 2007$ / kg H2 dispensed

$0.46 2007$ / kg H2 dispensed

$1.61 2007$ / kg H2 dispensed

14% % of design capacity CSD CO2 Emissions 2,310 g CO2 eq./ 116000 Btu

2 CSD CH4 Emissions 140 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

16,700 Btu / 116000Btu to Pump

7,400 Btu / 116000Btu to Pump

700 Btu / 116000Btu to Pump

Site storage

# of 2-hose Dispensers per Station

Hydrogen loss factor 0.50% CSD N2O Emissions

CSD GHG Emissions

Cost Per Mile

9 g CO2 eq./ 116000 Btu

2,470 g CO2 eq./ 116000 Btu

$0.69 2007$ / mi

3,020 lb Fuel Share $0.12 2007$ / mi

70 kW 48.0 mi / gge $0.07 2007$ / mi

Vehicle Mass

Fuel cell size

Hybridization battery (peak power) 30 kW 15,000 mi / yr $0.12 2007$ / mi

160,000 mi $0.27 2007$ / mi

2015

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,400 Btu / gge fuel consumed

12,400 Btu / gge fuel consumed

7,700 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Vehicle Cycle CO2 Emissions

Vehicle Cycle CH4 Emissions

Vehicle Cycle N2O Emissions

Vehicle Cycle GHG Emissions

1,750 g CO2 eq/ gge fuel consumed

170 g CO2 eq/ gge fuel consumed

7 g CO2 eq/ gge fuel consumed

1,940 g CO2 eq/ gge fuel consumed

Inputs Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Gas Trucks for Delivery (with Terminal and Geologic Storage)

Hydrogen Production

Forecourt Dispensing
Table 6.5.1. WTP and WTW Results for the Central Biomass—Gaseous H2 Truck Delivery Pathway

WTP WTW

Coal input (including upstream)a 22,700 Btu/116,000 Btu 470 Btu/mi

Natural gas input (including upstream)a 15,300 Btu/116,000 Btu 400 Btu/mi

Petroleum input (including upstream)a 17,500 Btu/116,000 Btu 360 Btu/mi

Fossil energy input (including upstream)a 59,500 Btu/116,000 Btu 1,240 Btu/mi

WTP CO2 emissionsb 5,000 g/116,000 Btu 100 g/mi

WTP CH4 emissions 13 g/116,000 Btu 0 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 5,400 g CO2-eq./

116,000 Btu

110 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $5.74 2007$/kg $0.12 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Figure 6.5.2. Cost analysis inputs and high-level results for the central biomass—gaseous H2

truck delivery pathway

77 
78 

Figure 6.5.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—gaseous H2 truck delivery pathway 

Figure 6.5.4. Breakdown of levelized costs for the central biomass—gaseous H2 truck delivery 

pathway 

$2.21 

$3.49 

$0.03 

Biomass Gasification - Delivery of Gaseous 

Hydrogen in Trucks 

Production 

Delivery 

Losses 
Table 6.5.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Gaseous H2 Truck Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.64 $0.62 $0.96 $2.21

 Feed handling and drying $0.11

 Gasification, tar reforming, and quench $0.10

 Compression and sulfur removal $0.09

 SMR, WGS, and PSA $0.18

 Steam system and power generation $0.09

 Cooling water and other utilities $0.02

 Buildings and structures $0.04

Delivery $1.81 $1.18 $0.51 $3.49

 Gaseous H2 terminal $0.59

 Truck and trailer $1.19

 Geologic storage $0.11

 Gaseous refueling station $0.95 $0.46 $0.20 $1.61

 Refrigeration $0.12

 Compressor $0.50

 Cascade storage $0.17

 Low pressure storage $0.00

 Dispenser and accessories $0.17

Losses $0.03

Total $2.45 $1.80 $0.96 $0.51 $5.74

6.5.2 Energy Use and Emissions Breakdown

Figures 6.5.5 and 6.5.6 show the WTW energy inputs and losses for the central biomass—

gaseous H2 truck delivery pathway. 

Figures 6.5.7 and 6.5.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central biomass—gaseous H2 truck delivery pathway. 

79 
80 

Figure 6.5.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—gaseous H2 truck delivery pathway 

Figure 6.5.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—gaseous H2 truck delivery pathway 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

Biomass Production & 

Delivery 

Hydrogen Production Gaseous H2 Truck 

Delivery 

Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Biomass Gasification with Gaseous H2 Delivery in Trucks) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
81 

Figure 6.5.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—gaseous H2 truck delivery pathway 

Figure 6.5.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—gaseous H2 truck delivery pathway 

-30,000 

-20,000 

-10,000 

0 

10,000 

20,000 

30,000 

Biomass Production & 

Delivery 

Hydrogen Production Gaseous H2 Truck 

Delivery 

Forecourt Storage & 

Dispensing 

g CO2 eq / GGE 

WTW Emissions (Biomass Gasification with Gaseous H2 Delivery in Trucks) 

CO2 CH4 N2O 
82 

6.5.3 Sensitivities 

6.5.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central biomass—pipeline delivery 

pathway. These sensitivities focused primarily on cost factors; however, several sensitivities also 

affect energy use and emissions. Figure 6.5.9 shows the effects of several production parameters 

on the pathway’s levelized cost, and Table 6.5.3 shows the effects of varying production energy 

efficiency on WTW energy use and emissions. 

Figure 6.5.9. Production sensitivities for the central biomass—gaseous H2 truck delivery pathway 

Table 6.5.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Gaseous H2 Truck Delivery Pathway 

44% 

Efficiency 

46% 

Efficiency 

48% 

Efficiency 

WTW GHG emissions (g/mile) 110 110 110 

WTW fossil energy (Btu/mile) 1,300 1,200 1,200 

WTW petroleum energy (Btu/mile) 370 360 360 

WTW total energy (Btu/mile) 6,800 6,500 6,200 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.5.4 shows the 

differences in energy use and GHG emissions between the U.S. average grid mix (which was 

used for all other sensitivities) and a hypothetical green grid mix that is 100% renewable energy 

(solar and wind). 
83 

Table 6.5.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Gaseous H2 Truck Delivery Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 110 80 40 

WTW fossil energy (Btu/mile) 1,200 900 500 

WTW petroleum energy (Btu/mile) 360 260 340 

WTW total energy (Btu/mile) 6,500 4,600 6,000 

6.5.3.2 Delivery Sensitivities 

Delivery cost, energy use, and emissions are strongly dependent upon the daily consumption of 

hydrogen within a city and the delivery distance from the central facility to the city gate. 

Sensitivities were run to show some of those effects. Daily consumption was varied by keeping 

the city size constant and adjusting the penetration of hydrogen vehicles from the base case of 

15%. The resulting consumption is shown in Figure 6.5.10. 

Figure 6.5.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—gaseous H2 truck delivery pathway 

As expected there are economies of scale for higher vehicle penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to the city 

gate is shortened. Figures 6.5.11 and 6.5.12 show those economic effects (the figures show 

identical data but are organized differently). 













          





	



	



	




	


84 

As Figure 6.5.12 shows, there is a $1.17 increase in levelized cost when the production facility is 

assumed to be 150 miles from the city gate as compared to being at the city gate. There is a much 

larger levelized-cost increase when the distance is assumed to be 1,000 miles because the 

levelized cost of trucking increases with added distance due to additional driver time, additional 

fuel requirements, and an increased number of trucks and trailers required. 

Figure 6.5.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—gaseous H2 truck delivery pathway 

















        


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85 

Figure 6.5.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—gaseous H2 truck delivery pathway 

The effects of penetration and distance between the production facility and the city gate on 

WTW GHG emissions, WTW petroleum use, and WTW fossil energy use are shown in Figures 

6.5.13, 6.5.14, and 6.5.15, respectively. In each case, the energy use and emissions decrease 

when the production facility is closer to the city gate because of reduced diesel use for trucking. 

























          


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86 

Figure 6.5.13. WTW GHG emissions versus penetration for the central biomass—gaseous H2 truck 

delivery pathway 

Figure 6.5.14. WTW petroleum use versus penetration for the central biomass—gaseous H2 truck 

delivery pathway 











































 
 
 
 
 
 
 
 
 
 





	



			



	

	


	



















































 
 
 
 
 
 
 
 
 
 



		








		


	

	


	
87 

Figure 6.5.15. WTW fossil energy use versus penetration for the central biomass—gaseous H2

truck delivery pathway 

The effects of city population on levelized cost of hydrogen, GHG emissions, and petroleum 

energy use are shown in Figures 6.5.16, 6.5.17, and 6.5.18. Levelized hydrogen cost remains 

nearly constant for all city populations studied. GHG emissions and petroleum energy use 

generally increase with increasing city population. The apparent bounce at 500,000 people in 

Figure 6.5.16 is caused by a difference between costs for the terminal and for the trucks. The 

terminal costs are declining through the entire range as population increases due to economies of 

scale (not shown). The truck costs are increasing through the entire population range due to 

increased city size increasing truck travel distance (not shown). In most cases, they cancel each 

other out; however, between 100,000 and 500,000 people the decrease in terminal cost is greater 

than the increase in truck cost. 

Figure 6.5.19 shows the effect of fuel economy on the levelized cost of hydrogen. The 

relationship between fuel economy and city hydrogen use is shown in Figure 6.5.20. 

Figures 6.5.21 and 6.5.22 show that GHG emissions and petroleum energy use decrease with 

increasing fuel economy, as one might expect. 

Figures 6.5.23, 6.5.24, and 6.5.25 show the effects of forecourt size on levelized cost of 

hydrogen, GHG emissions, and petroleum energy use for the central biomass—gaseous H2 truck 

delivery pathway. Cost, emissions, and petroleum energy use decrease with increasing forecourt 

size up to 800 kg/day. 


















 
         





	
 
!

"




"








	


	

	


	
88 

Figure 6.5.16. Levelized cost versus city population for the central biomass—gaseous H2 truck 

delivery pathway 

Figure 6.5.17. GHG emissions versus city population for the central biomass—gaseous H2 truck 

delivery pathway 

	










  	 
  




	

	
	
	







	













     

 	
!


 



!




89 

Figure 6.5.18. Petroleum energy use versus city population for the central biomass—gaseous H2

truck delivery pathway 

Figure 6.5.19. Levelized cost versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway 

















     

 !

	 
	
!



	

			



	

		





	



	  		  	










90 

Figure 6.5.20. City hydrogen use versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway 

Figure 6.5.21. GHG emissions versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway 

	














    	

	





















    	







	






	
	
91 

Figure 6.5.22. Petroleum use versus fuel economy for the central biomass—gaseous H2 truck 

delivery pathway 

Figure 6.5.23. Levelized cost versus forecourt size for the central biomass—gaseous H2 truck 

delivery pathway 









	




	  		  	

				
	

	
		

	
					















	 
   
    




	



		

92 

Figure 6.5.24. GHG emissions versus forecourt size for the central biomass—gaseous H2 truck 

delivery pathway 

Figure 6.5.25. Petroleum energy use versus forecourt size for the central biomass—gaseous H2

truck delivery pathway 



	



	



   	 
   
 

	












	








   	 
   
 




	





6.6 Central Biomass—Liquid Truck Delivery and Gaseous Dispensing

Figure 6.6.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix F for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central biomass—liquid 

truck delivery and gaseous dispensing pathway are summarized in Table 6.6.1. 

Net GHG emissions include carbon dioxide uptake occurring during growth of the biomass. As 

noted above, the analysis assumes that 100% of the carbon in the biomass is provided by 

atmospheric carbon dioxide and that land use change is assumed to have neither positive nor 

negative effects on emissions. 

6.6.1 Cost Breakdown

Figure 6.6.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central biomass—liquid truck delivery and gaseous 

dispensing pathway. The financial assumptions used in this analysis are detailed in Section 5.0. 

93 
Figure 6.6.1. Summary of major inputs, assumptions, and outputs by subsystem for the central biomass—liquid truck delivery and gaseous 

dispensing pathway

94 

25%

16,013,000 Btu / dry ton

Energy Use for Farming Trees 235,000 Btu / dry ton

='Params - Upstream'!D3

Biomass moisture content

Woody biomass LHV

Biomass price at H2 production

Biomass Share of Levelized Cost

$75 2007 $ / dry ton

Fraction of Woody Biomass $1.00 2007$ / kg H2 dispensed

LUC GHG changes ='Params - U g / dry ton

Average distance from farm to H2 prod. ='Params - U miles -25,540 g CO2 eq./ 116000 Btu

13 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

200 Btu / 116000Btu to Pump

600 Btu / 116000Btu to Pump

2,800 Btu / 116000Btu to Pump

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

WTG GHG Emissions

36 g CO2 eq./ 116000 Btu

-25,490 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

Biomass consumption 13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

155,200 kg / day $1,300 2007$ / daily kg H2 (effective capacity)

90%

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 produced

1.32 gal / kg H2 produced

79.3 gal / kg H2 produced 0.87

46.0%

Total Capital Investment $181,080,000 2007$ US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.66 2007$ / kg H2 dispensed

$0.23 2007$ / kg H2 dispensed

$0.41 2007$ / kg H2 dispensed

$2.30 2007$ / kg H2 dispensed

10%

Central plant design capacity

Capacity factor

Number of production facilities necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Coal Input (including upstream) Assumed Plant Life 40 27,230 g CO2 eq./ 116000 Btu

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

5,300 Btu / 116000Btu to Pump

9,700 Btu / 116000Btu to Pump

3,300 Btu / 116000Btu to Pump

140 g CO2 eq./ 116000 Btu

44 g CO2 eq./ 116000 Btu

27,410 g CO2 eq./ 116000 Btu

Production CO2 Emissions

Production CH4 Emissions

Production N2O Emissions

Production GHG Emissions

Total capital investment $1,980 2007$ / daily kg H2 (effective capacity)

Liquefaction electricity consumption 8.5 kWh / kg H2 dispensed Levelized Electricity cost $0.58 2007$ / kg H2 dispensed

0.03 kWh / kg H2 dispensed

8.57 kWh / kg H2 dispensed City Population 1,247,000 people

Terminal electricity consumption

Total electricity consumption

Diesel consumption 7.6 gal / 1000 kg H2 dispensed Hydrogen Vehicle Penetration 15%

Levelized Diesel cost

Levelized Labor cost

Levelized Other operating costs

$0.03 2007$ / kg H2 dispensed

$0.09 2007$ / kg H2 dispensed

$0.24 2007$ / kg H2 dispensed

City hydrogen use 121,100 kg / day

Total Capital Investment $239,448,000 2007$ One-way distance for delivery 98 miles Levelized Cost of Delivery $1.80 2007$ / kg H2 delivered

1,103,000 kg H2

10,200

4,400 kg / truckload 7,220 g CO2 eq./ 116000 Btu

79.3% 440 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

51,700 Btu / 116000Btu to Pump

23,000 Btu / 116000Btu to Pump

3,000 Btu / 116000Btu to Pump

Terminal Design Capacity

Number of truck-trips required per year

Truck hydrogen capacity

Liquefaction energy efficiency

Hydrogen losses 2.8%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

Onboard Storage Pressure

30 g CO2 eq./ 116000 Btu

7,690 g CO2 eq./ 116000 Btu

12,700 psi

Electricity consumption 0.51 kWh / kg H2 dispensed Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

1,000 kg / day

conventional unleaded gasoline)

$1,330 2007$ / daily kg H2 (effective capacity)

Total Capital Investment per Station 122

Total Capital Investment

$1,315,000 2007$ / station

$160,485,000 2007$ / all stations 1

4,600 kg H2

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Cascade Pumps

Liquid H2 storage capacity per Station

Usable Cascade Storage per Station 70 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$0.49 2007$ / kg H2 dispensed

$0.05 2007$ / kg H2 dispensed

$0.48 2007$ / kg H2 dispensed

$1.02 2007$ / kg H2 dispensed

400% % of design capacity CSD CO2 Emissions

2 CSD CH4 Emissions

Coal Input (including upstream) Included in Delivery Section

Natural Gas Input (including upstream) Included in Delivery Section

Petroleum Input (including upstream) Included in Delivery Section

Site storage

# of 2-hose Dispensers per Station

Hydrogen Losses 1.1% CSD N2O Emissions

CSD GHG Emissions

Included in Delivery Section

Included in Delivery Section

Included in Delivery Section

Included in Delivery Section

Cost Per Mile $0.67 2007$ / mi

3,020 lb Fuel Share $0.11 2007$ / mi

70 kW 48.0 mi / gge $0.07 2007$ / mi

Vehicle Mass

Fuel cell size

Hybridization battery (peak power) 30 kW 15,000 mi / yr $0.12 2007$ / mi

160,000 mi $0.27 2007$ / mi

2015

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Veh. Cycle CO2 Emissions

Veh. Cycle CH4 Emissions

Veh. Cycle N2O Emissions

Veh. Cycle GHG Emissions

1,670 g CO2 eq/ gge fuel consumed

170 g CO2 eq/ gge fuel consumed

6 g CO2 eq/ gge fuel consumed

1,850 g CO2 eq/ gge fuel consumed

Forecourt Dispensing

Inputs Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production
Table 6.6.1. WTP and WTW Results for the Central Biomass—Liquid Truck Delivery and Gaseous 

Dispensing Pathway

WTP WTW

Coal input (including upstream)a 57,200 Btu/116,000 Btu 1,190 Btu/mi

Natural gas input (including upstream)a 33,400 Btu/116,000 Btu 700 Btu/mi

Petroleum input (including upstream)a 9,100 Btu/116,000 Btu 190 Btu/mi

Fossil energy input (including upstream)a 367,400 Btu/116,000 Btu 2,080 Btu/mi

WTP CO2 emissionsb 8,900 g/116,000 Btu 190 g/mi

WTP CH4 emissions 24 g/116,000 Btu 0 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 9,600 g CO2-eq./ 

116,000 Btu

200 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $5.12 2007$/kg $0.11 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Electricity @ Natural Gas @ 

$0.0847/kWh $10.49/MMBtu

Biomass Production Biomass @ Hydrogen Production: Total capital investment $1,296 2007$ / daily kg H2 (effective capacity)

and Delivery: $75.02/dry short ton Gasifier Levelized Cost of Capital $0.66 2007$ / kg H2 dispensed

Poplar Planting SMR Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Fertilization WGS Variable O&M Costs $0.41 2007$ / kg H2 dispensed

Harvesting PSA Total Levelized Cost $2.30 2007$ / kg H2 dispensed

Truck Transport

Total capital investment $1,977 2007$ / daily kg H2 (effective capacity)

Liquefaction & Levelized Electricity cost $0.58 2007$ / kg H2 dispensed

Electricity @ $0.0635/kWh Truck Delivery: Levelized Diesel cost $0.03 2007$ / kg H2 dispensed

Diesel @ $3.23/gallon Liquefier Levelized Labor cost $0.09 2007$ / kg H2 dispensed

Liquid H2 Storage Levelized Other operating costs $0.24 2007$ / kg H2 dispensed

Liquid H2 Truck

Levelized Cost of Delivery $1.80 2007$ / kg H2 delivered

Forecourt Total capital investment $ 1,325 2007$ / daily kg H2 (effective capacity)

Electricity @ $0.0956/kWh Distribution: Levelized Cost of Capital $ 0.49 2007$ / kg H2 dispensed

Vaporizer Energy & Fuel $ 0.05 2007$ / kg H2 dispensed

Compressor Other O&M Costs $ 0.48 2007$ / kg H2 dispensed

Gaseous H2 Storage Levelized Cost of Dispensing $ 1.02 2007$ / kg H2 dispensed

Dispensing

Hydrogen @ $5.12/kg

Figure 6.6.2. Cost analysis inputs and high-level results for the central biomass—liquid truck 

delivery and gaseous dispensing pathway

Figure 6.6.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.6.2. 

95 
96 

Figure 6.6.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—liquid truck delivery and gaseous dispensing pathway 

Figure 6.6.4 and Table 6.6.2 show the breakdown of levelized costs for the central biomass—

liquid truck delivery and gaseous dispensing pathway. 

Figure 6.6.4. Breakdown of levelized costs for the central biomass—liquid truck delivery and 

gaseous dispensing pathway 

$2.21 

$2.81 

$0.09 

Biomass Gasification - Delivery of Liquid 

Hydrogen in Trucks 

Production 

Delivery 

Losses 
Table 6.6.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.64 $0.62 $0.96 $2.21

 Feed handling and drying $0.11

 Gasification, tar reforming, and quench $0.10

 Compression and sulfur removal $0.09

 SMR, WGS, and PSA $0.18

 Steam system and power generation $0.09

 Cooling water and other utilities $0.02

 Buildings and structures $0.04

Delivery $1.35 $0.81 $0.65 $2.81

 Tractor/trailer $0.18

 Terminal $0.30

 Liquefier $0.57 $0.16 $0.58 $1.31

 Forecourt $0.49 $0.48 $0.05 $1.02

Losses $0.09

Total $1.99 $1.43 $0.96 $0.65 $5.12

6.6.2 Energy Use and Emissions Breakdown

Figures 6.6.5 and 6.6.6 show the WTW energy inputs and losses for the central biomass—liquid 

truck delivery and gaseous dispensing pathway. 

Figures 6.6.7 and 6.6.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central biomass—liquid truck delivery and gaseous

dispensing pathway. 

97 
98 

Figure 6.6.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—liquid truck delivery and gaseous dispensing pathway 

Figure 6.6.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—liquid truck delivery and gaseous dispensing pathway 

0 

10,000 

20,000 

30,000 

40,000 

50,000 

60,000 

70,000 

80,000 

Biomass Production & 

Delivery 

Hydrogen Production Liquefaction & Truck 

Delivery 

Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Biomass Gasification with Liquid H2 Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
99 

Figure 6.6.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—liquid truck delivery and gaseous dispensing pathway 

Figure 6.6.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—liquid truck delivery and gaseous dispensing pathway 

-30,000 

-20,000 

-10,000 

0 

10,000 

20,000 

30,000 

Biomass Production & 

Delivery 

Hydrogen Production Liquefaction & Truck 

Delivery 

Forecourt Storage & 

Dispensing 

g CO2 eq / GGE 

WTW Emissions (Biomass Gasification with Liquid H2 Delivery) 

CO2 CH4 N2O 
100 

6.6.3 Sensitivities 

6.6.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central biomass—liquid truck 

delivery and gaseous dispensing pathway. These sensitivities focused primarily on cost factors; 

however, several sensitivities also affect energy use and emissions. Figure 6.6.9 shows the 

effects of several production parameters on the pathway’s levelized cost, and Table 6.6.3 shows 

the effects of varying production energy efficiency on WTW energy use and emissions. 

Figure 6.6.9. Production sensitivities for the central biomass—liquid truck delivery and gaseous 

dispensing pathway 

Table 6.6.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway 

44% 

Efficiency 

46% 

Efficiency 

48% 

Efficiency 

WTW GHG emissions (g/mile) 200 200 200 

WTW fossil energy (Btu/mile) 2,100 2,100 2,100 

WTW petroleum energy (Btu/mile) 200 190 180 

WTW total energy (Btu/mile) 8,000 7,700 7,400 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.6.4 shows the 

differences in energy use and GHG emissions between the U.S. average grid mix (which was 

used for all other sensitivities) and a hypothetical green grid mix that is 100% renewable energy 

(solar and wind). 
101 

Table 6.6.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Liquid Truck Delivery and Gaseous Dispensing Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 200 150 30 

WTW fossil energy (Btu/mile) 2,100 1,500 300 

WTW petroleum energy (Btu/mile) 190 130 140 

WTW total energy (Btu/mile) 7,700 5,500 6,500 

6.6.3.2 Delivery Sensitivities 

Delivery cost, energy use, and emissions are strongly dependent upon the daily consumption of 

hydrogen within a city and the delivery distance from the central facility to the city gate. 

Sensitivities were run to show some of those effects. Daily consumption was varied by keeping 

the city size constant and adjusting the penetration of hydrogen vehicles from the base case of 

15%. The resulting consumption is shown in Figure 6.6.10. 

Figure 6.6.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—liquid truck delivery and gaseous dispensing pathway 

As expected there are economies of scale for higher vehicle penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to the city 

gate is shortened. Figures 6.6.11 and 6.6.12 show those economic effects (the figures show 

identical data but are organized differently). In cases where the hydrogen vehicle penetration is 

5% or 15%, only one liquefier is necessary. Two liquefiers are needed for the 25% penetration 

case because of size limitations, resulting in increased levelized cost due to increased levelized 













          





	



	



	




	


102 

liquefier capital costs. Levelized liquefier capital costs are higher because each of the two 

liquefiers is smaller than the one in the 15% penetration case. 

Figure 6.6.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and gaseous 

dispensing pathway 



















          


'	#&"$

	
#$

		
 '		!	

	

	

	

	

	

	
103 

Figure 6.6.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and gaseous 

dispensing pathway 

As Figure 6.6.12 shows, there is a $0.14 increase in levelized cost when the production facility is 

assumed to be 150 miles from the city gate as compared to being at the city gate. There is a much 

larger levelized-cost increase when the distance is assumed to be 1,000 miles because the 

levelized cost of trucking increases with added distance due to additional driver time, additional 

fuel requirements, and an increased number of trucks and trailers required. Figure 6.6.13 shows 

the liquid truck portion of the levelized cost; note that the base case distance is 62 miles and that 

the truck’s levelized cost is $0.18 for all penetration levels at that distance. Because the city size 

is constant and the assumed station size is sufficient to utilize a full truckload at each station, 

each delivery has the same travel distance and takes the same amount of time within the city 

regardless of penetration level; therefore, the levelized cost within the city gate is constant for all 

penetration levels. 




























