Technical Report

NREL/TP-6A1-46612

September 2009

Hydrogen Pathways: Cost, 

Well-to-Wheels Energy Use, 

and Emissions for the Current 

Technology Status of Seven 

Hydrogen Production, Delivery, 

and Distribution Scenarios

Mark Ruth

National Renewable Energy Laboratory

Melissa Laffen and Thomas A. Timbario

Alliance Technical Services, Inc.
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

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

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Technical Report

NREL/TP-6A1-46612

September 2009

Hydrogen Pathways: Cost, 

Well-to-Wheels Energy Use, 

and Emissions for the Current 

Technology Status of Seven 

Hydrogen Production, Delivery, 

and Distribution Scenarios

Mark Ruth

National Renewable Energy Laboratory

Melissa Laffen and Thomas A. Timbario

Alliance Technical Services, Inc.

Prepared under Task No. HS07.1002
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iii

Acknowledgements 

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

support during this analysis. 

The FreedomCar and Fuel Partnership’s Fuel Pathway Integration Technical Team 

(FPITT) identified the need to examine concurrently the cost and well-to-wheels energy 

use and emissions of various hydrogen production and delivery 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 

performed the gap analysis that identified issues reported in Section 11. Current and past 

members of the team include Don Gardner and Matt Watkins (Exxon Mobil 

Corporation); Graham Moore, Bhaskar Balasubramanian, and Jonathan Weinert 

(Chevron Corporation); Jim Uihlein and Maria Curry-Nkansah (BP America Inc.); Ed 

Casey (Conoco-Phillips Company); Henk Mooiweer, Karel Kapoun and CJ Guo (Shell 

Hydrogen, LLC); Johanna Levene, Todd Ramsden, and Darlene Steward [National 

Renewable Energy Laboratory (NREL)]; and Fred Joseck [Department of Energy 

(DOE)]. 

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

assumptions. Macro-System Model (MSM) developers include Victor Diakov (NREL) 

and Tim Sa, Mike Goldsby, Andy Lutz, and Keith Vanderveen [Sandia National 

Laboratories (SNL)]. H2A developers who assisted include Maggie Mann, Johanna 

Levene, Todd Ramsden, and Darlene Steward (NREL) and Brian James (Directed 

Technologies, Inc.). The Hydrogen Delivery Scenario Analysis Model (HDSAM) 

developers who assisted include Amgad Elgowainy [Argonne National Laboratory 

(ANL)] and Matt Ringer (NREL). The Greenhouse Gas, Regulated Emission, and 

Energy for Transportation (GREET) model developers who assisted include Amgad 

Elgowainy, Ye Wu, and Michael Wang (ANL). James Beetham (University of Colorado) 

assisted with MSM runs and data collection. Tien Nguyen (DOE) and Genevieve Saur 

(NREL) provided assistance in finding sources. 

Fred Joseck (DOE) provided leadership, guidance, and funding for which we are grateful, 

and this analysis would not have been possible without him. 
iv

Table of Contents

Acknowledgements ............................................................................................................ iii

1.0 Executive Summary ...................................................................................................... 1

2.0 Introduction ................................................................................................................... 3

2.1 Document’s Intent ..................................................................................................... 3

2.2 Market State and Technology Development Assumptions ....................................... 3

2.3 Analysis Boundaries ................................................................................................. 4

2.4 Pathways ................................................................................................................... 4

2.5 Models Used in the Pathway Analyses ................................................................... 13

3.0 Resource Assumptions ................................................................................................ 15

3.1 Natural Gas ............................................................................................................. 15

3.2 Electricity ................................................................................................................ 16

3.3 Biomass (Wood) ..................................................................................................... 21

3.4 Coal ......................................................................................................................... 24

3.5 Carbon Sequestration .............................................................................................. 26

4.0 Status of Supporting Infrastructure ............................................................................. 29

4.1 Natural Gas Supply Infrastructure .......................................................................... 29

4.2 Electricity Transmission Grid ................................................................................. 34

4.3 Biomass Truck Transportation and Delivery .......................................................... 38

4.4 Coal Moved by Railway ......................................................................................... 40

5.0 Production Technology Description and Assumptions............................................... 44

5.1 Distributed Natural Gas Reforming ........................................................................ 44

5.2 Distributed Electrolysis ........................................................................................... 45

5.3 Central Biomass Gasification ................................................................................. 48

5.4 Central Natural Gas Reforming .............................................................................. 49

5.5 Central Electrolysis ................................................................................................. 51

5.6 Central Coal with Carbon Capture and Sequestration ............................................ 51

6.0 Delivery Technology Description and Assumptions .................................................. 55

6.1 Liquid Hydrogen Delivery ...................................................................................... 55

6.1.1 Liquid Hydrogen Truck ................................................................................... 55

6.1.2 Liquefier ........................................................................................................... 56

6.2 Gaseous Hydrogen Delivery ................................................................................... 58

6.2.1 Pipeline ............................................................................................................ 59

6.2.2 Compressor ...................................................................................................... 59

6.3 Compression, Storage, and Dispensing .................................................................. 61

7.0 Vehicle Assumptions .................................................................................................. 65

7.1 Vehicle Fuel Economy ............................................................................................ 65

7.2 Vehicle Criteria Pollutant Emissions ...................................................................... 67

8.0 Financial Assumptions ................................................................................................ 69

9.0 Pathway Results .......................................................................................................... 71

9.1 Distributed Natural Gas .......................................................................................... 71

9.1.1 Cost Breakdown ............................................................................................... 71

9.1.2 Energy Use and Emissions Breakdown ........................................................... 75

9.1.3 Natural Gas Supply Scenarios ......................................................................... 77

9.1.4 Sensitivities ...................................................................................................... 78
v

9.1.5 Advanced Conversion and Delivery/Distribution Technology ........................ 79

9.2 Distributed Electricity ............................................................................................. 82

9.2.1 Cost Breakdown ............................................................................................... 82

9.2.2 Energy Use and Emissions Breakdown ........................................................... 87

9.2.3 Electricity Supply Scenarios ............................................................................ 88

9.2.4 Sensitivities ...................................................................................................... 89

9.2.5 Advanced Conversion and Delivery/Distribution Technology ........................ 90

9.3 Central Biomass – Liquid Delivery ........................................................................ 91

9.3.1 Cost Breakdown ............................................................................................... 92

9.3.2 Energy Use and Emissions Breakdown ........................................................... 96

9.3.3 Biomass Supply Scenarios ............................................................................... 99

9.3.4 Sensitivities .................................................................................................... 100

9.4 Central Biomass – Pipeline Delivery .................................................................... 110

9.4.1 Cost Breakdown ............................................................................................. 111

9.4.2 Energy Use and Emissions Breakdown ......................................................... 115

9.4.3 Biomass Supply Scenarios ............................................................................. 118

9.4.4 Sensitivities .................................................................................................... 118

9.4.5 Advanced Conversion and Delivery / Distribution Technology .................... 123

9.5 Central Natural Gas – Pipeline Delivery .............................................................. 126

9.5.1 Cost Breakdown ............................................................................................. 126

9.5.2 Energy Use and Emissions Breakdown ......................................................... 130

9.5.3 Natural Gas Supply Scenarios ....................................................................... 133

9.5.4 Sensitivities .................................................................................................... 133

9.5.5 Advanced Conversion and Delivery/Distribution Technology ...................... 134

9.6 Central Wind Electricity – Pipeline Delivery ....................................................... 135

9.6.1 Cost Breakdown ............................................................................................. 135

9.6.2 Energy Use and Emissions Breakdown ......................................................... 140

9.6.3 Wind Electricity Supply Scenarios ................................................................ 142

9.6.4 Sensitivities .................................................................................................... 143

9.6.5 Advanced Conversion and Delivery/Distribution Technology ...................... 144

9.7 Central Coal with Carbon Capture and Sequestration (CCS) – Pipeline Delivery 146

9.7.1 Cost Breakdown ............................................................................................. 146

9.7.2 Energy Use and Emissions Breakdown ......................................................... 150

9.7.3 Coal Supply Scenarios ................................................................................... 153

9.7.4 Sensitivities .................................................................................................... 154

9.7.5 Advanced Conversion and Delivery/Distribution Technology ...................... 155

10.0 Pathway Results Comparison ................................................................................. 157

11.0 Analysis Gaps ......................................................................................................... 167

12.0 References ............................................................................................................... 170

Appendix A — Distributed Natural Gas Supporting Tables and Figures ...................... 176

Appendix B — Distributed Electrolysis Supporting Tables and Figures ....................... 185

Appendix C — Biomass–Liquid Truck Supporting Tables and Figures ........................ 192

Appendix D — Biomass–Pipeline Supporting Tables and Figures ................................ 200

Appendix E — Natural Gas–Pipeline Supporting Tables and Figures ........................... 209

Appendix F — Coal–Pipeline with Carbon Capture and Sequestration Supporting Tables 

and Figures .............................................................................................................. 218
vi

Appendix G — Wind Electrolysis–Pipeline Supporting Tables and Figures ................. 227

Appendix H — Platinum Resource Availability and Cost ............................................. 236

Appendix I — Enlarged Graphics ................................................................................... 239

Acronyms ........................................................................................................................ 277
1

1.0 Executive Summary

The United States (U.S.) Department of Energy’s (DOE) Fuel Cell Technologies

Program (the Program) has identified a need to understand the cost, energy use, and 

emissions tradeoffs of various hydrogen production, delivery, and distribution options 

under consideration for fuel cell vehicles. The Program 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 document reports the levelized cost in 2005 U.S. dollars, energy use, and GHG 

emission benefits of the seven hydrogen production, delivery, and distribution pathways 

reported in Table 1.0.1. Current technology status is reported for each pathway and 

refers to technology that has been demonstrated at the bench scale at a minimum. All the 

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

Table 1.0.1. Seven 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 350 bar compressed gas

2 Electricity Distributed No Not applicable 350 bar compressed gas

3 Biomass Central No Liquid H2 in trucks 350 bar compressed gas

4 Biomass Central No Gaseous H2 in pipelines 350 bar compressed gas

5 Natural Gas Central No Gaseous H2 in pipelines 350 bar compressed gas

6 Wind Electricity Central No Gaseous H2 in pipelines 350 bar compressed gas

7 Coal Central Yes Gaseous H2 in pipelines 350 bar compressed gas

Plausible production scenarios for mature hydrogen transportation-fuel markets combined 

with market penetration of hydrogen fuel cell vehicles were used in this analysis. They 

are not 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.

The pathways are described in detail, and system-level parameters are reported and 

referenced. Availability, cost, and characteristics of necessary resources are reported, as 

is the current status of supporting infrastructure. The sensitivities of each pathway’s cost, 

pathway energy use, well-to-wheels energy use, and well-to-wheels emissions to many of 

the primary parameters are reported as an aid in understanding and assessing technology 

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

benefits of various options. Some of the results are compared with those of current 

gasoline, diesel, and E85 vehicles including gasoline hybrid electric vehicles.

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

linking the H2A Production Model, the Hydrogen Delivery Scenario Analysis Model 

(HDSAM), and the Greenhouse Gas, Regulated Emission, and Energy for Transportation 
2

(GREET) Model. The MSM links those models so a single run utilizes the capabilities of 

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

enables users to analyze the pathways and complete sensitivity analyses that are not 

reported in this document. 

The analysis has been reviewed by the FreedomCar and Fuel Partnership’s Fuel Pathway 

Integration Technical Team (FPITT), which includes members from DOE, national 

laboratories, and energy companies (BP America Inc., Chevron Corporation, ConocoPhillips Company, Exxon Mobil Corporation, and Shell Hydrogen, LLC). 

This report compares fuel cost and well-to-wheel (WTW) emissions among multiple 

hydrogen fuel pathways and benchmarks those results against current gasoline and diesel 

fuel. Figure 1.0.1 illustrates six of the seven hydrogen pathways have GHG emissions 

that are lower than all the crude oil–based pathways and E85 generated from corn grain. 

All seven hydrogen pathways use less petroleum per mile traveled than the other 

pathways because of the increased efficiency fuel cells provide. Distributed electrolysis 

has high GHG emissions and high petroleum use when compared with the other 

hydrogen pathways because of the electricity grid mix. The coal pathway has low GHG 

emissions because 90% of the carbon dioxide generated in the hydrogen production 

facility is sequestered. 

Central Natural Gas - 

Pipeline

Distributed Natural Gas

Central Coal - Pipeline

Distributed Electrolysis

Wind Electricity 

Electrolysis - Pipeline

Central Biomass - 

Pipeline

Central Biomass - Liquid 

Trucks

0

100

200

300

400

500

600

700

800

900

1,000

0 100 200 300 400 500 600

WTW Petroleum Energy Use (Btu / mile)

WTW Greenhouse Gas Emissions (g / mile)

Natural Gas

Coal

Grid Electricity

Wind Electricity

Biomass

Gasoline ICE

 5300 Btu/mile Petroleum Use

 480 g/mile GHG emissions

Gasoline Hybrid

 3600 Btu/mile Petroleum Use

 330 g/mile GHG emissions

Diesel ICE

 4500 Btu/mile Petroleum Use

 410 g/mile GHG emissions

Corn E85 Flex-Fuel ICE

 1700 Btu/mile Petroleum Use

 390 g/mile GHG emissions

Stover E85 Flex-Fuel ICE

 1700 Btu/mile Petroleum Use

 170 g/mile GHG emissions

Figure 1.0.1. Comparison of pathways’ petroleum use and greenhouse gas emissions
3

2.0 Introduction

2.1 Document’s Intent

The U.S. DOE has identified a need to understand the lifecycle cost, energy use, and 

emissions tradeoffs of various hydrogen production and delivery pathways under 

consideration to enable a transition from a hydrocarbon-based economy to a hydrogenand-electricity-based economy.

Feedstock, capital, capacity, and utility-sensitivity analyses on the cost of delivered 

hydrogen have been conducted for seven potential hydrogen production and delivery 

pathways using MSM. 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 objectives of this analysis were: 

• Improved understanding of the primary parameters that affect the levelized cost,

WTW fossil energy requirements, and WTW emissions of each of the seven

pathways analyzed

• Referencing those parameters and performing an initial sensitivity analysis around 

them 

• Giving industry (through FPITT) the opportunity to review those primary 

assumptions and provide feedback 

• Completing a gap analysis around the parameters to identify possible production, 

delivery, and distribution issues. 

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. 

2.2 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 firstof-a-kind plants and low production levels of vehicles. Specifically, today’s technical 

status is extrapolated to a scenario where 50% 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.
4

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

technologies, and costs are reported in 2005 U.S. dollars. 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 larger-scale performance and equipment requirements and costs were 

necessary. 

Designs and costs in this analysis do not include additional requirements of first-of-akind 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 plant” techniques (techniques which 

inherently assume that the technology is mature and do not include additional 

contingency, capital costs, and yield loss necessary for of first-of-a-kind plants cost 

estimation). 

2.3 Analysis Boundaries

WTW energy use and emissions are assessed for each pathway using the GREET model. 

Included in the assessment are feedstock recovery, transportation, and storage; fuel 

production, transportation, storage, and distribution; and vehicle operation. 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. 

Energy used and emissions generated to produce the vehicles, produce the equipment 

required to recover the feedstock, produce the fuel, etc., are not included. The GREET 2 

series is capable of including energy and emissions for production, maintenance, and 

disposal of the vehicles, but it was not used in this analysis.

2.4 Pathways

The seven pathways included in this analysis are shown in Table 2.4.1. 

Table 2.4.1. Seven 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 350 bar compressed gas

2 Electricity Distributed No Not applicable 350 bar compressed gas

3 Biomass Central No Liquid H2 in trucks 350 bar compressed gas

4 Biomass Central No Gaseous H2 in pipelines 350 bar compressed gas

5 Natural Gas Central No Gaseous H2 in pipelines 350 bar compressed gas

6 Wind Electricity Central No Gaseous H2 in pipelines 350 bar compressed gas

7 Coal Central Yes Gaseous H2 in pipelines 350 bar compressed gas
5

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 electricity pathway, Pathway 3 is 

the central biomass with liquid delivery pathway, and Pathway 4 is the central biomass 

with pipeline delivery. The product from each of the pathways is the same: gaseous 

hydrogen with sufficient purity for dispensing to a hydrogen fuel-cell vehicle, 

compressed to 6,250 psi (430 bar) for on-board storage at 5,000 psi (350 bar).

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 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 9.0. 

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 6,250 psi (430 bar) and stored onsite prior to dispensing as a gaseous fuel to the 5,000-psi (350 bar) vehicle fuel tank. The 

flow diagram in Figure 2.4.1 shows the fuel production and delivery components of the 

distributed natural gas pathway and the energy balance for the major hydrogen-related 

subsystems, and the pathway is on a 1-gallon gasoline equivalent (gge) basis. The 

production technologies are detailed in Section 5.0, and the forecourt technologies are 

detailed in Section 6.0. 
6

159,000 Btu 54,000 Btu 

Natural Gas Energy Lost

11,000 Btu

Electricity

Hydrogen Production: 

Desulfurizer

SMR

WGS

PSA

Forecourt 

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 2.4.1. 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). In fact, several stations utilizing this 

pathway have already been installed throughout the world as seen in Table A.1., 

Appendix A (Fuel Cells 2000, 2009). 

Pathway 2—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 6,250 psi (430 

bar) and stored on-site prior to dispensing as a gaseous fuel to the 5,000-psi (350 bar) 

vehicle fuel tank. The flow diagram in Figure 2.4.2 shows the fuel production and 

delivery components of the distributed electricity pathway and the energy balance for the 

major hydrogen-related subsystems, and the pathway is on a 1-gge basis. The production 

technologies are detailed in Section 5.0, and the forecourt technologies are detailed in 

Section 6.0. 

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

clean, inexpensive electricity is available. 
7

3.0 gal 76,000 Btu 

Water Energy Lost

192,000 Btu

Electricity

Hydrogen Production: 

Demineralizer

Elec. Transformer/Rectifier

Electrolyzer

Scrubber

Forecourt 

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 2.4.2. Flow diagram and energy balance of distributed electricity pathway

Values may not sum to zero due to rounding.

Pathway 3—Central Biomass–Liquid Truck Delivery

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, and delivered 

via tube trailer to a 1,500 kg/day forecourt hydrogen refueling station, where it is 

vaporized, compressed to 6,250 psi (430 bar), and dispensed as a gaseous fuel to the 

5,000-psi (350 bar) vehicle fuel tank. The flow diagram in Figure 2.4.3 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, and the pathway is on 

a 1-gge basis. The production technologies are detailed in Section 5.0, and the delivery 

technologies are detailed in Section 6.0. 
8

4,000 Btu 7,000 Btu

Electricity Natural Gas

271,000 Btu Biomass

152,000 Btu Energy Lost

 129,000 Btu Hydrogen gas

31,000 Btu Electricity

1,000 Btu Diesel 13,000 Btu Hydrogen Lost

1,000 Btu Electricity

33,000 Btu Energy Lost

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Vaporizer

Compressor

Truck Delivery:

Liquefier

Liquid H2 Storage

Liquid H2 Truck

Hydrogen Production: 

Gasifier

PSA

Liquefaction &

SMR

WGS

Figure 2.4.3. Flow diagram and energy balance of central biomass–liquid truck delivery 

pathway

Values may not sum to zero due to rounding.

The biomass pathways were selected for this study because of their potential to provide 

hydrogen with low- or zero-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; while sensitivities to regionality are outside the scope of this study, they may 

be determined as more data become available. 

This is the only pathway studied that utilizes liquid hydrogen delivery. Comparison 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 both delivery options (liquid truck and gaseous 

pipeline) with parameters such as delivery distance and degree of hydrogen penetration in 

the vehicular fuel market. 
9

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 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 1,500 kg/day forecourt hydrogen refueling station. 

There the hydrogen is compressed to 6,250 psi (430 bar) and dispensed as a gaseous fuel

to the 5,000-psi (350 bar) vehicle fuel tank. The flow diagram in Figure 2.4.4 shows the 

fuel production and delivery components of the central biomass–pipeline delivery 

pathway and the energy balance for the major hydrogen-related subsystems. The 

production technologies are detailed in Section 5.0, and the delivery technologies are 

detailed in Section 6.0. 

3,000 Btu 6,000 Btu

Electricity Natural Gas

245,000 Btu Biomass

138,000 Btu Energy Lost

 117,000 Btu Hydrogen gas

2,000 Btu Electricity

1,000 Btu Hydrogen Lost

11,000 Btu Electricity

13,000 Btu Energy Lost

Hydrogen Production: 

Gasifier

SMR

WGS

PSA

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

116,000 Btu

Hydrogen Gas

Compressor

Gaseous H2 Storage

Dispensing

Figure 2.4.4. Flow diagram and energy balance of central biomass–pipeline delivery 

pathway

Values may not sum to zero due to rounding.
10

Pathway 5—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 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 1,500 kg/day forecourt 

hydrogen refueling station. There the hydrogen is compressed to 6,250 psi (430 bar) and 

dispensed as a gaseous fuel to the 5,000-psi (350 bar) vehicle fuel tank. The flow 

diagram in Figure 2.4.5 shows the fuel production and delivery components of the central 

natural gas–pipeline delivery pathway and the energy balance for the major hydrogenrelated subsystems. The production technologies are detailed in Section 5.0, and the 

delivery technologies are detailed in Section 6.0. 

161,000 Btu Natural Gas

46,000 Btu Energy Lost

 117,000 Btu Hydrogen gas

2,000 Btu Electricity

1,000 Btu Hydrogen Lost

11,000 Btu Electricity

13,000 Btu Energy Lost

Hydrogen Production: 

Desulfurizer

SMR

WGS

Forecourt 

Distribution:

PSA

Compression &

Pipeline Delivery:

Compressor

116,000 Btu

Hydrogen Gas

2,000 Btu

Electricity

Compressor

Gaseous H2 Storage

Dispensing

Geologic Storage

Pipeline

Figure 2.4.5. 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 
11

hydrogen for oil refining. It is expected to result in the lowest cost of hydrogen when 

pipeline delivery is employed. 

Pathway 6—Central Wind Electricity–Pipeline Delivery

In the central wind electricity 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 the electricity 

purchased. 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 1,500 kg/day forecourt hydrogen refueling station. There the hydrogen is 

compressed to 6,250 psi (430 bar) and dispensed as a gaseous fuel to the 5,000 psi (350 

bar) vehicle fuel tank. The flow diagram in Figure 2.4.6 shows the fuel production and 

delivery components of the central wind electricity pathway and the energy balance for 

the major hydrogen-related subsystems. The production technologies are detailed in 

Section 5.0, and the delivery technologies are detailed in Section 6.0. 

3.0 gal Water

71,000 Btu Energy Lost

 117,000 Btu Hydrogen gas

2,000 Btu Electricity

1,000 Btu Hydrogen Lost

11,000 Btu Electricity

13,000 Btu Energy Lost

116,000 Btu

Hydrogen Gas

188,000 Btu

Electricity

Compressor

Gaseous H2 Storage

Dispensing

Geologic Storage

Pipeline

Forecourt 

Distribution:

Scrubber

Compression &

Pipeline Delivery:

Compressor

Hydrogen Production: 

Demineralizer

Elec. Transformer/Rectifier

Electrolyzer

Figure 2.4.6. Flow diagram and energy balance of central wind electricity–pipeline delivery 

pathway

Values may not sum to zero due to rounding.
12

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 has potential geographic limitations, the wind electricity 

pathway can be implemented anywhere that wind-power credits are available for 

purchase.

Pathway 7—Central Coal with Carbon Capture and Sequestration (CCS)–

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 sulfuric acid 

removal prior to entering a PSA unit, which is used 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 1,500 kg/day forecourt hydrogen refueling station. 

There the hydrogen is compressed to 6,250 psi (430 bar) and dispensed as a gaseous fuel 

to the 5,000-psi (350 bar) vehicle fuel tank. The flow diagram in Figure 2.4.7 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. The 

production technologies are detailed in Section 5.0, and the delivery technologies are 

detailed in Section 6.0. 
13

213,000 Btu Coal

101,000 Btu Energy Lost

 117,000 Btu Hydrogen gas

2,000 Btu Electricity

1,000 Btu Hydrogen Lost

11,000 Btu Electricity

13,000 Btu Energy Lost

6,000 Btu

Electricity

& CCS: 

Gasifier

Hydrogen Production 

Shift Converter

H2S Removal

CO2 Removal

Compression &

PSA

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 2.4.7. Flow diagram and energy balance of central coal with CCS–pipeline delivery 

pathway

Values may not sum to zero due to rounding.

Coal is the most abundant native fossil fuel in the U.S. and is available at lower cost than 

other fossil fuels. 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. 

2.5 Models Used in the Pathway Analyses

The H2A Production Model Version 2.1 (Steward, Ramsden, and Zuboy, 2008) 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. 
14

The H2A Delivery Scenario Analysis Model (HDSAM) Version 2.0 (Mintz, Elgowainy, 

and Gillette, 2008) 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 

2.0 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 model (Argonne National Laboratory, 2009) calculates the full fuel-cycle 

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 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, a modified version of GREET 1.8b downloaded on September 5, 2008, was 

utilized. The GREET model was modified to make it consistent with previous versions 

by adjusting the “method for dealing with co-products of soybean-based fuel” from 

displacement to energy-based allocation. 

MSM (Ruth et al., 2009) links the H2A Production Model, HDSAM, and GREET 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 as inputs 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, 

efficiencies of different technologies, energy use and emissions of various pathways, 

hydrogen production capacity to meet demand, and 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 singleparameter and multi-parameter sensitivities. The MSM will be updated with future 

versions of the H2A Production Model, HDSAM, and GREET as they are made public. 

For access to the MSM, please contact Mark Ruth at mark.ruth@nrel.gov. 
15

3.0 Resource Assumptions

The extent to which each of the pathways analyzed in this study can be deployed to 

supply hydrogen fuel for light-duty vehicles depends on the availability, cost, and quality 

of required feedstocks, energy sources, and supporting infrastructures. This section 

examines the availability, cost, and characteristics of each of the feedstocks and energy 

sources utilized by the seven pathways: natural gas, electricity (including wind 

electricity), biomass, and coal. The current status and potential of carbon sequestration in 

the U.S. are also briefly explored because carbon sequestration is an element of the 

central coal–pipeline delivery pathway assessed in this study. 