          


&	"%!#

&	

&				
 	

	

	

	

	
104 

Figure 6.6.13. Truck levelized cost versus distance between production facility and city gate for 

the central biomass—liquid truck delivery and gaseous dispensing pathway 

The most notable feature in Figure 6.6.13 is the insensitivity of transport levelized cost to 

changes in FCEV penetration. The significant drop in the levelized cost of hydrogen as FCEV 

penetration increases to 15% (shown in Figure 6.6.11) is due to the reduced cost of liquefaction, 

which is shown in Figure 6.6.14 (liquefier cost is constant when penetration levels are kept 

constant no matter how far the liquefiers are from the city). When the penetration is increased to 

25% from 15%, two smaller liquefiers are needed due to scale limitations; thus, the capital cost 

per annual kilogram increases, resulting in increased levelized cost. 

The majority of the liquefaction system’s cost driver is capital (Table 6.6.2 shows that the capital 

accounts for $0.57/kg H2 of the $1.31/kg H2 total liquefaction cost). As shown in Figure 6.6.15, 

capital-cost reduction drives the cost decrease as penetration increases. 















          


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#$

		
 '		!



	

	

	

	

	

	

	
105 

Figure 6.6.14. Liquefaction system levelized cost versus penetration for the central biomass—

liquid truck delivery and gaseous dispensing pathway 

Figure 6.6.15. Liquefaction system capital cost (levelized) versus penetration for the central 

biomass—liquid truck delivery and gaseous dispensing pathway 


































          



	
"%!#

&	

&				
 



	


	

	

	

	


































          



	
		#&"$

'	

'		 		
!



	
		

	

	

	

	
106 

The additional cost variable for the levelized cost of the liquefaction system is the system 

efficiency, because increased efficiency reduces the energy required for liquefaction. Figure 

6.6.16 shows the effect of penetration (directly affecting liquefaction system size) on efficiency. 

Note that one liquefier is needed for 5% and 15% penetration, two for 25%, three for 50%, four 

for 75%, and five for 100% penetration, and that larger liquefaction systems result in higher 

efficiencies. More efficient liquefaction systems result in lower GHG emissions and fossil 

energy use. 

Figure 6.6.16. Liquefaction system efficiency versus penetration for the central biomass—liquid 

truck delivery and gaseous dispensing pathway 

The effects of penetration and distance between the production facility and the city gate on 

WTW GHG emissions, WTW petroleum use, and WTW fossil energy use are shown in Figures 

6.6.17, 6.6.18, and 6.6.19, respectively. In each case, the energy use and emissions decrease as 

liquefaction system efficiency increases with penetration and then plateaus as discussed above. 

Energy use and emissions are also reduced when the production facility is closer to the city gate 

because of reduced diesel use for trucking. 

		
	


	

	












	










	





      	 
   

	
	


	

	

107 

Figure 6.6.17. WTW GHG emissions versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

Figure 6.6.18. WTW petroleum use versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

















 
         




	



			


	

	


	





















 
         


		








		

	

	


	




	
108 

Figure 6.6.19. WTW fossil energy use versus penetration for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

The effects of city population on levelized cost of hydrogen, GHG emissions, and petroleum 

energy use are shown in Figures 6.6.20, 6.6.21, and 6.6.22. Levelized hydrogen cost decreases 

slightly with increasing city population. GHG emissions also generally decrease with increasing 

city population, while petroleum energy use increases with increasing city population above a 

population of 500,000 due to increased city area with increased population. 

Figure 6.6.23 shows the effect of fuel economy on the levelized cost of hydrogen. The cost of 

hydrogen increases with increasing fuel economy above 40 mpgge. The relationship between 

fuel economy and city hydrogen use is shown in Figure 6.6.24. As with FCEV penetration, the 

number and scale of the liquefiers affects the levelized cost. At 30 mpgge, two smaller liquefiers 

are necessary and result in higher costs than the single liquefier needed for the higher fuel 

economies does. Because the hydrogen demand is reduced as fuel economies increase, 

liquefaction of reduced amounts of hydrogen results in higher levelized costs. 

Figures 6.6.25 and 6.6.26 show that GHG emissions and petroleum energy use decrease with 

increasing fuel economy, as one might expect. 

Figures 6.6.27, 6.6.28, and 6.6.29 show the effects of forecourt size on levelized cost of 

hydrogen, GHG emissions, and petroleum energy use for the central biomass—liquid truck 

delivery and gaseous dispensing pathway. 
















 
         





	
 
!

"




"








	


	

	


	
109 

Figure 6.6.20. Levelized cost versus city population for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 

Figure 6.6.21. GHG emissions versus city population for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 

	










  	 
  




	

	
	
	







	











     

	












110 

Figure 6.6.22. Petroleum energy versus city population for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

Figure 6.6.23. Levelized cost versus fuel economy for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 





	

	

















     



	
	






	

			





	

	

		




	  		  	










111 

Figure 6.6.24. City hydrogen use versus fuel economy for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

Figure 6.6.25. GHG emissions versus fuel economy for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 

	














    	

	

































  	



 





	





	
	


112 

Figure 6.6.26. Petroleum energy use versus fuel economy for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 

Figure 6.6.27. Levelized cost versus forecourt size for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 



	
	
	
			















  	

	

		

	
			
	

		


	











 
     


	






113 

Figure 6.6.28. GHG emissions versus forecourt size for the central biomass—liquid truck delivery 

and gaseous dispensing pathway 

Figure 6.6.29. Petroleum energy use versus forecourt size for the central biomass—liquid truck 

delivery and gaseous dispensing pathway 






















   	   






	











	







   


	


6.7 Central Biomass—Liquid Truck Delivery and Cryo-Compressed 

Dispensing

Figure 6.7.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing.

(See Appendix G for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway are summarized in Table 6.7.1. 

Net GHG emissions include carbon dioxide uptake occurring during growth of the biomass. As 

noted above, the analysis assumes that 100% of the carbon in the biomass is provided by 

atmospheric carbon dioxide and that land use change is assumed to have neither positive nor 

negative effects on emissions. 

6.7.1 Cost Breakdown

Figure 6.7.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central biomass—liquid truck delivery and cryocompressed dispensing pathway. The financial assumptions used in this analysis are detailed in 

Section 5. 

114 
115 

 of major inputs, assumptions, and outputs by subsystem for the central biomass—liquid truck delivery and cryocompressed dispensing pathway 

Biomass moisture content 25%Woody biomass LHV 16,013,000 Btu / dry ton

235,000 Btu / dry ton Biomass price at H2 production $75 2007 $ / dry ton

Fraction of Woody Biomass 100% Biomass Share of Levelized Cos $1.02 2007$ / kg H2 dispensed

LUC GHG changes 0 g / dry ton

200 Btu / 116000Btu to Pump Average distance from farm to H2 prod. 40 miles WTG CO2 Emissions -26,040 g CO2 eq./ 116000 Btu

600 Btu / 116000Btu to Pump WTG CH4 Emissions 13 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump WTG N2O Emissions 36 g CO2 eq./ 116000 Btu

WTG GHG Emissions -25,990 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 Central plant design capacity 155,200 kg / day Total capital investment $1,300 2007$ / daily kg H2 (effective capacity)1.32 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $0.67 2007$ / kg H2 dispensed

79.3 gal / kg H2 produced Number of production facilities 0.87 Fixed O&M Costs $0.24 2007$ / kg H2 dispensed

Process energy efficiency 46.0% Variable O&M Costs $0.42 2007$ / kg H2 dispensed

81,080,000 2007$ Electricity Mix US Mix Total Levelized Cost $2.35 2007$ / kg H2 dispensed

After-tax IRR 10%

5,400 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 27,800 g CO2 eq./ 116000 Btu9,900 Btu / 116000Btu to Pump Production CH4 Emissions 140 g CO2 eq./ 116000 Btu

3,300 Btu / 116000Btu to Pump Production N2O Emissions 45 g CO2 eq./ 116000 Btu

Production GHG Emissions 28,000 g CO2 eq./ 116000 Btu

8.5 kWh / kg H2 Total capital investment $2,000 2007$ / daily kg delivered

0.02 kWh / kg H3 Levelized Electricity cost $0.59 2007$ / kg H2 delivered

8.5 kWh / kg H4 City Population 1,247,000 people Levelized Diesel cost $0.03 2007$ / kg H2 delivered7.7 gal / 1000 kg H2 Hydrogen Vehicle Penetration 15% Levelized Labor cost $0.09 2007$ / kg H2 delivered

City hydrogen use 121,100 kg / day Levelized Other operating costs $0.24 2007$ / kg H2 delivered

42,361,000 2007$ One-way distance for delivery 98 miles

Terminal Design Capacity 1,124,000 kg H2 Levelized Cost of Delivery $1.82 2007$ / kg H2 delivered

Number of truck-trips required 10,400

52,400 Btu / 116000Btu to Pump Truck hydrogen capacity 4,400 kg / truckload Delivery CO2 Emissions 7,320 g CO2 eq./ 116000 Btu23,400 Btu / 116000Btu to Pump Liquefaction energy efficiency 79.3% Delivery CH4 Emissions 450 g CO2 eq./ 116000 Btu

3,000 Btu / 116000Btu to Pump Hydrogen losses 2.8% Delivery N2O Emissions 30 g CO2 eq./ 116000 Btu

Delivery GHG Emissions 7,800 g CO2 eq./ 116000 BtuHydrogen outlet pressure 12,700 psi

0.49 kWh / kg H2 Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

Total Hydrogen Dispensed 1,000 kg / day Total capital investment $2,120 2007$ / daily kg

$2,100,000 2007$ / station Number of Dispensing Stations 122 Levelized Cost of Capital $0.90 2007$ / kg H2 dispensed

56,147,000 2007$ / all stations Number of Cascade Pumps 1 Energy & Fuel $0.05 2007$ / kg H2 dispensed

Liquid H2 storage capacity per Station 4,600 kg H2 Other O&M Costs $0.61 2007$ / kg H2 dispensedUsable Cascade Storage per Station 0 kg H2 Levelized Cost of Dispensing $3.38 2007$ / kg H2 dispensed

ded in Delivery Section Site storage 390% % of design capacity CSD CO2 Emissions Included in Delivery Section

ded in Delivery Section # of 2-hose Dispensers per Station 2 CSD CH4 Emissions Included in Delivery Section

ded in Delivery Section Hydrogen losses 3.1% CSD N2O Emissions Included in Delivery Section

CSD GHG Emissions Included in Delivery SectionCost Per Mile $0.69 2007$ / mi

3,020 lb Fuel Share $0.12 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / mi

Purchase Year 2015 Financing $0.10 2007$ / miVehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Veh. Cycle CO2 Emissions 1,670 g / gge fuel consumed

12,100 Btu / gge fuel consumed Storage System Cost (assume 700Bar $2,400 2007$ Veh. Cycle CH4 Emissions 170 g / gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle N2O Emissions 6 g / gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g / gge fuel consumed

Outputs

Vehicle

Biomass Production & Delivery

 Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production

Cryo-Compressed Dispensing
Table 6.7.1. WTP and WTW Results for the Central Biomass—Liquid Truck Delivery and CryoCompressed Dispensing Pathway

WTP WTW

Coal input (including upstream)a 58,000 Btu/116,000 Btu 1,210 Btu/mi

Natural gas input (including upstream)a 33,900 Btu/116,000 Btu 710 Btu/mi

Petroleum input (including upstream)a 9,200 Btu/116,000 Btu 190 Btu/mi

Fossil energy input (including upstream)a 374,100 Btu/116,000 Btu 2,110 Btu/mi

WTP CO2 emissionsb 9,000 g/116,000 Btu 190 g/mi

WTP CH4 emissions 24 g/116,000 Btu 1 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 9,800 g CO2-eq./ 

116,000 Btu

200 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $5.73 2007$/kg $0.12 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Figure 6.7.2. Cost analysis inputs and high-level results for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway

Figure 6.7.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.7.2. 

116 
117 

Figure 6.7.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central biomass—liquid truck delivery and cryo-compressed dispensing pathway 

Figure 6.7.4 and Table 6.7.2 show the breakdown of levelized costs for the central biomass—

liquid truck delivery and cryo-compressed dispensing pathway. 

Figure 6.7.4. Breakdown of levelized costs for the central biomass—liquid truck delivery and cryocompressed dispensing pathway 

$2.21 

$3.38 

$0.14 

Biomass Gasification - Delivery of Liquid Hydrogen - 

Cryocompressed Dispensing 

Production 

Delivery 

Losses 
Table 6.7.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.64 $0.62 $0.96 $2.21

 Feed handling and drying $0.11

 Gasification, tar reforming, and quench $0.10

 Compression and sulfur removal $0.09

 SMR, WGS, and PSA $0.18

 Steam system and power generation $0.09

 Cooling water and other utilities $0.02

 Buildings and structures $0.04

Delivery $1.77 $0.94 $0.66 $3.38

 Tractor/trailer $0.18

 Terminal $0.31

 Liquefier $0.58 $0.17 $0.59 $1.33

 Forecourt $0.90 $0.61 $0.05 $1.56

Losses $0.14

Total $2.41 $1.56 $0.96 $0.66 $5.73

6.7.2 Energy Use and Emissions Breakdown

Figures 6.7.5 and 6.7.6 show the WTW energy inputs and losses for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway. 

Figures 6.7.7 and 6.7.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central biomass—liquid truck delivery and cryocompressed dispensing pathway. 

118 
119 

Figure 6.7.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway 

Figure 6.7.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central biomass—liquid truck delivery and cryo-compressed dispensing pathway 

0 

10,000 

20,000 

30,000 

40,000 

50,000 

60,000 

70,000 

80,000 

90,000 

Biomass Production & 

Delivery 

Hydrogen Production Liquefaction & Truck 

Delivery 

Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Biomass Gasification with Liquid H2 Delivery & 

Cryocompressed Dispensing) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
120 

Figure 6.7.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway 

Figure 6.7.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central biomass—liquid truck delivery and cryo-compressed dispensing 

pathway 

-30,000 

-20,000 

-10,000 

0 

10,000 

20,000 

30,000 

40,000 

Biomass Production & 

Delivery 

Hydrogen Production Liquefaction & Truck 

Delivery 

Forecourt Storage & 

Dispensing 

g CO2 eq / GGE 

WTW Emissions (Biomass Gasification with Liquid H2 Delivery & 

Cryocompressed Dispensing) 

CO2 CH4 N2O 
121 

6.7.3 Sensitivities 

6.7.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway. These sensitivities focused primarily on cost 

factors; however, several sensitivities also affect energy use and emissions. Figure 6.7.9 shows 

the effects of several production parameters on the pathway’s levelized cost, and Table 6.7.3 

shows the effects of varying production energy efficiency on WTW energy use and emissions. 

Figure 6.7.9. Production sensitivities for the central biomass—liquid truck delivery and cryocompressed dispensing pathway 

Table 6.7.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway 

44% 

Efficiency 

46% 

Efficiency 

48% 

Efficiency 

WTW GHG emissions (g/mile) 200 200 200 

WTW fossil energy (Btu/mile) 2,100 2,100 2,100 

WTW petroleum energy (Btu/mile) 200 190 190 

WTW total energy (Btu/mile) 8,100 7,800 7,600 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.7.4 shows the 

differences in energy use and GHG emissions between the U.S. average grid mix (which was 

used for all other sensitivities) and a hypothetical green grid mix that is 100% renewable energy 

(solar and wind). 
122 

Table 6.7.4. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Biomass—Liquid Truck Delivery and Cryo-Compressed Dispensing Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 200 150 30 

WTW fossil energy (Btu/mile) 2,100 1,500 300 

WTW petroleum energy (Btu/mile) 190 140 150 

WTW total energy (Btu/mile) 7,800 5,600 6,600 

6.7.3.2 Delivery Sensitivities 

Delivery cost, energy use, and emissions are strongly dependent upon the daily consumption of 

hydrogen within a city and the delivery distance from the central facility to the city gate. 

Sensitivities were run to show some of those effects. Daily consumption was varied by keeping 

the city size constant and adjusting the penetration of hydrogen vehicles from the base case of 

15%. The resulting consumption is shown in Figure 6.7.10. 

Figure 6.7.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway 

As expected, there are economies of scale for higher vehicle penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to the city 

gate is shortened. Figures 6.7.11 and 6.7.12 show those economic effects (the figures show 

identical data but are organized differently). 













          





	



	



	




	


123 

Figure 6.7.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and cryocompressed dispensing pathway 













          


'	#&"$

	
#$

		
 '		!	

	

	

	

	

	

	
124 

Figure 6.7.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass—liquid truck delivery and cryocompressed dispensing pathway 

As Figure 6.7.12 shows, there is a $0.14 increase in levelized cost when the production facility is 

assumed to be 150 miles from the city gate as compared to being at the city gate. There is a much 

larger levelized-cost increase when the distance is assumed to be 1,000 miles because the 

levelized cost of trucking increases with added distance due to additional driver time, additional 

fuel requirements, and an increased number of trucks and trailers required. Figure 6.7.13 shows 

the liquid truck portion of the levelized cost; note that the base case distance is 62 miles and that 

the truck’s levelized cost is $0.18 for all penetration levels at that distance. Because the city size 

is constant and the assumed station size is sufficient to utilize a full truckload at each station, 

each delivery has the same travel distance and takes the same amount of time within the city 

regardless of penetration level; therefore, the levelized cost within the city gate is constant for all 

penetration levels. 



















          


&	"%!#

&	

&				
 	

	

	

	

	
125 

Figure 6.7.13. Truck levelized cost versus distance between production facility and city gate for 

the central biomass—liquid truck delivery and cryo-compressed dispensing pathway 

The most notable feature in Figure 6.7.13 is the insensitivity of transport levelized cost to 

changes in FCEV penetration. The significant drop in the levelized cost of hydrogen as FCEV 

penetration increases to 15% (shown in Figure 6.7.11) is due to the reduced cost of liquefaction, 

which is shown in Figure 6.7.14 (liquefier cost is constant for all distances from the city). Note 

that one liquefier is needed for 5% and 15% penetration, two for 25%, three for 50%, four for 

75%, and five for 100% penetration. The two liquefiers at 25% penetration are smaller than the 

one at 15% penetration, thus their capital cost when normalized to annual throughput is higher. 

The higher capital cost results in higher levelized costs. 

The majority of the liquefaction system’s cost driver is capital (Table 6.7.2 shows that the capital 

accounts for $0.58/kg H2 of the $1.33/kg H2 total liquefaction cost). As shown in Figure 6.7.15, 

capital-cost reduction drives the cost decrease as penetration increases. 















          


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#$

		
 '		!



	

	

	

	

	

	

	
126 

Figure 6.7.14. Liquefaction system levelized cost versus penetration for the central biomass—

liquid truck delivery and cryo-compressed dispensing pathway 

Figure 6.7.15. Liquefaction system capital cost (levelized) versus penetration for the central 

biomass—liquid truck delivery and cryo-compressed dispensing pathway 


































          



	
"%!#

&	

&				
 



	


	

	

	

	


































          



	
		#&"$

'	

'		 		
!



	
		

	

	

	

	
127 

The additional cost variable for the liquefaction system levelized cost is the system efficiency 

because increased efficiency reduces the energy required for liquefaction. Figure 6.7.16 shows 

the effect of penetration (directly affecting liquefaction system size) on efficiency. As in the 

previous figures, smaller liquefaction systems result in lower efficiencies. 

Figure 6.7.16. Liquefaction system efficiency versus penetration for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway 

The effects of penetration and distance between the production facility and the city-gate on 

WTW GHG emissions, WTW petroleum use, and WTW fossil energy use are shown in Figures 

6.7.17, 6.7.18, and 6.7.19, respectively. In each case, the energy use and emissions decrease as 

liquefaction system efficiency increases with penetration and then plateaus as discussed above. 

Energy use and emissions are also reduced when the production facility is closer to the city gate 

because of reduced diesel use for trucking. 

		
	


	

	












	










	





      	 
   

	
	


	

	

128 

Figure 6.7.17. WTW greenhouse gas emissions versus penetration for the central biomass—liquid 

truck delivery and cryo-compressed dispensing pathway 

Figure 6.7.18. WTW petroleum use versus penetration for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway 

















 
         




	



			


	

	


	




	





















 
         


		








		

	

	


	




	
129 

Figure 6.7.19. WTW fossil energy use versus penetration for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway 

The effects of city population on levelized cost of hydrogen, GHG emissions, and petroleum 

energy use are shown in Figures 6.7.20, 6.7.21, and 6.7.22. Levelized hydrogen cost decreases 

slightly with increasing city population. GHG emissions also generally decrease with increasing 

city population, while petroleum energy use increases with increasing city population above a 

population of 5,000. 

Figure 6.7.23 shows the effect of fuel economy on the levelized cost of hydrogen. As with FCEV 

penetration, the number and scale of the liquefiers affects the levelized cost. At 30 mpgge, two 

smaller liquefiers are necessary and result in higher costs than the single liquefier needed for the 

higher fuel economies does. Because the hydrogen demand is reduced as fuel economies 

increase, liquefaction of reduced amounts of hydrogen results in higher levelized costs. The 

relationship between fuel economy and city hydrogen use is shown in Figure 6.7.24. 

Figures 6.7.25 and 6.7.26 show that GHG emissions and petroleum energy use decrease with 

increasing fuel economy, as one might expect. 

Figures 6.7.27, 6.7.28, and 6.7.29 show the effects of forecourt size on levelized cost of 

hydrogen, GHG emissions, and petroleum energy use for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway. 
















 
         





	
 
!

"




"






	


	

	


	




	
130 

Figure 6.7.20. Levelized cost versus city population for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

	










  	 
  




	

	
	
	







	
131 

Figure 6.7.21. GHG emissions versus city population for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

Figure 6.7.22. Petroleum use versus city population for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 













     

	

















	

	

















     



	
	






	
132 

Figure 6.7.23. Levelized cost versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

Figure 6.7.24. City hydrogen use versus fuel economy for the central biomass—liquid truck 

delivery and cryo-compressed dispensing pathway 

			



	

		





	



	  		  	











	














    	

	






133 

Figure 6.7.25. GHG emissions versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

Figure 6.7.26. Petroleum use versus fuel economy for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 



























  	



 





	





	
	





	
	
	
			















  	

	

		

	
			
	
134 

Figure 6.7.27. Levelized cost versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

Figure 6.7.28. GHG emission versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

		














 	  
   	

	






















   	   






	

135 

Figure 6.7.29. Petroleum use versus forecourt size for the central biomass—liquid truck delivery 

and cryo-compressed dispensing pathway 

6.8 Central Natural Gas—Pipeline Delivery 

Figure 6.8.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix H for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central natural gas—

pipeline delivery pathway are summarized in Table 6.8.1. 

6.8.1 Cost Breakdown 

Figure 6.8.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central natural gas—pipeline delivery pathway. The 

financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.8.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.8.2. 

Figure 6.8.4 and Table 6.8.2 show the breakdown of levelized costs for the central natural gas—

pipeline delivery pathway. 



