Additional resources and supporting infrastructures required for producing hydrogen 

and/or FCVs include water, platinum, carbon fiber, steel, concrete, dispensing equipment, 

monitoring/safety equipment, testing equipment, land, and skilled labor. Assessment of 

these resources and infrastructures is outside the scope of this study; however, DOE and 

the Fuel Pathway Integration Tech Team are currently supporting separate analyses of 

water and carbon-fiber resources. A summary of platinum resources analyses conducted 

to date for the DOE Hydrogen Program is provided in Appendix H. 

3.1 Natural Gas

Natural gas is an important potential-hydrogen feedstock and also a significant 

electricity-generation feedstock, accounting for more than 15% of current electricity 

generation in the U.S. Its availability and cost, therefore, impact the viability and cost of 

hydrogen for several of the pathways studied. 

Availability and Utilization

U.S. reserves of dry natural gas were estimated to be 237,726 billion cubic feet for 2007 

(Energy Information Administration, 2009i). Data from EIA (Energy Information 

Administration, 2009c) show that the United States withdrew 26,032,337 million cubic 

feet of natural gas in 2008, which was up from 24,590,602 in 2007. For the same 2007–

2008 time period, data (Energy Information Administration, 2009b) show the United 

States consumed 23,208,677 million cubic feet of natural gas in 2008 and 23,047,229 

million cubic feet in 2007, increasing about 0.1%. Total consumption includes lease and 

plant fuel, pipeline and distribution use, and volumes delivered to consumers. The 2008 

consumption was at near-record levels, second only to the amount consumed in 2000. 

One reason for the jump in consumption over 2007 levels was the 5.6% increase in 

heating degree days for 2008. 

If the entire fleet of U.S. passenger vehicles were run on hydrogen produced from natural 

gas, 10 trillion normal cubic feet would be required annually to produce the necessary 

hydrogen (not including natural gas necessary for generation of the electricity used within 

the pathways). Ten trillion normal cubic feet is 43% of the total natural gas consumption 

in 2008. The demand calculation is based on a total vehicle miles traveled in passenger 

vehicles of 2.78 trillion (Bureau of Transportation Statistics, 2007), the vehicle fuel 
16

economy used in this study (45 mpgge), and a yield of hydrogen from natural gas of 4.5 

Nm3 natural gas/kg H2 (159 Nft3

 natural gas/kg H2, which is 71% efficiency on an LHV 

basis). This calculation and the natural gas supply scenarios for lower fuel cell vehicle 

penetration rates are shown in Section 9.1. 

Resource Cost

In cases where hydrogen is produced from natural gas, the natural gas price used for this 

analysis is $0.24/Nm3 ($6.73/MMBtu), and in cases where natural gas is used for 

supplemental heat, the natural gas price used for this analysis is $0.34/Nm3

($9.52/MMBtu). These prices are different because industrial rates for natural gas were 

assumed for cases based on natural gas and because commercial rates were assumed for 

cases based on other feedstocks. Both rates are from EIA (2005) and are based on the 

High A Case. In 2007, the electric power price of natural gas was $7.31 per thousand 

cubic feet ($7.23/MMBtu). The cost jumped to $9.35 per thousand cubic feet 

($9.24/MMBtu) in 2008 (Energy Information Administration, 2009d). 

Characteristics

Natural gas consists of a high percentage of methane and varying amounts of ethane, 

propane, butane, and inert gases (nitrogen, carbon dioxide, and helium). Table 3.1.1 

(Avallone and Baumeister, 1996) shows the composition and heating value of various 

natural gas samples from across the country. In this analysis, the natural gas has a higher 

heating value of 1089 Btu/ft3

 and a lower heating value of 983 Btu/ft3. 

Table 3.1.1. Composition and Heating Value of Natural Gas

Composition, mole %

Oil or Gas Well Pipeline

State of origin LA MS NM TX CO KS OK

Methane 92.1 96.3 67.7 43.6 94.3 72.3 75.4

Ethane 3.8 0.1 5.6 18.3 2.1 5.9 6.4

Propane 1.0 0.0 3.1 14.2 0.4 2.7 3.6

Butane 0.3 0.0 1.5 8.6 0.2 0.3 1.0

Nitrogen 0.9 1.0 17.4 3.0 0.0 17.8 12.0

Carbon dioxide 1.1 2.3 0.1 0.5 2.8 0.1 0.1

Helium trace trace 1.4 trace trace 0.4 0.4

Heating value* 1,062 978 1,044 1,899 1,010 934 1,044 * Gross / higher heating value, Btu/ft3

, dry at 60°F and 30 inches of Hg.

3.2 Electricity

Electricity is a primary feedstock for the hydrogen production pathways employing 

electrolysis and is an important energy source for all of the pathways studied, as it is used 

to run pumps, compressors, and other equipment and controls. Electricity prices vary due 

to many factors including the energy source used to generate electricity, purchase 
17

volumes, time of day (peak vs. off-peak), and reliability requirements. The energy use 

and emissions attributable to electricity consumption also vary widely depending on how 

the electricity is produced. The grid mix and electricity prices used in this study are 

intended to represent a U.S. average; individual facilities may experience different mixes 

and prices. 

Availability and Utilization

EIA data (Energy Information Administration, 2009e) for 2008 show that the United 

States generated 4,110,259 million kilowatt-hours of electricity, which was down from 

4,156,745 million kilowatt-hours in 2007. For that same period, data (Energy 

Information Administration, 2009f) show that sales of electricity in the United States 

were 3,721,562 million kilowatt-hours and 3,764,561 million kilowatt-hours in 2008 and 

2007, respectively. 

If the entire fleet of U.S. passenger vehicles were run on hydrogen produced in 

distributed electrolysis plants, 3.5 trillion kilowatt-hours would be required annually to 

produce the necessary hydrogen. Three and a half trillion kilowatt-hours is 85% of the 

total electricity generated in 2008. The demand calculation is based on a total vehicle 

miles traveled in passenger vehicles of 2.78 trillion (Bureau of Transportation Statistics, 

2007), the vehicle fuel economy used in this study (45 mpgge), and a yield of hydrogen 

from electricity of 55 kWh electricity/kg hydrogen (62% efficiency on a hydrogen LHV 

basis). This calculation and the electricity supply scenarios for lower fuel cell vehicle 

penetration rates are shown in Section 9.2. 

The GREET U.S. mix was used in these pathway analyses and is shown in Table 3.2.1. It 

is based on the 2005 grid mix (Energy Information Administration, 2005). For 

comparison, Table 3.2.2 (Energy Information Administration, 2009e) displays the net 

generation by energy source for the years 2007 and 2008; they are similar to the 2005 

mix. 

 

Table 3.2.1. GREET U.S. Mix

% of Total

Biomass 1.2

Coal 51.7

Natural Gas 15.7

Nuclear 20.3

Residual Oil 2.9

Others (Carbon Neutral) 8.2

Total 100.0
18

Table 3.2.2. Net Generation by Energy Source

2007 2008 2007 2008

thousand megawatt-hours % of total

Coal1 2,016,456 1,994,385 48.5 48.5

Petroleum liquids2 49,505 31,162 1.2 0.8

Petroleum coke 16,234 14,192 0.4 0.3

Natural gas 896,590 876,948 21.6 21.3

Other gases3 13,453 11,573 0.3 0.3

Nuclear 806,425 806,182 19.4 19.6

Hydroelectric conventional 247,510 248,085 6.0 6.0

Other renewables4 105,238 123,603 2.5 3.0

Hydroelectric pumped storage -6,896 -6,238 -0.2 -0.2

Other5 12,231 10,367 0.3 0.3

Total 4,156,745 4,110,259 100.0 100.0

1

 Anthracite, bituminous, subbituminous, lignite, waste coal, and coal synfuel. 

2 Distillate fuel oil, residual fuel oil, jet fuel, kerosene, and waste oil.

3 Blast furnace gas, propane gas and other manufactured and waste gases derived from 

fossil fuels.

4

 Wood, black liquor, other wood waste, biogenic municipal solid waste, landfill gas, 

sludge waste, agriculture byproducts, other biomass, geothermal, solar thermal, 

photovoltaic, and wind. 

5 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased 

steam, fire-derived fuel, and miscellaneous technologies.

Feedstock Conversion Efficiency

Figure 3.2.1 shows various types of power plants for electricity generation and their 

thermodynamic efficiencies. Hydroelectric plants are by far the most efficient at over 

90%. However, as shown previously, hydroelectric plants contribute just 6% of the 

electricity-generation mix. At over 48% of the source mix, coal is the largest source of 

power generation in the United States. A coal-fired steam turbine plant has an efficiency 

of just under 40%, whereas an integrated gasification combined cycle (IGCC) coal-fired 

plant can achieve approximately 45%. Typically, this type of plant uses syngas to fire a 

gas turbine whose waste heat is utilized by a steam turbine system.

Resource Cost

Commercial electricity cost an average of $0.0965 per kilowatt-hour in 2007. That cost 

jumped to $0.1028 per kilowatt-hour in 2008. Industry paid $0.0639 and $0.0701 per 

kilowatt-hour in 2007 and 2008, respectively (Energy Information Administration, 

2009a). The pathway analyses use the 2005 electricity prices from the Annual Energy 

Outlook 2005 High A Case (Energy Information Administration, 2005): $0.08159 per 

kilowatt-hour (in 2005 dollars) for commercial electricity and $0.05549 per kilowatt-hour 

(in 2005 dollars) for industrial electricity. The commercial electricity price is used for 
19

the distributed natural gas pathway and for electricity used at the refueling station in the 

central production pathways. The industrial electricity price is used for the distributed 

electricity pathway and for electricity used in the centralized production of hydrogen. 

Wind Electricity

Wind power contributed more than a third of all new electric-generating capacity in 2007, 

installing 5,332 MW of capacity and expanding the U.S.’s total wind power–generating 

capacity by 45% in a single year from 11,575 MW to 16,907 MW; as of April 2009, the 

installed capacity has grown to 28,365 MW as seen in Figure 3.2.2 (National Renewable 

Energy Laboratory, 2009). Figure 3.2.3 shows the U.S. wind resource map for different 

wind power classes [ranging from 3 (fair) to 7 (superb)]. 

DOE released a report (United States Department of Energy, 2008) concluding that the 

U.S. possessed sufficient wind resources that would enable it to obtain 20% of its 

electricity (1.16 billion MWh) from wind by the year 2030. In 2007, the U.S. wind 

power capacity totaled 11,575 MW (11.6 GW), with wind power installations across 35 

states. In 2008, 52,025,898 thousand kilowatt-hours of wind electricity were generated in 

the U.S., up from 34,449,927 in 2007 (Energy Information Administration, 2009). Wind

sources contributed approximately 1.4% of the electricity consumed. 

Figure 3.2.1. Efficiency in electricity generation from various sources (van Aart, 2004)

0

10

20

30

40

50

60

70

80

90

100

Hydro power plant

Tidal power plant

Large gas fired CCGT power plant

Melted carbonates fuel cell (MCFC)

Pulverised coal boilers with ultra-critical steam parameters

Solid oxide fuel cell (SOFC)

Coal fired IGCC

Atmospheric Circulating Fluidised Bed Combustion (CFBC)

Pressurised Fluidised Bed Combustion (PFBC)

Large gas turbine (MW range)

Steam turbine coal-fired power plant

Steam turbine fuel-oil power plant

Wind turbine

Nuclear power plant

Biomass and biogas

Waste-to-electricity power plant

Diesel engine as decentralised CHP unit (electrical share)

Small and micro turbines (up to 100 kW)

Photovoltaic cells

Geothermal power plant

Solar power tower

Efficiency (%)
20

Figure 3.2.2. Installed wind capacity as of April 2009 (National Renewable Energy 

Laboratory, 2009)

. 

Figure 3.2.3. U.S. wind resource map (National Renewable Energy Laboratory, 2009)
21

Figure 3.2.4 shows the 2007 “bus-bar” energy cost for wind (wind plant costs only) by 

location (land-based or offshore) and by class of wind power. The U.S. has more than 

8,000,000 MW (8,000 GW) of available land-based wind resources that can be captured 

economically. 

Figure 3.2.4. Wind energy supply curve (U.S. Department of Energy, 2008)

If the entire fleet of U.S. passenger vehicles were run on hydrogen produced from wind 

electricity, 3.4 trillion kilowatt-hours would be required annually to produce the 

necessary hydrogen, and 3.4 trillion kilowatt-hours is 6,500% of the total wind electricity

consumption in 2008. The demand calculation is based on a total vehicle miles traveled 

in passenger vehicles of 2.78 trillion (Bureau of Transportation Statistics, 2007), the 

vehicle fuel economy used in this study (45 mpgge), and a yield of hydrogen from wind 

electricity of 53 kWh wind electricity/kg H2. This calculation and the wind electricity 

supply scenarios for lower fuel cell vehicle penetration rates are shown in Section 9.6.

3.3 Biomass (Wood)

Woody or herbaceous biomass may be a viable feedstock for hydrogen production in 

some areas of the U.S. and is already used in limited quantities in electricity generation. 

Biomass availability and cost vary widely and are location-specific. 

Availability and Utilization

The electric power sector, which is composed of electricity generation and combined heat 

and power (CHP) plants within North America and whose primary business is to sell 

electricity and/or heat to the public, generated a net of 10.9 billion kilowatt-hours in 2008 

from wood and derived fuels, up from 10.7 billion kilowatt-hours in 2007; the industrial 
22

sector generated a net of 27.9 billion kilowatt-hours in 2008, down from 28.3 billion 

kilowatt-hours in 2007 (Energy Information Administration, 2009j). This category 

included black liquor and wood/wood waste solids and liquids. The renewable energy 

sector contributed 9% of the 2008 electricity mix (Energy Information Administration, 

2009k). Consumption of wood-derived fuels in 2008 was 2.041 quadrillion Btu (quads), 

accounting for approximately 52% of all biomass consumed for energy (3.884 quads, 

includes biofuels, waste, and wood-derived fuels) and 28% of all renewable energy 

consumed (7.301 quads). 

In a joint study sponsored by the U.S. Department of Energy and the U.S. Department of 

Agriculture (Perlack et al., 2005), Oak Ridge National Laboratory sought to determine 

whether the land resources of the U.S. are capable of producing a sustainable supply of 

biomass sufficient to displace 30% or more of the U.S.’s present petroleum consumption. 

This goal would require approximately one billion dry tons of biomass feedstock per 

year. The researchers concluded that forestland and agriculture land, the two largest 

potential biomass sources, had the potential to provide 1.3 billion dry tons per year of 

biomass (see Figure 3.3.1) around the mid-21st century. This annual potential represents 

an increase in production of more than sevenfold from the amount of biomass consumed 

at the time of the report for bioenergy. 

The report stated that forestlands in the contiguous U.S. could sustainably produce 368 

million dry tons of biomass annually. That projection includes 52 million dry tons of 

fuelwood harvested from forests, 145 million dry tons of residues from wood-processing 

mills and pulp and paper mills, 47 million dry tons of urban wood residues including 

construction and demolition debris, 64 million dry tons of residues from logging and siteclearing operations, and 60 million dry tons of biomass from fuel-treatment operations to 

reduce fire hazards. 

Concurrently, agricultural lands in the U.S. could produce one billion dry tons of biomass 

annually and still continue to meet food, feed, and export demands. This reported 

projection includes 428 million dry tons of annual crop residues, 377 million dry tons of 

perennial crops, 87 million dry tons of grains used for biofuels, and 106 million dry tons 

of animal manure, process residues, and other miscellaneous feedstocks. 
23

Figure 3.3.1. Annual biomass resource potential from forestland and agricultural land 

(Perlack et al., 2005)

If the entire fleet of U.S. passenger vehicles were run on hydrogen produced from 

biomass, 890 million dry tons of biomass would be required annually to produce the 

necessary hydrogen, and 890 million dry tons is 730% of the wood-derived fuels 

consumed in the U.S. in 2008. The demand calculation is based on a total vehicle miles 

traveled in passenger vehicles of 2.78 trillion (Bureau of Transportation Statistics, 2007), 

the vehicle fuel economy used in this study (45 mpgge), and a yield of hydrogen from 

biomass of 12.8 kg dry biomass/kg H2. This calculation and the biomass supply 

scenarios for lower fuel cell vehicle penetration rates are shown in Section 9.3.

Resource Cost

Table 3.3.1 summarizes the estimate of the main components that make up the non-feed 

and food crop biomass available in the U.S. in the near-term at approximately $65 per ton 

delivered to the processing plant (Board on Energy and Environmental Systems, 2008). 

The table also includes other estimates for comparison. 

Table 3.3.1. Estimated Primary Solid Biomass Components Available in the United States 

in the Near Term and 2030 for Less than about $65 per Ton (2007 dollars) 

Biomass Amount (million tons per year)

NRC NearTermWalsh et al. 

(2000)

Milbrandt 

(2005)

Perlack et al. 

(2005)

NRC 

2030

Crop residue 160 50 173 179 315

Forest residues 55 44 62 136 55

Mill wastes1 5 90 88 106

Urban wood waste 30 37 34 37 30

Energy crops 85 188 99 - 100

Total 335 509 456 458 490 1 NRC estimate includes only the fraction that is estimated as not already being used.
24

Characteristics

Table 3.3.2 provides a typical analysis of dry wood (Avallone and Baumeister, 1996). 

Table 3.3.2. Typical Analysis of Dry Wood

Most Woods, range

Proximate analysis, %

 Volatile matter 74–82

 Fixed carbon 17–23

 Ash 0.5–2.2

Ultimate Analysis, %

 Carbon 49.6–53.1

 Hydrogen 5.8-6.7

 Oxygen 39.8–43.8

Heating value, Btu/lb 8,560–9,130

3.4 Coal

Because reserves of coal are abundant in the U.S., coal cannot be overlooked as a 

potential feedstock for hydrogen production. It is also the dominant feedstock for 

electricity production in the U.S. Coal availability and prices thus have both direct and 

indirect consequences for the costs of the hydrogen production pathways studied. 

Availability and Utilization

Data from EIA (Energy Information Administration, 2008d) show that the United States 

produced 1.15 billion short tons of coal in 2007 from 1,374 mines, but no data on coal 

production were reported for 2008. As of January 2008, the demonstrated U.S. reserve 

base was estimated to contain 489 billion short tons (Energy Information Administration, 

2009l). Data (Energy Information Administration, 2009g) show the United States 

consumed 1.13 billion short tons of coal in 2007; data available for 2008 show the United 

States consumed 1.12 billion short tons of coal, down slightly from the previous year. 

If the entire fleet of U.S. passenger vehicles were run on hydrogen produced from coal, 

550 million short tons of coal would be required annually to produce the necessary 

hydrogen (not including coal necessary for generation of the electricity used within the 

pathways), and 550 million short tons is 49% of the total coal consumption in 2008. The 

demand calculation is based on a total vehicle miles traveled in passenger vehicles of 

2.78 trillion (Bureau of Transportation Statistics, 2007), the vehicle fuel economy used in 

this study (45 mpgge), and a yield of hydrogen from coal of 7.85 kg coal/kg hydrogen 

(54% efficiency for Pittsburgh #8 coal on an LHV basis). This calculation and coal 

supply scenarios for lower fuel cell vehicle penetration rates are shown in Section 9.7.
25

Resource Cost

Electric utility plants paid an average of $36.06 (2007 dollars) per short ton in 2007 

(Energy Information Administration, 2008b). As was the case for coal production, no 

price data were available for 2008. 

Characteristics

Approximate composition for the general ranks of coal (anthracite, bituminous, 

subbituminous, and lignite) used in electricity generation as well as their calorific values 

(Avallone and Baumeister, 1996) are shown in Table 3.4.1. The 2007 U.S. production 

volume (Energy Information Administration, 2008d) and 2007 U.S. average open-market 

sales price (Energy Information Administration, 2008a) for the coal ranks are shown in 

Table 3.4.2. Coal rank depends on the volatile matter, fixed carbon, inherent moisture, 

and oxygen. Typically, coal rank increases as the amount of fixed carbon increases and 

the amount of volatile matter and moisture decreases. For this analysis, Pittsburgh #8 

coal is assumed.

Table 3.4.1. Approximate Composition and Calorific Value of General Ranks of Coal

% of Combustible Calorific 

Value, 

Btu/lb

Moisture Volatile 

Matter

Fixed 

Carbon

Oxygen

Anthracite 4.3 5.1 81.0 6.1 12,880

Bituminous1 8.4 36.1 46.9 14.4 12,177

Subbituminous2 21.4 32.8 40.9 32.1 9,607

Lignite 36.8 27.8 29.5 45.1 7,000

1

 Average of high-volatile bituminous A, B, and C coals.

2

 Average of subbituminous A, B, and C coals.

Table 3.4.2. U.S. Production Volume and Average Open-Market Sales Price for General 

Ranks of Coal

2007 U.S. Production, 

thousand short tons

2007 U.S. Average OpenMarket Sales Price

Anthracite 1,568 $52.24

Bituminous 542,758 $40.80

Subbituminous 523,724 $10.69

Lignite 78,585 $14.89
26

3.5 Carbon Sequestration

Carbon sequestration entails the capturing and storing of CO2 that would otherwise be 

released into the atmosphere. It is of particular interest in commercial-scale plants using 

fossil energy because economies of scale are needed to make it practical and affordable. 

Carbon sequestration is assumed only for the central coal pathway in this report. 

Two carbon dioxide capture methods—geological and terrestrial sequestration—are 

being explored by DOE (see Figure 3.5.1). Geological sequestration involves the 

separation and capture of CO2 at the point of emissions from stationary sources followed 

by storage in underground geological formations (i.e., deep salt formations or depleted oil 

and gas reservoirs). Terrestrial sequestration involves the net removal of CO2 from the 

atmosphere by plants during photosynthesis and its capture in vegetative biomass and in 

soils. Carbon dioxide uptake takes place in both land and in aquatic environments. 

Figure 3.5.1. Geological and terrestrial sequestration (National Energy Technology 

Laboratory, 2008)

DOE formed Regional Carbon Sequestration Partnerships, public/private cooperative 

efforts to develop guidelines for the most suitable technologies, regulations and 

infrastructure needs for carbon capture, and storage for different regions of the U.S. and 

Canada. Seven partnerships exist and include: 1) Big Sky Carbon Sequestration 

Partnership (BSCSP); 2) Midwest Geological Sequestration Consortium (MGSC); 3) 

Midwest Regional Carbon Sequestration Partnership (MRCSP); 4) Plains CO2 Reduction 
27

(PCOR) Partnership; 5) Southeast Regional Carbon Sequestration Partnership 

(SECARB); 6) Southwest Regional Partnership (SWP); and 7) West Coast Regional 

Carbon Sequestration Partnership (WESTCARB). A map depicting the partnership 

locations can be seen in Figure 3.5.2. 

The partnerships began in 2003 with a characterization phase to develop the framework 

to validate and deploy carbon capture and storage technologies. During this phase, the 

partnerships identified potential geological storage basins across North America. The 

conservative estimate of storage potential in North America can be found in Table 3.5.1

(National Energy Technology Laboratory, 2008). 

Table 3.5.1. Conservative Geological Carbon Storage Potential in Gigatonnes

Reservoir Type Low High

Deep saline formations 3,300 12,600

Unmineable coal seams 160 180

Oil and gas fields 140 140

Currently, the partnerships are nearing the end of the validation phase, which as implied, 

validates the most promising regional carbon-sequestration opportunities. Eleven 

terrestrial sequestration projects were implemented during this phase on abandoned mine 

land, wetlands, agricultural fields, prairie lands, and forests. Figure 3.5.2 shows the 

validation-phase CO2 storage products being developed as well as their locations across 

the U.S. and Canada (National Energy Technology Laboratory, 2008). The development 

phase, estimated to extend to 2018, involves utilizing either geological or terrestrial 

sequestration of one million tons or more of CO2 by each partnership. 
28

Figure 3.5.2. Regional carbon sequestration partnerships and their respective validation 

carbon storage projects (National Energy Technology Laboratory, 2008)
29

4.0 Status of Supporting Infrastructure 

4.1 Natural Gas Supply Infrastructure

The natural gas supply infrastructure in the U.S. consists of more than 210 natural gas 

pipeline systems, more than 1,400 compressor stations to maintain pressure on the natural 

gas pipeline network, more than 11,000 delivery points, 5,000 receipt points, 1,400 

interconnection points, 24 hubs, 400 underground natural gas storage facilities, 49 

import/export locations, 8 liquefied natural gas (LNG) import facilities, and 100 LNG 

peaking facilities (Energy Information Administration, 2008e). Table 4.1.1 estimates the 

natural gas pipeline mileage for the regions listed in Figure 4.1.1. As can be seen from 

the table, over 305,000 miles of pipeline exist in the United States; the Southwest region 

comprises over 109,000 miles of that total while the Western region has the least amount 

at fewer than 25,000 miles.

Table 4.1.1. Natural Gas Pipeline Mileage (Energy Information Administration, 2008e)

Ideally, natural gas pipelines would be utilized at or as close as possible to 100%. In 

reality, however, that rarely occurs. Several factors contribute to less-than-perfect 

utilization such as scheduled or unscheduled maintenance, decreases in demand, and 

weather disturbances. Figure 4.1.1 shows the interregional natural gas pipeline capacity 

levels with arrows indicating the direction of the interregional pipelines. Utilization rates 

below 100% do not necessarily mean that additional capacity is available for use. For 

instance, in the summer months, average utilization rates will be low compared to winter 

months. Additionally, rates can exceed 100% of the certified capacity (minimum level of 

service over an extended period of time) in periods of high demand. This rate can be 

accomplished by temporarily increasing compression within safety limits. 
30

Figure 4.1.1. Interregional natural gas pipeline capacity levels (Energy Information 

Administration, 2008e)

Energy and Environmental Analysis (EEA), an ICF International Company, analyzed 

natural gas infrastructure requirements for hydrogen production for the U.S. Department 

of Energy (Vidas, 2007). The premise of the study was that hydrogen transportation fuel 

will be supplied to early adopters of hydrogen-fueled vehicles by distributed natural gas–

fueled steam methane reformers co-located with refueling stations. EEA sought to 

determine how much natural gas would be required for hydrogen production, how the 

natural gas demand would be distributed geographically, whether the existing or expected 

future natural gas transmission system could accommodate the anticipated demand, 

whether physical constraints would prevent local distribution companies (LDCs) from 

being able to supply natural gas to refueling stations, and how much needed natural gas 

infrastructure improvements would cost. It was assumed that 15% of light-duty vehicles 

in 27 largest U.S. cities (11.7 million vehicles) would be fueled by hydrogen, and that all 

of the hydrogen would be produced at 1,500 kg/day refueling stations using natural gas. 