	

	

	















   


	


Figure 6.8.1. Summary of major inputs, assumptions, and outputs by subsystem for the central natural gas—pipeline delivery pathway

136 

NG Delivery Pressure

NG Quality at Delivery

Outputs

Average of gas companies

Average of gas companies

95.7%

400 g / MMbtu NG

NG Cost in 2015

NG Share of Levelized Cost

$6.09 2007 $ / mmBTU

$1.52 2007$ / kg H2 dispensed

97.2%

30 g / MMbtu NG

 199,400 g / MMbtu NG

600 g CO2 eq./ 116000 Btu

1,260 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

200 Btu / 116000Btu to Pump

125,600 Btu / 116000Btu to Pump

500 Btu / 116000Btu to Pump

NG Recovery Efficiency

NG emitted during recovery

NG processing energy efficiency

NG emitted during processing

NG emitted during transport

NG transport distance 500 miles

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

WTG GHG Emissions

3 g CO2 eq./ 116000 Btu

1,870 g CO2 eq./ 116000 Btu

300 psi

0.1564 MMBtu/kg H2 produced

Hydrogen Output Pressure

Hydrogen Outlet Quality 99.9%

Central plant design capacity 379,400 kg / day $632 2007$ / daily kg H2 (effective capacity)

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.57 kWh / kg H2

3.36 gal / kg H2

1.50 gal / kg H2 90%

0.35

Total Capital Investment $215,844,000 2007$ 71.9%

US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.34 2007$ / kg H2 dispensed

$0.06 2007$ / kg H2 dispensed

$0.08 2007$ / kg H2 dispensed

$2.00 2007$ / kg H2 dispensed

10%

Capacity factor p

necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Assumed Plant Life 40 SMR CO2 Emissions

SMR CH4 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,900 Btu / 116000Btu to Pump

48,800 Btu / 116000Btu to Pump

300 Btu / 116000Btu to Pump SMR N2O Emissions

SMR GHG Emissions

10,200 g CO2 eq./ 116000 Btu

500 g CO2 eq./ 116000 Btu

12 g CO2 eq./ 116000 Btu

10,700 g CO2 eq./ 116000 Btu

Electricity consumption for compressor Total capital investment $3,340 2007$ / daily kg H2 (effective capacity)

Electricity consumption for geo storage

Total electricity consumption

0.56 kWh / kg H2 produced

0.01 kWh / kg H2 produced

0.57 kWh / kg H2 produced 1,247,000 people

15%

121,100 kg / day

Total Capital Investment $404,341,000 2007$ 62 miles

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Delivery

$1.71 2007$ / kg H2 dispensed

$0.04 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.15 2007$ / kg H2 dispensed

1,324,700 kg H2

3

1.5 miles / line

122

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,800 Btu / 116000Btu to Pump

2,200 Btu / 116000Btu to Pump

100 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Distance from City to Production Facility

Geologic storage capacity

Number of trunk pipelines

Service-line length

Number of service lines

Hydrogen losses 0.80%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

390 g CO2 eq./ 116000 Btu

24 g CO2 eq./ 116000 Btu

2 g CO2 eq./ 116000 Btu

420 g CO2 eq./ 116000 Btu

Electricity consumption 4.4 kWh / kg H2 produced

Hydrogen outlet pressure

Basis -- Hydrogen Quantity

12,700 psi

116,000 Btu (116,000 Btu/gal non-oxygenated 

1,000 kg / day

conventional unleaded gasoline)

Total Capital Investment per Station $2,650 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$2,629,000 2007$ / station

$320,679,000 2007$ / all stations 122

5

Inlet pressure of hydrogen at stations 300 psi 370 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

130 kg H2 Levelized Cost of Dispensing

42% % of design capacity

$1.08 2007$ / kg H2 dispensed

$0.41 2007$ / kg H2 dispensed

$0.43 2007$ / kg H2 dispensed

$1.93 2007$ / kg H2 dispensed

3,370 g CO2 eq./ 116000 Btu

2

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

24,400 Btu / 116000Btu to Pump

10,800 Btu / 116000Btu to Pump

900 Btu / 116000Btu to Pump

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station

Site storage

# 2-hose Dispensers per Station

Hydrogen Losses 0.50%

CSD CO2 Emissions

CSD CH4 Emissions

CSD N2O Emissions

CSD GHG Emissions

210 g CO2 eq./ 116000 Btu

14 g CO2 eq./ 116000 Btu

3,590 g CO2 eq./ 116000 Btu

Cost Per Mile

3,020 lb

70 kW 48.0 mi / gge

Vehicle Mass

Fuel cell size

Hybridization battery (peak power) 30 kW 15,000 mi / yr

160,000 mi

2015

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing

$0.69 2007$ / mi

$0.13 2007$ / mi

$0.07 2007$ / mi

$0.12 2007$ / mi

$0.27 2007$ / mi

$0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Veh. Cycle CO2 Emissions

Veh. Cycle CH4 Emissions

Veh. Cycle N2O Emissions

Veh. Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

170 g CO2 eq / gge fuel consumed

6 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Inputs

Vehicle

NG Recovery, Processing, & Transport

Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Dispensing
Table 6.8.1. WTP and WTW Results for the Central Natural Gas—Pipeline Delivery Pathway

WTP WTW

Coal input (including upstream)a 30,400 Btu/116,000 Btu 630 Btu/mi

Natural gas input (including upstream)a 187,400 Btu/116,000 Btu 3,910 Btu/mi

Petroleum input (including upstream)a 1,800 Btu/116,000 Btu 40 Btu/mi

Fossil energy input (including upstream)a 219,600 Btu/116,000 Btu 4,580 Btu/mi

WTP CO2 emissionsb 14,600 g/116,000 Btu 300 g/mi

WTP CH4 emissions 80 g/116,000 Btu 2 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 16,600 g CO2-eq./ 

116,000 Btu

350 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $6.07 2007$/kg $0.13 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Figure 6.8.2. Cost analysis inputs and high-level results for the central natural gas—pipeline 

delivery pathway

137 
138 

Figure 6.8.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen from the central natural gas—pipeline delivery pathway 

Figure 6.8.4. Breakdown of levelized costs for the central natural gas—pipeline delivery pathway 

$1.97 

$4.08 

$0.03 

Central Natural Gas Reforming - Delivery of Gaseous 

Hydrogen in Pipelines 

Production 

Delivery 

Losses 
Table 6.8.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost for the 

Central Natural Gas—Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.33 $0.14 $1.50 $1.97

 Process plant equipment $0.24

 Balance of plant and offsites $0.09

 SCR NOx control on stack $0.00

Delivery $2.80 $0.83 $0.45 $4.08

 Central compressor $0.12

 Transmission pipeline $0.30

 Distribution pipeline $1.64

 Geologic storage $0.09

 Gaseous refueling station $1.08 $0.43 $0.41 $1.93

 Refrigeration $0.12

 Compressor $0.41

 Cascade storage $0.12

 Low pressure storage $0.30

 Dispenser and accessories $0.13

Losses $0.03

Total $3.13 $0.97 $1.50 $0.45 $6.08

6.8.2 Energy Use and Emissions Breakdown

Figures 6.8.5 and 6.8.6 show the WTW energy inputs and losses for the central natural gas—

pipeline delivery pathway. 

Figures 6.8.7 and 6.8.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central natural gas—pipeline delivery pathway. 

139 
140 

Figure 6.8.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

natural gas—pipeline delivery pathway 

Figure 6.8.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central natural gas—pipeline delivery pathway 

0 

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

140,000 

NG Production & 

Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Natural Gas SMR with Pipeline H2 Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
141 

Figure 6.8.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

natural gas—pipeline delivery pathway 

Figure 6.8.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central natural gas—pipeline delivery pathway 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

NG Production & 

Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

Dispensing 

g CO2 eq/GGE 

WTW Emissions (Natural Gas SMR with Pipeline H2 Delivery) 

N2O CH4 CO2 
142 

6.8.3 Sensitivities 

6.8.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central natural gas—pipeline 

delivery pathway. These sensitivities focused primarily on cost factors; however, several 

sensitivities also affect energy use and emissions. Figure 6.8.9 shows the effects of several 

production parameters on the pathway’s levelized cost. 

Figure 6.8.9. Production sensitivities for central natural gas–pipeline delivery pathway 

The assumed electrical grid mix also affects the energy use and emissions. Table 6.8.3 shows the 

differences in energy use and GHG emissions between the U.S. average grid mix (which was 

used for all other sensitivities) and a hypothetical green grid mix that is 100% renewable energy 

(solar and wind). 

Table 6.8.3. The Effects of Fuel Economy and Grid Mix on Use of Primary Energy and Emissions 

from the Central Natural Gas—Pipeline Delivery Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 350 240 250 

WTW fossil energy (Btu/mile) 4,600 3,200 3,600 

WTW petroleum energy (Btu/mile) 40 30 10 

WTW total energy (Btu/mile) 4,800 3,400 4,100 

6.8.3.2 Delivery Sensitivities 

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 6.4.3. 

The effects of the sensitivities will be the same for all pipeline delivery scenarios. 
6.9 Central Wind Electricity—Pipeline Delivery

Figure 6.9.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix I for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central wind 

electricity—pipeline delivery pathway are summarized in Table 6.9.1. 

6.9.1 Cost Breakdown

Figure 6.9.2 shows the feedstock and energy price inputs and the resulting hydrogen production, 

delivery, and distribution costs for the central wind electricity—pipeline delivery pathway. The 

financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.9.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.9.2. 

Figure 6.9.4 and Table 6.9.2 show the breakdown of levelized costs for the central wind 

electricity—pipeline delivery pathway. 

143 
Figure 6.9.1. Summary of major inputs, assumptions, and outputs by subsystem for the central wind electricity—pipeline delivery pathway

144 

NG Delivery Pressure

NG Quality at Delivery

Outputs

Average of gas companies

Average of gas companies

95.7%

400 g / MMbtu NG

NG Cost in 2015

NG Share of Levelized Cost

$6.09 2007 $ / mmBTU

$1.52 2007$ / kg H2 dispensed

97.2%

30 g / MMbtu NG

 199,400 g / MMbtu NG

600 g CO2 eq./ 116000 Btu

1,260 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

200 Btu / 116000Btu to Pump

125,600 Btu / 116000Btu to Pump

500 Btu / 116000Btu to Pump

NG Recovery Efficiency

NG emitted during recovery

NG processing energy efficiency

NG emitted during processing

NG emitted during transport

NG transport distance 500 miles

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

WTG GHG Emissions

3 g CO2 eq./ 116000 Btu

1,870 g CO2 eq./ 116000 Btu

300 psi

0.1564 MMBtu/kg H2 produced

Hydrogen Output Pressure

Hydrogen Outlet Quality 99.9%

Central plant design capacity 379,400 kg / day $632 2007$ / daily kg H2 (effective capacity)

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.57 kWh / kg H2

3.36 gal / kg H2

1.50 gal / kg H2 90%

0.35

Total Capital Investment $215,844,000 2007$ 71.9%

US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$0.34 2007$ / kg H2 dispensed

$0.06 2007$ / kg H2 dispensed

$0.08 2007$ / kg H2 dispensed

$2.00 2007$ / kg H2 dispensed

10%

Capacity factor p

necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Assumed Plant Life 40 SMR CO2 Emissions

SMR CH4 Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,900 Btu / 116000Btu to Pump

48,800 Btu / 116000Btu to Pump

300 Btu / 116000Btu to Pump SMR N2O Emissions

SMR GHG Emissions

10,200 g CO2 eq./ 116000 Btu

500 g CO2 eq./ 116000 Btu

12 g CO2 eq./ 116000 Btu

10,700 g CO2 eq./ 116000 Btu

Electricity consumption for compressor Total capital investment $3,340 2007$ / daily kg H2 (effective capacity)

Electricity consumption for geo storage

Total electricity consumption

0.56 kWh / kg H2 produced

0.01 kWh / kg H2 produced

0.57 kWh / kg H2 produced 1,247,000 people

15%

121,100 kg / day

Total Capital Investment $404,341,000 2007$ 62 miles

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Delivery

$1.71 2007$ / kg H2 dispensed

$0.04 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.15 2007$ / kg H2 dispensed

1,324,700 kg H2

3

1.5 miles / line

122

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,800 Btu / 116000Btu to Pump

2,200 Btu / 116000Btu to Pump

100 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Distance from City to Production Facility

Geologic storage capacity

Number of trunk pipelines

Service-line length

Number of service lines

Hydrogen losses 0.80%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

390 g CO2 eq./ 116000 Btu

24 g CO2 eq./ 116000 Btu

2 g CO2 eq./ 116000 Btu

420 g CO2 eq./ 116000 Btu

Electricity consumption 4.4 kWh / kg H2 produced

Hydrogen outlet pressure

Basis -- Hydrogen Quantity

12,700 psi

116,000 Btu (116,000 Btu/gal non-oxygenated 

1,000 kg / day

conventional unleaded gasoline)

Total Capital Investment per Station $2,650 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$2,629,000 2007$ / station

$320,679,000 2007$ / all stations 122

5

Inlet pressure of hydrogen at stations 300 psi 370 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

130 kg H2 Levelized Cost of Dispensing

42% % of design capacity

$1.08 2007$ / kg H2 dispensed

$0.41 2007$ / kg H2 dispensed

$0.43 2007$ / kg H2 dispensed

$1.93 2007$ / kg H2 dispensed

3,370 g CO2 eq./ 116000 Btu

2

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

24,400 Btu / 116000Btu to Pump

10,800 Btu / 116000Btu to Pump

900 Btu / 116000Btu to Pump

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station

Site storage

# 2-hose Dispensers per Station

Hydrogen Losses 0.50%

CSD CO2 Emissions

CSD CH4 Emissions

CSD N2O Emissions

CSD GHG Emissions

210 g CO2 eq./ 116000 Btu

14 g CO2 eq./ 116000 Btu

3,590 g CO2 eq./ 116000 Btu

Cost Per Mile

3,020 lb

70 kW 48.0 mi / gge

Vehicle Mass

Fuel cell size

Hybridization battery (peak power) 30 kW 15,000 mi / yr

160,000 mi

2015

 Fuel Share

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing

$0.69 2007$ / mi

$0.13 2007$ / mi

$0.07 2007$ / mi

$0.12 2007$ / mi

$0.27 2007$ / mi

$0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Veh. Cycle CO2 Emissions

Veh. Cycle CH4 Emissions

Veh. Cycle N2O Emissions

Veh. Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

170 g CO2 eq / gge fuel consumed

6 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Inputs

Vehicle

NG Recovery, Processing, & Transport

Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Dispensing
Table 6.9.1. WTP and WTW Results for the Central Wind Electricity—Pipeline Delivery Pathway

WTP WTW

Coal input (including upstream)a 27,300 Btu/116,000 Btu 570 Btu/mi

Natural gas input (including upstream)a 12,100 Btu/116,000 Btu 250 Btu/mi

Petroleum input (including upstream)a 1,000 Btu/116,000 Btu 20 Btu/mi

Fossil energy input (including upstream)a 40,400 Btu/116,000 Btu 840 Btu/mi

WTP CO2 emissionsb 3,800 g/116,000 Btu 80 g/mi

WTP CH4 emissions 10 g/116,000 Btu 0 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 4,000 g CO2-eq./ 

116,000 Btu

80 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen ($/kg) $8.41 2007$/kg $0.18 2007$/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Electricity @ Total capital investment $1,320 2007$ / daily kg H2 (effective capacity)

$0.0574/kWh Levelized Cost of Capital $0.67 2007$ / kg H2 dispensed

Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Variable O&M Costs $0.06 2007$ / kg H2 dispensed

Total Levelized Cost $4.33 2007$ / kg H2 dispensed

Total capital investment $3,339 2007$ / daily kg H2 (effective capacity)

Electricity for compressor @ $0.0587/kWh Levelized Cost of Delivery $1.71 2007$ / kg H2 dispensed

Energy & Fuel $0.04 2007$ / kg H2 dispensed

Electricity for geologic storage Other O&M Costs $0.40 2007$ / kg H2 dispensed

@ $0.0634/kWh Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Total capital investment $2,648 2007$ / daily kg H2 (effective capacity)

Electricity @ $0.0955/kWh Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Energy & Fuel $0.41 2007$ / kg H2 dispensed

Other O&M Costs $0.43 2007$ / kg H2 dispensed

Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Compressor

Geologic Storage

Pipeline

Electricity Generation, Scrubber

Transmission & Distribution

Compression &

Dispensing

Hydrogen @ $8.41/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Figure 6.9.2. Cost analysis inputs and high-level results for the central wind electricity—pipeline 

delivery pathway

145 
146 

Figure 6.9.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen from the central wind electricity—pipeline delivery pathway 

$4.27 $4.08 

$0.05 

Wind Electrolysis - Delivery of Gaseous 

Hydrogen in Pipelines 

Delivery Production 

Losses 
147 

Figure 6.9.4. Breakdown of levelized costs for the central wind electricity—pipeline delivery 

pathway 

Fuel costs are not the only costs of ownership of a vehicle. Vehicle ownership costs including 

fuel, maintenance, tires, repairs, insurance, registration, and vehicle depreciation and financing 

are shown in figure 6.9.5. Note that the costs in the figure are not discounted (i.e., a discount rate 

was not used to reduce future costs to their net present values). That methodology has the same 

effect as a discount rate of 0%. 
148 

Table 6.9.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost from 

the Central Wind Electricity—Pipeline Delivery Pathway 

Cost Component Capital 

Other 

O&M Feedstock 

Energy/ 

Fuel Total 

Production $0.66 $0.29 $3.33 $4.27 

 Electrolyzer stack $0.43 

 Hydrogen gas management system $0.10 

 Electrolyte management system $0.06 

 Power electronics $0.06 

 Mechanical balance of plant $0.01 

Delivery $2.80 $0.83 $0.45 $4.08 

 Central compressor $0.12 

 Transmission pipeline $0.30 

 Distribution pipeline $1.64 

 Geologic storage $0.09 

 Gaseous refueling station $1.08 $0.43 $0.41 $1.93 

 Compressor $0.46 

 Cascade storage $0.14 

 Low Pressure storage $0.34 

 Dispenser and accessories $0.14 

Losses $0.05 

Total $3.46 $1.12 $3.33 $0.45 $8.41

Figure 6.9.5. Breakdown of vehicle ownership costs for the central wind electricity—pipeline 

delivery pathway 

6.9.2 Energy Use and Emissions Breakdown 

Figures 6.9.6 and 6.9.7 show the WTW energy inputs and losses for the central wind 

electricity—pipeline delivery pathway. 

#%&+

#%%)

#%%&

#%%' #%%,

#%%(

#%'*

#%&%


	
	



#
	
 



	





	


!

	

	

149 

Figures 6.9.8 and 6.9.9 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central wind electricity—pipeline delivery pathway. 

Figure 6.9.6. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

wind electricity—pipeline delivery pathway 

Figure 6.9.7. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central wind electricity—pipeline delivery pathway 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

40,000 

Electricity Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

Dispensing 

Btu/GGE 

WTW Energy Input (Wind Electrolysis with Pipeline H2 Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
150 

Figure 6.9.8. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

wind electricity—pipeline delivery pathway 

Figure 6.9.9. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central wind electricity—pipeline delivery pathway 

Figures 6.9.10 and 6.9.11 show the energy inputs and emissions, respectively, for the vehicle 

cycles in addition to those for the fuel production cycle. The fuel production cycle values are 

consistent with those reported in Figures 6.9.7 and 6.9.9. 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

Electricity Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

Dispensing 

g CO2 eq/GGE 

WTW Emissions (Wind Electrolysis with Pipeline H2 Delivery) 

CO2 CH4 N2O 
151 

Figure 6.9.10. Life-cycle petroleum, natural gas, and coal inputs for both the central wind 

electricity—pipeline delivery pathway and the vehicle cycle 

Figure 6.9.11. Life-cycle CO2, CH4, and N2O emissions for both the central wind electricity—

pipeline delivery pathway and the vehicle cycle 

6.9.3 Sensitivities 

6.9.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central wind electricity—pipeline 

delivery pathway. These sensitivities focused primarily on cost factors. Figure 6.9.12 shows the 

effects of several production parameters on the pathway’s levelized cost. 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

30,000 

35,000 

40,000 

Electricity 

Production & 

Delivery 

Hydrogen 

Production 

Pipeline Transport Forecourt Storage & 

Dispensing 

Vehicle Cycle 

Btu/GGE 

WTW Energy Input Including Vehicle Cycle (Wind Electrolysis w/ Pipeline Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

Electricity Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage & 

Dispensing 

Vehicle Cycle 

g CO2 eq/GGE 

WTW Emissions Including Vehicle Cycle (Wind Electrolysis with Pipeline H2 Delivery) 

CO2 CH4 N2O 
152 

Note that the electricity cost is the sensitivity with the greatest potential effect on the levelized 

cost. The baseline electricity cost is the industrial electricity price and may be too low for wind 

electricity. 

Effects of the sensitivities on WTW energy use and emissions are not shown because, due to the 

assumption that the electricity feedstock is wind-generated, the production fossil energy use and 

emissions are zero at all efficiencies. 

Figure 6.9.12. Production sensitivities for the central wind electricity—pipeline delivery pathway 

6.9.3.2 Delivery Sensitivities 

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 6.4.3. 

The effects of the sensitivities will be the same for all pipeline delivery scenarios. 

6.10 Central Coal with Carbon Capture and Storage—Pipeline Delivery 

Figure 6.10.1 shows the major inputs, assumptions, and outputs for each of the subsystems 

considered in the well-to-tank analysis, including feedstock supply and hydrogen dispensing. 

(See Appendix J for more details on this pathway.) 

The WTP and WTW cost of hydrogen, energy use, and emissions for the central coal with 

CCS—pipeline delivery pathway are summarized in Table 6.10.1. 

6.10.1 Cost Breakdown 

Figure 6.10.2 shows the feedstock and energy price inputs and the resulting hydrogen 

production, delivery, and distribution costs for the central coal with CCS—pipeline delivery 

pathway. The financial assumptions used in this analysis are detailed in Section 5. 

Figure 6.10.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 6.10.2. 
Figure 6.10.4 and Table 6.10.2 show the breakdown of levelized costs for the central coal with 

CCS—pipeline delivery pathway. 

153 
Figure 6.10.1. Summary of major inputs, assumptions, and outputs by subsystem for the central coal with CCS—pipeline delivery pathway

154 

Coal price at H2 production

Coal Share of Levelized Cost

$34 2007 $ / ton

$0.30 2007$ / kg H2 dispensed

Energy Recovery 99.3%

WTG CO2 Emissions

WTG CH4 Emissions

WTG N2O Emissions

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

116,400 Btu / 116000Btu to Pump

200 Btu / 116000Btu to Pump

700 Btu / 116000Btu to Pump Average distance from coal mine to H2 prod. 65 miles WTG GHG Emissions

110 g CO2 eq./ 116000 Btu

430 g CO2 eq./ 116000 Btu

1 g CO2 eq./ 116000 Btu

540 g CO2 eq./ 116000 Btu

300 psi

7.8 kg (dry) / kg H2 produced

Hydrogen Output Pressure

Hydrogen Outlet Quality 99.9%

307,700 kg / day $2,500 2005$ / daily kg H2 (effective capacity)

90%

Coal consumption

Natural gas consumption

Electricity consumption

Process Water Consumption

Cooling Water Consumption

0.0 MMBtu/kg H2 produced

1.72 kWh / kg H2

2.91 gal / kg H2 produced

0.00 gal / kg H2 produced 0.44

56.8%

Total Capital Investment $691,378,000 2005$ US Mix

Total capital investment

Levelized Cost of Capital

Fixed O&M Costs

Variable O&M Costs

Total Levelized Cost

$1.29 2005$ / kg H2 dispensed

$0.30 2005$ / kg H2 dispensed

$0.18 2005$ / kg H2 dispensed

$2.06 2005$ / kg H2 dispensed

10%

Coal Input (including upstream) 40

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

99,400 Btu / 116000Btu to Pump

7,200 Btu / 116000Btu to Pump

1,100 Btu / 116000Btu to Pump

Central plant design capacity

Capacity factor

Number of production facilities necessary

Process energy efficiency

Electricity Mix

After-tax IRR

Assumed Plant Life

CO2 Captured for Sequestration

CO2 Captured for Sequestration

90%

4,925,000 kg CO2 / day

Production CO2 Emissions

Production CH4 Emissions

ProductionN2O Emissions

Production GHG Emissions

4,510 g CO2 eq./ 116000 Btu

440 g CO2 eq./ 116000 Btu

9 g CO2 eq./ 116000 Btu

4,960 g CO2 eq./ 116000 Btu

Total capital investment $3,340 2007$ / daily kg dispensed

1,247,000 people

Electricity consumption for compressor

Electricity consumption for geo storage

Total electricity consumption

0.56 kWh / kg H2 dispensed

0.01 kWh / kg H2 dispensed

0.57 kWh / kg H2 dispensed 15%

121,100 kg / day

Total Capital Investment $404,341,000 2007$ 62 miles

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Delivery

$1.71 2007$ / kg H2 dispensed

$0.04 2007$ / kg H2 dispensed

$0.40 2007$ / kg H2 dispensed

$2.15 2007$ / kg H2 dispensed

1,325,000 kg H2

3

1.5 miles / line

122

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

3,700 Btu / 116000Btu to Pump

1,300 Btu / 116000Btu to Pump

100 Btu / 116000Btu to Pump

City Population

Hydrogen Vehicle Penetration

City hydrogen use

Distance from City to Production Facility

Geologic storage capacity

Number of trunk pipelines

Service-line length

Number of service lines

Hydrogen losses 0.76%

Delivery CO2 Emissions

Delivery CH4 Emissions

Delivery N2O Emissions

Delivery GHG Emissions

390 g CO2 eq./ 116000 Btu

24 g CO2 eq./ 116000 Btu

2 g CO2 eq./ 116000 Btu

420 g CO2 eq./ 116000 Btu

12,700 psi

Electricity consumption 4.4 kWh / kg H2

Hydrogen outlet pressure

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

1,000 kg/day

conventional unleaded gasoline)

Total Capital Investment per Station $2,650 2007$ / daily kg H2 (effective capacity)

Total Capital Investment

$2,629,000 2007$ / station

$320,679,000 2007$ / all stations 122

5

Inlet pressure of hydrogen at stations 300 psi 370 kg H2

Average Dispensing Rate per Station

Number of Dispensing Stations

Number of Compression Steps

Usable Low Pressure Storage per Station

Usable Cascade Storage per Station 130 kg H2

Total capital investment

Levelized Cost of Capital

Energy & Fuel

Other O&M Costs

Levelized Cost of Dispensing

$1.08 2007$ / kg H2 dispensed

$0.41 2007$ / kg H2 dispensed

$0.43 2007$ / kg H2 dispensed

$1.93 2007$ / kg H2 dispensed

42% % of design capacity CSD CO2 Emissions 3,370 g CO2 eq./ 116000 Btu

2 CSD CH4 Emissions 210 g CO2 eq./ 116000 Btu

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

24,400 Btu / 116000Btu to Pump

10,800 Btu / 116000Btu to Pump

900 Btu / 116000Btu to Pump

Site storage

# of 2-hose Dispensers per Station

Hydrogen Losses 0.50% CSD N2O Emissions

CSD GHG Emissions

Cost Per Mile

14 g CO2 eq./ 116000 Btu

3,590 g CO2 eq./ 116000 Btu

$0.69 2007$ / mi

3,020 lb Fuel Share $0.13 2007$ / mi

70 kW 48.0 mi / gge $0.07 2007$ / mi

Vehicle Mass

Fuel cell size

Size of hybridization battery 30 kW 15,000 mi / yr $0.12 2007$ / mi

160,000 mi $0.27 2007$ / mi

2015

 Maintenance, Tires, Repairs

 Insurance & Registration

 Depreciation

 Financing $0.10 2007$ / mi

$33,700 2007$

$4,500 2007$

$2,400 2007$

Coal Input (including upstream)

Natural Gas Input (including upstream)

Petroleum Input (including upstream)

2,300 Btu / gge fuel consumed

12,100 Btu / gge fuel consumed

6,900 Btu / gge fuel consumed

Fuel Economy

Vehicle Miles Traveled

Vehicle Lifetime

Purchase Year

Vehicle Purchase Cost

Fuel Cell System Cost

Hydrogen Storage System Cost

Tax Credit $0 2007$

Vehicle Cycle CO2 Emissions

Vehicle Cycle CH4 Emissions

Vehicle Cycle N2O Emissions

Vehicle Cycle GHG Emissions

1,670 g CO2 eq / gge fuel consumed

170 g CO2 eq / gge fuel consumed

6 g CO2 eq / gge fuel consumed

1,850 g CO2 eq / gge fuel consumed

Inputs Outputs

Vehicle

Coal Production & Delivery

Assumptions

Pipelines for Delivery

Hydrogen Production & Carbon Capture and Sequestration (CCS)

Forecourt Dispensing
Table 6.10.1. WTP and WTW Results for the Central Coal with CCS—Pipeline Delivery Pathway

WTP WTW

Coal input (including upstream)a 128,000 Btu/116,000 Btu 5,100 Btu/mi

Natural gas input (including upstream)a 19,500 Btu/116,000 Btu 410 Btu/mi

Petroleum input (including upstream)a 2,800 Btu/116,000 Btu 60 Btu/mi

Fossil energy input (including upstream)a 150,300 Btu/116,000 Btu 5,560 Btu/mi

WTP CO2 emissionsb 8,400 g/116,000 Btu 180 g/mi

WTP CH4 emissions 40 g/116,000 Btu 1 g/mi

WTP N2O emissions 0 g/116,000 Btu 0 g/mi

WTP GHG emissions 9,500 g CO2-eq./ 

116,000 Btu

200 g/mi

Cost per kg Cost per mile

Levelized cost of hydrogen $6.14 2007 $/kg $0.13 2007 $/mi a Coal, natural gas, and petroleum inputs include those used directly in the hydrogen production and delivery 

pathway as feedstocks and fuels; those used to produce electricity and other materials used in the pathway; and 

those used upstream of the pathway to recover, refine, and deliver the feedstock.

b Includes the carbon content of CO, CH4, and volatile organic compound emissions that decompose in the 

atmosphere to CO2. 