At this penetration rate, almost 6,400 refueling stations (with a utilization factor of 75%) 

would be required in the 27 cities. Assuming that 170 cubic feet of natural gas is 

required to produce 1 kg of hydrogen, each station will require 255,000 cubic feet of 

natural gas per day. This volume of natural gas is considered a large load for an LDC, 

equivalent to the average load of 1,200 homes or two to three industrial plants. 
31

EEA compared the natural gas needs for hydrogen against the total load for each city (all 

sectors) to determine the impact on transmission systems and estimated that hydrogen 

would increase total (all-sector) peak natural gas demand by an average of 1.7% (ranging 

from 0.6% to 5.8%) over projected demand in 2025 for the 27 cities. Only 3 of the 27 

cities would experience a natural gas demand increase of more than 3% as a result of 

hydrogen production: Miami, Seattle, and Orlando. 

The natural gas needs for hydrogen were also compared against residential and 

commercial loads to determine the impact on distribution systems. Hydrogen would 

increase residential/commercial peak natural gas demand by an average of 2.6% (ranging 

from 1.4% to over 45%) over projected demand in 2025 for the 27 cities. Four cities 

would experience a residential/commercial natural gas demand increase of more than 5% 

as a result of hydrogen production: Los Angeles, Miami, Phoenix, and Orlando. 

Natural gas is delivered to city gates in interstate transmission pipelines that are 20–36 

inches in diameter and flow at pressures between 1,000 and 750 psig. At the city gate, 

the pressure is stepped down to ~400 psig or lower. LDCs deliver the gas from the city 

gate to the end user through smaller-diameter trunk lines (>125 psig, ~20-inch diameter), 

high-pressure feeders (125–25 psig, ~12-inch diameter), low-pressure feeders (25–15 

psig, ~6-inch diameter), and mains (15–5 psig, ~2-inch diameter). Figure 4.1.2 shows a 

hypothetical 12-mile by 16-mile city-wide gas distribution grid. Figure 4.1.3 shows 

hypothetical pressures in distribution mains serving a two-square mile area.
32

Figure 4.1.2. Hypothetical 12 x 16-mile city-wide gas distribution grid (Vidas, 2007)

Figure 4.1.3. Hypothetical pressures (psig) in distribution mains at maximum design flows 

(Vidas, 2007)
33

EEA concluded that the changes to transmission pipeline capacities needed to 

accommodate the hydrogen production will depend on what LNG terminals, pipeline, and 

storage assets are built in the coming years to meet overall natural gas demand growth. 

Required hydrogen-related gas transmission expenditures were estimated to cost $1 to 

$1.5 billion, roughly 2% of the gas transmission expenditures expected in the next 20 

years. Assuming gradual growth of hydrogen, EEA did not anticipate that gas 

transmission pipelines would represent a barrier to hydrogen production. 

New service lines will have to be installed to accommodate refueling stations with natural 

gas loads of 255,000 cubic feet per day because a station of this size will require more 

gas than can be supplied through a typical 2-inch-diameter main. Initial stations may be 

sited on streets with feeder lines to minimize the cost to LDCs. Steward et al. (2009) 

asserted that 1,500 kg/day hydrogen stations with on-site hydrogen production from 

natural gas using SMR would need to tie into 4-inch or larger natural gas feeder lines.

One strategy under consideration for implementing early hydrogen fueling infrastructure 

is to establish networks of fueling stations in a limited number of urban centers, 

beginning with Southern California and the area surrounding New York City (Greene et 

al., 2008). Because existing gasoline stations are potential sites for future hydrogen fuel 

stations, the Fuel Pathway Integration Technical Team (Steward et al., 2009) assessed the 

proximity of existing gasoline fueling stations in Los Angeles to natural gas feeder lines. 

As shown in Figure 4.1.4, there are around 1,500 gasoline stations within a half mile of a 

feeder line in Los Angeles.

 

Figure 4.1.4 Number of refueling stations within one mile of natural gas feeder line in Los 

Angeles (Steward et al., 2009)
34

In HDSAM, the cost of installed pipelines with diameters less than 6 inches is estimated 

using the following equation: 

$/mile=5280*(5.6822*D^2-15.767*D+66.212) 

where D is the pipeline diameter in inches. Using this equation, a 4-inch feeder line will 

cost $496,600 per mile (installed). The average distance of refueling stations in the Los 

Angeles metropolitan area to a feeder line is 0.73 miles, correlating to a cost of $362,500 

(installed) (Steward et al., 2009).

EEA (Vidas, 2007) estimated that required hydrogen-related gas distribution expenditures 

will cost $1 to $2.5 billion, about 1.5% of the gas distribution expenditures expected in 

the next 20 years. LDCs in warm locations with relatively low natural gas loads will be 

impacted most severely by the addition of natural gas–derived hydrogen. 

4.2 Electricity Transmission Grid 

The North American electricity transmission system is composed of three major 

interconnected power systems: the Eastern Interconnections, the Western 

Interconnections, and the Electric Reliability Council of Texas. Within each system, 

disturbances or reliability events are felt nearly instantaneously throughout the system. 

This transmission system was built over the past 100 years by vertically integrating 

utilities that produced electricity at large generation stations located close to fuel 

supplies. Over 150,000 miles of high-voltage transmission lines (both alternating current 

and direct current) link generators to load centers across the states and along the borders 

with Mexico and Canada. A 2002 U.S. Department of Energy report found that the 

U.S.’s transmission system was under stress (Abraham, 2002). Findings of that report 

attributed the stress to growth in electricity demand and new generation, lack of 

investment in new transmission facilities, and the incomplete transition to fully efficient 

and competitive wholesale markets. These factors allow for transmission bottlenecks, 

which lead to increased electricity costs to consumers as well as increased risk of 

blackouts. 

Transmission bottlenecks occur when there is not enough transmission capability to 

accommodate all requests to ship power over existing lines and maintain adequate safety 

margins for reliability. Because electricity cannot be stored economically as of yet, 

transmission-system operators must deny requests for transmission service when they 

receive too many to prevent lines from becoming overloaded. Bottlenecking is managed 

through Transmission Loading Relief (TLR), also known as “calls,” which determines 

which requests will be denied. The DOE report (Abraham, 2002) shows that the number 

of TLR calls increased between 1997 and 2001 (see Figure 4.2.1). More recent data are

unavailable at this time. Frequent TLR calls increase consumer electricity costs by 

denying low-cost transactions in favor of high-cost transactions.
35

Figure 4.2.1. Transmission loading relief calls for 1997-2001 (Abraham, 2002)

Out of 186 transmission paths for the Eastern Interconnection, 50 were used to their 

maximum capacity at some point during the year, and 21 paths were congested more than 

10% of the hours during the year studied in the 2002 DOE report. Figure 4.2.2 shows a 

map of the congestion for the Eastern Interconnection. The highest levels of congestion 

were found to be transmissions from Minnesota to Wisconsin, from the Midwest to the 

Mid-Atlantic, from the Mid-Atlantic to New York, and from the Southeast to Florida. Of 

the 106 transmission paths for the Western Interconnection, 37 were congested at some 

point during the year, half of these are congested less than 10% of the time, and no path is 

congested more than 60% of the hours during the year studied in the 2002 DOE report 

(see Figure 4.2.3). The Western Interconnection was built primarily to carry power over 

long distances, unlike that of the Eastern Interconnection, which may account for the 

differences between the two. 

Construction of new transmission facilities would alleviate the stress of bottlenecking. 

However, investment in new transmission facilities (see Figure 4.2.4) is lagging behind 

investment in new generation and growth in electricity demand. Construction of highvoltage transmission facilities is expected to increase by 6% (in line miles) by 2012 in 

contrast to the expected 20% increase in electricity demand and generation capacity (in 

MW). This projected growth, which does not include impacts of potential transportation 

technologies such as plug-in hybrid electric vehicles (PHEVs), was deemed inadequate to 

ensure grid reliability (Abraham, 2002). The North American Electric Reliability 
36

Corporation asserts that PHEVs have the potential to support grid reliability by 

supplementing electricity generation capacity during times of peak usage and drawing 

charging power from the grid during off-peak hours (North American Electric Reliability 

Corporation, 2009). FCVs may also have potential to support grid reliability; however, 

examination of grid effects of electric vehicles (PHEVs or FCVs) is beyond the scope of 

this study. 

Figure 4.2.2. Map of Eastern Interconnection Congestion (Abraham, 2002)
37

Figure 4.2.3. Map of Western Interconnection Congestion (Abraham, 2002)

Figure 4.2.4. New transmission facility investment for the period 1975–2000 (Abraham, 

2002)
38

4.3 Biomass Truck Transportation and Delivery

Delivery of biomass can be accomplished in multiple ways with rail or truck being the 

most common. The form of the truck is typically that of a tractor-trailer. Trailers can 

come in several varieties: log trailer, container trailer, or bulk van. Regardless of the 

tractor and trailer setup, an over-the-road truck of this combination is limited to a gross 

vehicle weight of 80,000 lbs. As an example and depending on the type of tractor 

(sleeper cab or non-sleeper), a bulk van will have a legal payload in the range of 42,000 

to 52,000 lbs (20 to 25 tons), which translates to between 97 and 131 cubic yards of 

biomass (Hubbard, Biles, Mayfield, and Ashton, 2007). The capital cost of a tractor is 

approximately $75,000; a trailer costs approximately $35,000 (Harris et al., 2004). 

Using the assumptions in this study, if the entire fleet of U.S. passenger vehicles were run 

on hydrogen produced from biomass, 890 million dry tons of biomass would be required 

annually to produce the necessary hydrogen (see Section 3.3). If all of this biomass were 

delivered by trucks with a payload of 20–25 tons, and each truck delivered three payloads 

per day on average, approximately 32,000–41,000 trucks would be needed. 

The total number of Class 8 trucks (gross vehicle weight 33,001 lbs and more) in 2002 

was estimated to be over 2.15 million. Annual retail sales of new Class 8 trucks ranged

from 140,000 to 284,000 for the years 1998–2007 and averaged 200,000 over that 10-

year timeframe (Davis et al., 2009). Truck availability is therefore not likely to limit 

implementation of biomass-gasification-based hydrogen production plants.

Perlack et al. (2005) estimated that 368 million dry tons of woody biomass is available 

from U.S. forest lands. Thus, to produce enough hydrogen to fuel all U.S. passenger 

vehicles, herbaceous biomass from agricultural lands would also be needed. Issues that 

impact biomass delivery distances and costs for woody and herbaceous biomass are 

described below. 

Woody Biomass

In whatever form it takes (slash, small trees with limbs, or tree sections), woody biomass 

has an inherently low bulk density. Transportation costs are high due to this low bulk 

density because air is a major component of the transported biomass volume. Bulk 

density can be increased by processing (chipping, grinding, or shredding), which allows 

for the biomass to be compacted (see Figure 4.3.1). Processing, however, decreases 

biomass storage durability and longevity (Hubbard, Biles, Mayfield, and Ashton, 2007). 

Additionally, woody biomass has a low energy density when compared to other fossil 

fuels (coal). For example, wood chips have approximately three times the bulk per unit 

energy than coal does and as a result need three times the storage space (Harris et al., 

2004). Therefore, when compared to fossil fuels, biomass has a high transportation cost. 
39

Figure 4.3.1. Bulk volume of woody biomass in different processed forms with the same 

weight (Hubbard, Biles, Mayfield, and Ashton, 2007)

A tradeoff between feedstock transportation and plant efficiency has resulted in an 

optimum electricity-generating power plant size of about 40–50 MW (1,750 tons woody 

biomass per day). This sized plant operating at full capacity would typically receive 70 

truckloads per business day, requiring 140 daily truck trips (Timmons, Damery, Allen, 

and Petraglia, 2007). Processed (chipped) woody biomass can be accomplished at a cost 

of approximately $12 per ton in-woods cost. Assuming a freight cost of $2 per mile, a 25 

ton payload of chipped biomass and a 50-mile delivery distance to the plant, the biomass 

can be transported at the cost of approximately $16 per ton (Harris et al., 2004) for a 

feedstock cost of $28 per wet ton or $37.33 per dry ton. The 2012 industry initiation/low 

demand cost target, which was used in the analysis, is $35 per dry ton in 2002 dollars or 

$37.96 per dry ton in 2005 dollars (Hess, Denney, Wright, Radtke, and Perlack, 2007).

Herbaceous Biomass

The National Renewable Energy Laboratory conducted a tradeoff analysis (Aden et al., 

2002) to determine the effect of ethanol production plant size on the required radius of 

corn stover collection. A maximum corn stover yield of 2 metric tons (MT) was 

assumed. It was also assumed that the ethanol plant would be located in the middle of the 

farmland from which the corn stover would be collected and that 75% of the total 

surrounding land area is farm land that can be planted. In Figure 4.3.2, 100% access 

represents a scenario in which all farmers are growing corn continuously and are willing 

to sell their stover, a highly unlikely scenario. A 50% access represents a scenario in 

which farmers split their land between soybean and corn. It was found that this scenario 

is also unlikely because a soybean/corn rotation would not likely produce 2 MT per acre. 

A 10% access is a more realistic scenario. Aden et al. assumed that plants would not 

collect corn stover outside a 50-mile radius around the ethanol plant. The plant size from 

Figure 4.3.2 corresponding to 10% access, and a 50-mile radius is 2,000 MT stover per 

day (1,823 tons stover per day). This sized ethanol plant is comparable to the 1,750-tonper-day power plant discussed in the woody biomass section. 
40

Figure 4.3.2. Effect of plant size on collection distance (Aden et al., 2002)

Figure 4.3.3 shows the relative contribution of the sources of costs for stover collection 

and delivery based on analyses done by Oak Ridge National Laboratory. The figure 

shows that 23% of the total delivered stover cost ($62 per dry MT/$56 per dry ton) is 

transportation cost. This $13-per-ton stover transport cost agrees favorably with the $16-

per-ton woody biomass transport cost, both of which assume a 50-mile delivery distance.

Figure 4.3.3. Breakdown of corn stover costs (Aden et al., 2002)

4.4 Coal Moved by Railway

For 2007, EIA reported that 1,138,529 thousand short tons of coal were moved via 

railroad from 18 states for electric-generation purposes (Energy Information 

Administration, 2008c). In November 2007, the U.S. Department of Transportation 

conducted research to determine future rail capacity to deliver increasing amounts of coal 

and the amount of investment that might be needed to fulfill that capacity (McCollum, 
41

Ogden, and Chernicoff, 2007). The study looked at several different scenarios (see Table 

4.4.1) for coal demand growth (see Figure 4.4.1) and considered the tradeoff between 

pulverized coal (PC) or IGCC power plants, as well as an additional amount of coal to 

produce hydrogen for fuel cell vehicles. 

Table 4.4.1. Various Scenarios for Coal Demand Growth 

Scenario Description

BAU1 Baseline scenario using EIA projection for coal power demand and 

assuming that all new coal plants will be PC

BAU2 BAU2a and BAU2b: A similar scenario to BAU1 but assuming that all 

new coal plants will be IGCC. BAU2b only: In addition to building 

new IGCC plants, all old PC plants are gradually retrofitted to IGCC.

BAU2+LowH2 A similar scenario to BAU2b except that in addition to IGCC plants 

being built, extra coal is used to supply a fleet of hydrogen fuel cell 

vehicles that obtain a 50% share of the total vehicle market by the year 

2050

BAU2+HighH2 A similar scenario to BAU2b except that in addition to IGCC plants 

being built, extra coal is used to supply a fleet of hydrogen fuel cell 

vehicles that obtain a 100% share of the total vehicle market by the 

year 2050

Figure 4.4.1. Total annual coal demand for various scenarios (McCollum, Ogden, and 

Chernicoff, 2007)
42

Coal traffic on each rail line was modeled using a confidential set of data known as the 

Carload Waybill Sample. Waybill sample data from 2004 (see Figure 4.4.2) were used in 

conjunction with the projections of the Freight Analysis Framework 2 (FAF2) program, 

which provides estimates of freight commodity flows. Projections were divided into coal 

(modified for the various scenarios) and non-coal (taken directly from FAF2) categories. 

Hypothetical waybill for future years for the various scenarios was then routed onto the 

rail network. Forty-two routes were identified that will likely carry the bulk of the coal 

demand in the future (see Figure 4.4.3). These routes represent approximately 5% of all 

route mileage in the North American rail network but are responsible for transporting 

more than 80% of the coal shipped by rail. 

Four different capacity enhancement strategies were analyzed: 1) upgrading the signaling 

system to centralized traffic control; 2) upgrading the signaling system to positive train 

control; 3) adding new mainline track; and 4) upgrading the quality of mainline track, 

allowing heavier-capacity rail cars to be transported over them. It was determined that 

the incremental capital costs of adding capacity to all 42 routes is on the order of $0.5–

$5.5 billion (in discounted terms, over the timeframe 2004–2050). The report also 

concluded that it did not seem likely that the incremental costs of adding new capacity 

will markedly increase coal transportation rates or the delivered price of coal, even under 

aggressive scenarios of coal demand growth. 

Figure 4.4.2. Rail traffic on the rail network for 2004 waybill sample data (McCollum, 

Ogden, and Chernicoff, 2007)
43

Figure 4.4.3. Coal rail routes (McCollum, Ogden, and Chernicoff, 2007)
44

5.0 Production Technology Description and Assumptions

The hydrogen production technologies used in each of the seven pathways examined in 

this study are described below. Note that this study assumes that energy used in the 

production facility for lighting, control systems, etc. 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.

5.1 Distributed Natural Gas Reforming

The H2A distributed natural gas model (James, 2008) 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 tube-in-shell SMR with hydro-desulfurization pre-treatment 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. 

Reforming (CnHm + nH2O  (n+m/2)H2 + nCO) and water-gas shift (CO + H2O  CO2

+ H2) are the main reactions in the steam-reforming process. The reformer heat is 

supplied by the PSA offgas; a small amount of natural gas is added for burner control. 

The amount of natural gas added is equal to 10% of the heating value of the PSA offgas. 

The high-temperature-shift and low-temperature-shift reactors convert the majority of the 

CO into CO2 and H2 through the water-gas shift reaction.

A PSA unit is used to separate the hydrogen from the other components in the shifted gas 

stream, mainly CO2 and unreacted CO, CH4, and other hydrocarbons. The hydrogen 

purity achieved from a PSA unit can be greater than 99.99%. For this analysis, the 

concentration of hydrogen in the shifted stream prior to the PSA is between 60 and 65 

mol%. Therefore, part of the PSA hydrogen product stream is recycled back into the 

PSA feed to increase the hydrogen concentration to 70 mol%. For a 70-mol% hydrogen 

PSA feed, an overall hydrogen recovery rate of 85% is typical with a product purity of 

99.9 vol%. 

A single 1,500 kg/day unit is assumed (as opposed to the previous H2A assumption of 

parallel 750 kg/day units). 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 6,250 psi (maximum) for transfer into a four-bed, high-pressure 

cascade system to allow rapid filling of 5,000-psi onboard hydrogen vehicular tanks. A 

process flow diagram is shown in Figure 5.1.1. 
45

Figure 5.1.1. Distributed natural gas reforming process flow diagram (James, 2008)

5.2 Distributed Electrolysis

The system modeled in the H2A distributed electrolysis model (Ramsden, 2008b) is a 

standalone, grid-powered electrolyzer system with a total hydrogen production capacity 

of 1,500 kg/day. The system is based on the hydro bi-polar alkaline electrolyzer system 

[Atmospheric Type No.5040–5150 amp direct current (DC)]. 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. 

KOH 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. A process flow chart and a mass balance diagram are shown in Figure 5.2.1 

and Figure 5.2.2, respectively. 

The electrolyzer system receives alternating current (AC) grid electricity, which is 

converted via transformer and rectifier sub-systems into DC electricity for use by the 

electrolyzer stack. The transformer subsystem is an oil-immersed, ambient air-cooled 

unit, manufactured to IEC-76. The rectifier sub-system converts the AC voltage to DC 

voltage using thyristors. Cooling is generally accomplished via forced air cooling 

achieved by fan(s) on the bottom of the rectifier cabinet but can also be accomplished 

with cooling water. The electrolyzer system uses 4.8 kWh of electricity per Nm3 of 

hydrogen produced (53.4 kWh per kilogram of hydrogen produced) with the electrolyzer 

stack requiring 4.3 kWh and the remainder used by the balance of plant. 
46

Figure 5.2.1. Distributed electrolysis process flow diagram (Ramsden, 2008b)

Figure 5.2.2. Distributed electrolysis mass balance diagram (Ramsden, 2008b)

Gas Purification

Water (4)

Electrolyzer

Hydrogen (2)

Oxygen (3)

Water (1)

Hydrogen Generation Unit

Hydrogen

Oxygen
47

The electrolyzer system requires high-purity water to avoid deterioration of electrolyzer 

performance. Process water is demineralized and softened to a specific resistance of 1 to 

2 megaohm/cm in the demineralizer unit. The system requires 1 L of process water per 

Nm3 of hydrogen produced (2.939 gal/kg H2).

The system requires 100 L of cooling water per Nm3 of hydrogen produced (293.9 gal/kg 

H2 produced). It is assumed that the cooling water system is a closed water loop (see 

Figure 5.2.3), which is maintained at approximately 30°C via a water evaporative spray 

cooler. The spray cooler requires approximately 611 kg/day of water (0.41 L/kg H2 – 

0.11 gal/kg H2).

The electrolyzer system produces hydrogen and oxygen from the electrolysis of feed 

water. The gas from each cell in the electrolyzer stack is collected in the hydrogen and 

oxygen flow channels and is fed into the gas/lye (KOH) separators. The lye, separated 

from the produced gas, is recycled through the lye pump, through the lye cooler, and back 

into the lye tank. Excess heat in the electrolyzer is removed by the lye cooler. Oxygen is 

removed from the lye in the oxygen/lye separator. The system modeled does not capture 

the oxygen gas, but capture of the high-purity oxygen gas is a possibility. Saturated 

hydrogen gas from the hydrogen/lye separator is fed to the gas scrubber subsystem, 

which purifies the hydrogen. The hydrogen gas is held in a small gas holder unit and 

then is compressed to 435 psig (30 bar). Following compression, residual oxygen is 

removed from the hydrogen gas by the deoxidizer unit, and the hydrogen gas is then dried 

in the twin-tower dryer. The purity of the hydrogen gas coming off the electrolyzer stack 

is 99.9 %. Following the gas purifier, deoxidizer, and dryer stages, the purity of 

hydrogen increases to 99.9998% (2 ppm impurities).

Figure 5.2.3. Distributed electrolysis process flow diagram cooling water detail (Ramsden, 

2008b)

Temperature (C)

Mass Flow Rate (kg/day)

Duty (Watt)

Q Duty (Watt)

80

1908

H2-WET

WATERHX

Q=20106.9

40

1908

H2-COLD

34

H2OCOLD 40000

45

40000

H2OHOT2

FLASH2

40

1561

H2-DRYER

40

CONDENS 347

EVAPHX

Q=20049.5

SPRAY

25

611

SPRAYH2O 18

21011

AIR3

37

21008

AIR4

FLASH3 37

20806

AIR5

37

202

H2OMIST1

45

H2OHOT 40000

25

20000

AIR1

AC

25

AIR2 20198

25

198

HUMIDITY

38

202

H2OMIST2
48

5.3 Central Biomass Gasification

The systems examined in the H2A central biomass gasification model (Mann and 

Steward, 2008) 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 Figure 5.3.1. The as-received wood is dried from 50 wt% moisture to 12% 

employing a rotary dryer. The dryer uses gas from the char combustor as the drying 

medium. Conveyors and hoppers are used to feed the wood to the low-pressure, 

indirectly heated entrained flow gasifier. Heat for the endothermic gasification reactions 

is supplied by circulating hot synthetic olivine, which is calcined magnesium silicate 

[primarily enstatite (MgSiO3), forsterite (Mg2SiO3), and hematite (Fe2O3)] used as a sand 

for applications between the gasifier and a char combustor vessel. A small amount of 

MgO is added to the fresh olivine to keep it from forming glass-like bed agglomerations 

that would result from biomass potassium interacting with the silicate compounds. The 

gasification medium is steam. The char that is formed in the gasifier is burned in the 

combustor to reheat the olivine. Particulate removal is performed through cyclone 

separators. Ash and any sand particles are landfilled.

Figure 5.3.1. Central biomass gasification flow diagram (Mann and Steward, 2008)
49

Reforming (CnHm + nH2O  (n+m/2)H2 + nCO) and water-gas shift (CO + H2O  CO2

+ H2) are the main reactions in the steam-reforming process. The reformer heat is 

supplied by PSA offgas; a small amount of natural gas is added for burner control. The 

amount of natural gas added is equal to 10% of the heating value of the PSA offgas. The 

high-temperature-shift and low-temperature-shift reactors convert the majority of the CO 

into CO2 and H2 through the water-gas shift reaction.

A PSA unit is used to separate the hydrogen from the other components in the shifted gas 

stream, mainly CO2 and unreacted CO, CH4, and other hydrocarbons. The hydrogen 

purity achieved from a PSA unit can be greater than 99.99%. For this analysis, the 

concentration of hydrogen in the shifted stream prior to the PSA is between 60 and 65 

mol%. Therefore, part of the PSA hydrogen product stream is recycled back into the 

PSA feed to increase the hydrogen concentration to 70 mol%. For a 70-mol% hydrogen 

PSA feed, an overall hydrogen recovery rate of 85% is typical with a product purity of 

99.9 vol%. 

The steam-cycle produces power in addition to providing steam for the gasifier and 

reformer operations. The steam cycle is integrated with the biomass-to-hydrogen 

production process. There is an extraction steam turbine/generator, and steam is supplied 

to the reformer and gasifer from the intermediate and low pressure turbine sections, 

respectively. Superheated steam enters the intermediate pressure turbine at 1,000oF and

1,265 psia and is expanded to a pressure of 450 psia. The steam then enters a lowpressure turbine and is expanded to a pressure of 35 psia. Finally, the steam enters a 

condensing turbine and is expanded to a pressure of 1.5 psia. Preheaters, steam 

generators, and superheaters are integrated within the process design. The condensate 

from the syngas compressor and the condensate from the cooled shifted-gas stream prior 

to the PSA are sent to the steam cycle, de-gassed, and combined with the make-up water. 

A pinch analysis was performed to determine the heat integration of the system.

A cooling water system is also included in the Aspen Plus® model to determine the 

requirements of each cooling-water heat exchanger within the hydrogen production 

system as well as the requirements of the cooling tower. The cooling water supply 

temperature is 90°F, and the return temperature is 110°F.

5.4 Central Natural Gas Reforming 

Steam reforming of hydrocarbons continues to be the most efficient, economical, and 

widely used process for production of hydrogen and mixtures of hydrogen and carbon 

monoxide (CO). The H2A central natural gas reforming model (Steward, 2008) assesses

the economic production of hydrogen by steam reforming of natural gas.

A process flow chart is shown in Figure 5.4.1, and the stream summaries are shown in 

Table 5.4.1. Natural gas is fed to the plant from the pipeline at a pressure of 450 psia. 

The gas is generally sulfur-free, but odorizers with mercaptans must be cleaned from the 

gas to prevent contamination of the reformer catalyst. The desulfurized natural gas 
50

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 CO and H2, is strongly endothermic, and the 

metallurgy of the tubes usually limits the reaction temperature to 1,400°F–1,700°F. 

Figure 5.4.1. Central natural gas process flow diagram (Steward, 2008)

Table 5.4.1. Central Natural Gas Stream Summary (Steward, 2008)

STREAM 

NUMBER 1 2 3 4 5

Natural 

Gas Steam Air Hydrogen

Stack 

Gas

Mole Fraction

 Ar 0.0000 0.0000 0.0093 0.0000 0.0073

 CH4 0.9000 0.0000 0.0000 0.0000 0.0000

 C2H6 0.0500 0.0000 0.0000 0.0000 0.0000

 CO2 0.0000 0.0000 0.0004 0.0013 0.1677

 H2 0.0000 0.0000 0.0000 0.9947 0.0000

 H2O 0.0000 1.0000 0.0101 0.0000 0.1835

 N2 0.0500 0.0000 0.7724 0.0040 0.6115

 O2 0.0000 0.0000 0.2078 0.0000 0.0301

NOx ---- ---- ---- ---- 20 ppm

Total Flow 

(lbmol/hr) 6,981 24,432 29,489 16,102 37,697

Total Flow (lb/hr) 121,060 440,145 851,008 35,008 1,095,760

Temperature (°F) 59 750 60 108 280

Pressure (psia) 450.0 450.0 14.7 346.0 14.7
51

Reforming (CnHm + nH2O  (n+m/2)H2 + nCO) and water-gas shift (CO + H2O  CO2

+ H2) are the main reactions in the steam-reforming process. The reformer heat is 

supplied by the PSA offgas; a small amount of natural gas is added for burner control. 

The amount of natural gas added is equal to 10% of the heating value of the PSA offgas. 

The high-temperature-shift and low-temperature-shift reactors convert the majority of the 

CO into CO2 and H2 through the water-gas shift reaction.

A PSA unit is used to separate the hydrogen from the other components in the shifted gas 

stream, mainly CO2 and unreacted CO, CH4, and other hydrocarbons. The hydrogen 

purity achieved from a PSA unit can be greater than 99.99%. For this analysis, the 

concentration of hydrogen in the shifted stream prior to the PSA is between 60 and 65 

mol%. Therefore, part of the PSA hydrogen product stream is recycled back into the 

PSA feed to increase the hydrogen concentration to 70 mol%. For a 70-mol% hydrogen 

PSA feed, an overall hydrogen recovery rate of 85% is typical with a product purity of 

99.9 vol%. 

The flue gas path of the fired reformer is integrated with additional boiler surfaces to 

produce about 700,000 lb/hour steam. Of this, about 450,000 lb/hour is superheated to 

450 psia and 750°F to be added to the incoming natural gas. Additional 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 water-gas shift reactor to produce additional H2. 

5.5 Central Electrolysis

The system modeled in the H2A central electrolysis model (Ramsden, 2008a) 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. As such, the process description for distributed electrolysis in Section 5.2 

describes this production process as well.

The H2A central electrolysis model is not based on wind-power, so this analysis assumed 

that a single facility is buying electricity from the grid and wind-power credits for all the 

electricity purchased. Because the facility is using grid power, the operating capacity 

factor is 97%. If the facility were co-sited with the wind turbines, it is likely to have a 

lower operating capacity because the turbines will not be generating electricity much of 

the time. The optimal location and the capacity factor were not included in this analysis.

5.6 Central Coal with Carbon Capture and Sequestration

The H2A central coal with carbon capture and sequestration model (Rutkowski, 2008a) 

uses capital and operating cost data to be used to arrive at a plant gate cost for hydrogen 

produced from coal gasification. Hydrogen cost was determined by first preparing a 

plant design for hydrogen production based on currently available process technology 
52

and then meeting current permitting regulations for environmental compliance. This 

baseline plant captures CO2. 

To arrive at a cost estimate for hydrogen, the design includes commercially available 

process technology obtained from verifiable sources. The plant utilizes a Wabash Riverscale ConocoPhillips (EGasTM) 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. Two-stage Selexol® 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 EGasTM gasifier is the gasifier of choice for this study because it has been 

operated on both bituminous and subbituminous coals. 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. Table 5.6.1 presents the properties of 

Pittsburgh No. 8 coal used in the H2A analysis. A process flow chart is shown in Figure 

5.6.1, and the energy efficiencies are shown in Table 5.6.2. 

Table 5.6.1. Pittsburgh No. 8 Coal Properties (Rutkowski, 2008a)

Coal Constituents

Component Air Dry, % Dry, % As Received, %

Carbon 71.88% 73.79% 69.36%

Hydrogen 4.97% 4.81% 5.18%

Nitrogen 1.26% 1.29% 1.22%

Sulfur 2.99% 3.07% 2.89%

Ash 10.30% 10.57% 9.94%

Oxygen 8.60% 6.47% 11.41%

Total 100.00% 100.00% 100.00%

Moisture 6.00%

Volatile matter 38.20% 35.91%

Fixed carbon 51.23% 48.15%

Total (including ash) 100.00% 100.00%

Heating Values, standard units

Value

Dry, Btu/English 

ton

As Received, 

Btu/English ton

High heating value 26,488,000 24,900,000

High heating value free of moisture and ash 29,620,000

Low heating value 23,806,000

Heating Values, SI units

Value Dry, MJ/kg

As Received, 

MJ/kg

High heating value 30.804 28.957

High heating value free of moisture and ash 34.446

Low heating value 27.685
53

Ash Constituents of Coal: Dry Coal-Based

Component Dry, %

Silica, SiO2 48.10%

Aluminum oxide, Al2O3 22.00%

Iron oxide, Fe2O3 24.00%

Titanium dioxide, TiO2 1.30%

Calcium oxide, CaO 1.30%

Magnesium oxide, MgO 0.60%

Sodium oxide, Na2O 0.30%

Potassium oxide, K2O 1.50%

Sulfur trioxide, SO3 0.80% 

Phosphorous pentoxide, P2O5 0.10%

Total 100.00%

Ash Fusion Temperature, degrees F

Item

Reducing 

Atmosphere

Oxidizing 

Atmosphere

Initial deformation 2,015 2,570

Spherical 2,135 2,614

Hemispheric 2,225 2,628

Fluid 2,450 2,685

Ash Fusion Temperature, degrees C

Item

Reducing 

Atmosphere

Oxidizing 

Atmosphere

Initial deformation 1,087 1,396

Spherical 1,154 1,420

Hemispheric 1,204 1,428

Fluid 1,329 1,460

Figure 5.6.1. Central coal with carbon capture process flow diagram (Rutkowski, 2008a)
54

Table 5.6.2. Energy Efficiencies of Process Components of the Central Coal with Carbon 

Capture and Sequestration Pathway (Rutkowski, 2008a)

 Energy efficiencies for individual process 

steps (add rows as appropriate) Value Basis Reference

Gasifier Cold Gas Effieiency 72%

LHV efficiency of energy in 

gasifier product gas coming out 

of gasifier divided by energy in 

coal fed to gasifier. Aspen Plus Model

Carbon Conversion 99% Percent of carbon in coal 

converted to gaseous product

ConocoPhillips 

gasifier spec.

Shift Reactor Conversion 90% Molar percent of CO converted 

to CO2

Haldor Topsoe 

commercial catalyst 

spec.

PSA Hydrogen Separation 80% Percent hydrogen rercovered 

from PSA feed gas

UOP commercial 

PSA design spec.
55

6.0 Delivery Technology Description and Assumptions

The hydrogen delivery and distribution technologies used in each of the seven pathways 

examined in this study are described below. Note that this study assumes that energy 

used in the hydrogen refueling station for lighting, cryogenic pumping, security cameras, 

etc. 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.

6.1 Liquid Hydrogen Delivery

The components for the liquid hydrogen pathway include: central production → liquefier 

→ liquid hydrogen (including liquid storage for plant outages) → liquid hydrogen truck 

transmission and distribution → and liquid 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 fuel stations as well as distances traveled. The 

capital and operating costs of the delivery trucks, including the amount of diesel fuel 

required, are computed. Additionally, the cost of appropriately sized liquefiers, terminal 

storage, liquid pumps, vaporizers, etc. 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. 

6.1.1 Liquid Hydrogen Truck

A typical liquid hydrogen trailer can carry up to 3,900 kg of hydrogen. HDSAM

calculates the amount of hydrogen that is loaded on a trailer when it leaves the terminal. 

The equation is as follows:

Where:

Vtank = water volume of the trailer (m3) 

ρLH2 = density of liquid hydrogen (g/L)

ALH2Truck = availability of the liquid truck

The amount of hydrogen loaded on the trailer is then used to calculate the amount of boiloff losses during delivery to a station, using the following equation: 
56

Where: 

H2,prev = hydrogen in trailer from previous station 

Br = boil-off rate (fraction of a day) 

T = travel time (days) 

HDSAM assumes there are only combinations of one tractor and one trailer. 

Additionally, it is assumed that the stations are the same distance from the terminal and 

that the same amount of hydrogen is delivered to each station. 

Total fuel cost is determined by multiplying the HDSAM fuel cost value by the fuel 

consumption by trip, which is calculated based on truck fuel economy and distance 

traveled. Total capital (truck and trailer), labor and other operational and maintenance 

costs are added together so a cost for hydrogen can be determined. 

6.1.2 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 6.1.1. Figure 6.1.1

shows how the energy requirement of a liquefier decreases as the design capacity or 

hydrogen flow rate drops below 5 tonnes/day. 

Figure 6.1.1. Liquefier energy requirement versus hydrogen flow rate (National Renewable 

Energy Laboratory, 2006)
57

The formula for the actual power requirement is as follows:

Where:

Preq = curve fit from Figure 6.1.1 

Favg = average hydrogen flow rate out 

loss = hydrogen loss during liquefaction 

The thermodynamically ideal system for liquefaction assumes reversible isothermal 

compression and a reversible isentropic expansion. The theoretical power requirement is 

calculated using the following formula: 

Where:

Wnet = idealized net work required by the liquefier [kWh / (kg/day)] 

m = design capacity of the liquefier (kg/day) 

T1 = inlet temperature to the liquefier (K)

sm = hydrogen entropy at the inlet temperature [kWh / K(kg/day)] 

sout = hydrogen entropy at the outlet temperature [kWh / K(kg/day)] 

hin = hydrogen enthalpy at the inlet temperature [kWh / (kg/day)] 

hout = hydrogen enthalpy at the outlet temperature [kWh / (kg/day)] 

The liquefier efficiency is then just the theoretical power divided by the actual power 

requirement. 

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 6.1.2 displays the costs for a liquefier only and does not 

include other direct and indirect costs such as installation, contingencies, property taxes 

and engineering. The costs in Figure 6.1.2 were determined from reports published from 

1986 to 2002 and were scaled to 2005 dollars using the GDP Deflator Price Index found 

in EIA’s Short Term Energy Outlook. 

It is assumed that a 30 tonne/day liquefier will require approximately 25,000 m2

 of land. 

The land required for other sizes of liquefiers is calculated by taking the ratio of the 

design capacity to 30 tonnes/day; the result is then raised to the 0.6 power. That result is 

multiplied by 25,000 to give the amount of land required.
58

Figure 6.1.2. Liquefier cost versus design capacity (National Renewable Energy 

Laboratory, 2006)

The annual energy requirement is calculated using the following formula: 

Where:

Eann = annual energy requirement 

Pliq = actual power requirement 

The total utility cost is then determined by multiplying the H2A fuel/utility cost by the 

annual energy requirement. Total capital, labor, and other operational and maintenance 

costs (not inclusive to what is presented here) are added together so a cost for hydrogen 

can be determined.

6.2 Gaseous Hydrogen Delivery

The components for gaseous hydrogen pathways include: 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, their location, lengths, and diameters. 
59

The pipeline system requires a compressor to increase hydrogen pressure from its 

production level to the pressure at the terminus of the transmission line. Design 

requirements for the pipeline central compressor can be calculated as a function of 

change in pressure and the peak hydrogen throughput (after accounting for losses in the 

pathway). 

6.2.1 Pipeline

Pipeline diameter is calculated using the Panhandle B pipeline equation and is used to 

simulate compressible flow. The equation is as follows:

Where:

qsc = gas rate at standard conditions (scf / day)

Tsc = temperature at standard conditions (°R)

Psc = pressure at standard conditions (psia)

P1 = inlet pressure (psia)

P2 = outlet pressure (psia)

d = inside pipe diameter (in)

γ = mean gas relative density (air = 1)

L = pipeline length (mile)

Tm = mean temperature of pipeline (°R)

Zm = mean compressibility factor

E = pipeline efficiency

Tsc, Psc, and E are assumed to be 530 R, 14.7 psia, and 0.92, respectively. It is assumed 

that no energy is required by the pipeline. 

The H2A Delivery Components model uses a cost curve to estimate the capital cost of a 

hydrogen pipeline system. Data from the curve are based on a University of California, 

Davis study and is broken down into four parts: pipeline material cost, labor cost, 

miscellaneous cost and right-of-way cost. It is assumed that the cost of hydrogen 

pipeline will be 10% higher than that of natural gas pipeline given that materials and 

weld-types may be different. Total capital, labor, and other operational and maintenance 

costs for each part of the pipeline (transmission, trunk, and service) are added together so 

a cost for hydrogen can be determined (National Renewable Energy Laboratory, 2006). 

6.2.2 Compressor

A compressor is required to raise the pressure of the hydrogen produced at a central 

facility to the pressure in a pipeline. These compressors are integral parts of the pipeline 

delivery network. HDSAM is designed to cost a centralized compressor that can raise the 
60

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. 

Also, an electrical-powered compressor is assumed.

A cost curve has been developed to estimate the capital cost of a compressor. Data for 

the cost curve were acquired from an article published in the Oil and Gas Journal in the 

year 2000. Costs include the purchase costs for natural gas compressors, the cost of an 

aftercooler, and other direct and indirect capital costs (installation, contingencies, 

property taxes, and engineering). The data were adapted to that of a hydrogen 

compressor (1.3 times the cost of a natural gas compressor) and inflated to 2005 dollars 

using the GDP Implicit Deflator Price Index in EIA’s Short Term Energy Outlook. 

Figure 6.2.1 shows the cost of a compressor versus power draw. 

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. The equation is as follows: 

Where:

ηisentrop = isentropic compressor efficiency 

Favg = average hydrogen flow rate 

R = gas constant

T1 = inlet gas temperature

Nst = number of compression stages

k = ratio of specific heats

p2 = outlet pressure

p1 = inlet pressure
61

Figure 6.2.1. Compressor cost as a function of power draw (National Renewable Energy 

Laboratory, 2006)

The total utility cost is determined by multiplying the HDSAM fuel/utility cost by the 

annual energy requirement. Total capital, labor, and other operational and maintenance 

costs (not inclusive to what is presented here) are added together so a cost for hydrogen 

can be determined.

6.3 Compression, Storage, and Dispensing

Hydrogen distribution requires compression, storage, and dispensing at the fueling station 

to transfer hydrogen at 6250 psi to vehicles in the required fill-up time.
62

Much like gasoline stations, hydrogen stations will experience seasonal demand. 

Summer demand is assumed in HDSAM to be approximately 10% higher than the 

average demand whereas winter demand is 10% lower. During early infrastructure 

development especially, a long-term storage system will be needed to store the 10% 

production excess in production during the winter for release to supplement production in 

the summer months (Nexant 2008). Figure 6.3.1 shows the annual schedule of 

production and demand used in the H2A models. 

Figure 6.3.1. Hydrogen demand and required annual storage (Nexant 2008)

H2A appropriately sizes the storage capacity to handle the maximum of the two green 

shaded areas in Figure 6.3.1 and to handle any losses that may occur during the storage 

period. The daily design flow rate for the production plant is determined by calculating 

the annual hydrogen demand (area under the black or blue lines in Figure 6.3.1), adding 

all of the annual losses, and dividing by 365 days minus scheduled production outage 

days. Storage capacity is based on: 1) plant-outage period; 2) 10% increase in summer 

demand; 3) length of the summer period; and 4) length of the winter period. H2A 

assumes a plant-outage period of 10 days. 

In addition to seasonal demand, demand variation occurs daily during the week as well as 

hourly during the day. Peak demand occurs on Fridays between 4:00 and 6:00 p.m. 

(Nexant, 2008). Figure 6.3.2 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). 

The refueling site is the best location to handle daily and hourly fluctuations in demand 

and takes the form of low-pressure storage (2,500 psi). This eliminates the need for 

scaling upstream components to handle daily and hourly demand variations. For 

distributed hydrogen production facilities and stations supplied by pipeline, the lowpressure storage at the refueling station is sized at 30% of the total daily demand (472 kg 
63

H2 for distributed facilities and 470 kg H2 for pipeline-supplied facilities). For liquid 

trucks, the liquid storage tank (6,920 kg H2) would satisfy the increase in additional 

storage. Because truck deliveries do not exceed two deliveries per day, the truck would 

carry half the daily demand plus the 30% excess.

Figure 6.3.2. Hydrogen daily average demand (Nexant, 2008)

Refueling stations also include a cascade charging system with at least one bank of three

pressure vessels operating under different pressures (6,000, 4,350, and 2,000 psi) to 

satisfy vehicle refueling requirements. Each vessel holds 21.3 kg hydrogen at a 

maximum pressure of 6,250 psi. For distributed hydrogen production facilities, the 

refueling station modeled includes cascade storage for 325 kg H2. For stations receiving 

liquid hydrogen, the cascade storage volume is 453 kg H2, and for stations supplied by 

pipeline, the cascade storage is sized for 582 kg H2. 

The number of dispensers is determined by the metric utilized in gasoline stations known 

as hose-occupied fraction (HOF). The HOF is the average fraction of time that each hose 

is occupied during the peak hour of the day. By determining the HOF of a gasoline 

station, the number of dispensers at a hydrogen station can be selected such that the HOF 

is approximately equal to that of a gasoline station. Figure 6.3.3 shows the number of 

dispensers for a range of refueling station daily demands in kg/day (Nexant, 2008). 

An equation, based on Figure 6.3.3, can also be used to determine the number of 

dispensers given a daily capacity (kg/day): 

# of Dispensers = Daily Capacity/(305.85*Daily Capacity0.0763) 
64

Figure 6.3.3. Recommended number of refueling station dispensers (Nexant 2008)

Once the number of dispensers is known, the maximum flow rate can be determined. 

This flow rate is integral in determining the required size of the refueling station 

compressor and cascade charging system.

The dispensing pressure is assumed to be 6,250 psi. A conservative assumption and 

worst-case scenario of occupying all the dispensing hoses during the first three minutes 

of each hour simultaneously is made to ensure adequate sizing of the refueling station 

components (see Section 2.3.2, Nexant, 2008). In addition, a small amount of 2,500-psi 

storage (1 day) is provided for in H2A at the liquid terminal to ensure smooth loading of 

liquid hydrogen trucks. 

Dispensers are unlikely to use a significant amount of energy for operation, so there are 

no costs associated to fuel or utilities related to the dispenser. Capital, labor, and other 

operational and maintenance costs for compressed hydrogen storage are pooled together 

so the total hydrogen cost can be determined. 
65

7.0 Vehicle Assumptions

Vehicle assumptions are engineering estimates based on both simulation and performance 

of the current generation of vehicles being tested under the Program’s technology 

validation function. 

7.1 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 is 45 miles per gallon gasoline 

equivalent (mpgge) 

The fuel economy of 45 mpgge was estimated by running simulations using the 

Powertrain Simulation Analysis Toolkit (PSAT) V6.2 SP1, which was developed by 

Argonne National Laboratory. Simulations were run for both mid-size passenger cars 

and light trucks. The on-road adjusted fuel economies of the mid-size passenger car and 

light truck were estimated to be 53.6 mpgge and 37.8 mpgge, respectively. For a lightduty vehicle that is the composite of a car and a light truck, the two fuel economies were 

averaged using a weighting factor that reflects the ratio of new light truck sales to new 

car sales. Using the EIA-estimated light truck sales share of 46.4% for 2008, the on-road 

fuel economy of a new light-duty vehicle was estimated to be 45 mpgge (Singh and 

Nguyen, 2009). 

In PSAT simulations, vehicle weight is specified because it is a crucial factor in 

determining a vehicle’s fuel economy. Additional vehicle glider assumptions used in this 

analysis are listed in Table 7.1.1 (Rousseau and Wallner, 2008), and light truck 

parameters can be found in Delorme, Pagerit, Sharer, and Rousseau (2009). A wide 

variety of data sources were used to characterize the PSAT mid-size passenger car and

fuel cell propulsion system. These sources include vehicle tear-down data, various 

automotive models, personal communications, and literature reviews. 

Table 7.1.1. PSAT Mid-Size Passenger Car Assumptions 

Parameter Unit Value

Glider mass kg 990

Frontal area m

2 2.1

Drag coefficient 0.29

Wheel radius m 0.137

Rolling resistance 0.008

0–60 mph S 9 ± 0.1

0–30 mph S 3

Grade at 60 mph % 6

Maximum speed mph >1001

1 Two-gear transmission used for series
66

Table 7.1.2 shows the PSAT fuel cell system assumptions while Figure 7.1.1 shows the 

fuel cell power versus system efficiency used for PSAT simulations (Rousseau and 

Wallner, 2008). 

Table 7.1.2. PSAT Fuel Cell System Assumptions

Parameter Unit Current Status FreedomCAR Goal

Specific power W/kg 500 650

Peak efficiency % 55 60

Figure 7.1.1. Fuel cell power versus system efficiency (Rousseau and Wallner, 2008)

Other studies on fuel economy have taken place. In another study that was based on the 

assumptions above, PSAT estimated that the overall [2008 Environmental Protection 

Agency (EPA) adjusted] vehicle fuel economy for fuel cell hybrid electric vehicles 

(HEVs) is 50.7 mpgge with an error bar of 7.5 mpgge (Rousseau and Wallner, 2008). 

The mid-size vehicle fuel economy used in this study (53.6 mpgge) is within that range. 

Another simulated analysis was conducted in 2005 by the National Renewable Energy 

Laboratory (NREL) (National Renewable Energy Laboratory, 2005). Its fuel economy 

versus fuel cell size results are shown in Figure 7.1.2. The fuel cell HEV fuel economy 

shown in Figure 7.1.2 (52.5 mpgge) reflects EPA-combined fuel economy. Forty-five 

mpgge is equivalent to discounting the 52.5 mpgge by 15%, which is an approximation of 

EPA’s pre-2008 reduction factor used to calculate on-road fuel economy from 

dynamometer test results. (The EPA reduction factor was equivalent to adjusting the citydriving test result downward by 10% and the highway-driving test result downward by 22%.)

NREL also collects fuel economy data under the Hydrogen Fleet and Infrastructure 

Demonstration and Validation Project (Wipke, Sprik, Kurtz, and Ramsden, 2009). 

Results from 2009 for that project are shown in Figure 7.1.3, and the upper range of those 

results includes 45 mpgge, which is the fuel economy used for this analysis.
67

Figure 7.1.2. Fuel economy versus fuel cell size (Rousseau and Wallner, 2008)

Figure 7.1.3. NREL hydrogen fleet and infrastructure demonstration and validation project 

fuel economy (Wipke, Sprik, Kurtz, and Ramsden, 2009)

7.2 Vehicle Criteria Pollutant Emissions

Table 7.2.1 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 were used for this study. 

Dyno (1) Window-Sticker (2) On-Road (3)(4) 0

10

20

30

40

50

60

70

80

Fuel Economy (miles/kg H2

)

Fuel Economy

 Gen 1

 Gen 2

Created: Mar-03-09 10:57 AM

(1) One data point for each make/model. Combined City/Hwy fuel economy per DRAFT SAE J2572.

(2) Adjusted combined City/Hwy fuel economy (0.78 x Hwy, 0.9 x City).

(3) Excludes trips < 1 mile. One data point for on-road fleet average of each make/model.

(4) Calculated from on-road fuel cell stack current or mass flow readings.
68

Hydrogen FCVs 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 7.2.1. Change in Exhaust as Compared to a Gasoline Vehicle

Vehicle Exhaust 

VOC

Evap. 

VOC

CO NOx Exhaust 

PM

CH4 N2O TBW 

PM

H2 FCV -100% -100% -100% -100% -100% -100% -100% 0%
69

8.0 Financial Assumptions

The H2A model uses a common set of economic assumptions to allow for consistent and 

comparable results across technology options. Table 8.0.1 provides a set of key 

economic parameters selected by H2A analysts and discussed with industry collaborators 

who participated in the H2A effort.

Table 8.0.1. H2A Key Economic Parameters

Parameter Value

Reference year 2005 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 8.0.1, H2A uses an IRR of 10% real. 

The 10% real value was derived from return on equity statistics (adjusted for inflation) 

for large company stocks over the period from 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 steady-state 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 8.0.1 shows the after-tax IRR for 

multiple combinations of equity to debt financing at three different interest rates for 

production of hydrogen from coal in central facilities (see section 9.7 for details); 

delivery costs were not included in the data shown. Technologies with different ratios of 

capital to operating cost will result in slightly different curves.