Figure 6.10.2. Cost analysis inputs and high-level results for the central coal with CCS—pipeline 

delivery pathway

155 
156 

Figure 6.10.3. Contribution of hydrogen production, delivery, and losses to the levelized cost of 

hydrogen for the central coal with CCS—pipeline delivery pathway 

Figure 6.10.4. Breakdown of levelized costs for the central coal with CCS—pipeline delivery 

pathway 

$2.04 

$4.08 

$0.03 

Coal Gasification with CCS - Delivery of Gaseous 

Hydrogen in Pipelines 

Production 

Delivery 

Losses 
Table 6.10.2. Contribution of Production and Delivery Processes to Levelized Hydrogen Cost from 

the Central Coal with CCS—Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $1.27 $0.48 $0.29 $2.04

 Coal handling prep and feed $0.10

 Feedwater and misc. BOP systems $0.02

 Gasifier and accessories $0.23

 Air separation unit $0.25

 Hydrogen separation and gas cleanup $0.34

 Heat-recovery steam generator ducting 

and stack $0.06

 Steam turbine generator $0.04

 Cooling water system $0.02

 Ash handling system $0.03

 Accessory electric plant $0.04

 Instrumentation and control $0.03

 Buildings and structures $0.02

 ZnO polisher and CO2 comp. $0.08

Delivery $2.80 $0.83 $0.45 $4.08

 Central compressor $0.12

 Transmission pipeline $0.30

 Distribution pipeline $1.64

 Geologic storage $0.09

 Gaseous refueling station $1.08 $0.43 $0.41 $1.93

 Refrigeration $0.12

 Compressor $0.41

 Cascade storage $0.12

 Low pressure storage $0.30

 Dispenser and accessories $0.13

Losses $0.03

Total $4.07 $1.31 $0.29 $0.45 $6.14

6.10.2 Energy Use and Emissions Breakdown

Figures 6.10.5 and 6.10.6 show the WTW energy inputs and losses for the central coal with 

CCS—pipeline delivery pathway. The WTW energy inputs to coal mining and delivery include 

those necessary to produce 116,000 Btu of coal for gasification. Additional WTW energy inputs 

for coal needed for heating, electricity, and process inefficiency are reported as inputs to 

hydrogen production. 

Figures 6.10.7 and 6.10.8 show the WTW emissions resulting from the delivery of 116,000 Btu 

hydrogen to a vehicle fuel tank using the central coal with CCS—pipeline delivery pathway. 

157 
158 

Figure 6.10.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using the central 

coal with CCS—pipeline delivery pathway 

Figure 6.10.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen using 

the central coal with CCS—pipeline delivery pathway 

0 

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

Coal Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage 

& Dispensing 

Btu/GGE 

WTW Energy Input (Coal Gasification with CCS & Pipeline H2 Delivery) 

Petroleum Input (including upstream) 

Natural Gas Input (including upstream) 

Coal Energy Input (including upstream) 
159 

Figure 6.10.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using the central 

coal with CCS—pipeline delivery pathway 

Figure 6.10.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu hydrogen 

to a vehicle using the central coal with CCS—pipeline delivery pathway 

6.10.3 Sensitivities 

6.10.3.1 Production Sensitivities 

Several sensitivities were run on the production portion of the central coal with CCS—pipeline 

delivery pathway. These sensitivities focused primarily on cost factors; however, several 

sensitivities also affect energy use and emissions. Figure 6.10.9 shows the effects of several 

production parameters on the pathway’s levelized cost, and Table 6.10.3 shows the effect of 

varying production efficiency on the WTW results. 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

6,000 

Coal Production 

& Delivery 

Hydrogen Production Pipeline Transport Forecourt Storage 

& Dispensing 

g CO2 eq / GGE 

WTW Emissions (Coal Gasification with CCS & Pipeline H2 Delivery) 

CO2 CH4 N2O 
160 

Figure 6.10.9. Production sensitivities for the central coal with CCS—pipeline delivery pathway 

Table 6.10.3. The Effects of Production Energy Efficiency on Primary Energy Use and Emissions 

from the Central Coal with CCS—Pipeline Delivery Pathway 

48% 

Efficiency 

57% 

Efficiency 

64% 

Efficiency 

WTW GHG emissions (g/mile) 220 200 190 

WTW fossil energy (Btu/mile) 6,500 5,600 5,100 

WTW petroleum energy (Btu/mile) 70 60 60 

WTW total energy (Btu/mile) 6,700 5,800 5,300 

The assumed electrical grid mix also affects the energy use and emissions because grid 

electricity is needed for delivery and distribution. Electricity for the production facility is 

generated internally and can be considered a parasitic loss. Table 6.10.4 shows the differences in 

energy use and GHG emissions between the U.S. average grid mix (which was used for all other 

sensitivities) and a hypothetical green grid mix that is 100% renewable energy (solar and wind). 

Table 6.10.4. The Effects of Grid Mix on Use of Primary Energy and Emissions from the Central 

Coal with CCS—Pipeline Delivery Pathway 

U.S. Average 

Grid Mix 

(48 mpgge) 

U.S. Average 

Grid Mix 

(68 mpgge) 

“Green” Grid 

Mix 

(48 mpgge) 

WTW GHG emissions (g/mile) 200 140 70 

WTW fossil energy (Btu/mile) 5,600 3,900 4,200 

WTW petroleum energy (Btu/mile) 60 40 20 

WTW total energy (Btu/mile) 5,800 4,100 4,900 

6.10.3.2 Delivery Sensitivities 

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 6.4.3. 

The effects of the sensitivities will be the same for all pipeline delivery scenarios. 
7 Pathway Results Comparison

In this section, results from the individual pathways are compared. Each pathway’s current 

estimated levelized hydrogen cost, WTW petroleum use, and WTW GHG emissions are shown 

in comparison to the other pathways. Key parameters are shown in Table 7.0.1. 

Table 7.0.1. Key Analysis Parameters

Parameter Value and Section with Description

Technology status Current technology (Section 1.2). Technology is described in Sections

2.0 and 3.0, and parameters are shown in the appendices.

City size 553 mi2 and 1,247,000 people (equivalent to Indianapolis, IN) (Section 

1.2)

Market penetration 15% of hydrogen vehicles (Section 1.2)

Fuel cell vehicle fuel 

economy

Base case of 48 mpgge analyzed, with a sensitivity case of 68 mpgge 

Analysis boundaries Includes feedstock recovery, transportation, and storage; fuel 

production, transportation, storage, and distribution; and vehicle 

operation (Section 1.3)

Monetary value 2007 dollars—except coal with CCS production option, which is in 2005 

dollars (Section 5.0)

Equity financing 100% (Section 5.0)

After tax internal rate of 

return

10% (Section 5.0)

Effective total tax rate 38.9%

Carbon capture efficiency in 

coal with CCS case

90% (Section 6.10)

Figure 7.0.1 shows the levelized cost of hydrogen for all 10 hydrogen pathways with the 

parameters described in Section 6.0, based on an assumed FCEV fuel economy of 48 mpgge. 

(More details on the 10 hydrogen pathways analyzed can be found in Appendices A–J.) Some of 

the most important pathway parameters are shown in Table 7.0.1, and additional parameters are 

in Sections 1–6. Sensitivities on parameters in each hydrogen pathway are reported in Section 6. 

The base case analysis of the hydrogen pathways assumes a 48 mpgge fuel economy. A 

sensitivity analysis using a fuel economy of 68 mpgge was also conducted. Figure 7.0.2 shows 

the levelized hydrogen cost results for all 10 pathways for both the 48 mpgge and 68 mpgge fuel 

economies. 

161 
162 

Figure 7.0.1. Levelized cost of hydrogen for all pathways, based on 48 mpgge fuel economy 

Figure 7.0.2. Levelized cost of hydrogen for all pathways for both 48 and 68 mpgge fuel economy 

$0.00 

$1.00 

$2.00 

$3.00 

$4.00 

$5.00 

$6.00 

$7.00 

$8.00 

$9.00 

$10.00 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Levelized Cost($/kg) 

CSD Share ($/GGE) 

Pathway Losses Share ($/GGE) 

Delivery Share ($/GGE) 

Production Share ($/GGE) 

$0.00 

$1.00 

$2.00 

$3.00 

$4.00 

$5.00 

$6.00 

$7.00 

$8.00 

$9.00 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Levelized Cost ($/GGE) 

48 mpgge Fuel Economy 

68 mpgge Fuel Economy 
The levelized cost of hydrogen is calculated directly in the H2A model for the distributed 

hydrogen production cases and includes both production and CSD costs. For central production 

cases, the levelized cost of hydrogen is the sum of levelized production cost, levelized delivery 

cost, the cost of excess production due to losses during delivery, and the cost of CSD. 

DOE’s Fuel Cells Technologies Office has set a hydrogen threshold cost of $2.00–$4.00/gge 

delivered at the pump (Ruth and Joseck 2011). The comparison in Figure 7.0.1 shows that the 

hydrogen cost target is close to being met by distributed natural gas reforming. Niche 

opportunities with low-cost feed or capital costs, different financing options, or higher capacities 

may help other technologies meet the target. Likewise, delivery costs may be reduced for 

pipeline delivery if the fuel cell vehicle penetration were greater than 15%, giving those 

technologies a greater opportunity to meet the target. Otherwise, additional research is necessary 

to meet targets. Other analysts have used different parameters and reached slightly different 

levelized costs of hydrogen in their studies. Fletcher and Callaghan (2006) is one example of an 

analysis that showed that the previous $2.00–$3.00/gge levelized cost target (Hydrogen, Fuel 

Cells and Infrastructure Technology Program 2007) had been met for the distributed natural gas 

reforming pathway. The primary differences between their analysis and this one are the cost-year 

dollars (they worked in 2005$ and this analysis is in 2007$) and a lower cost for CSD (they 

estimated $0.88/kg, and the estimate in this study is $2.43/kg). 

Production costs range from 32% to 73% of the pathway levelized costs. Figure 7.0.3 shows a 

breakdown of those production costs into capital, feedstock, and other O&M costs. Most 

technologies are feedstock driven (i.e., feedstock costs make up the majority of the levelized 

cost); however, the biomass and coal technologies have relatively low feedstock costs and are 

evenly balanced and capital driven, respectively.

163 
164 

Figure 7.0.3. Production levelized costs for 10 pathways 

Levelized cost is not the only cost of concern. Capital costs are also important because a capital 

investment with the expectation of a payback and profit is necessary for the technologies to be 

developed. Figure 7.0.4 shows the capital costs for each pathway normalized to a daily 

dispensing basis. They are also broken into production, delivery, and dispensing shares. The nonpipeline technologies (distributed production and other delivery technologies) require less capital 

per daily kg of hydrogen than the pipeline technologies do. That status indicates the benefit of 

distributed and flexible infrastructure at lower penetrations, such as the 15% penetration 

considered in this report. At higher penetrations, one can expect that the normalized delivery 

capital cost will drop for pipeline pathways due to economies of scale. 

$0.00 

$1.00 

$2.00 

$3.00 

$4.00 

$5.00 

$6.00 

$7.00 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Production Levelized Costs ($ / kg) 

Production: O&M Levelized Cost ($/kg) 

Production: Capital Levelized Cost ($/kg) 

Production: Feedstock Levelized Cost ($/kg) 
165 

Figure 7.0.4. Normalized capital costs for 10 pathways 

Figure 7.0.5 shows a comparison of direct energy use between pathways. Direct energy includes 

only the energy used directly by the pathway (i.e., feedstock, electricity, and fuel used to run the 

equipment). It differs from the WTW energy in that WTW energy includes upstream energy 

requirements as well as energy used directly by the pathway. For example, while electricity is 

reported as a pathway energy source, the primary energy sources used to generate the electricity 

(e.g., coal, natural gas) are included in the WTW calculations. As expected, the dominant 

pathway energy source is the one named in the title of each pathway. 

$0 

$1,000 

$2,000 

$3,000 

$4,000 

$5,000 

$6,000 

$7,000 

$8,000 

$9,000 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Capital Cost ($ / daily kg) 

Dispensing Capital Cost 

Delivery Capital Cost 

Production Capital Cost 
166 

Figure 7.0.5. Pathway energy use for 10 pathways 

The pathway efficiency can be considered the inverse of the energy use; Figure 7.0.6 shows 

those efficiencies. The yellow bars show the production efficiencies that are calculated as the 

lower heating value (LHV) of the hydrogen produced divided by the LHV of all the production 

inputs reported in Section 6.0. The blue bars show the pathway efficiencies that are calculated as 

the LHV of the hydrogen delivered divided by the LHV of all the pathway inputs, which are 

shown in Figure 7.0.5. The red bars show the WTP efficiencies that are calculated as the LHV of 

the hydrogen delivered divided by the LHV of all the primary energy inputs (coal, natural gas, 

crude oil, and biomass) that are used directly or indirectly by the pathway. 

As an example, Figure 7.0.6 shows that the production efficiency of the distributed natural gas 

reforming pathway is 71% (i.e., 71% of all of the energy delivered to the hydrogen production 

plant is contained in the hydrogen product). Because the pathway includes both the production 

plant and CSD, the pathway efficiency must account for hydrogen lost and energy required for 

compression; thus, the pathway efficiency is somewhat lower at 65% for the distributed natural 

gas reforming pathway. Some additional energy is required to produce and deliver the natural 

gas and electricity to the facility, so the WTP efficiency is lower yet at 52% for the distributed 

natural gas reforming pathway. 

The pathways with the highest efficiency are the natural gas and ethanol pathways, followed by 

electrolysis and coal, and those with the lowest efficiency are the biomass pathways. One of the 

primary reasons the pathway efficiency is lower than reported in 2009 is that the onboard storage 

pressure is 700 bar instead of 350 bar (as was used in 2009). The increased pressure requires 

additional electricity for compression and the WTP efficiency of electricity production is low. 

0 

50,000 

100,000 

150,000 

200,000 

250,000 

300,000 

350,000 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Pathway Energy Requirements (Btu / GGE) 

Direct Diesel Use (Btu / GGE) 

Direct Nat Gas Use (Btu / GGE) 

Direct Electricity Use (Btu / GGE) 

Direct Coal Use (Btu / GGE) 

Direct Biomass Use (Btu / GGE) 

Direct Ethanol Use (Btu / GGE) 
167 

Figure 7.0.6. WTW, pathway, and production efficiencies for 10 hydrogen pathways 

Figure 7.0.7 shows the WTW petroleum use for the 10 hydrogen pathways. As vehicle fuel 

economy has a direct impact on per-mile WTW energy use and emissions, petroleum use for 

both the 48 mpgge fuel economy base case and the 68 mpgge sensitivity case are shown. In the 

pathways with truck delivery (biomass—liquid trucks, biomass—cryo-compressed, and 

biomass—gas trucks), most of the petroleum is used for hydrogen delivery. In technologies 

where biomass is used as a feedstock (central biomass gasification and distributed ethanol 

reforming), petroleum is used for farming and for biomass delivery to either the hydrogen or 

ethanol facility. Petroleum is also required for grid electricity production (0.9% of the grid mix is 

electricity generated from residual oil), so technologies requiring large amounts of electricity 

also utilize large amounts of petroleum. 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Energy Efficiency (LHV basis) 

Production Efficiency 

Pathway Efficiency 

Well-to-Pump Efficiency 
168 

Figure 7.0.7. WTW petroleum energy use for 10 hydrogen pathways 

Figure 7.0.8 shows the WTW natural gas use for the 10 hydrogen pathways, again showing the 

results for both the 48 mpgge and 68 mpgge cases. As expected, the pathways where natural gas 

is the primary energy source require the most natural gas. Natural gas is required for grid 

electricity production (21.5% of the grid mix is electricity generated from natural gas). Because 

distributed electrolysis and liquid truck delivery technologies require large amounts of grid 

electricity, they also utilize large amounts of natural gas. Finally, natural gas is also utilized in 

petroleum refining, so technologies with truck delivery require more natural gas than those 

without (e.g., delivery of hydrogen in a truck requires more natural gas on a WTW basis than 

delivery via pipeline). 

Figure 7.0.9 shows the comparative WTW GHG emissions for the 10 hydrogen pathways, shown 

for both 48 mpgge and 68 mpgge cases. Hydrogen FCEVs have no tailpipe GHG emissions 

because reacting hydrogen forms water, so the WTP emissions are the same as the WTW 

emissions. 

0 

50 

100 

150 

200 

250 

300 

350 

400 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

WTW Petroleum Energy Use (Btu / mile) 

48 mpgge Fuel Economy 

68 mpgge Fuel Economy 
169 

Figure 7.0.8. WTW natural gas energy use for 10 hydrogen pathways 

The primary source (66%) of GHG emissions for the distributed natural gas reforming pathway 

is generation of hydrogen with some additional GHGs generated to produce electricity for CSD 

and in natural gas recovery and delivery. Distributed ethanol reforming is based on ethanol 

produced from corn stover, so the GHGs removed from the atmosphere to grow biomass are 

nearly equivalent to those generated producing ethanol and hydrogen. Additional emissions are 

generated producing power necessary for CSD. Distributed electrolysis requires 50 kWh 

electricity per kg H2 produced, and additional electricity for CSD. The current grid mix produces 

660 g CO2-eq./kWh, so electricity generation is the primary emitter of its 820 g CO2-eq./mile 

traveled. In all of the biomass production pathways, the GHGs removed from the atmosphere to 

grow biomass are essentially equivalent to the GHGs generated in producing hydrogen (see 

Sections 6.4–6.7 for details). The two biomass pathways utilizing delivery of liquid hydrogen 

have higher emissions for delivery and dispensing because of the amount of electricity required 

to liquefy hydrogen. All the GHGs emitted from the central electrolysis of wind electricity 

pathway are from electricity generation for CSD, which is assumed to be purchased from the grid 

without wind energy credits. Fifty percent of the GHGs emitted from the central coal with CCS 

and pipeline delivery pathway are GHGs that were not sequestered in the hydrogen production 

process, with the most of the remainder emitted during electricity production for CSD and some 

for coal mining and hydrogen transport. 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

4,500 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

WTW Natural Gas Energy Use (Btu / mile) 

48 mpgge Fuel Economy 

68 mpgge Fuel Economy 
170 

Figure 7.0.9. WTW GHG emissions for 10 hydrogen pathways 

As shown in Figure 7.0.9, all of the pathways except distributed electrolysis result in GHG 

emissions (on a g/mile basis) lower than 400 g/mile based on a fuel economy of 48 mpgge, and 

below 250 g/mile when a fuel economy of 68 mpgge is considered. Distributed electrolysis has 

high GHG emissions when compared to the other hydrogen pathways because of the assumed 

U.S. average electricity grid mix. The pathways that use natural gas as a feedstock use little 

petroleum but have high GHG emissions compared to most of the other pathways due to the 

GHGs released in producing hydrogen from natural gas. The coal pathway has slightly lower 

GHG emissions because of the efficient sequestration system that is assumed. The biomass and 

ethanol cases have higher petroleum use than all but the distributed electrolysis pathway because 

the biomass and ethanol are delivered using trucks. 

Of the four delivery options from central production, pipeline delivery has the lowest GHG 

emissions and lowest petroleum use. The two liquid truck delivery options have higher GHG 

emissions due to emissions from generating electricity for liquefaction. The GHG emissions for 

liquid hydrogen dispensed as a cryo-compressed liquid are slightly lower than those dispensed as 

a gas because the liquid pump requires less electricity than the necessary compressor does. 

Hydrogen delivered in a gas truck has low GHG emissions but high petroleum use because each 

truckload only carries 520 kg of hydrogen. 

Because using hydrogen as a transportation fuel has an effect on both WTW GHG emissions and 

WTW petroleum use, and because that effect varies depending upon the hydrogen 

production/delivery pathway, Figure 7.0.10 shows GHG emissions relative to petroleum use for 

the 10 hydrogen pathways, based on a 48 mpgge fuel economy. 

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

WTW GHG Emissions (g CO2-eq / mile) 

GHG emission range 

based on 48 to 68 

mpgge fuel economy 
171 

Figure 7.0.10. Comparison of pathways’ petroleum use and GHG emissions (48 mpgge) 

Figures 7.0.11a and 7.0.11b show the levelized fuel cost per mile and the WTW GHG emissions 

for the 10 hydrogen pathways analyzed for 48 mpgge and 68 mpgge fuel economies, 

respectively. Ideally, one technology would be the obvious one to focus on because it has both 

the lowest cost and the lowest GHG emissions. In this case, there is an obvious tradeoff between 

GHG emissions and levelized cost. The natural gas technologies have the lowest cost but the 

highest emissions, and the biomass technologies, ethanol, and wind electrolysis have lower 

emissions but higher costs. 

Central Natural Gas - 

Pipeline 

Distributed 

Natural Gas 

Central Coal Gasification 

w/CCS - Pipeline 

Distributed Electrolysis 

(U.S. Grid mix, 44% Coal) 

Wind Electricity 

Electrolysis - Pipeline 

Central Biomass - 

Cryocompressed 

Central Biomass - Liquid 

Truck 

Central BiomassGas Truck 

Central Biomass - 

Pipeline Distributed 

Ethanol

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

1,000 

0 50 100 150 200 250 300 350 400 

WTW Greenhouse Gas Emissions (g / mile) 

WTW Petroleum Energy Use (Btu / mile) 

Natural Gas 

Coal 

Grid Electricity 

Wind Electricity 

Biomass 

Ethanol 
172 

Figure 7.0.11a. Comparison of pathways’ levelized costs per mile and GHG emissions (based on 

48 mpgge fuel economy) 

Central Biomass - 

Liquid Trucks 

Central Biomass - 

Pipelines 

Central Biomass - 

Gas Trucks 

Central Biomass - 

Cryocompressed 

Central Coal Gasification 

w/CCS- Pipeline 

Distributed Electrolysis 

(U.S. Grid mix, 44% Coal) 

Distributed Natural Gas 

Central Natural Gas - 

Pipeline 

Wind Electricity 

Electrolysis - Pipeline 

Distributed 

Ethanol 

Conventional 

Gasoline Vehicle 

Gasoline Hybrid 

Electric Vehicle 

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

1,000 

$0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.12 $0.14 $0.16 $0.18 $0.20 

WTW Greenhouse Gas Emissions (g / mile) 

Levelized Cost of Hydrogen ($ / mile without fuel taxes) 

Biomass 

Coal 

Grid Electricity 

Natural Gas 

Wind Electricity 

Ethanol 
173 

Figure 7.0.11b. Comparison of pathways’ levelized costs per mile and GHG emissions (based on 

68 mpgge fuel economy) 

Figure 7.0.12 shows the levelized cost of hydrogen on a per-mile-traveled basis, calculated for 

both 48 mpgge and 68 mpgge fuel economies. Figure 7.0.13 shows the levelized cost of 

hydrogen on a per-mile-traveled basis (assuming 48 mpgge fuel economy) with three possible 

costs of carbon. The tops of the blue bars match what has been shown previously—levelized cost 

per mile with no cost of carbon. The tops of the red bars indicate the wholesale, levelized costs 

including a $50/ton CO2-equivalent cost, and the tops of the yellow bars indicate the wholesale, 

levelized costs including a $100/ton CO2-equivalent cost. The carbon cost calculation is based on 

WTW GHG emissions, so it includes increased costs due to upstream emissions as well as those 

generated while producing the hydrogen. 