Figure 8.0.1 also shows the before-tax IRR for the same equity to debt ratios. Corporate 

income tax can be considered a reduction in profits, so a pre-tax IRR is always greater 

than an after-tax IRR. Pre-tax IRRs are shown in Figure 8.0.1 because they are often 

easier to compare to performance of stocks or bonds, which are reported on a pre-tax 

basis.
70

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

equity to debt ratios (Central Production of Hydrogen from Coal with CCS)
71

9.0 Pathway Results

This study assessed the WTW cost, energy use, and GHG emissions of each of the seven 

pathways listed in Table 9.0.1 (see detailed descriptions of each pathway in Section 2.4). 

Table 9.0.1. Seven Hydrogen Production, Delivery, and Distribution Pathways

Central or

Distributed

Production

Feedstock Delivery

Method

Carbon

Capture and

Sequestration

Hydrogen

Distribution for Fueling

1 Distributed Natural Gas Not applicable No 350 bar compressed gas

2 Distributed Electricity Not applicable No 350 bar compressed gas

3 Central Biomass Liquid H2 in trucks No 350 bar compressed gas

4 Central Biomass Gaseous H2 in pipelines No 350 bar compressed gas

5 Central Natural Gas Gaseous H2 in pipelines No 350 bar compressed gas

6 Central Wind Electricity Gaseous H2 in pipelines No 350 bar compressed gas

7 Central Coal Gaseous H2 in pipelines Yes 350 bar compressed gas

The hydrogen production technologies are described in Section 5.0, and the delivery 

technologies are detailed in Section 6.0. This section presents the results of the WTW 

cost, energy use, and GHG emissions analysis for each pathway. 

9.1 Distributed Natural Gas

Figure 9.1.1 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. The complete set of assumptions is detailed in Appendix A.

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

distributed natural gas pathway are summarized in Table 9.1.1. 

9.1.1 Cost Breakdown

Figure 9.1.2 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 8.0. 

Figure 9.1.3 shows the contributions of hydrogen production, distribution (compression, 

storage, and dispensing—CSD), and losses to the levelized cost of hydrogen shown in 

Figure 9.1.2. 

Figure 9.1.4 and Table 9.1.2 show the breakdown of levelized costs for the distributed 

natural gas pathway. 
72

NG Delivery Pressure Average of gas companies

NG Quality at Delivery Average of gas companies

NG Recovery Efficiency 97.2%

NG emitted & combusted during recovery 0.35%

NG processing energy efficiency 97.2% NG Cost $0.243 2005 $ / Nm^3

NG emitted & combusted during processin 0.15% NG Cost $0.907 2005$ / kg H2 distributed

NG emitted & combusted during transport 0.14 g / MMBtu

NG transport distance 500 miles WTG CO2 Emissions 5,485 g / 116000Btu to Pump

Coal Input from "Well" 322 Btu / 116000Btu to Pump WTG CH4 Emissions 239 g / 116000Btu to Pump

Natural Gas Input from "Well" 124,113 Btu / 116000Btu to Pump Compression Reqs (stages & eff) average of gas companies WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 497 Btu / 116000Btu to Pump WTG GHG Emissions 11,475 g CO2 eq./ 116000 Btu

Natural Gas consumption 4.5 N m^3/kg H2 produced Hydrogen Output Pressure 300 psi

Electricity consumption 1.11 kWh / kg H2 Hydrogen Outlet Quality 1

Process Water Consumption 5.77 L / kg H2

Electricity price $0.0816 2005 $/kWh Design Capacity 1,500 kg/day Total capital investment $2.44

2005$ / annual kg H2 

(effective capacity)

Capacity factor 85% Electricity cost $0.09 2005$ / kg H2 produced

Process energy efficiency 71.3% Other operating costs $0.36 2005$ / kg H2 produced

Total Capital Investment $1,138,995 2005$ Electricity Mix US Mix Levelized Cost of Prod (excl feedsto $0.71 2005$ / kg H2 distributed

After-tax IRR 10%

Assumed Plant Life 20 years

SMR CO2 Emissions 10,523 g / 116000Btu to Pump

Coal Input from "Well" 6,572 Btu / 116000Btu to Pump SMR CH4 Emissions 11 g / 116000Btu to Pump

Natural Gas Input from "Well" 47,754 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 664 Btu / 116000Btu to Pump SMR GHG Emissions 10,815 g CO2 eq./ 116000 Btu

Electricity consumption 1.96 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $8.56

2005$ / annual kg H2 

(effective capacity)

Number of Distribution Stations 270 Electricity cost $0.16 2005$ / kg H2

Total Capital Investment $3,993,763 2005$ Energy efficiency 94%

Number of Compression Stages 6 Levelized Cost of Distribution $1.88 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 62%

 

capacity CSD CO2 Emissions 1,502 g / 116000Btu to Pump

Coal Input from "Well" 11,382 Btu / 116000Btu to Pump CSD CH4 Emissions 2 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,269 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 848 Btu / 116000Btu to Pump CSD GHG Emissions 1,558 g CO2 eq./ 116000 Btu

Inputs Outputs

NG Recovery, Processing, & Transport

Graphic Depiction & Assumptions

Hydrogen Production

Compression, Storage, & Dispensing

Figure 9.1.1. Summary of distributed natural gas pathway major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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. 
73

Table 9.1.1. Well-to-Pump and Well-to-Wheels Results for Distributed Natural Gas Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 18,300 Btu / 116,000 Btu 410 Btu / mi

Natural Gas Input from "Well"* 175,100 Btu / 116,000 Btu 3,900 Btu / mi

Petroleum Input from "Well"* 2,000 Btu / 116,000 Btu 45 Btu / mi

Fossil Energy Input from "Well"* 195,400 Btu / 116,000 Btu 4,350 Btu / mi

WTP CO2 Emissions*,** 12,700 g / 116,000 Btu 280 g / mi

WTP CH4 Emissions 41 g / 116,000 Btu 1 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 13,700 g CO2 eq. / 116,000 Btu 310 g / mi

Levelized Cost of Hydrogen ($/kg) $3.50 2005 $/kg $0.0777 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2 

Coal, natural gas, and petroleum inputs from “well” 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.

Natural Gas @ Total capital investment $2.44 2005$ / annual kg H2 (effective capacity)

$6.81/MMBtu Electricity cost $0.09 2005$ / kg H2 produced

Natural gas cost $0.91 2005$ / kg H2 distributed

Other operating costs $0.36 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $0.71 2005$ / kg H2 distributed

Total capital investment $8.56 2005$ / annual kg H2 (effective capacity)

Electricity @ $0.082/kWh Electricity cost $0.16 2005$ / kg H2

Levelized Cost of Distribution $1.88 2005$ / kg H2 distributed

* 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.

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

Pipeline Transport PSA

Recovery SMR

Processing WGS

Dispensing

Hydrogen @ $3.50/kg

Electricity @

$0.082/kWh

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Figure 9.1.2. Cost analysis inputs and high-level results for distributed natural gas 

pathway
74

Distributed Natural Gas

$1.61

$1.88

$0.00

Production

CSD

Losses

Figure 9.1.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for distributed natural gas pathway

Figure 9.1.4. Breakdown of levelized costs for distributed natural gas pathway
75

Table 9.1.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost

for Distributed Natural Gas Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.45 $0.26 $0.91 $1.61

 Feed & Desulfurization $0.05

 Reformer $0.09

 Water-Gas Shift $0.08

 PSA $0.03

 Cooling & Condensing $0.03

 Supports & Controls $0.03

 System Assembly $0.10

 Miscellaneous $0.04

Compression, Storage, & Dispensing $1.26 $0.16 $0.46 $1.88

 Compressor (Levelized) $0.80

 Storage (Levelized) $0.94

 Dispenser (Levelized) $0.03

 Remainder of Station (Levelized) $0.11

Losses $0.00

Total $1.71 $0.42 $0.91 $0.46 $3.50

9.1.2 Energy Use and Emissions Breakdown

Figures 9.1.5 and 9.1.6 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.
76

6,600 Btu Coal

47,800 Btu Natural Gas (inc. heating fuel)

700 Btu Petroleum

300 Btu Coal

124,100 Btu Natural Gas

500 Btu Petroleum

11,400 Btu Coal

3,300 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.

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Transport PSA

Recovery SMR

Processing WGS

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

Figure 9.1.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using 

distributed natural gas pathway

WTW Energy Input (Distributed Natural Gas)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Nat Gas Production

& Delivery

Hydrogen

Production

Compression,

Storage,

Dispensing

Btu/GGE

Petroleum Input from

"Well" 

Natural Gas Input from

"Well" 

Coal Input from "Well" 

Figure 9.1.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using distributed natural gas pathway

Figures 9.1.7 and 9.1.8 show the WTW emissions resulting from the delivery of 116,000 

Btu hydrogen to a vehicle fuel tank using the distributed natural gas pathway. 
77

CO2 Emissions 600 g/116,000 Btu CO2 Emissions 10,500 g/116,000 Btu

CH4 Emissions 28 g/116,000 Btu CH4 Emissions 11 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 10,800 g CO2 eq./116,000 Btu

GHG Emissions 1,300 g CO2 eq./116,000 Btu

CO2 Emissions 1,500 g/116,000 Btu

Electricity CH4 Emissions 2 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 1,600 g CO2 eq./116,000 Btu

* 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.

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Recovery SMR

Processing WGS

and Delivery*: Desulfurizer

Electricity

Pipeline Transport PSA

Natural Gas Production Hydrogen Production: 

Figure 9.1.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

distributed natural gas pathway

WTW Emissions (Distributed Natural Gas)

0

2,000

4,000

6,000

8,000

10,000

12,000

Nat Gas Production &

Delivery

Hydrogen Production Compression, Storage,

Dispensing

g/GGE

CO2 CH4 N2O

Figure 9.1.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using distributed natural gas pathway

9.1.3 Natural Gas Supply Scenarios 

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy used in this study (45 mpgge), 
78

and a yield of hydrogen from natural gas of 4.5 Nm3 natural gas/kg H2 (159 Nft3 natural 

gas/kg H2), the amount of natural gas required to supply 100%, 75%, 50%, or 25% of 

light-duty vehicles with natural gas–derived hydrogen fuel was calculated and compared 

to the U.S. natural gas reserves and consumption estimates shown in Section 3.1 (Table 

9.1.3). 

Table 9.1.3. Natural Gas Supply Scenarios for Distributed Natural Gas Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Current Technology – 45 mpgge FCV, 

hydrogen production yield 4.5 Nm3/kg H2

1

Natural Gas Required (trillion ft3/yr) 10.0 7.5 5.0 2.5

Percent of Estimated U.S. Reserves 

(237.7 trillion ft3, dry)2 4% 3% 2% 1%

Percent of Annual U.S. Consumption 

(23.2 trillion ft3/yr)3 43% 32% 22% 11%

1 Calculation does not include energy or hydrogen losses. 2 Energy Information Administration (2009i) 3 Energy Information Administration (2009b)

No sample scenarios for domestic hydrogen production from natural gas are included in 

the Hydrogen Posture Plan (United States Department of Energy, 2006). 

9.1.4 Sensitivities

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 

9.1.9 shows the effects of several production parameters on the pathway’s levelized cost, 

and Table 9.1.4 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 9.1.5 

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). 
79

$3.20 $3.30 $3.40 $3.50 $3.60 $3.70 $3.80 $3.90 $4.00 $4.10 $4.20

Operating Capacity

 Feedstock Cost ($/Nm^3)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($ / kg)

95% 85% 60%

$0.17 $0.24 $0.32

$0.5 M $1.5 M $2.5 M

80% 70% 60%

Figure 9.1.9. Production sensitivities for distributed natural gas pathway

Table 9.1.4. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Distributed Natural Gas Pathway (current technology)

60% 

Efficiency

70% 

Efficiency

80% 

Efficiency

WTW GHG Emissions (g/mile) 350 310 270

WTW Fossil Energy (Btu/mile) 5,030 4,350 3,850

WTW Petroleum Energy (Btu/mile) 47 45 43

WTW Total Energy (Btu/mile) 5,120 4,430 3,930

Table 9.1.5. The Effects of Grid Mix on Use of Primary Energy and Emissions from 

Distributed Natural Gas Pathway (current technology)

U.S. Average 

Grid Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 310 250

WTW Fossil Energy (Btu/mile) 4,350 3,790

WTW Petroleum Energy (Btu/mile) 45 14

WTW Total Energy (Btu/mile) 4,430 4,060

9.1.5 Advanced Conversion and Delivery/Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the Hydrogen, Fuel Cells and Infrastructure 

Technologies (HFCIT) Multi-Year Program Plan (MYPP). The vehicle fuel economy 

was increased to 65 mpgge. In addition, the electricity grid mix was updated to match 

EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 18.5% 

nuclear, 1.9% residual oil, 1.0% biomass, and 8.3% zero-carbon). WTW results from 
80

cases with those modifications are shown in Table 9.1.6. The results match those in 

Hydrogen Program Record 9002 (2009). 

Table 9.1.6. Well-to-Wheels Results for Distributed Natural Gas Pathway with Advanced 

Technology 

Coal Input from "Well" 370 Btu / mi

Natural Gas Input from "Well" 2440 Btu / mi

Petroleum Input from "Well" 29 Btu / mi

Fossil Energy Input from "Well" 2840 Btu / mi

WTW CO2 Emissions 190 g / mi

WTW CH4 Emissions 0.58 g / mi

WTW N2O Emissions 0.001 g / mi

WTW GHG Emissions 200 g / mi

Levelized Cost of Hydrogen ($ / kg) $3.23 2005 $ / kg

Levelized Cost of Hydrogen ($ / mi) $0.0496 2005 $ / mi

Several sensitivities were run on this pathway. They focused primarily on cost factors; 

however, several sensitivities also affect energy use and emissions. Figure 9.1.10 shows 

the effects of several production parameters on the pathway’s levelized cost, and Table 

9.1.7 shows the effect of varying production energy efficiency on WTW energy use and 

emissions. 

$3.00 $3.10 $3.20 $3.30 $3.40 $3.50 $3.60 $3.70 $3.80 $3.90

 Operating Capacity

 Feedstock Cost ($/Nm^3)

Production Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($/kg)

87%

85%

$0.15 $0.18 $0.29

$400K $900K $1.4 mill

77% 67%

95% 60%

Figure 9.1.10. Production sensitivities for distributed natural gas pathway with advanced 

technology 
81

Table 9.1.7. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Distributed Natural Gas Pathway (advanced technology)

67% 

Efficiency

77% 

Efficiency

87% 

Efficiency

WTW GHG Emissions (g/mile) 230 200 190

WTW Fossil Energy (Btu/mile) 3,230 2,840 2,550

WTW Petroleum Energy (Btu/mile) 31 29 28

WTW Total Energy (Btu/mile) 3,300 2,910 2,630

The assumed electrical grid mix also affects the energy use and emissions. Table 9.1.8 

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 9.1.8. The Effects of Grid Mix on Use of Primary Energy and Emissions from 

Distributed Natural Gas Pathway (advanced technology)

Projected U.S. 

Average Grid 

Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 200 150

WTW Fossil Energy (Btu/mile) 2,840 2,330

WTW Petroleum Energy (Btu/mile) 29 9

WTW Total Energy (Btu/mile) 2,910 2,580

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy for advanced FCVs used in this 

study (65 mpgge), and a yield of hydrogen from natural gas of 4.0 Nm3

 natural gas/kg H2

(140 Nft3

 natural gas/kg H2), the amount of natural gas required to supply 100%, 75%, 

50%, or 25% of light-duty vehicles with natural gas–derived hydrogen fuel was 

calculated and compared to the U.S. natural gas reserves and consumption estimates 

shown in Section 3.1 (Table 9.1.9). 

Table 9.1.9. Natural Gas Supply Scenarios for Advanced Distributed Natural Gas Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Advanced Technology – 65 mpgge FCV, 

hydrogen production yield 4.0 Nm3/kg H2

1

Natural Gas Required (trillion ft3/yr) 6.1 4.6 3.1 1.5

Percent of Estimated U.S. Reserves 

(237.7 trillion ft3, dry)2 3% 2% 1% 0.6%

Percent of Annual U.S. Consumption 

(23.2 trillion ft3/yr)3 26% 20% 13% 7%

1 Calculation does not include energy or hydrogen losses.

2 Energy Information Administration (2009i) 3 Energy Information Administration (2009b)
82

9.2 Distributed Electricity

Figure 9.2.1 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. The complete set of assumptions is detailed in Appendix B. 

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

distributed electricity pathway are summarized in Table 9.2.1. 

9.2.1 Cost Breakdown

Figure 9.2.2 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 8.0. 

Figure 9.2.3 shows the contributions of hydrogen production, distribution (CSD), and 

losses to the levelized cost of hydrogen shown in Figure 9.2.2. 

Figure 9.2.4 and Table 9.2.2 show the breakdown of levelized costs for the distributed 

electricity pathway. 
83

Grid Mix

Biomass Fraction 1.20% Electricity Cost $0.055 2005 $ / kWh

Coal Fraction 51.70% Electricity Cost $2.804 2005$ / kg H2 distributed

Natural Gas Fraction 15.70%

Nuclear Fraction 20.30% WTG CO2 Emissions 353,525 g / 116000Btu to Pump

Coal Input from "Well" 310,710 Btu / 116000Btu to Pump Residual Oil Fraction 2.90% WTG CH4 Emissions 464 g / 116000Btu to Pump

Natural Gas Input from "Well" 89,250 Btu / 116000Btu to Pump Others (Carbon Neutral) 8.20% WTG N2O Emissions 5 g / 116000Btu to Pump

Petroleum Input from "Well" 23,152 Btu / 116000Btu to Pump WTG GHG Emissions 366,556 g CO2 eq./ 116000 Btu

Natural Gas consumption 0.0 N m^3/kg H2 produced Hydrogen Output Pressure 435 psi

Electricity consumption 53.48 kWh / kg H2 Hydrogen Outlet Quality 1

Process Water Consumption 0.00 L / kg H2

Design Capacity 1,500 kg/day Total capital investment $5.87

2005$ / annual kg H2 

(effective capacity)

Capacity factor 85% Other operating costs $0.60 2005$ / kg H2 produced

Process energy efficiency 62.3%

Levelized Cost of Prod (excl 

feedstock) $1.42 2005$ / kg H2 distributed

Total Capital Investment $2,738,292 2005$ After-tax IRR 10%

Assumed Plant Life 20

SMR CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump SMR CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump SMR GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption 1.73 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $8.55

2005$ / annual kg H2 

(effective capacity)

Number of Distribution Stations 270 Electricity cost $0.10 2005$ / kg H2

Total Capital Investment $3,989,011 2005$ Energy efficiency 95%

Number of Compression Stages 5 Levelized Cost of Distribution $1.82 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 62%

 

capacity CSD CO2 Emissions 1,647 g / 116000Btu to Pump

Coal Input from "Well" 12,477 Btu / 116000Btu to Pump CSD CH4 Emissions 2 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,584 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 930 Btu / 116000Btu to Pump CSD GHG Emissions 1,707 g CO2 eq./ 116000 Btu

Inputs Outputs

Electrolysis Electricity Generation & Transport

Graphic Depiction & Assumptions

Hydrogen Production

Compression, Storage, & Dispensing

Includes Resource Recovery, Processing, & Transport

Figure 9.2.1. Distributed electricity pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
84

Table 9.2.1. Well-to-Pump and Well-to-Wheels Results for Distributed Electricity Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 323,200 Btu / 116,000 Btu 7,190 Btu / mi

Natural Gas Input from "Well"* 92,800 Btu / 116,000 Btu 2,070 Btu / mi

Petroleum Input from "Well"* 24,100 Btu / 116,000 Btu 540 Btu / mi

Fossil Energy Input from "Well"* 440,100 Btu / 116,000 Btu 9,790 Btu / mi

WTP CO2 Emissions*,** 42,700 g / 116,000 Btu 950 g / mi

WTP CH4 Emissions 56 g / 116,000 Btu 1 g / mi

WTP N2O Emissions 1 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 44,300 g CO2 eq./ 116,000 Btu 980 g / mi

Levelized Cost of Hydrogen ($/kg) $6.05 2005 $/kg $0.1344 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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.

Electricity @ Total capital investment $5.87 2005$ / annual kg H2 (effective capacity)

$0.055/kWh Other operating costs $0.60 2005$ / kg H2 produced

Electricity Cost $2.80 2005$ / kg H2 distributed

Levelized Cost of Prod (excl feedstock) $1.42 2005$ / kg H2 distributed

Total capital investment $8.55 2005$ / annual kg H2 (effective capacity)

Electricity @ $0.055/kWh Electricity cost $0.10 2005$ / kg H2

Gaseous H2 Storage Levelized Cost of Distribution $1.82 2005$ / kg H2 distributed

Dispensing

Hydrogen @ $3.50/kg

Transmission & Distribution

Forecourt 

Distribution:

Compressor

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Water @

$1.66/thousand gal

Electricity Generation Hydrogen Production: 

Figure 9.2.2. Cost analysis inputs and high-level results for distributed electricity pathway
85

Distributed Electricity

$4.23

$1.82

$0.00

Production

CSD

Losses

Figure 9.2.3. Contribution of hydrogen production, CSD, and losses to the levelized cost of 

hydrogen for distributed electricity pathway
86

Figure 9.2.4. Breakdown of levelized costs for distributed electricity pathway

Table 9.2.2. Contribution of Production and CSD Processes to Levelized Hydrogen Cost

for Distributed Electricity Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.98 $0.45 $2.80 $4.23

 Electrolyzer Unit $0.31

 Transformer/Rectifier Unit $0.06

 Compressor Units to 30 bar (435 psig) $0.28

 Gas Holder $0.15

 Balance of Plant $0.18

Compression, Storage, & Dispensing $1.26 $0.10 $0.46 $1.82

 Compressor (Levelized) $0.73

 Storage (Levelized) $0.94

 Dispenser (Levelized) $0.03

 Remainder of Station (Levelized) $0.11

Losses $0.00

Total $2.24 $0.55 $2.80 $0.46 $6.05
87

9.2.2 Energy Use and Emissions Breakdown

Figures 9.2.5 and 9.2.6 show the WTW energy inputs and losses for the distributed 

electricity pathway. 

310,700 Btu Coal

89,300 Btu Natural Gas

23,200 Btu Petroleum

12,500 Btu Coal

3,600 Btu Natural Gas

900 Btu Petroleum Distribution 

losses 0.00%

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

Transmission & Distribution

Forecourt 

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 9.2.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using 

distributed electricity pathway

WTW Energy Input (Distributed Electrolysis)

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

Electricity

Generation

Hydrogen

Production

Compression,

Storage,

Dispensing

Btu/GGE

Petroleum Input from

"Well" 

Natural Gas Input from

"Well" 

Coal Input from "Well" 

Figure 9.2.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using distributed electricity pathway
88

Figures 9.2.7 and 9.2.8 show the WTW emissions resulting from the delivery of 116,000 

Btu hydrogen to a vehicle fuel tank using the distributed electricity pathway. 

CO2 Emissions 41,000 g/116,000 Btu CO2 Emissions 0 g/116,000 Btu

CH4 Emissions 54 g/116,000 Btu CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 1 g/116,000 Btu GHG Emissions 0 g CO2 eq./116,000 Btu

GHG Emissions 42,500 g CO2 eq./116,000 Btu

CO2 Emissions 1,600 g/116,000 Btu

Electricity CH4 Emissions 2 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 1,700 g CO2 eq./116,000 Btu

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Electricity Generation, Scrubber

Transmission & Distribution

Forecourt 

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Figure 9.2.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

distributed electricity pathway

WTW Emissions (Distributed Electrolysis)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

Electricity Generation Hydrogen Production Compression, Storage,

Dispensing

g/GGE

CO2 CH4 N2O

Figure 9.2.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using distributed electricity pathway

9.2.3 Electricity Supply Scenarios

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy used in this study (45 mpgge), 
89

and a yield of hydrogen from electricity of 55 kWh electricity/kg H2, the amount of 

electricity required to supply 100%, 75%, 50%, or 25% of light-duty vehicles with 

electrolysis-derived hydrogen fuel was calculated and compared to the projected 2030 

U.S. electricity demand (United States Department of Energy, 2009), the 2008 U.S. 

electricity generation, and the 2008 U.S. electricity consumption estimates shown in 

Section 3.2 (Table 9.2.3). 

Table 9.2.3. Electricity Supply Scenarios for Distributed Electricity Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Current Technology - 45 mpgge FCV, 

hydrogen production yield 55 kWh/kg H2

1

Electricity Required (trillion kWh/yr) 3.5 2.6 1.7 0.9

Percent of Projected 2030 U.S. 

Electricity Demand (5.8 trillion kWh)2 60% 45% 30% 15%

Percent of 2008 U.S. Net Electricity 

Generation (4.1 trillion kWh)

3 85% 64% 42% 21%

Percent of Annual U.S. Consumption 

(3.7 trillion kWh)4 94% 70% 47% 23%

1 Calculation does not include energy or hydrogen losses. 2 United States Department of Energy (2008)

3 Energy Information Administration (2009e)

4 Energy Information Administration (2009f)

No sample scenarios for domestic hydrogen production from grid electricity are included 

in the Hydrogen Posture Plan (United States Department of Energy, 2006). 

9.2.4 Sensitivities

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 

9.2.9 shows the effects of several production parameters on the pathway’s levelized cost, 

and Table 9.2.4 shows the effect of production energy efficiency on WTW energy use 

and emissions. 
90

$5.20 $5.40 $5.60 $5.80 $6.00 $6.20 $6.40 $6.60 $6.80 $7.00 $7.20

Operating Capacity

Electricity Cost ($/kWh)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($ / kg)

95% 85% 60%

$0.070 $0.040 $0.055

$1.0 M $2.7 M $4.0 M

67% 62% 58%

Figure 9.2.9. Production sensitivities for distributed electrolysis pathway

Table 9.2.4. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Distributed Natural Gas Pathway (current technology)

58% 

Efficiency

62% 

Efficiency

67% 

Efficiency

WTW GHG Emissions (g/mile) 1,050 980 920

WTW Fossil Energy (Btu/mile) 10,400 9,800 9,200

WTW Petroleum Energy (Btu/mile) 570 540 500

WTW Total Energy (Btu/mile) 12,000 11,300 10,600

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.