 

Central Biomass - 

Liquid Trucks 

Central Biomass - 

Pipelines 

Central Biomass - 

Gas Trucks 

Central Biomass - 

Cryocompressed 

Central Coal Gasification 

w/CCS- Pipeline 

Distributed Electrolysis 

(U.S. Grid mix, 44% Coal) 

Distributed Natural Gas 

Wind Electricity 

Electrolysis - Pipeline 

Distributed 

Ethanol 

Conventional 

Gasoline Vehicle 

Gasoline Hybrid 

Electric Vehicle 

0 

100 

200 

300 

400 

500 

600 

700 

800 

900 

1,000 

$0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.12 $0.14 $0.16 $0.18 $0.20 

WTW Greenhouse Gas Emissions (g / mile) 

Levelized Cost of Hydrogen ($ / mile without fuel taxes) 

Biomass 

Coal 

Grid Electricity 

Natural Gas 

Wind Electricity 

Ethanol 
174 

Figure 7.0.12. Per-mile levelized hydrogen costs for 10 hydrogen pathways 

Figure 7.0.13. Levelized hydrogen costs with possible cost of carbon for 10 hydrogen pathways 

(based on 48 mpgge fuel economy) 

$0.00 

$0.02 

$0.04 

$0.06 

$0.08 

$0.10 

$0.12 

$0.14 

$0.16 

$0.18 

$0.20 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Fuel Levelized Cost ($ / mile traveled) 

48 mpgge Fuel Economy 

68 mpgge Fuel Economy 

$0.00 

$0.05 

$0.10 

$0.15 

$0.20 

$0.25 

Distributed 

Natural Gas 

Reforming 

Distributed 

Ethanol 

Reforming 

Distributed 

Electrolysis 

(U.S. Grid 

Mix) 

Central 

Biomass 

Liquid 

Trucks 

Central 

Biomass 

Cryocompressed 

Central 

Biomass 

Gas Trucks 

Central 

Biomass 

Pipelines 

Central 

Natural 

Gas 

Reforming 

Pipelines 

Central 

Electrolysis 

(Wind 

Generation) 

Pipelines 

Central 

Coal 

Gasification 

w/CCS 

Pipelines 

Fuel Levelized Cost ($ / mile traveled) 

$100 / ton CO2 Eq Cost of Carbon 

$50 / ton CO2 eq Cost of Carbon 

$0 / ton CO2 eq Cost of Carbon 
8 Analysis Gaps

Though key input parameters have been adjusted in this study, many underlying assumptions 

used in the analysis rest on the default assumptions of the sub-models incorporated into the 

MSM (i.e., the default assumptions of the H2A Production, HDSAM, and GREET models). 

Below is a discussion of some of the analysis and modeling gaps identified during this analysis. 

Gaps were identified by the authors as well as through a review of the analysis by the Fuel 

Pathways Integration Technical Team of the U.S. DRIVE partnership, which includes 

representatives of four energy companies (Phillips 66, ExxonMobil, Chevron, and Shell), NREL, 

and the Hydrogen Systems Analyst of the U.S. Department of Energy. Some of the gaps and 

issues that were identified early in the scoping of the evaluation have been incorporated into the 

assessment and are reflected in the results described in the report. However, some gaps and 

issues have not yet been addressed or are beyond the scope of this effort; these gaps are noted 

below. 

8.1 Production

• General

o Limiting the analysis lifetime for distributed production to 20 years handicaps 

distributed production cases relative to central production cases (that are 

evaluated over a 40-year lifetime). 

• Central biomass gasification

o Only woody biomass has been included in the analysis. The H2A Production 

models do not currently include data to model herbaceous biomass feedstocks. 

The theoretical yields of hydrogen from herbaceous biomass should be compared 

with those from woody biomass. Empirical kinetic models on biomass 

gasification exist and may be used.

o The biomass gasification case has a high enough electricity demand to use 

industrial rates, yet commercial rates are assumed in the H2A analysis.

• Central natural gas reforming

o Waste heat is not considered to have any value in this analysis. An option where 

heat is used would be valuable because most of the reforming facilities built 

recently have customers for their waste heat.

o Equipment costs for central natural gas reforming should be further disaggregated 

to aid in transparency. 

o Additional information on water use for natural gas reforming should be provided. 

o Natural gas reforming should have some planned replacement costs over the 40-

year lifetime; however, none are included in the H2A calculation. H2A only has 

0.5% per year for unplanned replacement costs. 

• Central electrolysis using wind-generated electricity

o The analysis assumes that the average price of wind electricity matches AEO 

projections for grid-electricity prices. More detailed analysis of hour-by-hour 

175 
wind electricity prices is needed for a more accurate cost accounting of this 

pathway. 

o The central electrolysis analysis is based on a central electrolysis facility with an 

operating capacity factor of 97%. A facility may be co-sited with the wind 

turbines and have a lower operating capacity factor. The optimal location and 

capacity factor are not included in this analysis. 

• Central coal gasification with CCS

o The H2A model for this technology needs to be updated to 2007$ to be consistent 

with the other H2A cases.

o The availability of carbon sequestration sites and the cost of monitoring at and 

upkeep of those sites are not included in this analysis. A single cost for 

sequestration is included. 

o Cooling water requirements and costs are not included. More explanation is 

necessary regarding how the process is cooled. 

• Distributed natural gas reforming

o Cooling water requirements and costs are not included. More explanation is 

necessary regarding how the process is cooled. 

• Distributed electrolysis

o The hydrogen storage in the distributed electrolysis pathway is not optimized for 

peak power requirements. To optimize the pathway, the tradeoffs between the 

effects of full-time operation on the grid (transmission and distribution congestion 

and peaking power dispatch) and the costs of running the electrolyzers at lessthan-full-time need to be understood, and a study over 8,760 hours/year is needed. 

o The CSD electricity cost for distributed electrolysis should be using “industrial 

rates” due to high electricity usage for production. 

o The efficiency of distributed electrolysis is the same as for central electrolysis; 

however, distributed electrolysis is likely to have a lower efficiency due to a 

higher relative parasitic demand.

8.2 Delivery and Dispensing

• Geologic storage is modeled currently with variable pressure; however, constant pressure 

is required in salt caverns. The pressure requirements for non-salt geologic structures are 

not well understood and require study. 

• Geologic storage costs and requirements should be compared to those for natural gas to 

provide a cost baseline. 

• The need for hydrogen gas clean-up after the hydrogen is extracted from caverns or other 

geologic storage is not well understood and requires study. Gas clean-up requirements 

and costs are a gap in the analysis for all of the pathways employing hydrogen delivery 

by pipeline. 

176 
• HDSAM uses a formula to calculate transmission and trunk pipeline costs based on an 

optimization of pipeline diameters, based on a curve fitting of available data. It appears 

that there is a problem with this formula; the HDSAM team should investigate and revise 

HDSAM as necessary. 

• Average right-of-way costs are used in this analysis. Improved understanding of those 

costs and their effects on levelized costs would be helpful. 

• There are concerns about the design of the gas truck case:

o The production facility, geologic storage, and terminal appear to be co-located 

because there is no equipment for transport between them. 

o The gas-truck delivery case considered in this report requires 76 truck bays, 

which represents a very large terminal and would likely involve considerable 

logistics issues. 

o Terminal operators are unlikely to leave a trailer unattached from a tractor at the 

loading bay; however, the design does not allow for enough tractors to keep all of 

the trailers hooked up. 

o The number of compressor stages is unchanged between the other cases that have 

a lower inlet pressure and this one. It is likely that fewer stages are necessary.

o The terminal has only a single storage compressor. A backup is likely to be 

necessary.

o Using two compressors to serve 76 truck bays is likely to cause operational issues. 

More, smaller compressors are probably necessary.

o Scenarios with higher minimum on-trailer pressures should be considered because 

they may allow for less compression at the stations; however, the logistics 

regarding the number of truck fills need to be kept in mind. 

• Additional analysis is needed to determine the ideal size and siting of hydrogen 

distribution stations.

• Low-pressure storage requirements at stations should be revisited to identify the potential 

risks regarding downtime due to unplanned outages to determine if the current storage 

amount is sufficient.

• Cascade storage volumes should be compared to those used for dispensing from natural 

gas from gas pipelines. 

• The on-board storage pressure for all of the analyses in this report is 10,000 psi, which 

requires a maximum dispensing pressure of 12,688 psi. Tradeoffs should be analyzed. 

• The tradeoffs between hydrogen quality and fuel cell performance (i.e., durability, 

reliability, and efficiency) are not well understood. 

• Control and safety equipment costs for liquid delivery are more than 5 times higher than 

those for gaseous delivery and on-site production. Intuitively, they should be more 

similar.

177 
• The dispenser cost for liquid delivery (both gaseous and cryo-compressed dispensing) is 

less than 50% of that for gaseous delivery and on-site production. Intuitively, they should 

be more similar.

• There are slight errors in the electricity cost calculations for geologic storage and 

refueling station electricity use that need to be corrected.

8.3 Vehicle Costing

• The tool needs to be adjusted to allow for cryo-compressed storage costs when 

appropriate instead of just compressed gas onboard storage. 

• The vehicle CPM Tool only allows 10,000 and 15,000 miles per year. Adding 12,000 

miles per year (as a standard distance driven) would improve the analysis.

• The CPM Tool assumes a 100 kW-sized fuel cell stack for costing purposes, compared to 

a 70-kW stack assumed in GREET 2.

• Additional information on the tradeoffs between vehicle fuel economy and vehicle costs 

could be added if those data can be found.

8.4 Pathway Analysis

• Station sizes should be kept more consistent than in this analysis, where distributed 

production stations have an average daily dispensing rate of 1,330 kg/day; stations for 

pipelines and liquid truck delivery have an average daily dispensing rate of 1,000 kg/day; 

and stations for gas truck delivery have an average daily dispensing rate of 800 kg/day.

• The effects of different types of biomass (i.e., corn stover or forest residue instead of just 

short rotation woody crops) on cost, energy use, and emissions should be considered. 

• Other impact parameters such as water withdrawal, water consumption, and land use 

should be added to the analysis. 

• The analysis should balance analysis periods. One such need is to compare two back-toback distributed production stations (with a 20-year lifetime each) against a single central 

production unit with a 40-year lifetime.

178 
9 References

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Mintz, M.; Elgowainy, A.; Gillette, J. (September 2008). H2A Delivery Scenario Analysis Model 

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179 
Pacific Northwest National Laboratory (March 2004). An Approach to Handling Internal Rate of 

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Plotkin, S.; Singh, M.; Patterson, P.; Ward, J.; Wood, F.; Kydes, N.; Holte, J.; Moore, J.; Miller, 

G.; Das, S.; Greene, D. (2009). Multi-Path Transportation Futures Study: Vehicle 

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2011). Macro System Model (MSM) User Guide, Version 1.3. NREL/TP-6A10-51618. Golden, 

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181 
182 

 Distributed Natural Gas Supporting Tables and Figures
183 

NG Delivery Pressure Average of gas companiesNG Quality at Delivery Average of gas companies

NG Recovery Efficiency 95.7%NG emitted & combusted during recovery 399 g/MMbtu NG Cost $6.09 2007 $ / mmBTU

NG processing energy efficiency 97.2% NG Share of H2 Levelized Cost $1.28 2007$ / kg H2 dispensed

NG emitted & combusted during processing 33 g/MMbtuNG emitted & combusted during transport 199,400 g/MMbtu WTG CO2 Emissions 650 g CO2 eq./ 116000 Btu

300 Btu / 116000Btu to Pump NG transport distance 500 miles WTG CH4 Emissions 1,750 g CO2 eq./ 116000 Btu

127,200 Btu / 116000Btu to Pump Compression Req'ts. (stages & efficiency) WTG N2O Emissions 3 g CO2 eq./ 116000 Btu

500 Btu / 116000Btu to Pump WTG GHG Emissions 2,390 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

0.156 MMBtu/kg H2 produced Hydrogen Outlet Quality 99.9%

1.11 kWh / kg H2 produced

5.77 gal / kg H2 produced Distributed plant design capacity 1,500 kg / day Total capital investment $1,150 2007$ / daily kg H2 (effective capacity)

0.00 gal / kg H2 produced Capacity factor 89% Levelized Cost of Capital $0.59 2007$ / kg H2 dispensed

# of Plants Needed to Meet City Demand 92 Fixed O&M Costs $0.19 2007$ / kg H2 dispensed

$1,530,000 2007$ Process energy efficiency 71.4% Variable O&M Costs $0.12 2007$ / kg H2 dispensed

Electricity Mix US Mix Total Levelized Cost $2.17 2007$ / kg H2 dispensed

After-tax IRR 10%

5,600 Btu / 116000Btu to Pump Assumed Plant Life 20 Production CO2 Emissions 10,410 g CO2 eq./ 116000 Btu

49,200 Btu / 116000Btu to Pump Production CH4 Emissions 690 g CO2 eq./ 116000 Btu

400 Btu / 116000Btu to Pump Production N2O Emissions 8 g CO2 eq./ 116000 Btu

Production GHG Emissions 11,100 g CO2 eq./ 116000 Btu

4.4 kWh / kg H2 produced Hydrogen outlet pressure 12,700 psi

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

City Population 1,247,000 people conventional unleaded gasoline)

$5,059,000 2007$ / station Hydrogen Vehicle Penetration 15%

$465,391,000 2007$ / all stations City hydrogen use 121,100 kg / day Total capital investment $3,810 2007$ / daily kg H2 (effective capacity)

Average Dispensing Rate per Station 1,330 kg / day Levelized Cost of Capital $1.49 2007$ / kg H2 dispensed

Number of Dispensing Stations 92 Energy & Fuel $0.40 2007$ / kg H2 dispensed

Number of Compression Steps 5 Other O&M Costs $0.54 2007$ / kg H2 dispensed

Usable Low Pressure Storage per Station 1,450 kg H2 Levelized Cost of Dispensing $2.43 2007$ / kg H2 dispensedUsable Cascade Storage per Station 200 kg H2

21,900 Btu / 116000Btu to Pump Site storage 100% % of design capacity CSD CO2 Emissions 3,020 g CO2 eq./ 116000 Btu

9,700 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 3 CSD CH4 Emissions 190 g CO2 eq./ 116000 Btu

800 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD N2O Emissions 12 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,220 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.66 2007$ / mi

70 kW Fuel Economy 48.0 mi / GGE Fuel Share $0.10 2007$ / mi30 kW Vehicle Miles Traveled 15,000 mi / yr Maintenance, Tires, Repairs $0.07 2007$ / mi

Vehicle Lifetime 160,000 mi Insurance & Registration $0.12 2007$ / miPurchase Year 2015 Depreciation $0.27 2007$ / miVehicle Purchase Cost $33,700 2007$ Financing $0.10 2007$ / miFuel Cell System Cost $4,500 2007$

2,300 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Vehicle Cycle CO2 Emissions 1,670 g CO2 eq / gge fuel consumed

12,100 Btu / gge fuel consumed Tax Credit $0 2007$ Vehicle Cycle CH4 Emissions 170 g CO2 eq / gge fuel consumed

6,900 Btu / gge fuel consumed Vehicle Cycle N2O Emissions 6 g CO2 eq / gge fuel consumed

Vehicle Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

uts Outputs

Vehicle

NG Recovery, Processing, & Transport

Assumptions

Hydrogen Production

Average of gas companies
184 

Conversion Facility Dispensing

Coal 5,574 Btu/116000 Btu Coal 21,887 Btu/116000 Btu

Natural Gas 49,198 Btu/116000 Btu Natural Gas 9,703 Btu/116000 Btu

Petroleum 384 Btu/116000 Btu Petroleum 831 Btu/116000 Btu

Total Energy 56,638 Btu/116000 Btu Total Energy 38,243 Btu/116000 Btu

CO2 Emissions 10,407 g/116000 Btu CO2 Emissions 3,017 g/116000 Btu

CH4 Emissions 689 g/116000 Btu CH4 Emissions 186 g/116000 Btu

N2O Emissions 8 g/116000 Btu N2O Emissions 12 g/116000 Btu

GHG Emissions 11,104 g/116000 Btu GHG Emissions 3,216 g/116000 Btu

Total to Deliver 116000 Btu Fuel

tu/116000 Btu Coal 27,730

tu/116000 Btu Natural Gas 186,117

tu/116000 Btu Conversion Compression & Dispensing Petroleum 1,693

tu/116000 Btu Total Energy 222,915

116000 Btu Natura Gas Feedstock 159,044 Distribution Losses 0.00% CO2 Emissions 14,069

116000 Btu CH4 Emissions 2,621

116000 Btu N2O Emissions 24

116000 Btu GHG Emissions 16,714
185 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

NATURAL GASGasNoneCASCADE_700_BAR

1329 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

92

14%

2.50 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
186 

Value Units Reference Comments

s (remainder is conventional NG)

for recovery that is combusted natural gasfor recovery that is combusted shale gas

y

rocessing that is combusted natural gas

t and distribution

n

n

tral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

 Efficiency

ass Power Plants

f Biomass Power Plants

ency

n Plant Efficiency

of Biopower Plants

ciency

 Power Plants

f Coal Power Plants

y

ant Efficiency

of Coal-Electricity Plants

and Efficiency

urbine Share of Natural Gas Power Plants

s Turbine Share of Natural Gas Power Plants

hare of Natural Gas Power Plants

Cycle Gas Turbine Plant Efficiency

ed Cycle Efficiency

stion Boiler Plant Efficiency

of Natural Gas-Electricity Plants

cy

ty Plant Efficiency

tribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

199434 g / MMBtu

500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to several other 

models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, February). Annual

Energy Outlook 2007 with Projections to 2030. DOE/EIA0383(2007). Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html National 

electricity generation data from tables D-7 & D-8 using the 

2005 timeframe. Percentages calculated from total 

generation values reported with all renewables except 

biomass aggregated into the "Others (Carbon Neutral)" 

category 
187 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
188 

 Distributed Ethanol Supporting Tables and Figures
189 

Percent from Corn Stover 100% Ethanol Cost $3.04 2007 $ / gal

Corn Stover Production 2.21 dry ton / acre Ethanol Share of H2 Cost $5.29 2007$ / kg H2 dispensed

-21,100 Btu / 116000Btu to Pump Ethanol Yield from Corn Stover 90.0 gal / dry ton

400 Btu / 116000Btu to Pump Elec. Co-Prod. from Corn Stover Conversion 2.28 kWh / gal ethanol WTG CO2 Emissions -14,010 g CO2 eq./ 116000 Btu

12,700 Btu / 116000Btu to Pump WTG CH4 Emissions -20 g CO2 eq./ 116000 Btu

WTG N2O Emissions 1,140 g CO2 eq./ 116000 Btu

lectricity displaced by ethanol production WTG GHG Emissions -12,900 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

2.19 gal / kg H2 produced Hydrogen Outlet Quality 99.9%

0.49 kWh / kg H2 produced8.18 gal / kg H2 produced Distributed plant design capacity 1,500 kg / day Total capital investment $1,430 2007$ / daily kg H2 (effective capacity)

0.00 gal / kg H2 produced Capacity factor 89% Levelized Cost of Capital $0.83 2007$ / kg H2 dispensed

# of Plants Needed to Meet City Demand 92 Fixed O&M Costs $0.24 2007$ / kg H2 dispensed

$1,907,000 2007$ Process energy efficiency 67.4% Variable O&M Costs $0.07 2007$ / kg H2 dispensed

Electricity Mix US Mix Total Levelized Cost $6.42 2007$ / kg H2 dispensed

After-tax IRR 10%

2,400 Btu / 116000Btu to Pump Assumed Plant Life 20 SMR CO2 Emissions 13,080 g CO2 eq./ 116000 Btu

1,100 Btu / 116000Btu to Pump SMR CH4 Emissions 20 g CO2 eq./ 116000 Btu

100 Btu / 116000Btu to Pump SMR N2O Emissions 1 g CO2 eq./ 116000 Btu

SMR GHG Emissions 14,010 g CO2 eq./ 116000 Btu

4.4 kWh / kg H2 Hydrogen outlet pressure 12,700 psi

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

City Population 1,247,000 people conventional unleaded gasoline)

$5,059,000 2007$ / station Hydrogen Vehicle Penetration 15% Total capital investment $3,810 2007$ / daily kg H2 (effective capacity)

$465,390,000 2007$ / all stations City hydrogen use 121,100 kg / day Levelized Cost of Capital $1.49 2007$ / kg H2 dispensed

Average Dispensing Rate per Station 1,329 kg / day Energy & Fuel $0.40 2007$ / kg H2 dispensed

Number of Dispensing Stations 92 Other O&M Costs $0.54 2007$ / kg H2 dispensed

Number of Compression Steps 5 Levelized Cost of Dispensing $2.43 2007$ / kg H2 dispensedUsable Low Pressure Storage per Station 1450 kg H2Usable Cascade Storage per Station 200 kg H2 CSD CO2 Emissions 3,020 g CO2 eq./ 116000 Btu

21,900 Btu / 116000Btu to Pump Site storage 100% % of design capacity CSD CH4 Emissions 190 g CO2 eq./ 116000 Btu

9,700 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 3 CSD N2O Emissions 12 g CO2 eq./ 116000 Btu

800 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD GHG Emissions 11,320 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.75 2007$ / mi

70 kW Fuel Economy 48.0 mi / GGE Fuel Share $0.18 2007$ / mi30 kW Vehicle Miles Traveled 15,000 mi / yr Maintenance, Tires, Repairs $0.07 2007$ / mi

Vehicle Lifetime 160,000 mi Insurance & Registration $0.12 2007$ / miPurchase Year 2015 Depreciation $0.27 2007$ / miVehicle Purchase Cost $33,700 2007$ Financing $0.10 2007$ / miFuel Cell System Cost $4,500 2007$

2,300 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Veh. Cycle CO2 Emissions 1,670 g CO2 eq / gge fuel consumed

12,100 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle CH4 Emissions 170 g CO2 eq / gge fuel consumed

6,900 Btu / gge fuel consumed Veh. Cycle N2O Emissions 6 g CO2 eq / gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

uts Outputs

Vehicle

Ethanol Production

Assumptions

Hydrogen Production

Displacement method used for estimating effects 

of co-produced electricity on LCA results
190 

Conversion Facility Dispensing

Coal 2,442 Btu/116000 Btu Coal 21,887 Btu/116000 Btu

Natural Gas 1,082 Btu/116000 Btu Natural Gas 9,703 Btu/116000 Btu

Petroleum 93 Btu/116000 Btu Petroleum 831 Btu/116000 Btu

Total Energy 58,568 Btu/116000 Btu Total Energy 38,243 Btu/116000 Btu

CO2 Emissions 13,084 g CO2 eq/116000 Btu CO2 Emissions 3,017 g CO2 eq/116000 Btu

CH4 Emissions 21 g CO2 eq/116000 Btu CH4 Emissions 186 g CO2 eq/116000 Btu

N2O Emissions 1 g CO2 eq/116000 Btu N2O Emissions 12 g CO2 eq/116000 Btu

GHG Emissions 14,009 g CO2 eq/116000 Btu GHG Emissions 11,317 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

u/116000 Btu Coal 3,219

u/116000 Btu Natural Gas 11,219

u/116000 Btu Reforming CSD Petroleum 13,577

u/116000 Btu Total Energy 377,996

CO2 eq/116000 Btu Ethanol Feedstock 170,725 Distribution Losses 0.00% CO2 Emissions 2,090

CO2 eq/116000 Btu CH4 Emissions 183

CO2 eq/116000 Btu N2O Emissions 1,150CO2 eq/116000 Btu GHG Emissions 12,429
191 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

ETHANOLGasNoneCASCADE_700_BAR

1329 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

92

14%

2.50 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
192 

Value Units Reference Comments

n

n

tral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

 Efficiency

ass Power Plants

f Biomass Power Plants

ency

n Plant Efficiency

of Biopower Plants

ciency

 Power Plants

f Coal Power Plants

y

ant Efficiency

of Coal-Electricity Plants

and Efficiency

urbine Share of Natural Gas Power Plants

s Turbine Share of Natural Gas Power Plants

hare of Natural Gas Power Plants

Cycle Gas Turbine Plant Efficiency

ed Cycle Efficiency

stion Boiler Plant Efficiency

of Natural Gas-Electricity Plants

cy

ty Plant Efficiency

tribution Losses

rn (grain)

med Trees

itchgrass

rn Stover

est Residue

gar Cane

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%0.0%0.0%0.0%

100.0%

0.0%0.0%

GREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, February). Annual

Energy Outlook 2007 with Projections to 2030. DOE/EIA0383(2007). Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html National 

electricity generation data from tables D-7 & D-8 using the 

2005 timeframe. Percentages calculated from total 

generation values reported with all renewables except 

biomass aggregated into the "Others (Carbon Neutral)" 

category 

Requirement

 Fertilizer

ertilizer

tilizer

e

de

d use change included?nol Yield

ricity Co-Product

188,656 Btu / dry ton stover

7,700 g / dry ton stover2,000 g / dry ton stover

12,000 g / dry ton stover

0 g / dry ton0 g / dry ton

2.21 dry ton / acre

No

90.0 gal / dry ton

-2.28 kWh / gal ethanol

GREET default input In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET result In addition to corn grain requirementGREET default input In addition to corn grain requirementGREET default inputGREET default input
193 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
194 

 Distributed Electricity Supporting Tables and Figures
195 

U.S. Grid Mix Electricity price at H2 production 0.0574 2007$ / kWhBiomass Fraction 1% Electricity Share of H2 Cost $3.22 2007$ / kg H2 dispensedCoal Fraction 44%Natural Gas Fraction 21% WTG CO2 Emissions 36,930 g CO2 eq./ 116000 Btu

159,600 Btu / 116000Btu to Pump Nuclear Fraction 21% WTG CH4 Emissions 2,280 g CO2 eq./ 116000 Btu