9.2.5 Advanced Conversion and Delivery/Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the Hydrogen, Fuel Cells and Infrastructure 

Technologies (HFCIT) Multi-Year Program Plan (MYPP). The vehicle fuel economy 

was increased to 65 mpgge. In addition, the electricity grid mix was updated to match 

EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 18.5% 

nuclear, 1.9% residual oil, and 1.0% biomass, and 8.3% zero-carbon). 

WTW results from cases with those modifications are shown in Table 9.2.5. The results 

do not match those in Hydrogen Program Record 9002 (2009) because the production 

yield and cost of electrolyzers were modified in the Program Record case.
91

Table 9.2.5. Well-to-Wheels Results for Distributed Electrolysis Pathway with Advanced 

Technology 

Coal Input from "Well" 4050 Btu / mi

Natural Gas Input from "Well" 1330 Btu / mi

Petroleum Input from "Well" 220 Btu / mi

Fossil Energy Input from "Well" 5600 Btu / mi

WTW CO2 Emissions 540 g / mi

WTW CH4 Emissions 0.72 g / mi

WTW N2O Emissions 0.008 g / mi

WTW GHG Emissions 560 g / mi

Levelized Cost of Hydrogen ($/kg) $4.93 2005 $/kg

Levelized Cost of Hydrogen ($/mi) $0.0759 2005 $/mi

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy for advanced FCVs used in this 

study (65 mpgge), and a yield of hydrogen from electricity of 45 kWh electricity/kg H2, 

the amount of electricity required to supply 100%, 75%, 50%, or 25% of light-duty 

vehicles with electrolysis-derived hydrogen fuel was calculated and compared to the 

projected 2030 U.S. electricity demand (United States Department of Energy, 2009), the 

2008 U.S. electricity generation, and the 2008 U.S. electricity consumption estimates 

shown in Section 3.2 (Table 9.2.6). 

Table 9.2.6. Electricity Supply Scenarios for Advanced Distributed Electricity Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Advanced Technology – 65 mpgge FCV, 

hydrogen production yield 45 kWh/kg H2

1

Electricity Required (trillion kWh/yr) 2.0 1.5 1.0 0.5

Percent of Projected 2030 U.S. 

Electricity Demand (5.8 trillion kWh)2 34% 25% 17% 8%

Percent of 2008 U.S. Net Electricity 

Generation (4.1 trillion kWh)3 48% 36% 24% 12%

Percent of Annual U.S. Consumption 

(3.7 trillion kWh)4 52% 39% 26% 13%

1 Calculation does not include energy or hydrogen losses. 2 United States Department of Energy (2008)

3 Energy Information Administration (2009e)

4 Energy Information Administration (2009f)

9.3 Central Biomass – Liquid Delivery

Figure 9.3.1 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. The complete set of assumptions is detailed in Appendix C. 
92

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

central biomass–liquid truck delivery pathway are summarized in Table 9.3.1. 

The GHG emissions include carbon dioxide uptake of 112,500 g CO2 / dry ton biomass 

due to direct land use change. That uptake is in addition to carbon dioxide that is 

converted into plant matter and subsequently released during gasification and reforming. 

If the land use change had a neutral effect on GHG emissions, the WTP GHG emissions 

would increase by 1,700 CO2 eq. / 116,000 Btu H2, and the WTW GHG emissions would 

increase by 38 CO2 eq. / mile.

9.3.1 Cost Breakdown

Figure 9.3.2 shows the feedstock and energy price inputs and the resulting hydrogen 

production, delivery, and distribution costs for the central biomass–liquid truck delivery 

pathway. The financial assumptions used in this analysis are detailed in Section 8.0. 
93

Biomass moisture content 25%

Woody biomass LHV 16,811,019 Btu / dry ton

Fraction of Woody Biomass (Remaining is Herbaceous) 100%

Grams of Nitrogen / dry ton biomass 709

Grams of P2O5 / dry ton biomass 189 Biomass price at H2 production $37.96 2005 $ / dry ton

Grams of K2O / dry ton biomass 331 Levelized Cost of Biomass $0.61 2005$ / kg H2 distributed

Herbicide use 24 g / dry ton

Insecticide use 2 g / dry ton WTG CO2 Emissions -26,911 g / 116000Btu to Pump

Coal Input from "Well" 269 Btu / 116000Btu to Pump Average dist from farm to H2 production 40 miles WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 427 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 2,832 Btu / 116000Btu to Pump WTG GHG Emissions -26,867 g CO2 eq./ 116000 Btu

Biomass consumption 12.8 kg (dry) / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.17 N m^3/kg H2 produced Hydrogen Outlet Quality 98 minimum

Electricity consumption 0.98 kWh / kg H2

Process Water Consumption 5.00 L / kg H2 Central plant design capacity 155,236 kg/day Total capital investment $3.03 2005$ / annual kg H2 (effective capacity)

Natural gas price $0.340 2005$ / N m^3 Capacity factor 90% Levelized Electricity cost $0.05 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 46.0% Levelized Natural Gas Cost $0.06 2005$ / kg H2 produced

Total Capital Investment $154,644,297 2005$ Electricity Mix US Mix Levelized Other operating costs $0.32 2005$ / kg H2 produced

After-tax IRR 0 Levelized Cost of Prod (excl feedstock) $1.18 2005$ / kg H2 distributed

Assumed Plant Life 40

SMR CO2 Emissions 26,979 g / 116000Btu to Pump

Coal Input from "Well" 6,356 Btu / 116000Btu to Pump SMR CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 9,009 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 3,570 Btu / 116000Btu to Pump SMR GHG Emissions 27,091 g CO2 eq./ 116000 Btu

Liquefaction electricity consumption 8.2 kWh / kg H2 Total capital investment $6.37 2005$/annual kg delivered

Diesel consumption 7.3 gal / 1000 kg H2 Levelized Electricity cost $0.49 2005$ / kg H2 delivered

Levelized Diesel cost $0.01 2005$ / kg H2 delivered

City Population 1,247,364 people Levelized Labor cost $0.13 2005$ / kg H2 delivered

Hydrogen Vehicle Penetration 50% Levelized Other operating costs $0.28 2005$ / kg H2 delivered

Total Capital Investment $800,063,746 City hydrogen use 125,810,766 kg / yr

Liquefaction efficiency 80.3%

Terminal Design Capacity 3,532,139 kg H2 Levelized Cost of Distribution $2.04 2005$ / kg H2 distributed

Number of truck-trips required 31,009 per year

Truck hydrogen capacity 4,372 kg / truckload

One-way distance for delivery 49 miles Delivery CO2 Emissions 6,708 g / 116000Btu to Pump

Coal Input from "Well" 50,184 Btu / 116000Btu to Pump Hydrogen losses 10.1% Delivery CH4 Emissions 9 g / 116000Btu to Pump

Natural Gas Input from "Well" 14,462 Btu / 116000Btu to Pump Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 4,778 Btu / 116000Btu to Pump Delivery GHG Emissions 6,955 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal non-oxygenated 

conventional unleaded gasoline)

Total capital investment $5.85 2005$/annual kg

Number of Distribution Stations 270 Levelized Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.05 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 52%

 

capacity CSD CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump CSD GHG Emissions 0 g CO2 eq./ 116000 Btu

Inputs Outputs

Biomass Production & Delivery

Graphic Depiction & Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production

Forecourt Distribution

Figure 9.3.1. Central biomass–liquid truck delivery pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
94

Table 9.3.1. Well-to-Pump and Well-to-Wheels Results for Central Biomass–Liquid Truck 

Delivery Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 56,800 Btu / 116,000 Btu 100 Btu / mi

Natural Gas Input from "Well"* 23,900 Btu / 116,000 Btu 3,910 Btu / mi

Petroleum Input from "Well"* 11,200 Btu / 116,000 Btu 250 Btu / mi

Fossil Energy Input from "Well"* 91,900 Btu / 116,000 Btu 2,040 Btu / mi

WTP CO2 Emissions*,** 6,800 g / 116,000 Btu 150 g / mi

WTP CH4 Emissions* 12 g / 116,000 Btu 0 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 7,200 g CO2 eq. / 116,000 Btu 160 g / mi

Levelized Cost of Hydrogen ($/kg) $4.88 2005 $/kg $0.1086 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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.

Electricity @ Natural Gas @ 

$0.055/kWh $9.52/MMBtu

Biomass @ Total capital investment $3.03 2005$ / annual kg H2 (effective capacity)

$37.96/dry short ton Levelized Electricity cost $0.05 2005$ / kg H2 produced

Levelized Natural Gas Cost $0.06 2005$ / kg H2 produced

Levelized Cost of Biomass $0.61 2005$ / kg H2 distributed

Levelized Other operating costs $0.32 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.18 2005$ / kg H2 distributed

Total capital investment $6.37 2005$/annual kg delivered

Levelized Electricity cost $0.49 2005$ / kg H2 delivered

Electricity @ $0.055/kWh Levelized Diesel cost $0.01 2005$ / kg H2 delivered

Diesel @ $1.67/gallon Levelized Labor cost $0.13 2005$ / kg H2 delivered

Levelized Other operating costs $0.28 2005$ / kg H2 delivered

Levelized Cost of Delivery $2.04 2005$ / kg H2 delivered

Total capital investment $5.85 2005$/annual kg

Electricity @ $0.082/kWh Levelized Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.05 2005$ / kg H2 distributed

Harvesting

Truck Transport

Hydrogen @ $4.88/kg

Biomass Production

and Delivery:

Poplar Planting

Fertilization

Vaporizer

Compressor

Gaseous H2 Storage

Dispensing

Liquid H2 Storage

Liquid H2 Truck

Forecourt 

Distribution:

Hydrogen Production: 

Liquefaction &

Truck Delivery:

Liquefier

Gasifier

SMR

WGS

PSA

Figure 9.3.2. Cost analysis inputs and high-level results for central biomass–liquid truck 

delivery pathway

Figure 9.3.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 9.3.2. 
95

Biomass - Liquid Truck Delivery 

$1.60

$0.19

$3.09

Production

Delivery

Losses

Figure 9.3.3. Contribution of hydrogen production, delivery, and losses to the levelized 

cost of hydrogen for central biomass–liquid truck delivery pathway

Figure 9.3.4 and Table 9.3.2 show the breakdown of levelized costs for the central 

biomass–liquid truck delivery pathway. 

Figure 9.3.4. Breakdown of levelized costs for central biomass–liquid truck delivery 

pathway
96

Table 9.3.2. Contribution of Production and Delivery Processes to Levelized Hydrogen 

Cost for Central Biomass–Liquid Truck Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.53 $0.52 $0.55 $1.61

 Feed Handling & Drying $0.10

 Gasification, Tar Reforming, & Quench $0.09

 Compression & Sulfur Removal $0.08

 SMR, WGS, and PSA $0.15

 Steam System and Power Generation $0.07

 Cooling Water and Other Utilities $0.02

 Buildings & Structures $0.03

Delivery $1.76 $0.82 $0.52 $3.09

 Tractor/Trailer $0.24

 Terminal $0.34

 Liquefier $0.79 $0.19 $0.50 $1.46

 Gaseous Refueling Station $0.64 $0.40 $0.02 $1.05

 Cryogenic Storage $0.22

 Cascade Storage $0.20

 Dispenser $0.04

 Remainder of Station $0.18

Losses $0.19

Total $2.29 $1.34 $0.55 $0.52 $4.88

9.3.2 Energy Use and Emissions Breakdown

Figures 9.3.5 and 9.3.6 show the WTW energy inputs and losses for the central biomass–

liquid truck delivery pathway. 

Figures 9.3.7 and 9.3.8 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 

pathway. As noted above, carbon dioxide uptake within the plant matter and due to 

direct land use change is included in the biomass production section of the GHG 

calculations. If the land use change had a neutral effect on GHG emissions, the WTP 

GHG emissions would increase by 1,700 CO2 eq. / 116,000 Btu H2, and the WTW GHG 

emissions would increase by 38 CO2 eq. / mile.
97

6,400 Btu Coal

9,000 Btu Natural Gas

3,600 Btu Petroleum

300 Btu Coal

400 Btu Natural Gas

2,800 Btu Petroleum 271,000 Btu Biomass

50,200 Btu Coal

14,500 Btu Natural Gas

4,800 Btu Petroleum Liquefaction losses 0.50%

Transport losses 1.28%

0 Btu Coal *

0 Btu Natural Gas *

0 Btu Petroleum * Storage losses 4.06%

Dispensing

116,000 Btu

Hydrogen Gas

Distribution:

Vaporizer

Compressor

Gaseous H2 Storage

Liquefier

Liquid H2 Storage

Liquid H2 Truck

Forecourt 

PSA

Truck Transport

Liquefaction &

Truck Delivery:

* Electricity (1,000 Btu) is used in the distribution of hydrogen to the pump. However, GREET does not model this electricity usage for the 

case of liquid hydrogen delivery to the station; thus, the coal, natural gas, and petroleum used in the production of the electricity are not shown 

here.

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting

Figure 9.3.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using central 

biomass–liquid truck delivery pathway

WTW Energy Input (Biomass Gasification with Liquid H2 Delivery)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Biomass

Production &

Delivery

Hydrogen

Production

Liquefaction &

Truck Delivery

Forecourt Storage

& Dispensing 

Btu/GGE

Petroleum Input from "Well" 

Natural Gas Input from "Well" 

Coal Input from "Well" 

Figure 9.3.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using central biomass–liquid truck delivery pathway
98

Electricity Natural Gas

CO2 Emissions -26,900 g/116,000 Btu CO2 Emissions 27,000 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 27,100 g CO2 eq./116,000 Btu

GHG Emissions -26,900 g CO2 eq./116,000 Btu

CO2 Emissions 6,700 g/116,000 Btu

Electricity CH4 Emissions 9 g/116,000 Btu

Diesel N2O Emissions 0 g/116,000 Btu

GHG Emissions 7,000 g CO2 eq./116,000 Btu

CO2 Emissions 0 g/116,000 Btu

Electricity CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 0 g CO2 eq./116,000 Btu

Hydrogen Gas

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting PSA

Truck Transport

Liquefaction &

Truck Delivery:

Liquefier

Liquid H2 Storage

Liquid H2 Truck

Gaseous H2 Storage

Dispensing

116,000 Btu

Forecourt 

Distribution:

Vaporizer

Compressor

Figure 9.3.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

central biomass–liquid truck delivery pathway

WTW Emissions (Biomass Gasification with Liquid H2 Delivery)

-60,000

-40,000

-20,000

0

20,000

40,000

60,000

80,000

Biomass Production &

Delivery

Hydrogen Production Liquefaction & Truck

Delivery

Forecourt Storage &

Dispensing 

g/GGE

CO2 CH4 N2O

Figure 9.3.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using central biomass–liquid truck delivery pathway
99

9.3.3 Biomass Supply Scenarios

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy used in this study (45 mpgge), 

and a yield of hydrogen from biomass of 13 kg biomass (dry)/kg H2, the amount of 

biomass required to supply 100%, 75%, 50%, or 25% of light-duty vehicles with 

biomass-derived hydrogen fuel was calculated and compared to the projected U.S. 

biomass potential and the 2008 U.S. biomass consumption estimates shown in Section 

3.3 (Table 9.3.3). 

Table 9.3.3. Biomass Supply Scenarios for the Central Biomass–Liquid Truck Delivery

Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Current Technology – 45 mpgge FCV, hydrogen 

production yield 13 kg dry biomass/kg H2

1

Biomass Required (billion dry tons/yr) 0.89 0.67 0.45 0.22

Percent of U.S. Biomass Potential 

(1.4 billion dry tons)2 65% 49% 33% 16%

Percent of 2008 U.S. Wood Derived 

Fuels Consumption (0.12 billion dry 

tons)3 730% 550% 370% 180%

1 Calculation does not include energy or hydrogen losses. 2 Perlack et al. (2005) 3 Calculated from values in Energy Information Administration (2009k)

Table 9.3.4 compares a sample scenario for hydrogen production from biomass from 

DOE’s Hydrogen Posture Plan (United States Department of Energy, 2006) to a 20% 

FCV penetration scenario using the assumptions in this study, as described above. 
100

Table 9.3.4. Comparison of Biomass Supply Scenarios to Hydrogen Posture Plan

DOE Hydrogen Posture 

Plan (2006)

Hydrogen Pathways 

Report (2009)*

Total Hydrogen Demand 64 million metric tons/yr 63.1 million metric tons/yr

Amount of Demand to Be 

Supplied by Resource

13 million metric tons/yr 

(20%)

12.6 million metric tons/yr 

(20%)

Biomass Needed for H2 140-280 million metric 

tons/yr

162 million metric tons/yr

Biomass Availability 512-1,300 million dry short 

tons/yr

1,368 million dry short 

tons/yr

Biomass Consumption (current) 190 million metric tons/yr 110 million metric tons/yr 

(using 16.8 million Btu/dry 

short ton LHV for biomass)

Increase in Biomass 

Consumption with H2 Production

1.7-2.5 X 2.5 X

* Calculated using the assumptions in Table 9.3.3 with 20% penetration of FCVs in light-duty vehicle 

market

9.3.4 Sensitivities

Production Sensitivities

Several sensitivities were run on the production portion of the central biomass–liquid

truck delivery pathway. These sensitivities focused primarily on cost factors; however, 

several sensitivities also affect energy use and emissions. Figure 9.3.9 shows the effects 

of several production parameters on the pathway’s levelized cost, and Table 9.3.5 shows 

the effects of varying production energy efficiency on WTW energy use and emissions. 

$4.60 $4.70 $4.80 $4.90 $5.00 $5.10 $5.20

Staffing (FTE)

 Operating Capacity

 Feedstock Cost ($/dry ton)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

55%

25 54 70

95% 90% 80%

$26.30 $38.00 $49.00

$100 mill $154.6 mill $220 mill

46% 35%

Figure 9.3.9. Production sensitivities for central biomass–liquid truck delivery pathway
101

Table 9.3.5. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Central Biomass–Liquid Truck Delivery Pathway

38% 

Efficiency

48% 

Efficiency

58% 

Efficiency

WTW GHG Emissions (g/mile) 150 160 170

WTW Fossil Energy (Btu/mile) 2,090 2,040 2,010

WTW Petroleum Energy (Btu/mile) 290 250 220

WTW Total Energy (Btu/mile) 9,930 8,170 6,980

The assumed electrical grid mix also affects the energy use and emissions. Table 9.3.6 

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 9.3.6. The Effects of Grid Mix on Use of Primary Energy and Emissions from Central 

Biomass–Liquid Truck Delivery Pathway 

U.S. Average 

Grid Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 160 -13

WTW Fossil Energy (Btu/mile) 2,040 330

WTW Petroleum Energy (Btu/mile) 250 160

WTW Total Energy (Btu/mile) 8,170 7,010

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 50%. Resulting consumption is shown in Figure 9.3.10. 
102

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Vehicle Penetration

H2 Use (Kg/day)

62 mi from city

Figure 9.3.10. Daily hydrogen consumption versus hydrogen vehicle penetration for the 

central biomass–liquid truck delivery pathway

As expected there are economies of scale for higher penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to 

the city gate is shortened. Figures 9.3.11 and 9.3.12 show those economic effects (The 

figures show identical data but are organized differently.).
103

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

$7.00

$7.50

0 100 200 300 400 500 600 700 800 900 1000

Distance From City (mi)

Levelized Cost ($ / kg)

5% Penetration

10% Penetration

25% Penetration

50% Penetration

75% Penetration

100% Penetration

Figure 9.3.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass–liquid truck delivery pathway

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

$7.00

$7.50

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

Levelized Cost ($ / kg)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.3.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for the central biomass–liquid truck delivery pathway
104

As Figure 9.3.12 shows, there is a $0.20 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 9.3.13 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 $0.235 

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.

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

0 100 200 300 400 500 600 700 800 900 1000

Distance From City (mi)

Truck Delivery Levelized Cost ($ / kg)

5% Penetration

10% Penetration

25% Penetration

50% Penetration

75% Penetration

100% Penetration

Figure 9.3.13. Truck levelized cost versus distance between production facility and city 

gate for the central biomass–liquid truck delivery pathway

The most notable feature in Figure 9.3.13 is the reduction in levelized cost as penetration 

increases to 25%. That levelized cost decrease is due to reduced cost of liquefaction, 

which is shown in Figure 9.3.14 (Liquefier cost is constant for all distances from the 

city.). 
105

The majority of the liquefaction system’s cost driver is capital (Table 9.3.2 shows that the 

capital accounts for $0.79/kg H2 of the $1.47/kg H2 total liquefaction cost.). As shown in 

Figure 9.3.15 capital-cost reduction drives the cost decrease as penetration increases. 

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

H2 Penetration

Liquefaction System Levelized Cost ($ / kg)

62 mi from city

Figure 9.3.14. Liquefaction system levelized cost versus penetration for the central 

biomass–liquid truck delivery pathway
106

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

Capital Cost - Levelized ($ / kg)

62 mi from city

Figure 9.3.15. Liquefaction system capital cost (levelized) versus penetration for the 

central biomass–liquid truck delivery pathway

The additional cost variable for the liquefaction system levelized cost is the system 

efficiency because increased efficiency reduces the energy required for liquefaction. 

Figure 9.3.16 shows the effect of penetration (directly affecting liquefier size) on 

efficiency.
107

75%

76%

77%

78%

79%

80%

81%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

Efficiency (%)

62 mi from city

Figure 9.3.16. Liquefaction system efficiency versus penetration for the central biomass–

liquid truck delivery pathway

The effects of penetration and distance between production facility and city-gate on 

WTW greenhouse gas emissions, WTW petroleum use, and WTW fossil energy use are 

shown in Figures 9.3.17, 9.3.18, and 9.3.19, respectively. In each case, the energy use 

and emissions decrease as liquefier 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. 
108

 

150

160

170

180

190

200

210

220

230

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

WTW GHG Emissions (g CO2 eq / mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.3.17. WTW greenhouse gas emissions versus penetration for the central 

biomass–liquid truck delivery pathway
109

200

250

300

350

400

450

500

550

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

WTW Petroleum Energy Use (Btu / mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.3.18. WTW petroleum use versus penetration for the central biomass–liquid truck 

delivery pathway
110

1900

2000

2100

2200

2300

2400

2500

2600

2700

2800

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

WTW Fossil Energy Use (Btu / mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.3.19. WTW fossil energy use versus penetration for the central biomass–liquid

truck delivery pathway

9.4 Central Biomass – Pipeline Delivery

Figure 9.4.1 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. The complete set of assumptions is detailed in Appendix D. 

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

central biomass–pipeline delivery pathway are summarized in Table 9.4.1. 

The GHG emissions include carbon dioxide uptake of 112,500 g CO2 / dry ton biomass 

due to direct land use change. That uptake is in addition to carbon dioxide that is 

converted into plant matter and subsequently released during gasification and reforming. 

If the land use change had a neutral effect on GHG emissions, the WTP GHG emissions 

would increase by 1,700 CO2 eq. / 116,000 Btu H2, and the WTW GHG emissions would 

increase by 36 CO2 eq. / mile.
111

9.4.1 Cost Breakdown

Figure 9.4.2 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 8.0. 

Figure 9.4.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 9.4.2. 

Figure 9.4.4 and Table 9.4.2 show the breakdown of levelized costs for the central 

biomass–pipeline delivery pathway. 
112

Biomass moisture content 25%

Woody biomass LHV 16,811,019 Btu / dry ton

Fraction of Woody Biomass (Remaining is Herbaceous) 100%

Grams of Nitrogen / dry ton biomass 709

Grams of P2O5 / dry ton biomass 189 Biomass price at H2 production $37.96 2005 $ / dry ton

Grams of K2O / dry ton biomass 331 Levelized Cost of Biomass $0.56 2005$ / kg H2 distributed

Herbicide use 24 g / dry ton

Insecticide use 2 g / dry ton WTG CO2 Emissions -25,632 g / 116000Btu to Pump

Coal Input from "Well" 261 Btu / 116000Btu to Pump Average dist from farm to H2 production 40 miles WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 418 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 2,900 Btu / 116000Btu to Pump WTG GHG Emissions -25,590 g CO2 eq./ 116000 Btu

Biomass consumption 12.8 kg (dry) / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.17 N m^3/kg H2 produced Hydrogen Outlet Quality 1

Electricity consumption 0.98 kWh / kg H2

Process Water Consumption 5.00 L / kg H2 Central plant design capacity 155,236 kg/day Total capital investment $3.03

2005$ / annual kg H2 

(effective capacity)

Natural gas price $0.340 2005$ / N m^3 Capacity factor 90% Electricity cost $0.05 2005$ / kg H2 produced

Electricity price $0.055 2005 $/kWh Process energy efficiency 46.0% Natural Gas Cost $0.06 2005$ / kg H2 produced

Total Capital Investment $154,644,297 2005$ Electricity Mix US Mix Other operating costs $0.38 2005$ / kg H2 produced

After-tax IRR 0 Levelized Cost of Prod (excl feedsto $1.07 2005$ / kg H2 distributed

Assumed Plant Life 40

CO2 Emissions 25,733 g / 116000Btu to Pump

Coal Input from "Well" 6,063 Btu / 116000Btu to Pump CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 8,598 Btu / 116000Btu to Pump N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 3,623 Btu / 116000Btu to Pump GHG Emissions 25,839 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69%

 

capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Inputs Outputs

Biomass Production & Delivery

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

Figure 9.4.1. Central biomass–pipeline delivery pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
113

Table 9.4.1. Well-to-Pump and Well-to-Wheels Results for Central Biomass–Pipeline 

Delivery Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 27,300 Btu / 116,000 Btu 610 Btu / mi

Natural Gas Input from "Well"* 15,000 Btu / 116,000 Btu 340 Btu / mi

Petroleum Input from "Well"* 8,100 Btu / 116,000 Btu 180 Btu / mi

Fossil Energy Input from "Well"* 50,400 Btu / 116,000 Btu 1,120 Btu / mi

WTP CO2 Emissions*,** 2,900 g / 116,000 Btu 60 g / mi

WTP CH4 Emissions 7 g / 116,000 Btu 0 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 3,100 g CO2 eq. / 116000 Btu 70 g / mi

Levelized Cost of Hydrogen ($/kg) $4.23 2005 $/kg $0.0941 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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.

Electricity @ Natural Gas @ 

$0.055/kWh $9.52/MMBtu

Biomass @ Total capital investment $3.03 2005$ / annual kg H2 (effective capacity)

$37.96/dry short ton Electricity cost $0.05 2005$ / kg H2 produced

Natural Gas Cost $0.06 2005$ / kg H2 produced

Levelized Cost of Biomass $0.56 2005$ / kg H2 distributed

Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.07 2005$ / kg H2 distributed

Total capital investment $3.51 2005$/annual kg distributed

Electricity for compressor @ $0.056/kWh Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

@ $0.052/kWh

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Dispensing

Hydrogen @ $4.88/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Harvesting PSA

Truck Transport

Compression &

Poplar Planting SMR

Fertilization WGS

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Figure 9.4.2. Cost analysis inputs and high-level results for central biomass–pipeline 

delivery pathway
114

Biomass - Pipeline Delivery

$1.60

$0.02

$2.61

Production

Delivery

Losses

Figure 9.4.3. Contribution of hydrogen production, delivery, and losses to the levelized 

cost of hydrogen for central biomass–pipeline delivery pathway

Figure 9.4.4. Breakdown of levelized costs for central biomass–pipeline delivery pathway
115

Table 9.4.2. Contribution of Production and Delivery Processes to Levelized Hydrogen 

Cost for Central Biomass–Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.53 $0.52 $0.55 $1.61

 Feed Handling & Drying $0.10

 Gasification, Tar Reforming, & Quench $0.09

 Compression & Sulfur Removal $0.08

 SMR, WGS, and PSA $0.15

 Steam System and Power Generation $0.07

 Cooling Water and Other Utilities $0.02

 Buildings & Structures $0.03

Delivery $1.77 $0.58 $0.26 $2.61

 Central Compressor $0.08

 Transmission Pipeline $0.07

 Distribution Pipeline $0.70

 Geologic Storage $0.08

 Gaseous Refueling Station $1.06 $0.41 $0.23 $1.69

 Compressor $0.39

 Cascade Storage $0.29

 Low Pressure Storage $0.26

 Dispenser & Accessories $0.12

Losses $0.02

Total $2.30 $1.10 $0.55 $0.26 $4.23

9.4.2 Energy Use and Emissions Breakdown

Figures 9.4.5 and 9.4.6 show the WTW energy inputs and losses for the central biomass–

pipeline delivery pathway. 

Figures 9.4.7 and 9.4.8 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. 
116

6,100 Btu Coal

8,600 Btu Natural Gas

3,600 Btu Petroleum

300 Btu Coal

400 Btu Natural Gas

2,900 Btu Petroleum 245,000 Btu Biomass

3,300 Btu Coal

900 Btu Natural Gas

200 Btu Petroleum Transport losses 0.63%

17,700 Btu Coal

5,100 Btu Natural Gas

1,300 Btu Petroleum Storage losses 0.50%

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Harvesting PSA

Truck Transport

Compression &

Poplar Planting SMR

Fertilization WGS

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Figure 9.4.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using central 

biomass–pipeline delivery pathway

WTW Energy Input (Biomass Gasification with Pipeline H2 Delivery)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Biomass

Production &

Delivery

Hydrogen

Production

Pipeline Transport Forecourt Storage

& Dispensing 

Btu/GGE

Petroleum Input from "Well" 

Natural Gas Input from "Well" 

Coal Input from "Well" 

Figure 9.4.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using central biomass–pipeline delivery pathway
117

Electricity Natural Gas

CO2 Emissions -25,600 g/116,000 Btu CO2 Emissions 25,700 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 25,800 g CO2 eq./116,000 Btu

GHG Emissions -25,600 g CO2 eq./116,000 Btu

CO2 Emissions 436 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 452 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting PSA

Truck Transport

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 9.4.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

central biomass–pipeline delivery pathway

WTW Emissions (Biomass Gasification with Pipeline H2 Delivery)

-60,000

-40,000

-20,000

0

20,000

40,000

60,000

80,000

Biomass Production &

Delivery

Hydrogen Production Pipeline Transport Forecourt Storage &

Dispensing 

g/GGE

CO2 CH4 N2O

Figure 9.4.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using central biomass–pipeline delivery pathway
118

9.4.3 Biomass Supply Scenarios 

Because the feedstock, calculated yield, and assumed fuel economy for this pathway are 

the same as those for the central biomass–liquid truck delivery pathway, the supply 

scenarios are the same as those shown in Section 9.3.3. 

9.4.4 Sensitivities

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 9.4.9 shows the effects of 

several production parameters on the pathway’s levelized cost, and Table 9.4.3 shows the 

effects of varying production energy efficiency on WTW energy use and emissions. 

$4.00 $4.05 $4.10 $4.15 $4.20 $4.25 $4.30 $4.35 $4.40 $4.45 $4.50

Staffing (FTE)

 Operating Capacity Factor

 Feedstock Cost ($/dry ton)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

55%

25 54 70

95% 90% 80%

$26.30 $38.00 $49.00

$100M $154.6M $220M

46% 35%

Figure 9.4.9. Production sensitivities for central biomass–pipeline delivery pathway

Table 9.4.3. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Central Biomass–Pipeline Delivery Pathway (current technology)

35% 

Efficiency

46% 

Efficiency

55% 

Efficiency

WTW GHG Emissions (g/mile) 60 62 73

WTW Fossil Energy (Btu/mile) 1,190 1,040 1,100

WTW Petroleum Energy (Btu/mile) 240 170 160

WTW Total Energy (Btu/mile) 9,100 6,410 5,840

The assumed electrical grid mix also affects the energy use and emissions. Table 9.4.4 

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). 
119

Table 9.4.4. The Effects of Grid Mix on Use of Primary Energy and Emissions from Central 

Biomass–Pipeline Delivery Pathway 

U.S. Average 

Grid Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 62 -17

WTW Fossil Energy (Btu/mile) 1,040 220

WTW Petroleum Energy (Btu/mile) 170 130

WTW Total Energy (Btu/mile) 6,410 5,870

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 50%. Resulting consumption is shown in Figure 9.4.10. 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Vehicle Penetration

H2 Use (Kg/day)

62 mi from city

Figure 9.4.10. Daily hydrogen consumption versus hydrogen vehicle penetration for 

central biomass–pipeline delivery pathway

As expected there are economies of scale for higher penetration/hydrogen consumption, 

and the levelized cost of delivery decreases as the distance from the production plant to 

the city gate is shortened. Figures 9.4.11 and 9.4.12 show those economic effects (The 

figures show identical data but are organized differently.).
120

As Figure 9.4.12 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. 

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

0 200 400 600 800 1000

Distance to City (mi)

Levelized Cost of H2 at Pump ($ / kg)

5% Penetration

10% Penetration

25% Penetration

50% Penetration

75% Penetration

100% Penetration

Figure 9.4.11. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for central biomass–pipeline delivery pathway

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

0% 20% 40% 60% 80% 100%

H2 Penetration

Levelized Cost of H2 at Pump ($ / kg)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.4.12. Levelized cost versus hydrogen vehicle penetration and distance between 

production facility and city gate for central biomass–pipeline delivery pathway
121

The effects of penetration and distance between production facility and city gate on 

WTW greenhouse gas emissions, WTW petroleum use, and WTW fossil energy use are 

shown in Figures 9.4.13, 9.4.14, and 9.4.15. 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 9.4.1), and much of the pressure drop is in 

the service pipelines instead of the transmission or trunk pipelines.

50

55

60

65

70

75

80

85

90

95

100

0% 20% 40% 60% 80% 100%

H2 Penetration

WTW GHG Emissions (g/mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.4.13. WTW greenhouse gas emissions versus penetration for central biomass–

pipeline delivery pathway
122

170

175

180

185

190

195

200

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

H2 Penetration

Petroleum Energy Use (Btu/mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.4.14. WTW petroleum use versus penetration for central biomass–pipeline 

delivery pathway
123

1000

1025

1050

1075

1100

1125

1150

1175

1200

0% 20% 40% 60% 80% 100%

H2 Penetration

WTW Fossil Energy Use (Btu/mile)

0 mi from city

62 mi from city

150 mi from city

1000 mi from city

Figure 9.4.15. WTW fossil energy use versus penetration for central biomass–pipeline 

delivery pathway

9.4.5 Advanced Conversion and Delivery / Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the HFCIT MYPP. The vehicle fuel 

economy was increased to 65 mpgge. In addition, the electricity grid mix was updated to 

match EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 

18.5% nuclear, 1.9% residual oil, 1.0% biomass, and 8.3% zero-carbon). Well-to-wheels 

results from cases with those modifications are shown in Table 9.4.5. The results match 

those in Hydrogen Program Record 9002 (2009). 

Table 9.4.5. Well-to-Wheels Results for Central Biomass–Pipeline Delivery Pathway with 

Advanced Technology

Coal Input from "Well" 450 Btu / mi

Natural Gas Input from "Well" 210 Btu / mi

Petroleum Input from "Well" 100 Btu / mi

Fossil Energy Input from "Well" 750 Btu / mi

WTW CO2 Emissions 49 g / mi

WTW CH4 Emissions 0.096 g / mi

WTW N2O Emissions 0.004 g / mi

WTW GHG Emissions 53 g / mi

Levelized Cost of Hydrogen ($/kg) $3.26 2005 $/kg

Levelized Cost of Hydrogen ($/mi) $0.0501 2005 $/mi
124

Several sensitivities were run on the production portion of the central biomass–pipeline 

pathway. These sensitivities focused primarily on cost factors; however, several 

sensitivities also affect energy use and emissions. Figure 9.4.16 shows the effects of 

several production parameters on the pathway’s levelized cost, and Table 9.4.6 shows the 

effects of varying production energy efficiency on WTW energy use and emissions. 

$2.90 $3.00 $3.10 $3.20 $3.30 $3.40 $3.50 $3.60 $3.70

Staffing (FTE)

 Operating Capacity Factor

 Feedstock Cost ($/kg)

 Total Capital Investment

 Production Energy

Efficiency

H2 Levelized Cost ($ / kg)

72% 62% 52%

$95 mill $149 mill $220 mill

$0.05 $0.07 $0.09

95% 90% 80%

20 50 60

Figure 9.4.16. Production sensitivities for central biomass–pipeline delivery pathway with 

advanced technology 

Table 9.4.6. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Central Biomass–Pipeline Delivery Pathway (advanced technology)

52% 

Efficiency

62% 

Efficiency

72% 

Efficiency

WTW GHG Emissions (g/mile) 50 53 55

WTW Fossil Energy (Btu/mile) 770 750 730

WTW Petroleum Energy (Btu/mile) 112 96 84

WTW Total Energy (Btu/mile) 4,360 3,710 3,230

The assumed electrical grid mix also affects the energy use and emissions. Table 9.4.7 

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). The advanced conversion pathway has a 

higher conversion efficiency than the current technology, so less biomass is used; 

therefore, less carbon is removed from the atmosphere for each kilogram of hydrogen 

produced, and the “green” grid mix has GHG emissions less negative than that for the 

current technology. 
125

Table 9.4.7. The Effects of Grid Mix on Use of Primary Energy and Emissions from Central 

Biomass–Pipeline Delivery Pathway (advanced technology) 

Projected U.S. 

Average Grid 

Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 53 -9

WTW Fossil Energy (Btu/mile) 750 130

WTW Petroleum Energy (Btu/mile) 96 72

WTW Total Energy (Btu/mile) 3,710 3,300

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy for advanced FCVs used in this 

study (65 mpgge), and a yield of hydrogen from biomass of 9.8 kg biomass (dry)/kg H2, 

the amount of biomass required to supply 100%, 75%, 50%, or 25% of light-duty 

vehicles with biomass-derived hydrogen fuel was calculated and compared to the 

projected U.S. biomass potential and the 2008 U.S. biomass consumption estimates 

shown in Section 3.3 (Table 9.4.8). 

Table 9.4.8. Biomass Supply Scenarios for the Advanced Central Biomass–Liquid Truck 

Delivery Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Advanced Technology – 65 mpgge FCV, hydrogen 

production yield 9.8 kg dry biomass/kg H2

1

Biomass Required (billion dry tons/yr) 0.47 0.35 0.24 0.12

Percent of U.S. Biomass Potential 

(1.4 billion dry tons)2 34% 26% 17% 9%

Percent of 2008 U.S. Wood Derived 

Fuels Consumption (0.12 billion dry 

tons)3 390% 290% 190% 100%

1 Calculation does not include energy or hydrogen losses. 2 Perlack et al. (2005) 3 Calculated from values in Energy Information Administration (2009k)

Table 9.4.9 compares a sample scenario for hydrogen production from biomass from 

DOE’s Hydrogen Posture Plan (United States Department of Energy, 2006) to a 20% 

FCV penetration scenario using the advanced technology assumptions in this section, as 

described above. 
126

Table 9.4.9. Comparison of Biomass Supply Scenarios to Hydrogen Posture Plan for 

Advanced Hydrogen Technology

DOE Hydrogen Posture 

Plan (2006)

Hydrogen Pathways 

Report (2009)*

Total Hydrogen Demand 64 million metric tons/yr 63.1 million metric tons/yr

Amount of Demand to Be 

Supplied by Resource

13 million metric tons/yr 

(20%)

12.6 million metric tons/yr 

(20%)

Biomass Needed for H2 140-280 million metric 

tons/yr

64 million metric tons/yr

Biomass Availability 512-1,300 million dry short 

tons/yr

1,368 million dry short 

tons/yr

Biomass Consumption (current) 190 million metric tons/yr 110 million metric tons/yr 

(using 16.8 million Btu/dry 

short ton LHV for biomass)

Increase in Biomass 

Consumption with H2 Production

1.7-2.5 X 1.6 X 

* Calculated using the assumptions in Table 9.4.8 with 20% penetration of FCVs in light-duty vehicle 

market

9.5 Central Natural Gas – Pipeline Delivery

Figure 9.5.1 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. The complete set of assumptions is detailed in Appendix E. 

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

central natural gas–pipeline delivery pathway are summarized in Table 9.5.1. 

9.5.1 Cost Breakdown

Figure 9.5.2 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 8.0. 

Figure 9.5.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 9.5.2. 

Figure 9.5.4 and Table 9.5.2 show the breakdown of levelized costs for the central natural 

gas–pipeline delivery pathway. 
127

NG Delivery Pressure Average of gas companies

NG Quality at Delivery Average of gas companies

NG Recovery Efficiency 97.2%

NG emitted & combusted during recovery 0.35%

NG processing energy efficiency 97.2% NG Cost $0.243 2005 $ / Nm^3

NG emitted & combusted during processin 0.15% NG Cost $0.958 2005$ / kg H2 distributed

NG emitted & combusted during transport 0.14 g / MMBtu

NG transport distance 500 miles WTG CO2 Emissions 5,079 g / 116000Btu to Pump

Coal Input from "Well" 252 Btu / 116000Btu to Pump WTG CH4 Emissions 139 g / 116000Btu to Pump

Natural Gas Input from "Well" 122,927 Btu / 116000Btu to Pump Compression Reqs (stages & eff) average of gas companies WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 492 Btu / 116000Btu to Pump WTG GHG Emissions 8,571 g CO2 eq./ 116000 Btu

Natural gas consumption 4.50 N m^3/kg H2 produced Hydrogen Output Pressure 300 psi

Electricity consumption 0.57 kWh / kg H2 Hydrogen Outlet Quality 98 minimum

Process (De-Ionized) Water Consumption 12.70 L / kg H2

Cooling Water Consumption 5.66 L / kg H2 Central plant design capacity 379,387 kg/day Total capital investment $1.45

2005$ / annual kg H2 

(effective capacity)

Capacity factor 90% Electricity cost $0.03 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 71.9% Other operating costs $0.08 2005$ / kg H2 produced

Total Capital Investment $180,543,901 2005$ Electricity Mix US Mix Levelized Cost of Prod (excl feedsto $0.38 2005$ / kg H2 distributed

After-tax IRR 10%

Assumed Plant Life 40 years

SMR CO2 Emissions 10,233 g / 116000Btu to Pump

Coal Input from "Well" 3,440 Btu / 116000Btu to Pump SMR CH4 Emissions 7 g / 116000Btu to Pump

Natural Gas Input from "Well" 47,416 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 433 Btu / 116000Btu to Pump SMR GHG Emissions 10,410 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69%

 

capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Inputs Outputs

NG Recovery, Processing, & Transport

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

Figure 9.5.1. Central natural gas–pipeline delivery pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
128

Table 9.5.1. Well-to-Pump and Well-to-Wheels Results for Central Natural Gas–Pipeline 

Delivery Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 24,700 Btu / 116,000 Btu 550 Btu / mi

Natural Gas Input from "Well"* 176,400 Btu / 116,000 Btu 3,920 Btu / mi

Petroleum Input from "Well"* 2,500 Btu / 116,000 Btu 55 Btu / mi

Fossil Energy Input from "Well"* 203,500 Btu / 116,000 Btu 4,530 Btu / mi

WTP CO2 Emissions*,** 13,600 g / 116,000 Btu 300 g / mi

WTP CH4 Emissions 26 g / 116,000 Btu 1 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 14,300 g CO2 eq. / 116000 Btu 320 g / mi

Levelized Cost of Hydrogen ($/kg) $3.95 2005 $/kg $0.0878 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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.

Natural Gas @ Total capital investment $1.45 2005$ / annual kg H2 (effective capacity)

$6.81/MMBtu Electricity cost $0.03 2005$ / kg H2 produced

Other operating costs $0.08 2005$ / kg H2 produced

Natural gas cost $0.95 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $0.38 2005$ / kg H2 produced

Total capital investment $3.51 2005$/annual kg distributed

Electricity for compressor @ $0.056/kWh Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

@ $0.052/kWh

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

* 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.

Hydrogen @ $3.95/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Geologic Storage

Pipeline

Dispensing

Compression &

Pipeline Delivery:

Compressor

Processing WGS

Pipeline Transport PSA

and Delivery*: Desulfurizer

Recovery SMR

Electricity @

$0.055/kWh

Natural Gas Production Hydrogen Production: 

Figure 9.5.2. Cost analysis inputs and high-level results for central natural gas–pipeline 

delivery pathway
129

Central Natural Gas - Pipeline Delivery 

$1.32

$2.61

$0.02

Production

Delivery

Losses

Figure 9.5.3. Contribution of hydrogen production, delivery, and losses to the levelized 

cost of hydrogen from central natural gas–pipeline delivery pathway

Figure 9.5.4. Breakdown of levelized costs for central natural gas–pipeline delivery 

pathway
130

Table 9.5.2. Contribution of Production and Delivery Processes to Levelized Hydrogen 

Cost for Central Natural Gas–Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $0.26 $0.12 $0.95 $1.33

 Process Plant Equipment $0.18

 Balance of Plant and Offsites $0.07

 SCR NOx Control on Stack $0.00

Delivery $1.77 $0.58 $0.26 $2.61

 Central Compressor $0.08

 Transmission Pipeline $0.07

 Distribution Pipeline $0.70

 Geologic Storage $0.08

 Gaseous Refueling Station $1.06 $0.41 $0.23 $1.69

 Compressor $0.39

 Cascade Storage $0.29

 Low Pressure Storage $0.26

 Dispenser & Accessories $0.12

Losses $0.02

Total $2.03 $0.70 $0.95 $0.26 $3.95

9.5.2 Energy Use and Emissions Breakdown

Figures 9.5.5 and 9.5.6 show the WTW energy inputs and losses for the central natural 

gas–pipeline delivery pathway. 

Figures 9.5.7 and 9.5.8 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. 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. 
131

3,400 Btu Coal

47,400 Btu Natural Gas

400 Btu Petroleum

300 Btu Coal

122,900 Btu Natural Gas

500 Btu Petroleum

3,300 Btu Coal

900 Btu Natural Gas

200 Btu Petroleum Transport losses 0.63%

17,700 Btu Coal

5,100 Btu Natural Gas

1,300 Btu Petroleum Distribution losses 0.50%

* 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.

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Pipeline Transport PSA

Compression &

Recovery SMR

Processing WGS

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

Figure 9.5.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using central 

natural gas–pipeline delivery pathway

WTW Energy Input (Central SMR with Gaseous Pipeline Delivery)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Nat Gas Production

& Delivery

Hydrogen

Production

Pipeline Transport Forecourt Storage

& Dispensing 

Btu/GGE

Petroleum Input from "Well" 

Natural Gas Input from "Well" 

Coal Input from "Well" 

Figure 9.5.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using central natural gas–pipeline delivery pathway
132

CO2 Emissions 590 g/116,000 Btu CO2 Emissions 10,200 g/116,000 Btu

CH4 Emissions 16 g/116,000 Btu CH4 Emissions 7 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 10,400 g CO2 eq./116,000 Btu

GHG Emissions 1,000 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 500 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

* 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.

Electricity

Natural Gas Production Hydrogen Production: 

and Delivery: Desulfurizer

Recovery SMR

Processing WGS

Pipeline Transport PSA

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 9.5.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

central natural gas–pipeline delivery pathway

WTW Emissions (Central SMR with Gaseous Pipeline Delivery)

0

2,000

4,000

6,000

8,000

10,000

12,000

Nat Gas Production &

Delivery

Hydrogen Production Pipeline Transport Forecourt Storage &

Dispensing 

g/GGE

CO2 CH4 N2O

Figure 9.5.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using central natural gas–pipeline delivery pathway
133

9.5.3 Natural Gas Supply Scenarios 

Because the feedstock, calculated yield, and assumed fuel economy for this pathway are 

the same as those for the distributed natural gas pathway, the supply scenarios are the 

same as those shown in Section 9.1.3. 

9.5.4 Sensitivities

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 9.5.9 shows the effects of 

several production parameters on the pathway’s levelized cost, and Table 9.5.3 shows the 

effects of varying production energy efficiency on WTW energy use and emissions. 

$3.60 $3.70 $3.80 $3.90 $4.00 $4.10 $4.20 $4.30 $4.40 $4.50 $4.60

 Operating Capacity Factor

 Feedstock Cost ($/Nm^3)

Production Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

81%

95% 90%80%

$0.17 $0.24 $0.32

$150M $181M $250M

72% 50%

Figure 9.5.9. Production sensitivities for central natural gas–pipeline delivery pathway

Table 9.5.3. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Central Natural Gas–Pipeline Delivery Pathway (current technology)

50% 

Efficiency

72% 

Efficiency

81% 

Efficiency

WTW GHG Emissions (g/mile) 430 320 290

WTW Fossil Energy (Btu/mile) 6,200 4,500 4,100

WTW Petroleum Energy (Btu/mile) 62 55 54

WTW Total Energy (Btu/mile) 6,400 4,700 4,200

The assumed electrical grid mix also affects the energy use and emissions. Table 9.5.4 

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). 
134

Table 9.5.4. The Effects of Grid Mix on Use of Primary Energy and Emissions from Central 

Natural Gas–Pipeline Delivery Pathway 

U.S. Average 

Grid Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 320 240

WTW Fossil Energy (Btu/mile) 4,500 3,800

WTW Petroleum Energy (Btu/mile) 55 14

WTW Total Energy (Btu/mile) 4,700 4,200

Delivery Sensitivities

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 

9.4.4. The effects of the sensitivities will be the same for all pipeline delivery scenarios.

9.5.5 Advanced Conversion and Delivery/Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the Hydrogen, Fuel Cells and Infrastructure 

Technologies (HFCIT) Multi-Year Program Plan (MYPP). The vehicle fuel economy 

was increased to 65 mpgge. In addition, the electricity grid mix was updated to match 

EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 18.5% 

nuclear, 1.9% residual oil, and 1.0% biomass, and 8.3% zero-carbon). 

WTW results from cases with those modifications are shown in Table 9.5.5. 

Corresponding results were not published in Hydrogen Program Record 9002 (2009). 

Table 9.5.5. Well-to-Wheels Results for central natural gas–pipeline pathway with 

advanced technology

Coal Input from "Well" 340 Btu / mi

Natural Gas Input from "Well" 2760 Btu / mi

Petroleum Input from "Well" 40 Btu / mi

Fossil Energy Input from "Well" 3140 Btu / mi

WTW CO2 Emissions 208 g / mi

WTW CH4 Emissions 0.41 g / mi

WTW N2O Emissions 0.001 g / mi

WTW GHG Emissions 220 g / mi

Levelized Cost of Hydrogen ($/kg) $2.96 2005 $/kg

Levelized Cost of Hydrogen ($/mi) $0.0456 2005 $/mi
135

9.6 Central Wind Electricity – Pipeline Delivery

Figure 9.6.1 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. The complete set of assumptions is detailed in Appendix F. 

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

central wind electricity–pipeline delivery pathway are summarized in Table 9.6.1. 

9.6.1 Cost Breakdown

Figure 9.6.2 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 

8.0. 

Figure 9.6.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 9.6.2. 

Figure 9.6.4 and Table 9.6.2 show the breakdown of levelized costs for the central wind 

electricity–pipeline delivery pathway. 
136

Wind-generated electricity on the grid is assumed.

The electrolyzers are not necessarily co-located with the wind farm.

Electricity price at H2 production $0.055 2005 $ / short ton

Levelized Cost of Wind Electricity $2.99 2005$ / kg H2 distributed

WTG CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump WTG GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption 53.48 kWh / kg H2 Hydrogen Output Pressure 300 psi

Process Water Consumption 11.1 L / kg H2 Central plant design capacity 52,300 kg/day Total capital investment $5.96

2005$ / annual kg H2 

(effective capacity)

Cooling Water Consumption 1112 L / kg H2 Capacity factor 97% Electricity cost $2.96 2005$ / kg H2 produced

Process energy efficiency 62.3% Other operating costs $0.38 2005$ / kg H2 produced

Electrolyzer Cost 675 $ / kW Electricity Mix Wind Electricity Levelized Cost of Prod (excl feedsto $1.56 2005$ / kg H2 distributed

Total Capital Investment $110,432,050 2005$ After-tax IRR 10%

Assumed Plant Life 40

H2 Prod CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,307 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 949 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 453 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000

Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69%

 

capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,681 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,076 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Inputs Outputs

Wind Electricity

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

Figure 9.6.1. Central wind electricity–pipeline delivery pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
137

Table 9.6.1. Well-to-Pump and Well-to-Wheels Results for Central Wind Electricity–Pipeline 

Delivery Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 21,000 Btu / 116,000 Btu 470 Btu / mi

Natural Gas Input from "Well"* 6,000 Btu / 116,000 Btu 130 Btu / mi

Petroleum Input from "Well"* 1,600 Btu / 116,000 Btu 35 Btu / mi

Fossil Energy Input from "Well"* 28,600 Btu / 116,000 Btu 640 Btu / mi

WTP CO2 Emissions*,** 2,800 g / 116,000 Btu 62 g / mi

WTP CH4 Emissions 4 g / 116,000 Btu 0 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 2,900 g CO2 eq. / 116000 Btu 64 g / mi

Levelized Cost of Hydrogen ($/kg) $7.16 2005 $/kg $0.1591 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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. 