70,800 Btu / 116000Btu to Pump Residual Oil Fraction 1% WTG N2O Emissions 150 g CO2 eq./ 116000 Btu

6,100 Btu / 116000Btu to Pump Others (Carbon Neutral) 12% WTG GHG Emissions 39,360 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

50.0 kWh / kg H2 produced Hydrogen Outlet Quality 100.0%

2.94 gal / kg H2 produced

0.11 gal / kg H2 produced Distributed plant design capacity 1,500 kg / day Total capital investment $1,700 2007$ / daily kg H2 (effective capacity)

Capacity factor 89% Levelized Cost of Capital $0.77 2007$ / kg H2 dispensed

# of Plants Needed to Meet City Demand 91 Fixed O&M Costs $0.28 2007$ / kg H2 dispensed

$2,258,000 2007$ Process energy efficiency 66.8% Variable O&M Costs $0.06 2007$ / kg H2 dispensed

Electricity Mix US Mix Total Levelized Cost $4.32 2007$ / kg H2 dispensed

After-tax IRR 10%

86,400 Btu / 116000Btu to Pump Assumed Plant Life 20 years Production CO2 Emissions 0 g CO2 eq./ 116000 Btu

38,300 Btu / 116000Btu to Pump Production CH4 Emissions 0 g CO2 eq./ 116000 Btu

3,300 Btu / 116000Btu to Pump Production N2O Emissions 0 g CO2 eq./ 116000 Btu

Production GHG Emissions 0 g CO2 eq./ 116000 Btu

4.4 kWh / kg H2 Hydrogen outlet pressure 12,700 psi

$0.088 2007$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

City Population 1,247,000 people conventional unleaded gasoline)Hydrogen Vehicle Penetration 15%

$5,059,000 2007$ / station City hydrogen use 121,100 kg / day Total capital investment $3,810 2007$ / daily kg H2 (effective capacity)

$465,391,000 2007$ / all stations Average Dispensing Rate per Station 1,330 kg / day Levelized Cost of Capital $1.49 2007$ / kg H2 dispensed

Number of Dispensing Stations 92 Energy & Fuel $0.40 2007$ / kg H2 dispensed

Number of Compression Steps 0 Other O&M Costs $0.54 2007$ / kg H2 dispensed

Usable Low Pressure Storage per Station 1,450 kg H2 Levelized Cost of Dispensing $2.43 2007$ / kg H2 dispensedUsable Cascade Storage per Station 200 kg H2

21,900 Btu / 116000Btu to Pump Site storage 100% % of design capacity CSD CO2 Emissions 3,020 g CO2 eq./ 116000 Btu

9,700 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 3 CSD CH4 Emissions 190 g CO2 eq./ 116000 Btu

800 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD N2O Emissions 12 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,220 g CO2 eq./ 116000 Btu

3,020 lb Cost Per Mile $0.71 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Fuel Share $0.14 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Maintenance, Tires, Repairs $0.07 2007$ / mi

Vehicle Lifetime 160,000 mi Insurance & Registration $0.12 2007$ / mi

Purchase Year 2015 Depreciation $0.27 2007$ / miVehicle Purchase Cost $33,700 2007$ Financing $0.10 2007$ / mi

Fuel Cell System Cost $4,500 2007$

2,300 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Vehicle Cycle CO2 Emissions 1,670 g CO2 eq / gge fuel consumed

12,100 Btu / gge fuel consumed Tax Credit $0 2007$ Vehicle Cycle CH4 Emissions 7 g CO2 eq / gge fuel consumed

6,900 Btu / gge fuel consumed Vehicle Cycle N2O Emissions 0 g CO2 eq / gge fuel consumed

Vehicle Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

Forecourt Dispensing

uts Outputs

Vehicle

Electricity Generation & Transmission

Assumptions

Hydrogen Production
196 

Conversion Facility Dispensing

Coal 86,402 Btu/116000 Btu Coal 21,887 Btu/116000 Btu

Natural Gas 38,305 Btu/116000 Btu Natural Gas 9,703 Btu/116000 Btu

Petroleum 3,282 Btu/116000 Btu Petroleum 831 Btu/116000 Btu

Total Energy 150,970 Btu/116000 Btu Total Energy 38,243 Btu/116000 Btu

CO2 Emissions 0 g CO2 eq/116000 Btu CO2 Emissions 3,017 g CO2 eq/116000 Btu

CH4 Emissions 0 g CO2 eq/116000 Btu CH4 Emissions 186 g CO2 eq/116000 Btu

N2O Emissions 0 g CO2 eq/116000 Btu N2O Emissions 12 g CO2 eq/116000 Btu

GHG Emissions 0 g CO2 eq/116000 Btu GHG Emissions 3,216 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

u/116000 Btu Coal 267,934

u/116000 Btu Natural Gas 118,785

u/116000 Btu Electrolysis Dispensing Petroleum 10,177

u/116000 Btu Total Energy 468,159

CO2 eq/116000 Btu Electricity Feedstock 189,369 Dispensing Losses 0.00% CO2 Emissions 39,949

CO2 eq/116000 Btu CH4 Emissions 2,469

CO2 eq/116000 Btu N2O Emissions 162

CO2 eq/116000 Btu GHG Emissions 42,580
197 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

ELECTROLYSISGasNoneCASCADE_700_BAR

1329 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

92

14%

2.50 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
198 

Value Units Reference Comments

n

n

tral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

 Efficiency

ass Power Plants

f Biomass Power Plants

ency

n Plant Efficiency

of Biopower Plants

ciency

 Power Plants

f Coal Power Plants

y

ant Efficiency

of Coal-Electricity Plants

and Efficiency

urbine Share of Natural Gas Power Plants

s Turbine Share of Natural Gas Power Plants

hare of Natural Gas Power Plants

Cycle Gas Turbine Plant Efficiency

ed Cycle Efficiency

stion Boiler Plant Efficiency

of Natural Gas-Electricity Plants

cy

ty Plant Efficiency

tribution Losses

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, February). Annual

Energy Outlook 2007 with Projections to 2030. DOE/EIA0383(2007). Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html National 

electricity generation data from tables D-7 & D-8 using the 

2005 timeframe. Percentages calculated from total 

generation values reported with all renewables except 

biomass aggregated into the "Others (Carbon Neutral)" 

category 
199 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
200 

 Central Biomass—Pipeline Delivery Supporting Tables and 

Central Plant and Transported as Gas via Pipeline

2,000 Btu 15,000 Btu

Electricity for Electricity forCompression Forecourt

Hydrogen Gas Hydrogen Gas

s 118,000 Btu 116,000 Btu

0

138,000 Btu Energy Lost 1,000 Btu 17,000 Btu Energy Lost

HydrogenLost

Case DefinitionYear: 2015Hydrogen as GasCentral Production

37% WOODY BIOMASS Feedstock

Sequestration: NOTransport for Delivery: PipelineVehicle Efficiency: 48 mile / GGECity Hydrogen Use: 121096 kg/day

 Greenhouse 

 (g/mile)

124

WTP Efficiency (

CO2 Equivalent / 

GGE fuel available): 

GHG

13

 of H2 at 

6.32

 Total Energy 

6,594 Production Process Energy Efficiency 46%

 Petroleum 

u/mile) 153 Pathway Efficiency 43%

Central Production Compression & Pipeline Compression, Storage, & Dispensing 
201 

Biomass moisture content 25%

235,000 Btu / dry ton Woody biomass LHV 16,013,200 Btu / dry ton

Biomass price at H2 production $75 2007 $ / dry ton

Fraction of Woody Biomass 100% Biomass Share of Levelized Cos $0.97 2007$ / kg H2 dispensed

LUC GHG changes ='Params - U g / dry ton

200 Btu / 116000Btu to Pump Average dist from farm to H2 production pstream'!E15 miles WTG CO2 Emissions -24,830 g CO2 eq./ 116000 Btu

600 Btu / 116000Btu to Pump WTG CH4 Emissions 13 g CO2 eq./ 116000 Btu

2,900 Btu / 116000Btu to Pump WTG N2O Emissions 35 g CO2 eq./ 116000 Btu

WTG GHG Emissions -24,780 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 produced Central plant design capacity 155,200 kg / day Total capital investment $1,300 2007$ / daily kg H2 (effective capacity)1.32 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $0.64 2007$ / kg H2 dispensed

79.3 gal / kg H2 produced Number of production facilities necessary 0.87 Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Process energy efficiency 46.0% Variable O&M Costs $0.40 2007$ / kg H2 dispensed

$181,080,000 2007$ Electricity Mix US Mix Total Levelized Cost $2.24 2007$ / kg H2 dispensed

After-tax IRR 10%

5,100 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 26,510 g CO2 eq./ 116000 Btu9,500 Btu / 116000Btu to Pump Production CH4 Emissions 140 g CO2 eq./ 116000 Btu

3,400 Btu / 116000Btu to Pump Production N2O Emissions 43 g CO2 eq./ 116000 Btu

Production GHG Emissions 26,690 g CO2 eq./ 116000 Btu

0.56 kWh / kg H2 dispensed Total capital investment $3,300 2007$ / daily kg H2 (effective capacity)0.01 kWh / kg H2 dispensed

0.57 kWh / kg H2 dispensed City Population 1,247,000 people Levelized Cost of Capital $1.71 2007$ / kg H2 dispensed

Hydrogen Vehicle Penetration 15% Energy & Fuel $0.04 2007$ / kg H2 dispensedCity hydrogen use 121,100 kg / day Other O&M Costs $0.40 2007$ / kg H2 dispensed

$404,341,000 2007$ Distance from City to Production Facility 62 miles Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Geologic storage capacity 1,325,000 kg H2

Number of trunk pipelines 3 Delivery CO2 Emissions 390 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump Service-line length 1.5 miles / line Delivery CH4 Emissions 24 g CO2 eq./ 116000 Btu1,300 Btu / 116000Btu to Pump Number of service lines 122 Delivery N2O Emissions 2 g CO2 eq./ 116000 Btu

100 Btu / 116000Btu to Pump Hydrogen losses 0.80% Delivery GHG Emissions 420 g CO2 eq./ 116000 Btu

Hydrogen outlet pressure 12,700 psi

4.4 kWh / kg H2 dispensed Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated

 conventional unleaded gasoline)

$2,629,000 2007$ / station Average Dispensing Rate per Station 1,000 kg/day Total capital investment $2,650 2007$ / daily kg H2 (effective capacity)

$320,679,000 2007$ / all stations Number of Dispensing Stations 122 Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Number of Compression Steps 5 Energy & Fuel $0.41 2007$ / kg H2 dispensed

300 psi Usable Low Pressure Storage per Station 370 kg H2 Other O&M Costs $0.43 2007$ / kg H2 dispensed

Usable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

24,400 Btu / 116000 Btu to Pump Site storage 42% % of design capacity CSD CO2 Emissions 3,370 g CO2 eq./ 116000 Btu

10,800 Btu / 116000 Btu to Pump # of 2-hose Dispensers per Station 2 CSD CH4 Emissions 210 g CO2 eq./ 116000 Btu

900 Btu / 116000 Btu to Pump Hydrogen Losses 0.50% CSD N2O Emissions 14 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,590 g CO2 eq./ 116000 Btu

Cost Per Mile $0.70 2007$ / mi

3,020 lb Fuel Share $0.13 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / mi

Purchase Year 2015 Financing $0.10 2007$ / mi

Vehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Veh. Cycle CO2 Emissions 1,670 g CO2 eq/ gge fuel consumed

12,100 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Veh. Cycle CH4 Emissions 7 g CO2 eq/ gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle N2O Emissions 0 g CO2 eq/ gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g CO2 eq/ gge fuel consumed

puts Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Pipelines for DeliveryHydrogen Production

Forecourt Dispensing
202 

Conversion Facility Transport Dispensing

Coal 5,126 Btu/116000 Btu Coal 2,825 Btu/116000 Btu Coal 24,443 Btu/116000 Btu

Natural Gas 9,498 Btu/116000 Btu Natural Gas 1,253 Btu/116000 Btu Natural Gas 10,837 Btu/116000 Btu

Petroleum 3,390 Btu/116000 Btu Petroleum 107 Btu/116000 Btu Petroleum 928 Btu/116000 Btu

Total Energy 147,679 Btu/116000 Btu Total Energy 5,837 Btu/116000 Btu Total Energy 42,710 Btu/116000 Btu

CO2 Emissions 26,511 g CO2 eq/116000 Btu CO2 Emissions 389 g CO2 eq/116000 Btu CO2 Emissions 3,369 g CO2 eq/116000 Btu

CH4 Emissions 138 g CO2 eq/116000 Btu CH4 Emissions 24 g CO2 eq/116000 Btu CH4 Emissions 208 g CO2 eq/116000 Btu

N2O Emissions 43 g CO2 eq/116000 Btu N2O Emissions 2 g CO2 eq/116000 Btu N2O Emissions 14 g CO2 eq/116000 Btu

GHG Emissions 26,692 g CO2 eq/116000 Btu GHG Emissions 415 g CO2 eq/116000 Btu GHG Emissions 3,591 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

Btu Coal 32,598

Btu Natural Gas 22,210

Btu Gasification & Conversion Transport Dispensing Petroleum 7,338

Btu Total Energy 200,018

6000 Btu Biomass Feedstock 245,987 Transport Losses 0.77% Distribution Losses 0.50% CO2 Emissions 5,441

6000 Btu CH4 Emissions 383

6000 Btu N2O Emissions 93

6000 Btu GHG Emissions 5,916
203 

Hold Value Units

2015 20152007 2007

WOODY BIOMASS WOODY BIOMASSGas Gas

Pipeline Pipeline

CASCADE_700_BAR CASCADE_700_BAR

1000 1000 kg/day

passenger cars passenger cars

lightweight) Conventional Conventional

48.0 48.0 mile / gge

1,247,364 1,247,364 people

15% 15% (% vehicles in city)

138,832 138,832 H2 vehicles / city

15,000 15,000 mile / vehicle year

160,000 160,000 miles in vehicle life121,096 121,096 kg / d

 city 122 122

gasoline stations 19% 19%

s (mi) 2.17 2.17 miles

ations

e 100% 100%

None None

0% 0% wt %

o GVs fueled with CG & RFG 0% 0%

) to GVs fueled with CG & RFG 0% 0%

Vs fueled with CG & RFG 0% 0%

GVs fueled with CG & RFG 0% 0%

ssions to GVs fueled with CG & RFG 0% 0%

PM10 emissions to GVs fueled with CG & RFG 100% 100%

ssions to GVs fueled with CG & RFG 0% 0%

PM2.5 emissions to GVs fueled with CG & RFG 100% 100%

GVs fueled with CG & RFG 0% 0%

GVs fueled with CG & RFG 0% 0%

x for Transportation Use US Mix US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
204 

s (Remainder is Herbaceous)

sture Content

dieselelectricity

biomass (farmed trees)

mass (farmed trees)

mass (farmed trees)

 biomass (farmed trees)

n biomass (farmed trees)

nd use change included?

al

o hydrogen production facility

m to hydrogen production facility

om hydrogen production facility to farm (heavy heavy-dut

Value Units

100%

25%

234,964 Btu / dry ton

94%

5.7%

709

g / dry ton

189

g / dry ton

331

g / dry ton

24

g / dry ton

2.0

g / dry ton

No

0 g / dry ton

40 miles

5 mpg diesel5 mpg diesel

Reference Comments

H2A default

Current central H2A production via biomass 

gasification based on Mann, M & Steward, D.M. 

(2008, May 28)

GREET default input

H2A does not specify moisture content so 

GREET's default was used for GREET 

calculations

GREET default input Energy use and fertilizer based on short rotation woody crops (e.g., willow)GREET default inputGREET default inputGREET default input

Equivalent to 75 lb N / ac in the maintenance year

Year 3 or 4) which is reported by De La Torre 

Ugarte, 2003, App 3.1, assuming 6 dry tons 

biomass per acre, and harvesting once every 8 

years. App 3.1 is for planting on cropland that was

just used for traditional crops.

GREET default input

Equivalent to 20 lb P / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb P / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years

GREET default input

Equivalent to 35 lb K / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb K / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years)

GREET default input

Equivalent to 2.0 lb herbicide / ac in the planting 

year which similar to the 2.0 lb glyphosate / ac 

reported by De La Torre Ugarte, 2000, App 3.2, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years. Booth reported 

Trifluralin (5 L/ha) and Metribuzin (395 g/ha). App 

3.2 is for planting on currently idled cropland or 

cropland that was just used for pasture.

GREET default input

As a check, looked at Chastagner: Up to 56% of 

acreage annually sprayed with Dimethoate (Digon

400, 2-3 pints per acre); up to 56% of acreage 

annually sprayed with Permethrin 2LB (Ambush, 

6.4 ounces per acre); Up to 12% of acreage 

annually sprayed with Endosulfan 3 EC (24c WA990025, 2 qts per acre).

GREET default inputGREET default input GREET model default based on ANL personal communicationsGREET default input GREET basis: distance could be limited by transport costs?

GREET default inputGREET default input
205 

Value Units Reference Comments

as (remainder is conventional NG)

s for recovery that is combusted natural gas

y

s for recovery that is combusted shale gas

ncy

processing that is combusted natural gas

ort and distribution

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

199435 g / MMBtu

500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to 

several other models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
206 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
207 

 Central Biomass—Gaseous H2 Truck Delivery Supporting 

igures

d In Central Plant and Transported as Gas via Truck

5,000 Btu Electricity 7,000 Btu8,000 Btu Diesel Electricity for

Forecourt

mass

tricity Hydrogen Gas Hydrogen Gas

ral Gas 118,000 Btu 116,000 Btu

0

138,000 Btu Energy Lost 2,000 Btu 20,000 Btu Energy Lost

HydrogenLost

Case DefinitionYear: 2015Hydrogen as GasCentral Production

37% WOODY BIOMASS Feedstock

Sequestration: NOTransport for Delivery: Gas TruckVehicle Efficiency: 48 mile / GGECity Hydrogen Use: 121096 kg/day

Wheels Greenhouse 

ssions (g/mile)

113

WTP EfficiencyWTP Emissions (lb 

CO2 Equivalent / 

GGE fuel available): 

12

d Cost of H2 at 

/kg) 5.74

Wheels Total Energy 

/mile) 6,495 Production Process Energy Efficiency 46%

Wheels Petroleum 

Use (Btu/mile) 364 Pathway Efficiency 43%

Central Production 

Geologic 

Storage,Terminal, 

and Truck 

Compression, 

Storage, & 

Dispensing 
208 

Biomass moisture content 25%Woody biomass LHV 16,013,000 Btu / dry ton

235,000 Btu / dry ton Biomass price at H2 production $75.02 2007 $ / dry ton

Fraction of Woody Biomass 100% Biomass Share of Levelized Cos $0.97 2007$ / kg H2 dispensed

LUC GHG changes 0 g / dry ton

300 Btu / 116000Btu to Pump Average distance from farm to H2 prod. 40 miles WTG CO2 Emissions -24,850 g CO2 eq./ 116000 Btu

800 Btu / 116000Btu to Pump WTG CH4 Emissions 15 g CO2 eq./ 116000 Btu

3,200 Btu / 116000Btu to Pump WTG N2O Emissions 35 g CO2 eq./ 116000 Btu

WTG GHG Emissions -24,800 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 produced Central plant design capacity 155,200 kg / day Total capital investment $1,300 2007$ / daily kg H2 (effective capacity)1.32 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $0.65 2007$ / kg H2 dispensed

79.3 gal / kg H2 produced Number of production facilities necessary 0.87 Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Process energy efficiency 46.0% Variable O&M Costs $0.40 2007$ / kg H2 dispensed

$181,080,000 2007$ Electricity Mix US Mix Total Levelized Cost $2.25 2007$ / kg H2 dispensed

After-tax IRR 10%

5,200 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 26,620 g CO2 eq./ 116000 Btu

9,700 Btu / 116000Btu to Pump Production CH4 Emissions 140 g CO2 eq./ 116000 Btu

3,700 Btu / 116000Btu to Pump Production N2O Emissions 43 g CO2 eq./ 116000 Btu

Production GHG Emissions 26,800 g CO2 eq./ 116000 BtuTotal capital investment $2,100 2007$ / daily kg delivered

1.31 kWh / kg H2 dispensed Levelized Electricity cost $0.09 2007$ / kg H2 delivered

0.01 kWh / kg H2 dispensed Levelized Diesel cost $0.20 2007$ / kg H2 delivered

1.32 kWh / kg H2 dispensed City Population 1,247,000 people Levelized Labor cost $0.41 2007$ / kg H2 delivered

58.9 gal / 1000 kg H2 Hydrogen Vehicle Penetration 15% Levelized Other operating costs $0.34 2007$ / kg H2 delivered

City hydrogen use 121,100 kg / dayOne-way distance for delivery 62 miles Levelized Cost of Delivery $1.88 2007$ / kg H2 delivered

$254,858,000 2007$ Storage capacity (geologic + terminal) 1,470,000 kg H2

Number of truck-trips required 79,700 per year Delivery CO2 Emissions 910 g CO2 eq./ 116000 Btu

400 Btu / 116000Btu to Pump Truck hydrogen capacity 560 kg / truckload Delivery CH4 Emissions 32 g CO2 eq./ 116000 Btu

1,400 Btu / 116000Btu to Pump Efficiency of truck loading compressors 88.0% Delivery N2O Emissions 7 g CO2 eq./ 116000 Btu

9,800 Btu / 116000Btu to Pump Hydrogen losses 1.0% Delivery GHG Emissions 950 g CO2 eq./ 116000 Btu

Hydrogen outlet pressure 12,700 psi

2.1 kWh / kg H2 Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

$0.096 2007$ / kWh conventional unleaded gasoline)

Average Dispensing Rate per Station 800 kg / day Total capital investment $2,190 2007$ / daily kg

$1,744,000 2007$ / station Number of Dispensing Stations 152 Levelized Cost of Capital $0.95 2007$ / kg H2 dispensed

$265,136,000 2007$ / all stations Number of Compressor Steps 5 Energy & Fuel $0.20 2007$ / kg H2 dispensed

Usable Low Pressure Storage per Station N/A (storage on trucks) Other O&M Costs $0.46 2007$ / kg H2 dispensed

220 psi Usable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing $1.61 2007$ / kg H2 dispensed

16,700 Btu / 116000Btu to Pump Site storage 14% % of design capacity CSD CO2 Emissions 2,310 g CO2 eq./ 116000 Btu

7,400 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 2 CSD CH4 Emissions 140 g CO2 eq./ 116000 Btu

700 Btu / 116000Btu to Pump Hydrogen loss factor 0.50% CSD N2O Emissions 9 g CO2 eq./ 116000 Btu

CSD GHG Emissions 2,470 g CO2 eq./ 116000 BtuCost Per Mile $0.69 2007$ / mi

3,020 lb Fuel Share $0.12 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / miPurchase Year 2015 Financing $0.10 2007$ / miVehicle Purchase Cost $33,700 2007$

2,400 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Vehicle Cycle CO2 Emissions 1,750 g CO2 eq/ gge fuel consumed

12,400 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Vehicle Cycle CH4 Emissions 170 g CO2 eq/ gge fuel consumed

7,700 Btu / gge fuel consumed Tax Credit $0 2007$ Vehicle Cycle N2O Emissions 7 g CO2 eq/ gge fuel consumed

Vehicle Cycle GHG Emissions 1,940 g CO2 eq/ gge fuel consumed

puts Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Gas Trucks for Delivery (with Terminal and Geologic Storage)

Hydrogen Production

Forecourt Dispensing
209 

Conversion Facility Transport Dispensing

Coal 5,243 Btu/116000 Btu Coal 404 Btu/116000 Btu Coal 16,735 Btu/116000 Btu

Natural Gas 9,684 Btu/116000 Btu Natural Gas 1,447 Btu/116000 Btu Natural Gas 7,440 Btu/116000 Btu

Petroleum 3,748 Btu/116000 Btu Petroleum 9,774 Btu/116000 Btu Petroleum 719 Btu/116000 Btu

Total Energy 148,670 Btu/116000 Btu Total Energy 12,907 Btu/116000 Btu Total Energy 29,345 Btu/116000 Btu

CO2 Emissions 26,618 g CO2 eq/116000 Btu CO2 Emissions 906 g CO2 eq/116000 Btu CO2 Emissions 2,314 g CO2 eq/116000 Btu

CH4 Emissions 140 g CO2 eq/116000 Btu CH4 Emissions 32 g CO2 eq/116000 Btu CH4 Emissions 143 g CO2 eq/116000 Btu

N2O Emissions 43 g CO2 eq/116000 Btu N2O Emissions 7 g CO2 eq/116000 Btu N2O Emissions 9 g CO2 eq/116000 Btu

GHG Emissions 26,801 g CO2 eq/116000 Btu GHG Emissions 945 g CO2 eq/116000 Btu GHG Emissions 2,466 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

Btu Coal 22,678Btu Natural Gas 19,337

Btu Gasification & Conversion Transport Dispensing Petroleum 17,453

Btu Total Energy 195,274

6000 Btu Biomass Feedstock 2,126,049 Transport Losses 1.00% Distribution Losses 0.50% CO2 Emissions 4,988

6000 Btu CH4 Emissions 330

6000 Btu N2O Emissions 95

6000 Btu GHG Emissions 5,413
210 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

WOODY BIOMASSGasGas TruckCASCADE_700_BAR

800 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

152

23%

1.94 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput

Case definition: Limited to two deliveries per day

resulting in a maximum of 930 kg/day for gas 

truck dispensing

Input Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM Result Calculated as city hydrogen demand divided by forecourt station size.HDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
211 

s (Remainder is Herbaceous)

sture Content

dieselelectricity

biomass (farmed trees)

mass (farmed trees)

mass (farmed trees)

 biomass (farmed trees)

n biomass (farmed trees)

nd use change included?

al

o hydrogen production facility

m to hydrogen production facility

om hydrogen production facility to farm (heavy heavy-dut

Value Units

100%

25%

234,964 Btu / dry ton

94%

5.7%

709

g / dry ton

189

g / dry ton

331

g / dry ton

24

g / dry ton

2.0

g / dry ton

No

0 g / dry ton

40 miles

6 mpg diesel6 mpg diesel

Reference Comments

H2A default

Current central H2A production via biomass 

gasification based on Mann, M & Steward, D.M. 

(2008, May 28)

GREET default input

H2A does not specify moisture content so 

GREET's default was used for GREET 

calculations

GREET default input Energy use and fertilizer based on short rotation woody crops (e.g., willow)GREET default inputGREET default inputGREET default input

Equivalent to 75 lb N / ac in the maintenance year

Year 3 or 4) which is reported by De La Torre 

Ugarte, 2003, App 3.1, assuming 6 dry tons 

biomass per acre, and harvesting once every 8 

years. App 3.1 is for planting on cropland that was

just used for traditional crops.

GREET default input

Equivalent to 20 lb P / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb P / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years

GREET default input

Equivalent to 35 lb K / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb K / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years)

GREET default input

Equivalent to 2.0 lb herbicide / ac in the planting 

year which similar to the 2.0 lb glyphosate / ac 

reported by De La Torre Ugarte, 2000, App 3.2, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years. Booth reported 

Trifluralin (5 L/ha) and Metribuzin (395 g/ha). App 

3.2 is for planting on currently idled cropland or 

cropland that was just used for pasture.

GREET default input

From Chastagner: Up to 56% of acreage annually

sprayed with Dimethoate (Digon 400, 2-3 pints per

acre); up to 56% of acreage annually sprayed with

Permethrin 2LB (Ambush, 6.4 ounces per acre); 

Up to 12% of acreage annually sprayed with 

Endosulfan 3 EC (24c WA-990025, 2 qts/acre).

GREET default inputGREET default input GREET model default based on ANL personal communicationsGREET default input GREET basis: distance could be limited by transport costs?

GREET default inputGREET default input
212 

Value Units Reference Comments

as (remainder is conventional NG)

s for recovery that is combusted natural gas

y

s for recovery that is combusted shale gas

ncy

processing that is combusted natural gas

ort and distribution

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

124 g / MMBtu500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to 

several other models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
213 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
214 

 Central Biomass—Liquid Truck Delivery and Gaseous 

Supporting Tables and Figures
215 

Biomass moisture content 25%Woody biomass LHV 16,013,000 Btu / dry ton

235,000 Btu / dry ton Biomass price at H2 production $75 2007 $ / dry ton

Fraction of Woody Biomass ='Params - Upstream'!D3 Biomass Share of Levelized Cost $1.00 2007$ / kg H2 dispensedLUC GHG changes ='Params - U g / dry ton

200 Btu / 116000Btu to Pump Average distance from farm to H2 prod. ='Params - U miles WTG CO2 Emissions -25,540 g CO2 eq./ 116000 Btu

600 Btu / 116000Btu to Pump WTG CH4 Emissions 13 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump WTG N2O Emissions 36 g CO2 eq./ 116000 Btu

WTG GHG Emissions -25,490 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 produced Central plant design capacity 155,200 kg / day Total capital investment $1,300 2007$ / daily kg H2 (effective capacity)

1.32 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $0.66 2007$ / kg H2 dispensed79.3 gal / kg H2 produced Number of production facilities necessary 0.87 Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

Process energy efficiency 46.0% Variable O&M Costs $0.41 2007$ / kg H2 dispensed

$181,080,000 2007$ Electricity Mix US Mix Total Levelized Cost $2.30 2007$ / kg H2 dispensed

After-tax IRR 10%

5,300 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 27,230 g CO2 eq./ 116000 Btu9,700 Btu / 116000Btu to Pump Production CH4 Emissions 140 g CO2 eq./ 116000 Btu3,300 Btu / 116000Btu to Pump Production N2O Emissions 44 g CO2 eq./ 116000 Btu

Production GHG Emissions 27,410 g CO2 eq./ 116000 BtuTotal capital investment $1,980 2007$ / daily kg H2 (effective capacity)

8.5 kWh / kg H2 dispensed Levelized Electricity cost $0.58 2007$ / kg H2 dispensed

0.03 kWh / kg H2 dispensed Levelized Diesel cost $0.03 2007$ / kg H2 dispensed

8.57 kWh / kg H2 dispensed City Population 1,247,000 people Levelized Labor cost $0.09 2007$ / kg H2 dispensed

7.6 gal / 1000 kg H2 dispensed Hydrogen Vehicle Penetration 15% Levelized Other operating costs $0.24 2007$ / kg H2 dispensed

City hydrogen use 121,100 kg / day

$239,448,000 2007$ One-way distance for delivery 98 miles Levelized Cost of Delivery $1.80 2007$ / kg H2 delivered

Terminal Design Capacity 1,103,000 kg H2Number of truck-trips required per year 10,200

51,700 Btu / 116000Btu to Pump Truck hydrogen capacity 4,400 kg / truckload Delivery CO2 Emissions 7,220 g CO2 eq./ 116000 Btu

23,000 Btu / 116000Btu to Pump Liquefaction energy efficiency 79.3% Delivery CH4 Emissions 440 g CO2 eq./ 116000 Btu

3,000 Btu / 116000Btu to Pump Hydrogen losses 2.8% Delivery N2O Emissions 30 g CO2 eq./ 116000 Btu

Delivery GHG Emissions 7,690 g CO2 eq./ 116000 BtuOnboard Storage Pressure 12,700 psi

0.51 kWh / kg H2 dispensed Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

Average Dispensing Rate per Station 1,000 kg / day Total capital investment $1,330 2007$ / daily kg H2 (effective capacity)

$1,315,000 2007$ / station Number of Dispensing Stations 122 Levelized Cost of Capital $0.49 2007$ / kg H2 dispensed

$160,485,000 2007$ / all stations Number of Cascade Pumps 1 Energy & Fuel $0.05 2007$ / kg H2 dispensed

Liquid H2 storage capacity per Station 4,600 kg H2 Other O&M Costs $0.48 2007$ / kg H2 dispensedUsable Cascade Storage per Station 70 kg H2 Levelized Cost of Dispensing $1.02 2007$ / kg H2 dispensed

ncluded in Delivery Section Site storage 400% % of design capacity CSD CO2 Emissions Included in Delivery Section

ncluded in Delivery Section # of 2-hose Dispensers per Station 2 CSD CH4 Emissions Included in Delivery Section

ncluded in Delivery Section Hydrogen Losses 1.1% CSD N2O Emissions Included in Delivery Section

CSD GHG Emissions Included in Delivery SectionCost Per Mile $0.67 2007$ / mi

3,020 lb Fuel Share $0.11 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / miPurchase Year 2015 Financing $0.10 2007$ / miVehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Veh. Cycle CO2 Emissions 1,670 g CO2 eq/ gge fuel consumed

12,100 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Veh. Cycle CH4 Emissions 170 g CO2 eq/ gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle N2O Emissions 6 g CO2 eq/ gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g CO2 eq/ gge fuel consumed

Forecourt Dispensing

uts Outputs

Vehicle

Biomass Production & Delivery

Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production
216 

Gasification Liquefaction Transport Storage / Dispensing

Coal 5,262 Btu/116000 Btu Coal 51,701 Btu/116000 Btu Coal 14 Btu/116000 Btu Coal 0 Btu/116000 Btu

Natural Gas 9,735 Btu/116000 Btu Natural Gas 22,921 Btu/116000 Btu Natural Gas 120 Btu/116000 Btu Natural Gas 0 Btu/116000 Btu

Petroleum 3,257 Btu/116000 Btu Petroleum 1,961 Btu/116000 Btu Petroleum 1,047 Btu/116000 Btu Petroleum 0 Btu/116000 Btu

CO2 Emissions 27,225 g CO2 eq/116000 Btu CO2 Emissions 7,126 g CO2 eq/116000 Btu CO2 Emissions 93 g CO2 eq/116000 Btu CO2 Emissions 0 g CO2 eq/116000 Btu

CH4 Emissions 141 g CO2 eq/116000 Btu CH4 Emissions 440 g CO2 eq/116000 Btu CH4 Emissions 3 g CO2 eq/116000 Btu CH4 Emissions 0 g CO2 eq/116000 Btu

N2O Emissions 44 g CO2 eq/116000 Btu N2O Emissions 29 g CO2 eq/116000 Btu N2O Emissions 1 g CO2 eq/116000 Btu N2O Emissions 0 g CO2 eq/116000 Btu

GHG Emissions 27,410 g CO2 eq/116000 Btu GHG Emissions 7,596 g CO2 eq/116000 Btu GHG Emissions 97 g CO2 eq/116000 Btu GHG Emissions 0 g CO2 eq/116000 Btu

Gasification & Conversion Liquefaction Transport Storage / Dispensing

0 Btu

0 Btu Liquefaction Losses 0.50% Transport Losses 2.32% Storage Losses 1.15%

0 Btu

0 Btu
217 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

WOODY BIOMASSLiquidLiquid TruckLH2_TO_GH2

1000 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

122

19%

2.17 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
218 

s (Remainder is Herbaceous)

sture Content

dieselelectricity

biomass (farmed trees)

mass (farmed trees)

mass (farmed trees)

 biomass (farmed trees)

n biomass (farmed trees)

nd use change included?

al

o hydrogen production facility

m to hydrogen production facility

om hydrogen production facility to farm (heavy heavy-dut

Value Units

100%

25%

234,964 Btu / dry ton

94%

5.7%

709

g / dry ton

189

g / dry ton

331

g / dry ton

24

g / dry ton

2.0

g / dry ton

No

0 g / dry ton

40 miles

6 mpg diesel6 mpg diesel

Reference Comments

H2A default

Current central H2A production via biomass 

gasification based on Mann, M & Steward, D.M. 

(2008, May 28)

GREET default input

H2A does not specify moisture content so 

GREET's default was used for GREET 

calculations

GREET default input Energy use and fertilizer based on short rotation woody crops (e.g., willow)GREET default inputGREET default inputGREET default input

Equivalent to 75 lb N / ac in the maintenance year

Year 3 or 4) which is reported by De La Torre 

Ugarte, 2003, App 3.1, assuming 6 dry tons 

biomass per acre, and harvesting once every 8 

years. App 3.1 is for planting on cropland that was

just used for traditional crops.

GREET default input

Equivalent to 20 lb P / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb P / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years

GREET default input

Equivalent to 35 lb K / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb K / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years)

GREET default input

Equivalent to 2.0 lb herbicide / ac in the planting 

year which similar to the 2.0 lb glyphosate / ac 

reported by De La Torre Ugarte, 2000, App 3.2, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years. Booth reported 

Trifluralin (5 L/ha) and Metribuzin (395 g/ha). App 

3.2 is for planting on currently idled cropland or 

cropland that was just used for pasture.

GREET default input

From Chastagner: Up to 56% of acreage annually

sprayed with Dimethoate (Digon 400, 2-3 pints per

acre); up to 56% of acreage annually sprayed with

Permethrin 2LB (Ambush, 6.4 ounces per acre); 

Up to 12% of acreage annually sprayed with 

Endosulfan 3 EC (24c WA-990025, 2 qts/acre).

GREET default inputGREET default input GREET model default based on ANL personal communicationsGREET default input GREET basis: distance could be limited by transport costs?

GREET default inputGREET default input
219 

Value Units Reference Comments

as (remainder is conventional NG)

s for recovery that is combusted natural gas

y

s for recovery that is combusted shale gas

ncy

processing that is combusted natural gas

ort and distribution

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

124 g / MMBtu500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to 

several other models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
220 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
221 

 Central Biomass—Liquid Truck Delivery and Cryo

 Dispensing Supporting Tables and Figures
222 

Biomass moisture content 25%Woody biomass LHV 16,013,000 Btu / dry ton

235,000 Btu / dry ton Biomass price at H2 production $75 2007 $ / dry ton

Fraction of Woody Biomass 100% Biomass Share of Levelized Cos $1.02 2007$ / kg H2 dispensed

LUC GHG changes 0 g / dry ton

200 Btu / 116000Btu to Pump Average distance from farm to H2 prod. 40 miles WTG CO2 Emissions -26,040 g CO2 eq./ 116000 Btu

600 Btu / 116000Btu to Pump WTG CH4 Emissions 13 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump WTG N2O Emissions 36 g CO2 eq./ 116000 Btu

WTG GHG Emissions -25,990 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

13.5 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0059 MMBtu / kg H2 produced

0.98 kWh / kg H2 Central plant design capacity 155,200 kg / day Total capital investment $1,300 2007$ / daily kg H2 (effective capacity)

1.32 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $0.67 2007$ / kg H2 dispensed

79.3 gal / kg H2 produced Number of production facilities 0.87 Fixed O&M Costs $0.24 2007$ / kg H2 dispensed

Process energy efficiency 46.0% Variable O&M Costs $0.42 2007$ / kg H2 dispensed

$181,080,000 2007$ Electricity Mix US Mix Total Levelized Cost $2.35 2007$ / kg H2 dispensed

After-tax IRR 10%

5,400 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 27,800 g CO2 eq./ 116000 Btu9,900 Btu / 116000Btu to Pump Production CH4 Emissions 140 g CO2 eq./ 116000 Btu

3,300 Btu / 116000Btu to Pump Production N2O Emissions 45 g CO2 eq./ 116000 Btu

Production GHG Emissions 28,000 g CO2 eq./ 116000 Btu

8.5 kWh / kg H2 Total capital investment $2,000 2007$ / daily kg delivered

0.02 kWh / kg H3 Levelized Electricity cost $0.59 2007$ / kg H2 delivered

8.5 kWh / kg H4 City Population 1,247,000 people Levelized Diesel cost $0.03 2007$ / kg H2 delivered7.7 gal / 1000 kg H2 Hydrogen Vehicle Penetration 15% Levelized Labor cost $0.09 2007$ / kg H2 delivered

City hydrogen use 121,100 kg / day Levelized Other operating costs $0.24 2007$ / kg H2 delivered

$242,361,000 2007$ One-way distance for delivery 98 miles

Terminal Design Capacity 1,124,000 kg H2 Levelized Cost of Delivery $1.82 2007$ / kg H2 delivered

Number of truck-trips required 10,400

52,400 Btu / 116000Btu to Pump Truck hydrogen capacity 4,400 kg / truckload Delivery CO2 Emissions 7,320 g CO2 eq./ 116000 Btu23,400 Btu / 116000Btu to Pump Liquefaction energy efficiency 79.3% Delivery CH4 Emissions 450 g CO2 eq./ 116000 Btu

3,000 Btu / 116000Btu to Pump Hydrogen losses 2.8% Delivery N2O Emissions 30 g CO2 eq./ 116000 Btu

Delivery GHG Emissions 7,800 g CO2 eq./ 116000 BtuHydrogen outlet pressure 12,700 psi

0.49 kWh / kg H2 Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

Total Hydrogen Dispensed 1,000 kg / day Total capital investment $2,120 2007$ / daily kg

$2,100,000 2007$ / station Number of Dispensing Stations 122 Levelized Cost of Capital $0.90 2007$ / kg H2 dispensed

$256,147,000 2007$ / all stations Number of Cascade Pumps 1 Energy & Fuel $0.05 2007$ / kg H2 dispensed

Liquid H2 storage capacity per Station 4,600 kg H2 Other O&M Costs $0.61 2007$ / kg H2 dispensedUsable Cascade Storage per Station 0 kg H2 Levelized Cost of Dispensing $3.38 2007$ / kg H2 dispensed

ncluded in Delivery Section Site storage 390% % of design capacity CSD CO2 Emissions Included in Delivery Section

ncluded in Delivery Section # of 2-hose Dispensers per Station 2 CSD CH4 Emissions Included in Delivery Section

ncluded in Delivery Section Hydrogen losses 3.1% CSD N2O Emissions Included in Delivery Section

CSD GHG Emissions Included in Delivery SectionCost Per Mile $0.69 2007$ / mi

3,020 lb Fuel Share $0.12 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / mi

Purchase Year 2015 Financing $0.10 2007$ / miVehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Veh. Cycle CO2 Emissions 1,670 g / gge fuel consumed

12,100 Btu / gge fuel consumed Storage System Cost (assume 700Bar $2,400 2007$ Veh. Cycle CH4 Emissions 170 g / gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle N2O Emissions 6 g / gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g / gge fuel consumed

puts Outputs

Vehicle

Biomass Production & Delivery

 Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production

Cryo-Compressed Dispensing
223 

Gasification Liquefaction Transport Storage / Dispensing

Coal 5,366 Btu/116000 Btu Coal 52,430 Btu/116000 Btu Coal 14 Btu/116000 Btu Coal 0 Btu/116000 Btu

Natural Gas 9,927 Btu/116000 Btu Natural Gas 23,245 Btu/116000 Btu Natural Gas 120 Btu/116000 Btu Natural Gas 0 Btu/116000 Btu

Petroleum 3,321 Btu/116000 Btu Petroleum 1,989 Btu/116000 Btu Petroleum 1,047 Btu/116000 Btu Petroleum 0 Btu/116000 Btu

CO2 Emissions 27,763 g CO2 eq/116000 Btu CO2 Emissions 7,227 g CO2 eq/116000 Btu CO2 Emissions 93 g CO2 eq/116000 Btu CO2 Emissions 0 g CO2 eq/116000 Btu

CH4 Emissions 144 g CO2 eq/116000 Btu CH4 Emissions 447 g CO2 eq/116000 Btu CH4 Emissions 3 g CO2 eq/116000 Btu CH4 Emissions 0 g CO2 eq/116000 Btu

N2O Emissions 45 g CO2 eq/116000 Btu N2O Emissions 29 g CO2 eq/116000 Btu N2O Emissions 1 g CO2 eq/116000 Btu N2O Emissions 0 g CO2 eq/116000 Btu

GHG Emissions 27,952 g CO2 eq/116000 Btu GHG Emissions 7,703 g CO2 eq/116000 Btu GHG Emissions 97 g CO2 eq/116000 Btu GHG Emissions 0 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

Coal 58,018

Natural Gas 33,921

Gasification & Conversion Liquefaction Transport Storage / Dispensing Petroleum 9,197

u CO2 Emissions 9,043

u Biomass Feedstock 262,956 Liquefaction Losses 0.50% Transport Losses 2.32% Storage Losses 3.07% CH4 Emissions 607

u N2O Emissions 111

u GHG Emissions 9,760
224 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

WOODY BIOMASSLiquidLiquid TruckCRYOCOMPRESSE

D

1000 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

122

19%

2.17 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
225 

s (Remainder is Herbaceous)

sture Content

dieselelectricity

biomass (farmed trees)

mass (farmed trees)

mass (farmed trees)

 biomass (farmed trees)

n biomass (farmed trees)

nd use change included?

al

o hydrogen production facility

m to hydrogen production facility

om hydrogen production facility to farm (heavy heavy-dut

Value Units

100%

25%

234,964 Btu / dry ton

94%

5.7%

709

g / dry ton

189

g / dry ton

331

g / dry ton

24

g / dry ton

2.0

g / dry ton

No

0 g / dry ton

40 miles

6 mpg diesel6 mpg diesel

Reference Comments

H2A default

Current central H2A production via biomass 

gasification based on Mann, M & Steward, D.M. 

(2008, May 28)

GREET default input

H2A does not specify moisture content so 

GREET's default was used for GREET 

calculations

GREET default input Energy use and fertilizer based on short rotation woody crops (e.g., willow)GREET default inputGREET default inputGREET default input

Equivalent to 75 lb N / ac in the maintenance year

Year 3 or 4) which is reported by De La Torre 

Ugarte, 2003, App 3.1, assuming 6 dry tons 

biomass per acre, and harvesting once every 8 

years. App 3.1 is for planting on cropland that was

just used for traditional crops.

GREET default input

Equivalent to 20 lb P / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb P / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years

GREET default input

Equivalent to 35 lb K / ac in the maintenance year

(Year 3) which is in the range of 15-50 lb K / ac 

reported by De La Torre Ugarte, 2003, App 3.1, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years)

GREET default input

Equivalent to 2.0 lb herbicide / ac in the planting 

year which similar to the 2.0 lb glyphosate / ac 

reported by De La Torre Ugarte, 2000, App 3.2, 

assuming 6 dry tons biomass per acre and 

harvesting once every 8 years. Booth reported 

Trifluralin (5 L/ha) and Metribuzin (395 g/ha). App 

3.2 is for planting on currently idled cropland or 

cropland that was just used for pasture.

GREET default input

From Chastagner: Up to 56% of acreage annually

sprayed with Dimethoate (Digon 400, 2-3 pints per

acre); up to 56% of acreage annually sprayed with

Permethrin 2LB (Ambush, 6.4 ounces per acre); 

Up to 12% of acreage annually sprayed with 

Endosulfan 3 EC (24c WA-990025, 2 qts/acre).

GREET default inputGREET default input GREET model default based on ANL personal communicationsGREET default input GREET basis: distance could be limited by transport costs?

GREET default inputGREET default input
226 

Value Units Reference Comments

as (remainder is conventional NG)

s for recovery that is combusted natural gas

y

s for recovery that is combusted shale gas

ncy

processing that is combusted natural gas

ort and distribution

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

124 g / MMBtu500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to 

several other models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
227 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
228 

 Central Natural Gas—Pipeline Delivery Supporting Tables and 
229 

NG Delivery Pressure Average of gas companiesNG Quality at Delivery Average of gas companies

NG Recovery Efficiency 95.7% NG Cost in 2015 $6.09 2007 $ / mmBTUNG emitted during recovery 400 g / MMbtu NG NG Share of Levelized Cost $1.52 2007$ / kg H2 dispensedNG processing energy efficiency 97.2%

200 Btu / 116000Btu to Pump NG emitted during processing 30 g / MMbtu NG WTG CO2 Emissions 600 g CO2 eq./ 116000 Btu

m) 125,600 Btu / 116000Btu to Pump NG emitted during transport 199,400 g / MMbtu NG WTG CH4 Emissions 1,260 g CO2 eq./ 116000 Btu

) 500 Btu / 116000Btu to Pump NG transport distance 500 miles WTG N2O Emissions 3 g CO2 eq./ 116000 Btu

WTG GHG Emissions 1,870 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

0.1564 MMBtu/kg H2 produced Hydrogen Outlet Quality 99.9%

0.57 kWh / kg H23.36 gal / kg H2 Central plant design capacity 379,400 kg / day Total capital investment $632 2007$ / daily kg H2 (effective capacity)

1.50 gal / kg H2 Capacity factor p 90% Levelized Cost of Capital $0.34 2007$ / kg H2 dispensed

necessary 0.35 Fixed O&M Costs $0.06 2007$ / kg H2 dispensed

$215,844,000 2007$ Process energy efficiency 71.9% Variable O&M Costs $0.08 2007$ / kg H2 dispensed

Electricity Mix US Mix Total Levelized Cost $2.00 2007$ / kg H2 dispensedAfter-tax IRR 10%

2,900 Btu / 116000Btu to Pump Assumed Plant Life 40 SMR CO2 Emissions 10,200 g CO2 eq./ 116000 Btu

m) 48,800 Btu / 116000Btu to Pump SMR CH4 Emissions 500 g CO2 eq./ 116000 Btu

) 300 Btu / 116000Btu to Pump SMR N2O Emissions 12 g CO2 eq./ 116000 Btu

SMR GHG Emissions 10,700 g CO2 eq./ 116000 Btu

sor 0.56 kWh / kg H2 produced Total capital investment $3,340 2007$ / daily kg H2 (effective capacity)

age 0.01 kWh / kg H2 produced

0.57 kWh / kg H2 produced City Population 1,247,000 people Levelized Cost of Capital $1.71 2007$ / kg H2 dispensed

Hydrogen Vehicle Penetration 15% Energy & Fuel $0.04 2007$ / kg H2 dispensedCity hydrogen use 121,100 kg / day Other O&M Costs $0.40 2007$ / kg H2 dispensed

$404,341,000 2007$ Distance from City to Production Facility 62 miles Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Geologic storage capacity 1,324,700 kg H2Number of trunk pipelines 3 Delivery CO2 Emissions 390 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump Service-line length 1.5 miles / line Delivery CH4 Emissions 24 g CO2 eq./ 116000 Btu

m) 2,200 Btu / 116000Btu to Pump Number of service lines 122 Delivery N2O Emissions 2 g CO2 eq./ 116000 Btu

) 100 Btu / 116000Btu to Pump Hydrogen losses 0.80% Delivery GHG Emissions 420 g CO2 eq./ 116000 Btu

Hydrogen outlet pressure 12,700 psi

4.4 kWh / kg H2 produced Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

$2,629,000 2007$ / station Average Dispensing Rate per Station 1,000 kg / day Total capital investment $2,650 2007$ / daily kg H2 (effective capacity)

$320,679,000 2007$ / all stations Number of Dispensing Stations 122 Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Number of Compression Steps 5 Energy & Fuel $0.41 2007$ / kg H2 dispensed

s 300 psi Usable Low Pressure Storage per Station 370 kg H2 Other O&M Costs $0.43 2007$ / kg H2 dispensed

Usable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

24,400 Btu / 116000Btu to Pump Site storage 42% % of design capacity CSD CO2 Emissions 3,370 g CO2 eq./ 116000 Btu

m) 10,800 Btu / 116000Btu to Pump # 2-hose Dispensers per Station 2 CSD CH4 Emissions 210 g CO2 eq./ 116000 Btu

) 900 Btu / 116000Btu to Pump Hydrogen Losses 0.50% CSD N2O Emissions 14 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,590 g CO2 eq./ 116000 BtuCost Per Mile $0.69 2007$ / mi

3,020 lb Fuel Share $0.13 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / miPurchase Year 2015 Financing $0.10 2007$ / mi

Vehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Veh. Cycle CO2 Emissions 1,670 g CO2 eq / gge fuel consumed

m) 12,100 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Veh. Cycle CH4 Emissions 170 g CO2 eq / gge fuel consumed

) 6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Veh. Cycle N2O Emissions 6 g CO2 eq / gge fuel consumed

Veh. Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

Inputs Outputs

Vehicle

NG Recovery, Processing, & Transport

Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Dispensing
230 

Conversion Facility Transport Dispensing

Coal 2,919 Btu/116000 Btu Coal 2,825 Btu/116000 Btu Coal 24,444 Btu/116000 Btu

Natural Gas 48,778 Btu/116000 Btu Natural Gas 2,153 Btu/116000 Btu Natural Gas 10,837 Btu/116000 Btu

Petroleum 286 Btu/116000 Btu Petroleum 107 Btu/116000 Btu Petroleum 928 Btu/116000 Btu

Total Energy 52,759 Btu/116000 Btu Total Energy 5,837 Btu/116000 Btu Total Energy 42,710 Btu/116000 Btu

CO2 Emissions 10,194 g CO2 eq/116000 Btu CO2 Emissions 389 g CO2 eq/116000 Btu CO2 Emissions 3,369 g CO2 eq/116000 Btu

CH4 Emissions 498 g CO2 eq/116000 Btu CH4 Emissions 24 g CO2 eq/116000 Btu CH4 Emissions 208 g CO2 eq/116000 Btu

N2O Emissions 12 g CO2 eq/116000 Btu N2O Emissions 2 g CO2 eq/116000 Btu N2O Emissions 14 g CO2 eq/116000 Btu

GHG Emissions 10,703 g CO2 eq/116000 Btu GHG Emissions 415 g CO2 eq/116000 Btu GHG Emissions 3,591 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

Btu Coal 30,397

Btu Natural Gas 187,368

Btu Reforming Transport Dispensing Petroleum 1,797

Btu Total Energy 227,647

6000 Btu NG Feedstock 161,546 Transport Losses 0.77% Distribution Losses 0.50% CO2 Emissions 14,551

6000 Btu CH4 Emissions 1,994

6000 Btu N2O Emissions 30

6000 Btu GHG Emissions 16,575
231 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

NATURAL GASGasPipelineCASCADE_700_BAR

1000 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

122

19%

2.17 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
232 

Value Units Reference Comments

as (remainder is conventional NG)

s for recovery that is combusted natural gas

y

s for recovery that is combusted shale gas

ncy

processing that is combusted natural gas

ort and distribution

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

32.1%95.7%

399 g/MMBtu

49.0%96.5%

245 g/MMBtu

57.4%97.2%

33 g/MMBtu

90.7%

199434 g / MMBtu

500 miles

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

GREET default inputGREET default inputGREET default input Previously reported at percent of total NG not on a MMBtu basisGREET default inputGREET default inputGREET default inputGREET default inputWang, M.Q. (1999, August). GREET 1.5 - 

Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. 

Argonne, IL: Argonne National Laboratory.

GREET uses 97.5% which is comparable to 

several other models (Table 4.11)

GREET default inputGREET default inputGREET default inputGREET default inputGREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
233 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
234 

Central Wind Electricity—Pipeline Delivery Supporting Tables 

Central Plant and Transported as Gas via Pipeline

2,000 Btu 15,000 Btu

Electricity for Electricity forCompression Forecourt

Hydrogen Gas Hydrogen Gas

118,000 Btu 116,000 Btu

0

59,000 Btu Energy Lost 1,000 Btu 17,000 Btu Energy Lost

HydrogenLost

Case DefinitionYear: 2015Hydrogen as GasCentral Production

52% WIND Feedstock

Sequestration: NOTransport for Delivery: PipelineVehicle Efficiency: 48 mile / GGECity Hydrogen Use: 121096 kg/day

 Greenhouse 

 (g/mile)

84

WTP Efficiency (

CO2 Equivalent / 

GGE fuel available): 

GHG

9

 of H2 at 

8.41

 Total Energy 

4,672 Production Process Energy Efficiency 67%

 Petroleum 

u/mile) 22 Pathway Efficiency 60%

Central Production Compression & Pipeline Compression, Storage, & Dispensing 
235 

Electricity price at prod. facility $0.0574 2007$ / kWh 

Green credits for wind-generated electricity on the grid are assumed. Electricity $3.37 2007$ / kg H2 dispensedThe electrolyzers are not necessarily co-located with the wind farm.

0 Btu / 116000Btu to Pump A high capacity factor is available due to use of green credits. WTG CO2 Emissions 0 g CO2 eq./ 116000 Btu

0 Btu / 116000Btu to Pump WTG CH4 Emissions 0 g CO2 eq./ 116000 Btu0 Btu / 116000Btu to Pump WTG N2O Emissions 0 g CO2 eq./ 116000 Btu

WTG GHG Emissions 0 g CO2 eq./ 116000 BtuHydrogen Output Pressure 300 psi

50.0 kWh / kg H2 produced Hydrogen Outlet Quality 99.9%

2.94 gal / kg H2 produced

294 gal / kg H2 produced Central plant design capacity 52,300 kg / day Total capital investment $1,320 2007$ / daily kg H2 (effective capacity)

Capacity factor 98% Levelized Cost of Capital $0.67 2007$ / kg H2 dispensedNumber of production facilities necessary 2.36 Fixed O&M Costs $0.23 2007$ / kg H2 dispensed

$67,634,000 2007$ Process energy efficiency 66.7% Variable O&M Costs $0.06 2007$ / kg H2 dispensed

Electricity Mix US Mix Total Levelized Cost $4.33 2007$ / kg H2 dispensed

After-tax IRR 10%

0 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 0 g CO2 eq./ 116000 Btu

0 Btu / 116000Btu to Pump Production CH4 Emissions 0 g CO2 eq./ 116000 Btu

0 Btu / 116000Btu to Pump Production N2O Emissions 0 g CO2 eq./ 116000 Btu

Production GHG Emissions 0 g CO2 eq./ 116000 Btu

0.56 kWh / kg H2 dispensed Total capital investment $3,340 2007$ / daily kg H2 (effective capacity)

0.01 kWh / kg H2 dispensed

0.57 kWh / kg H2 dispensed City Population 1,247,000 people Levelized Cost of Delivery $1.71 2007$ / kg H2 dispensed

Hydrogen Vehicle Penetration 15% Energy & Fuel $0.04 2007$ / kg H2 dispensedCity hydrogen use 121,100 kg / day Other O&M Costs $0.40 2007$ / kg H2 dispensed

$404,341,000 2007$ Distance from City to Production Facility 62 miles Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Geologic storage capacity 1,324,700 kg H2Number of trunk pipelines 3 Delivery CO2 Emissions 390 g CO2 eq./ 116000 Btu

2,800 Btu / 116000Btu to Pump Service-line length 1.5 miles / line Delivery CH4 Emissions 24 g CO2 eq./ 116000 Btu1,300 Btu / 116000Btu to Pump Number of service lines 122 Delivery N2O Emissions 2 g CO2 eq./ 116000 Btu

100 Btu / 116000Btu to Pump Hydrogen losses 0.80% Delivery GHG Emissions 420 g CO2 eq./ 116000 Btu

Hydrogen outlet pressure 12,700 psi

4.4 kWh / kg H2 dispensed Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

$2,629,000 2007$ / station Average Dispensing Rate per Station 1,000 kg/day Total capital investment $2,650 2007$ / daily kg H2 (effective capacity)

$320,679,000 2007$ / all stations Number of Dispensing Stations 122 Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Number of Compression Steps 5 Energy & Fuel $0.41 2007$ / kg H2 dispensed

300 psi Useable Low Pressure Storage per Statio 370 kg H2 Other O&M Costs $0.43 2007$ / kg H2 dispensed

Useable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

24,500 Btu / 116000Btu to Pump Site storage 42% % of design capacity CSD CO2 Emissions 3,370 g CO2 eq./ 116000 Btu

10,800 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 2 CSD CH4 Emissions 210 g CO2 eq./ 116000 Btu

900 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD N2O Emissions 14 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,590 g CO2 eq./ 116000 BtuCost Per Mile $0.74 2007$ / mi

3,020 lb Fuel Share $0.18 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi

30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / mi

Purchase Year 2015 Financing $0.10 2007$ / mi

Vehicle Purchase Cost $33,700 2007$

2,400 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Vehicle Cycle CO2 Emissions 1,680 g CO2 eq / gge fuel consumed

12,100 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Vehicle Cycle CH4 Emissions 170 g CO2 eq / gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Vehicle Cycle N2O Emissions 6 g CO2 eq / gge fuel consumed

Vehicle Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

puts Outputs

Vehicle

Wind Electricity

Assumptions

Pipelines for DeliveryHydrogen Production

Forecourt Dispensing
236 

Conversion Facility Transport Dispensing

Coal 0 Btu/116000 Btu Coal 2,826 Btu/116000 Btu Coal 24,454 Btu/116000 Btu

Natural Gas 0 Btu/116000 Btu Natural Gas 1,252 Btu/116000 Btu Natural Gas 10,833 Btu/116000 Btu

Petroleum 0 Btu/116000 Btu Petroleum 107 Btu/116000 Btu Petroleum 929 Btu/116000 Btu

Total Energy 58,761 Btu/116000 Btu Total Energy 4,938 Btu/116000 Btu Total Energy 42,720 Btu/116000 Btu

CO2 Emissions 0 g CO2 eq/116000 Btu CO2 Emissions 390 g CO2 eq/116000 Btu CO2 Emissions 3,370 g CO2 eq/116000 Btu

CH4 Emissions 0 g CO2 eq/116000 Btu CH4 Emissions 24 g CO2 eq/116000 Btu CH4 Emissions 208 g CO2 eq/116000 Btu

N2O Emissions 0 g CO2 eq/116000 Btu N2O Emissions 2 g CO2 eq/116000 Btu N2O Emissions 14 g CO2 eq/116000 Btu

GHG Emissions 0 g CO2 eq/116000 Btu GHG Emissions 415 g CO2 eq/116000 Btu GHG Emissions 3,592 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

6000 Btu Coal 27,280

6000 Btu Natural Gas 12,085

6000 Btu Electrolysis Transport Dispensing Petroleum 1,036

6000 Btu Total Energy 223,902

2 eq/116000 Btu Electricity Feedstock 174,019 Transport Losses 0.77% Distribution Losses 0.50% CO2 Emissions 3,760

2 eq/116000 Btu CH4 Emissions 232

2 eq/116000 Btu N2O Emissions 15

2 eq/116000 Btu GHG Emissions 4,007
237 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

WINDGasPipelineCASCADE_700_BAR

1000 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

122

19%

2.17 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
238 

Value Units Reference Comments

SD

on

on

utral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

d Efficiency

mass Power Plants of Biomass Power Plants

ciency

on Plant Efficiency

 of Biopower Plants

ficiency

al Power Plants

 of Coal Power Plants

cy

Plant Efficiency

 of Coal-Electricity Plants

s and Efficiency

Turbine Share of Natural Gas Power Plants

as Turbine Share of Natural Gas Power Plants

 Share of Natural Gas Power Plants

e Cycle Gas Turbine Plant Efficiency

ined Cycle Efficiencyustion Boiler Plant Efficiency

 of Natural Gas-Electricity Plants

ncy

city Plant Efficiency

stribution Losses

Green - Zero 

Carbon

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

Case Definition

GREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
239 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available
240 

Central Coal with Carbon Capture and Storage—Pipeline

pporting Tables and Figures

Central Plant and Transported as Gas via Pipeline

2,000 Btu 15,000 Btu

Electricity for Electricity forCompression Forecourt

Hydrogen Gas Hydrogen Gas

118,000 Btu 116,000 Btu

0

89,000 Btu Energy Lost 1,000 Btu 17,000 Btu Energy Lost

HydrogenLost

Case DefinitionYear: 2015Hydrogen as GasCentral Production

42% COAL Feedstock

Sequestration: YESTransport for Delivery: PipelineVehicle Efficiency: 48 mile / GGECity Hydrogen Use: 121096 kg/day

Hydrogen Production cost in 2005$

 Total Energy 

5,800 Production Process Energy Efficiency 57%

 Petroleum 

u/mile) 59 Pathway Efficiency 52%

 Greenhouse 

 (g/mile)

199

WTP Efficiency (

CO2 Equivalent / 

GGE fuel available): 

GHG

21

 of H2 at 

6.14

Central Production Compression & Pipeline Compression, Storage, & Dispensing 
241 

Coal price at H2 production $34 2007 $ / tonCoal Share of Levelized Cost $0.30 2007$ / kg H2 dispensed

Energy Recovery 99.3%

WTG CO2 Emissions 110 g CO2 eq./ 116000 Btu

116,400 Btu / 116000Btu to Pump WTG CH4 Emissions 430 g CO2 eq./ 116000 Btu

200 Btu / 116000Btu to Pump WTG N2O Emissions 1 g CO2 eq./ 116000 Btu

700 Btu / 116000Btu to Pump Average distance from coal mine to H2 prod. 65 miles WTG GHG Emissions 540 g CO2 eq./ 116000 Btu

Hydrogen Output Pressure 300 psi

7.8 kg (dry) / kg H2 produced Hydrogen Outlet Quality 99.9%

0.0 MMBtu/kg H2 produced

1.72 kWh / kg H2 Central plant design capacity 307,700 kg / day Total capital investment $2,500 2005$ / daily kg H2 (effective capacity)2.91 gal / kg H2 produced Capacity factor 90% Levelized Cost of Capital $1.29 2005$ / kg H2 dispensed0.00 gal / kg H2 produced Number of production facilities necessary 0.44 Fixed O&M Costs $0.30 2005$ / kg H2 dispensed

Process energy efficiency 56.8% Variable O&M Costs $0.18 2005$ / kg H2 dispensed

$691,378,000 2005$ Electricity Mix US Mix Total Levelized Cost $2.06 2005$ / kg H2 dispensed

After-tax IRR 10%

99,400 Btu / 116000Btu to Pump Assumed Plant Life 40 Production CO2 Emissions 4,510 g CO2 eq./ 116000 Btu

7,200 Btu / 116000Btu to Pump CO2 Captured for Sequestration 90% Production CH4 Emissions 440 g CO2 eq./ 116000 Btu

1,100 Btu / 116000Btu to Pump CO2 Captured for Sequestration 4,925,000 kg CO2 / day ProductionN2O Emissions 9 g CO2 eq./ 116000 Btu

Production GHG Emissions 4,960 g CO2 eq./ 116000 BtuTotal capital investment $3,340 2007$ / daily kg dispensed

0.56 kWh / kg H2 dispensed0.01 kWh / kg H2 dispensed City Population 1,247,000 people Levelized Cost of Capital $1.71 2007$ / kg H2 dispensed

0.57 kWh / kg H2 dispensed Hydrogen Vehicle Penetration 15% Energy & Fuel $0.04 2007$ / kg H2 dispensed

City hydrogen use 121,100 kg / day Other O&M Costs $0.40 2007$ / kg H2 dispensed

$404,341,000 2007$ Distance from City to Production Facility 62 miles Levelized Cost of Delivery $2.15 2007$ / kg H2 dispensed

Geologic storage capacity 1,325,000 kg H2Number of trunk pipelines 3 Delivery CO2 Emissions 390 g CO2 eq./ 116000 Btu

3,700 Btu / 116000Btu to Pump Service-line length 1.5 miles / line Delivery CH4 Emissions 24 g CO2 eq./ 116000 Btu1,300 Btu / 116000Btu to Pump Number of service lines 122 Delivery N2O Emissions 2 g CO2 eq./ 116000 Btu

100 Btu / 116000Btu to Pump Hydrogen losses 0.76% Delivery GHG Emissions 420 g CO2 eq./ 116000 Btu

Hydrogen outlet pressure 12,700 psi

4.4 kWh / kg H2 Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

$2,629,000 2007$ / station Average Dispensing Rate per Station 1,000 kg/day Total capital investment $2,650 2007$ / daily kg H2 (effective capacity)

$320,679,000 2007$ / all stations Number of Dispensing Stations 122 Levelized Cost of Capital $1.08 2007$ / kg H2 dispensed

Number of Compression Steps 5 Energy & Fuel $0.41 2007$ / kg H2 dispensed

300 psi Usable Low Pressure Storage per Station 370 kg H2 Other O&M Costs $0.43 2007$ / kg H2 dispensed

Usable Cascade Storage per Station 130 kg H2 Levelized Cost of Dispensing $1.93 2007$ / kg H2 dispensed

24,400 Btu / 116000Btu to Pump Site storage 42% % of design capacity CSD CO2 Emissions 3,370 g CO2 eq./ 116000 Btu

10,800 Btu / 116000Btu to Pump # of 2-hose Dispensers per Station 2 CSD CH4 Emissions 210 g CO2 eq./ 116000 Btu

900 Btu / 116000Btu to Pump Hydrogen Losses 0.50% CSD N2O Emissions 14 g CO2 eq./ 116000 Btu

CSD GHG Emissions 3,590 g CO2 eq./ 116000 BtuCost Per Mile $0.69 2007$ / mi

3,020 lb Fuel Share $0.13 2007$ / mi

70 kW Fuel Economy 48.0 mi / gge Maintenance, Tires, Repairs $0.07 2007$ / mi30 kW Vehicle Miles Traveled 15,000 mi / yr Insurance & Registration $0.12 2007$ / mi

Vehicle Lifetime 160,000 mi Depreciation $0.27 2007$ / miPurchase Year 2015 Financing $0.10 2007$ / mi

Vehicle Purchase Cost $33,700 2007$

2,300 Btu / gge fuel consumed Fuel Cell System Cost $4,500 2007$ Vehicle Cycle CO2 Emissions 1,670 g CO2 eq / gge fuel consumed

12,100 Btu / gge fuel consumed Hydrogen Storage System Cost $2,400 2007$ Vehicle Cycle CH4 Emissions 170 g CO2 eq / gge fuel consumed

6,900 Btu / gge fuel consumed Tax Credit $0 2007$ Vehicle Cycle N2O Emissions 6 g CO2 eq / gge fuel consumed

Vehicle Cycle GHG Emissions 1,850 g CO2 eq / gge fuel consumed

uts Outputs

Vehicle

Coal Production & Delivery

Assumptions

Pipelines for Delivery

Hydrogen Production & Carbon Capture and Sequestration (CCS)

Forecourt Dispensing
242 

Conversion Facility Transport Dispensing

Coal 99,450 Btu/116000 Btu Coal 3,726 Btu/116000 Btu Coal 24,444 Btu/116000 Btu

Natural Gas 7,210 Btu/116000 Btu Natural Gas 1,253 Btu/116000 Btu Natural Gas 10,837 Btu/116000 Btu

Petroleum 1,101 Btu/116000 Btu Petroleum 107 Btu/116000 Btu Petroleum 928 Btu/116000 Btu

Total Energy 112,051 Btu/116000 Btu Total Energy 5,837 Btu/116000 Btu Total Energy 42,710 Btu/116000 Btu

CO2 Emissions 4,513 g CO2 eq/116000 Btu CO2 Emissions 389 g CO2 eq/116000 Btu CO2 Emissions 3,369 g CO2 eq/116000 Btu

CH4 Emissions 442 g CO2 eq/116000 Btu CH4 Emissions 24 g CO2 eq/116000 Btu CH4 Emissions 208 g CO2 eq/116000 Btu

N2O Emissions 9 g CO2 eq/116000 Btu N2O Emissions 2 g CO2 eq/116000 Btu N2O Emissions 14 g CO2 eq/116000 Btu

GHG Emissions 4,964 g CO2 eq/116000 Btu GHG Emissions 415 g CO2 eq/116000 Btu GHG Emissions 3,591 g CO2 eq/116000 Btu

Total to Deliver 116000 Btu Fuel

Btu Coal 243,989

Btu Natural Gas 19,515

Btu Gasification & Conversion Transport CSD Petroleum 2,837

Btu Including CCS Total Energy 161,962

16000 Btu Coal Feedstock 215,819 Transport Losses 0.77% Dispensing Losses 0.50% CO2 Emissions 8,381

16000 Btu CH4 Emissions 1,107

16000 Btu N2O Emissions 25

16000 Btu GHG Emissions 9,513
243 

al or lightweight)

ns in city

er of gasoline stations

tions (mi)

lculations

e Use

ns) to GVs fueled with CG & RFG

ative) to GVs fueled with CG & RFG

to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

 emissions to GVs fueled with CG & RFG

Wear PM10 emissions to GVs fueled with CG & RFG

5 emissions to GVs fueled with CG & RFG

Wear PM2.5 emissions to GVs fueled with CG & RFG

 to GVs fueled with CG & RFG

s to GVs fueled with CG & RFG

n Mix for Transportation Use

Value Units

20152007

COALGasPipelineCASCADE_700_BAR

1000 kg/day

passenger carsConventional

48.0 mile / gge

1,247,364 people

15% (% vehicles in city)

138,832 H2 vehicles / city

15,000 mile / vehicle year

160,000 miles in vehicle life121,096 kg / d

122

19%

2.17 miles

100%

None

0% wt %0%0%0%0%0%

100%

0%

100%

0%0%

US Mix

Reference Comments

Input Default for this study's current casesInput Default for this study's current casesInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definitionInput Case definition; lightweight materials not currently an MSM option

Input Default assumption for this study's current casesInput Case Definition: Indianapolis, INInput Case definition: Basis for Program PlanHDSAM ResultInput CPM only allows for 10K, 15K, and 20K/yr.Input - GREET2 defaultHDSAM ResultHDSAM ResultHDSAM ResultHDSAM ResultInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET default Case definition: Basis for Program PlanInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput: GREET defaultInput Case definition: Basis for Program Plan
244 

Value Units Reference Comments

ning and cleaning

 mining and cleaning transport to H2 plant

mine to hydrogen production facility

 coal mining, cleaning & delivery

mining & cleaning

ng & cleaning

ining & cleaning

al mining & cleaning

g & cleaning

mining & cleaning

al mining and cleaning

mining and cleaning

al mining and cleaning

 coal mining and cleaning

ning and cleaning

oal mining and cleaning

tion

tion

Neutral - Hydroelectric, Wind, Geothermal, Solar PV, etc)

and Efficiency

omass Power Plantse of Biomass Power Plants

fficiency

stion Plant Efficiency

cy of Biopower Plants

Efficiency

oal Power Plants

e of Coal Power Plants

ency

 Plant Efficiency

cy of Coal-Electricity Plants

es and Efficiency

s Turbine Share of Natural Gas Power Plants

Gas Turbine Share of Natural Gas Power Plants

er Share of Natural Gas Power Plants

ple Cycle Gas Turbine Plant Efficiency

bined Cycle Efficiencybustion Boiler Plant Efficiency

cy of Natural Gas-Electricity Plants

ency

tricity Plant Efficiency

Distribution Losses

99.3%

10,513 Btu/MMBtu Del. Coal

1,096 Btu/MMBtu Del. Coal

65 miles

11,609 Btu/MMBtu Del. Coal

7.0%

56.0%

3.0%1.0%9.0%

24.0%

493 Btu/MMBtu Del. Coal

3,948 Btu/MMBtu Del. Coal

211 Btu/MMBtu Del. Coal

70 Btu/MMBtu Del. Coal

634 Btu/MMBtu Del. Coal

1,692 Btu/MMBtu Del. Coal

US Mix

0.5%

44.2%21.5%21.0%

0.9%

11.8%

1.0%

99.0%43.0%32.1%32.2%

1.0%

99.0%47.0%34.1%34.2%37.0%46.0%17.0%33.1%55.0%34.8%40.9%34.8%

8.0%

2009 reported value was wrong, should have been 

~10513

GREET input DefaultDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixDefinition of US MixGREET default inputGREET default input By difference from IGCC plantsGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default inputGREET default input

Energy Information Administration. (2007, 

February). Annual Energy Outlook 2007 with 

Projections to 2030. DOE/EIA-0383(2007). 

Washington, D.C. Retreived from 

www.eia.doe.gov/oiaf/archive/aeo07/index.html 

National electricity generation data from tables D-7

& D-8 using the 2005 timeframe. Percentages 

calculated from total generation values reported 

with all renewables except biomass aggregated 

into the "Others (Carbon Neutral)" category 
245 

tion

 in Peak Hybridization Battery Power

cific Power

s

of hybridization battery over lifetime

) Mass

ehicle

es without batteries or fluids)

stem percentage of component mass

system percentage of component mass

out battery) percentage of component mass

r percentage of component mass

centage of component mass

troller percentage of component mass

iary System percentage of component mass

g BIW, interior, exterior, and glass

Powertrain System

Auxiliary Systems

ver lifetime

Value Units

3,020 lbNiMH

30 kW

272 W / lb110 lb

 2 

22 lb56 lb

2,832 lb

8.0%2.6%

23.0%

3.8%0.0%3.4%

19.3%39.9%

70 kW

226 lb546 lb

160,000 miles in vehicle life

Reference Comments

GREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 Default InputGREET2 CalculationGREET2 CalculationGREET2 Default Input Current analysis assumes 5-year life, 10-year analysis is available