Electricity @ Total capital investment $5.96 2005$ / annual kg H2 (effective capacity)

$0.055/kWh Electricity cost $2.96 2005$ / kg H2 produced

Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Wind Electricity $2.99 2005$ / kg H2 distributed

Levelized Cost of Prod (excl feedstock) $1.56 2005$ / kg H2 distributed

Electricity for compressor @ $0.056/kWh Total capital investment $3.51 2005$/annual kg distributed

Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage 

@ $0.052/kWh Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

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 @ $7.16/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Figure 9.6.2. Cost analysis inputs and high-level results for central wind electricity–

pipeline delivery pathway
138

Central Wind Electricity - Pipeline Delivery 

$4.50

$2.61

$0.05

Production

Delivery

Losses

Figure 9.6.3. Contribution of hydrogen production, delivery, and losses to the levelized 

cost of hydrogen from central wind electricity–pipeline delivery pathway
139

Figure 9.6.4. Breakdown of levelized costs for central wind electricity–pipeline delivery 

pathway

Table 9.6.2. Contribution of Production and Delivery Processes to Levelized Hydrogen 

Cost from Central Wind Electricity–Pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $1.16 $0.38 $2.96 $4.50

 Electrolyzer Units $0.37

 Transformer/Rectifier Units $0.07

 Compressor Units $0.34

 Gas Holders $0.17

 Balance of Plant $0.21

Delivery $1.77 $0.58 $0.26 $2.61

 Central Compressor $0.08
140

 Transmission Pipeline $0.07

 Distribution Pipeline $0.70

 Geologic Storage $0.08

 Gaseous Refueling Station $1.06 $0.41 $0.23 $1.69

 Compressor $0.39

 Cascade Storage $0.29

 Low Pressure Storage $0.26

 Dispenser & Accessories $0.12

Losses $0.05

Total $2.93 $0.96 $2.96 $0.26 $7.16

9.6.2 Energy Use and Emissions Breakdown

Figures 9.6.5 and 9.6.6 show the WTW energy inputs and losses for the central wind 

electricity–pipeline delivery pathway. 

Figures 9.6.7 and 9.6.8 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. 

0 Btu Coal

0 Btu Natural Gas

0 Btu Petroleum 188,000 Btu Electricity

3,300 Btu Coal

900 Btu Natural Gas

200 Btu Petroleum Transport losses 0.63%

17,700 Btu Coal

5,100 Btu Natural Gas

1,300 Btu Petroleum Storage losses 0.50%

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

Transmission & Distribution

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 9.6.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using central 

wind electricity–pipeline delivery pathway
141

WTW Energy Input (Wind-Generated Electricity with Pipeline H2 Delivery)

0

20,000

40,000

60,000

80,000

100,000

120,000

Electrolysis of Wind

Power

Pipeline Transport Forecourt Storage &

Dispensing 

Btu/GGE

Petroleum Input from "Well" 

Natural Gas Input from "Well" 

Coal Input from "Well" 

Figure 9.6.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using central wind electricity–pipeline delivery pathway

CO2 Emissions 0 g/116,000 Btu CO2 Emissions 0 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 0 g/116,000 Btu

GHG Emissions 0 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 450 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

Transmission & Distribution

Compression &

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Figure 9.6.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

central wind electricity–pipeline delivery pathway
142

WTW Emissions (Wind-Generated Electricity with Pipeline H2 Delivery)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Electrolysis of Wind Pow er Pipeline Transport Forecourt Storage &

Dispensing 

g/GGE

CO2 CH4 N2O

Figure 9.6.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using central wind electricity–pipeline delivery pathway

9.6.3 Wind Electricity Supply Scenarios

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy used in this study (45 mpgge), 

and a yield of hydrogen from wind electricity of 53 kWh wind electricity/kg H2, the 

amount of wind electricity required to supply 100%, 75%, 50%, or 25% of light-duty 

vehicles with wind electricity-derived hydrogen fuel was calculated and compared to the 

potential 2030 U.S. wind electricity generation capacity and the 2008 U.S. wind

electricity consumption estimates shown in Section 3.2 (Table 9.6.3). 

Table 9.6.3. Wind Electricity Supply Scenarios for the Central Wind Electricity–Pipeline 

Delivery Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Current Technology – 45 mpgge FCV, hydrogen 

production yield 53 kWh/kg H2

1

Wind Electricity Required 

(trillion kWh/yr) 3.4 2.5 1.7 0.84

Percent of Potential U.S. Capacity 

in 2030 (1.16 trillion kWh)2 290% 220% 150% 70%

Percent of 2008 U.S. Consumption 

(0.052 trillion kWh)3 6,500% 4,900% 3,200% 1,600%

1 Calculation does not include energy or hydrogen losses. 2 United States Department of Energy (2008) 3 Energy Information Administration (2009j)
143

Table 9.6.4 compares a sample scenario for hydrogen production from wind electricity 

from DOE’s Hydrogen Posture Plan (United States Department of Energy, 2006) to a 

20% FCV penetration scenario using the assumptions in this study, as described above. 

Table 9.6.4. Comparison of Wind Electricity Supply Scenarios to Hydrogen Posture Plan

DOE Hydrogen Posture 

Plan (2006)

Hydrogen Pathways 

Report (2009)*

Total Hydrogen Demand 64 million metric tons/yr 63.1 million metric tons/yr

Amount of Demand to Be 

Supplied by Resource

13 million metric tons/yr 

(20%)

12.6 million metric tons/yr 

(20%)

Wind Electricity Needed for H2 200 GWe 675 billion kWh/yr 

Wind Electricity Availability 2,300 GWe nameplate 

capacity

1,160 billion kWh/yr in 2030

Wind Electricity Consumption 

(current)

10 GWe installed 

nameplate capacity

52 billion kWh/yr in 2008

Increase in Wind Electricity 

Consumption with H2 Production

28 X 14 X

* Calculated using the assumptions in Table 9.6.3 with 20% penetration of FCVs in light-duty vehicle 

market

9.6.4 Sensitivities

Production Sensitivities

Several sensitivities were run on the production portion of the central electrolysis of 

wind-generated electricity–pipeline delivery pathway. These sensitivities focused 

primarily on cost factors. Figure 9.6.9 shows the effects of several production parameters 

on the pathway’s levelized cost. 

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 estimated in 

the Annual Energy Outlook 2005 High Case (Energy Information Administration, 2005) 

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.
144

$6.00 $6.25 $6.50 $6.75 $7.00 $7.25 $7.50 $7.75 $8.00 $8.25 $8.50

Operating Capacity Factor

Electricity Cost ($/kWh)

Electrolyzer Cost ($/kW)

 Production Energy Efficiency (HHV)

H2 Levelized Cost ($)

79%

98% 97% 85%

$0.039 $0.055 $0.072

$575 $675 $775

74% 69%

Figure 9.6.9. Production sensitivities for central wind electrolysis–pipeline delivery 

pathway

Delivery Sensitivities

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 

9.4.4. The effects of the sensitivities will be the same for all pipeline delivery scenarios.

9.6.5 Advanced Conversion and Delivery/Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the Hydrogen, Fuel Cells and Infrastructure 

Technologies (HFCIT) Multi-Year Program Plan (MYPP). The vehicle fuel economy 

was increased to 65 mpgge. In addition, the electricity grid mix was updated to match 

EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 18.5% 

nuclear, 1.9% residual oil, and 1.0% biomass, and 8.3% zero-carbon). 

WTW results from cases with those modifications are shown in Table 9.6.5. The results 

do not match those in Hydrogen Program Record 9002 (2009) because the production 

yield and cost of electrolyzers were modified in the Program Record case.

Table 9.6.5. Well-to-Wheels Results for central wind–pipeline pathway with advanced 

technology 

Coal Input from "Well" 290 Btu / mi

Natural Gas Input from "Well" 130 Btu / mi

Petroleum Input from "Well" 20 Btu / mi

Fossil Energy Input from "Well" 440 Btu / mi

WTW CO2 Emissions 41 g / mi

WTW CH4 Emissions 0.06 g / mi

WTW N2O Emissions 0.0006 g / mi

WTW GHG Emissions 43 g / mi
145

Levelized Cost of Hydrogen ($/kg) $4.88 2005 $/kg

Levelized Cost of Hydrogen ($/mi) $0.0752 2005 $/mi

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy for advanced FCVs used in this 

study (65 mpgge), and a yield of hydrogen from wind electricity of 45 kWh wind 

electricity/kg H2, the amount of wind electricity required to supply 100%, 75%, 50%, or 

25% of light-duty vehicles with wind electricity–derived hydrogen fuel was calculated 

and compared to the potential 2030 U.S. wind electricity generation capacity and the 

2008 U.S. wind electricity consumption estimates shown in Section 3.2 (Table 9.6.6). 

Table 9.6.6. Wind Electricity Supply Scenarios for the Central Wind Electricity–Pipeline 

Delivery Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Advanced Technology – 65 mpgge FCV, hydrogen 

production yield 45 kWh/kg H2

1

Wind Electricity Required 

(trillion kWh/yr) 2.0 1.5 1.0 0.5

Percent of Potential U.S. Capacity 

in 2030 (1.16 trillion kWh)2 170% 130% 80% 40%

Percent of 2008 U.S. Consumption 

(0.052 trillion kWh)3 3,800% 2,800% 1,900% 900%

1 Calculation does not include energy or hydrogen losses. 2 United States Department of Energy (2008) 3 Energy Information Administration (2009j)

Table 9.6.7 compares a sample scenario for hydrogen production from wind electricity 

from DOE’s Hydrogen Posture Plan (United States Department of Energy, 2006) to a 

20% FCV penetration scenario using the advanced technology assumptions in this 

section, as described above. 

Table 9.6.7. Comparison of Wind Electricity Supply Scenarios to Hydrogen Posture Plan 

for Advanced Hydrogen Technology
146

DOE Hydrogen Posture 

Plan (2006)

Hydrogen Pathways 

Report (2009)*

Total Hydrogen Demand 64 million metric tons/yr 63.1 million metric tons/yr

Amount of Demand to Be 

Supplied by Resource

13 million metric tons/yr 

(20%)

12.6 million metric tons/yr 

(20%)

Wind Electricity Needed for H2 200 GWe 390 billion kWh/yr 

Wind Electricity Availability 2,300 GWe nameplate 

capacity

1,160 billion kWh/yr in 2030

Wind Electricity Consumption 

(current)

10 GWe installed 

nameplate capacity

52 billion kWh/yr in 2008

Increase in Wind Electricity 

Consumption with H2 Production

28 X 8.5 X 

* Calculated using the assumptions in Table 9.6.6 with 20% penetration of FCVs in light-duty vehicle 

market

9.7 Central Coal with Carbon Capture and Sequestration (CCS) – Pipeline

Delivery

Figure 9.7.1 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. The complete set of assumptions is detailed in Appendix G.

The well-to-pump and well-to-wheels cost of hydrogen, energy use, and emissions for the 

central coal with CCS–pipeline delivery pathway are summarized in Table 9.7.1. 

9.7.1 Cost Breakdown

Figure 9.7.2 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 

8.0. 

Figure 9.7.3 shows the contributions of hydrogen production, delivery, and losses to the 

levelized cost of hydrogen shown in Figure 9.7.2. 

Figure 9.7.4 and Table 9.7.2 show the breakdown of levelized costs for the central coal 

with CCS–pipeline delivery pathway. 
147

Energy Recovery 99.3%

Energy Used 7049 Btu / MMBtu Coal 

Delivered

Diesel Used 3948 Btu / MMBtu Coal 

Delivered Coal price at H2 production $33.98 2005 $ / short ton

Electricity Used 1692 Btu / MMBtu Coal 

Delivered Levelized Cost of Coal $0.31 2005$ / kg H2 distributed

WTG CO2 Emissions 114 g / 116000Btu to Pump

Coal Input from "Well" 116,427 Btu / 116000Btu to Pump WTG CH4 Emissions 14 g / 116000Btu to Pump

Natural Gas Input from "Well" 145 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 712 Btu / 116000Btu to Pump WTG GHG Emissions 462 g CO2 eq./ 116000 Btu

Coal consumption 7.8 kg / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.00 N m^3/kg H2 produced

Electricity consumption 1.72 kWh / kg H2

Process Water Consumption 11.02 L / kg H2 Central plant design capacity 307,673 kg/day

Total capital investment $6.84 2005$ / annual kg H2 

(effective capacity)

Capacity factor 90% Electricity cost $0.10 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 53.6% Natural Gas Cost $0.00 2005$ / kg H2 produced

Total Capital Investment $691,377,851 2005$ Electricity Mix US Mix Other operating costs $0.38 2005$ / kg H2 produced

After-tax IRR 10% Levelized Cost of Prod (excl 

feedstock)

$1.76 2005$ / kg H2 distributed

Assumed Plant Life 40

CO2 Captured for sequestration 90% H2 Prod CO2 Emissions 3,803 g / 116000Btu to Pump

Coal Input from "Well" 105,782 Btu / 116000Btu to Pump CO2 Pipeline Length 100 miles H2 Prod CH4 Emissions 13 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,022 Btu / 116000Btu to Pump Number of injection wells 1 H2 Prod N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,332 Btu / 116000Btu to Pump Injection well depth 1524 m H2 Prod GHG Emissions 4,136 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal nonoxygenated conventional 

unleaded gasoline)

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69%

 

capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Coal Mining & Delivery

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production & CCS

Forecourt Distribution

Inputs Outputs

Figure 9.7.1. Central coal with CCS–pipeline delivery pathway summary of major inputs, assumptions, and outputs by subsystem 

Coal, natural gas, and petroleum inputs from “well” 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.
148

Table 9.7.1. Well-to-Pump and Well-to-Wheels Results for Central Coal with CCS–Pipeline 

Delivery Pathway

Well-to-Pump Well-to-Wheels

Coal Input from "Well"* 243,200 Btu / 116,000 Btu 5,410 Btu / mi

Natural Gas Input from "Well"* 9,200 Btu / 116,000 Btu 200 Btu / mi

Petroleum Input from "Well"* 3,600 Btu / 116,000 Btu 80 Btu / mi

Fossil Energy Input from "Well"* 256,000 Btu / 116,000 Btu 5,690 Btu / mi

WTP CO2 Emissions*,** 6,700 g / 116,000 Btu 150 g / mi

WTP CH4 Emissions 31 g / 116,000 Btu 1 g / mi

WTP N2O Emissions 0 g / 116,000 Btu 0 g / mi

WTP GHG Emissions* 7,500 g CO2 eq. / 116000 Btu 170 g / mi

Levelized Cost of Hydrogen ($/kg) $4.68 2005 $/kg $0.1040 2005 $/mi

* Well-to-pump results are rounded to the nearest hundred; well-to-wheels results are rounded to 

the nearest ten. 

** Includes the carbon content of CO, CH4, and volatile organic compound emissions that 

decompose in the atmosphere to CO2

Coal, natural gas, and petroleum inputs from “well” 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. 

Coal @ Total capital investment $6.84 2005$ / annual kg H2 (effective capacity)

$33.98/short ton Electricity cost $0.10 2005$ / kg H2 produced

Natural Gas Cost $0.00 2005$ / kg H2 produced

Electricity for CCS @ Levelized Cost of Coal $0.31 2005$ / kg H2 distributed

$0.055/kWh Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.76 2005$ / kg H2 distributed

Electricity for compressor @ $0.056/kWh Total capital investment $3.51 2005$/annual kg distributed

Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage 

@ $0.052/kWh Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

* This box represents the coal that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include coal used as a heating fuel or to produce electricity.

Hydrogen @ $4.68/kg

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Compressor

Geologic Storage

Pipeline

Forecourt 

PSA

Compression &

Pipeline Delivery:

Rail Transport H2S Removal

CO2 Removal

& Delivery*: Gasifier

Mining/Recovery Shift Converter

Hydrogen Production 

Coal Mining & CCS: 

Figure 9.7.2. Cost analysis inputs and high-level results for central coal with CCS–pipeline

delivery pathway
149

Central Coal with CCS - Pipeline Delivery 

$2.05

$2.61

$0.02

Production

Delivery

Losses

Figure 9.7.3. Contribution of hydrogen production, delivery, and losses to the levelized 

cost of hydrogen for the central coal with CCS–pipeline delivery pathway

Figure 9.7.4. Breakdown of levelized costs for central coal with CCS–pipeline delivery 

pathway
150

Table 9.7.2. Contribution of Production and Delivery Processes to Levelized Hydrogen 

Cost from Central Coal with CCS–pipeline Delivery Pathway

Cost Component Capital

Other 

O&M Feedstock

Energy/

Fuel Total

Production $1.27 $0.47 $0.31 $2.05

 Feed Handling $0.06

 Gasifier & Accessories $0.15

 Air Separation Unit $0.16

 Hydrogen Separation & Gas Cleanup $0.27

 Plant Utilities $0.13

 Buildings & Structures $0.01

 Instrumentation & Communications $0.02

 CO2 Compressor $0.07

 CO2 Injection Site $0.16

 CO2 Pipeline $0.24

Delivery $1.77 $0.58 $0.26 $2.61

 Central Compressor $0.08

 Transmission Pipeline $0.07

 Distribution Pipeline $0.70

 Geologic Storage $0.08

 Gaseous Refueling Station $1.06 $0.41 $0.23 $1.69

 Compressor $0.39

 Cascade Storage $0.29

 Low Pressure Storage $0.26

 Dispenser & Accessories $0.12

Losses $0.02

Total $3.04 $1.05 $0.31 $0.26 $4.68

9.7.2 Energy Use and Emissions Breakdown

Figures 9.7.5 and 9.7.6 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 gasifying. Additional WTW 

energy inputs for coal needed for heating, electricity, and process-inefficiency are 

reported as inputs to hydrogen production. 

Figures 9.7.7 and 9.7.8 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. 
151

105,800 Btu Coal

3,000 Btu Natural Gas

1,300 Btu Petroleum

116,400 Btu Coal

100 Btu Natural Gas

700 Btu Petroleum 213,000 Btu Coal

3,300 Btu Coal

900 Btu Natural Gas

200 Btu Petroleum Transport losses 0.63%

17,700 Btu Coal

5,100 Btu Natural Gas

1,300 Btu Petroleum Storage losses 0.50%

* This box represents the coal that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include coal used as a heating fuel or to produce electricity.

Hydrogen Gas

Gaseous H2 Storage

Dispensing

116,000 Btu

Pipeline

Forecourt 

Distribution:

Compressor

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

CO2 Removal

PSA

Mining/Recovery Shift Converter

Rail Transport H2S Removal

Hydrogen Production 

Coal Mining & CCS: 

& Delivery*: Gasifier

Figure 9.7.5. WTW energy inputs to deliver 116,000 Btu hydrogen to a vehicle using central 

coal with CCS–pipeline delivery pathway

WTW Energy Input (Coal Gasification with Pipeline H2 Delivery)

0

20,000

40,000

60,000

80,000

100,000

120,000

Coal Mining &

Delivery

Hydrogen

Production

Pipeline Transport Forecourt Storage

& Dispensing 

Btu/GGE

Petroleum Input from "Well" 

Natural Gas Input from "Well" 

Coal Input from "Well" 

Figure 9.7.6. WTW petroleum, natural gas, and coal inputs to deliver 116,000 Btu hydrogen 

using central coal with CCS–pipeline delivery pathway
152

CO2 Emissions 110 g/116,000 Btu CO2 Emissions 3,800 g/116,000 Btu

CH4 Emissions 14 g/116,000 Btu CH4 Emissions 13 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 4,100 g CO2 eq./116,000 Btu

GHG Emissions 460 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 450 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

* This box represents the coal that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include coal used as a heating fuel or to produce electricity.

Hydrogen Production 

Coal Mining & CCS: 

& Delivery*: Gasifier

Mining/Recovery Shift Converter

Rail Transport H2S Removal

CO2 Removal

PSA

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 9.7.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

central coal with CCS–pipeline delivery pathway

WTW Emissions (Coal Gasification with Pipeline H2 Delivery)

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Coal Mining & Delivery Hydrogen Production Pipeline Transport Forecourt Storage &

Dispensing 

g/GGE

CO2 CH4 N2O

Figure 9.7.8. WTW CO2, CH4, and N2O emissions resulting from delivery of 116,000 Btu 

hydrogen to a vehicle using central coal with CCS–pipeline delivery pathway
153

9.7.3 Coal Supply Scenarios

Assuming a total vehicle miles traveled in passenger vehicles of 2.78 trillion (Bureau of 

Transportation Statistics, 2007), the vehicle fuel economy used in this study (45 mpgge), 

and a yield of hydrogen from coal of 7.9 kg coal/kg H2, the amount of coal required to 

supply 100%, 75%, 50%, or 25% of light-duty vehicles with coal-derived hydrogen fuel 

was calculated and compared to the U.S. coal reserves, 2007 U.S. coal production, and 

2008 U.S. coal consumption estimates shown in Section 3.4 (Table 9.7.3). 

Table 9.7.3. Coal Supply Scenarios for the Central Coal with CCS–Pipeline Delivery

Pathway

100% 

Penetration

75% 

Penetration

50% 

Penetration

25% 

Penetration

Current Technology – 45 mpgge FCV, 

hydrogen production yield 7.85 kg coal/kg H2

1 

Coal Required (million short tons) 550 410 270 140

Percent of U.S. Reserves 

(489,000 million short tons)2 0.11% 0.08% 0.06% 0.03%

Percent of 2007 U.S. Production 

(1,171 million short tons)3 47% 35% 23% 12%

Percent of 2008 U.S. Consumption 

(1,122 million short tons)4 49% 37% 24% 12%

1 Calculation does not include energy or hydrogen losses. 2 United States Department of Energy (2008) 3 Energy Information Administration (2008d)

4 Energy Information Administration (2009j)

Table 9.7.4 compares a sample scenario for hydrogen production from biomass from 

DOE’s Hydrogen Posture Plan (United States Department of Energy, 2006) to a 20% 

FCV penetration scenario using the assumptions in this study, as described above. 
154

Table 9.7.4. Comparison of Coal Supply Scenarios to Hydrogen Posture Plan

DOE Hydrogen Posture 

Plan (2006)

Hydrogen Pathways 

Report (2009)*

Total Hydrogen Demand 64 million metric tons/yr 63.1 million metric tons/yr

Amount of Demand to Be 

Supplied by Resource

13 million metric tons/yr 

(20%)

12.6 million metric tons/yr 

(20%)

Coal Needed for H2 110 million metric tons/yr 99 million metric tons/yr

Coal Availability 268 billion tons estimated 

recoverable reserves, 493 

billion tons demonstrated 

coal base

489 billion short tons

Coal Consumption (current) 1,100 million metric tons/yr 

(all grades)

1,017 million metric tons/yr 

Increase in Coal Consumption 

with H2 Production

1.1 X 1.1 X

* Calculated using the assumptions in Table 9.7.3 with 20% penetration of FCVs in light-duty vehicle 

market

9.7.4 Sensitivities

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 9.7.9 shows 

the effects of several production parameters on the pathway’s levelized cost, and Table 

9.7.5 shows the effect of varying production efficiency on the WTW results. 

$4.50 $4.55 $4.60 $4.65 $4.70 $4.75 $4.80 $4.85 $4.90 $4.95 $5.00

Operating Capacity Factor

Coal Cost ($/short ton)

CCS Capital Cost

Production Total Direct Capital

Production Energy Efficiency (LHV)

H2 Levelized Cost ($)

60%

95% 90% 80%

$24 $34 $44

$350M $391M $500M

54% 45%

$75M $117M $175M

Figure 9.7.9. Production sensitivities for central coal with CCS–pipeline delivery pathway
155

Table 9.7.5. The Effects of Production Energy Efficiency on Primary Energy and Emissions 

from Central Coal with CCS–Pipeline Delivery Pathway (current technology)

45% 

Efficiency

54% 

Efficiency

60% 

Efficiency

WTW GHG Emissions (g/mile) 190 170 160

WTW Fossil Energy (Btu/mile) 6,700 5,700 5,200

WTW Petroleum Energy (Btu/mile) 89 80 76

WTW Total Energy (Btu/mile) 6,900 5,900 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 9.7.6 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 9.7.6. The Effects of Grid Mix on Use of Primary Energy and Emissions from Central 

Coal with CCS–pipeline Delivery Pathway 

U.S. Average 

Grid Mix

“Green” 

Grid Mix

WTW GHG Emissions (g/mile) 170 70

WTW Fossil Energy (Btu/mile) 5,700 4,700

WTW Petroleum Energy (Btu/mile) 80 28

WTW Total Energy (Btu/mile) 5,900 5,200

Delivery Sensitivities

Pipeline delivery sensitivities are reported for the biomass production scenario in Section 

9.4.4. The effects of the sensitivities will be the same for all pipeline delivery scenarios.

9.7.5 Advanced Conversion and Delivery/Distribution Technology

For advanced technology analysis, parameters were changed to future projections. The 

“Future” H2A production case was used, and HDSAM was modified to include 

achievement of delivery targets as defined in the Hydrogen, Fuel Cells and Infrastructure 

Technologies (HFCIT) Multi-Year Program Plan (MYPP). The vehicle fuel economy 

was increased to 65 mpgge. In addition, the electricity grid mix was updated to match 

EIA’s projection for technology success in 2020 (51.1% coal, 19.2% natural gas, 18.5% 

nuclear, 1.9% residual oil, and 1.0% biomass, and 8.3% zero-carbon). 

WTW results from cases with those modifications are shown in Table 9.7.7. The results 

do not match those in Hydrogen Program Record 9002 (2009) because the H2A case with 

advanced technology has a larger electricity byproduct than the case used for the Program 
156

Record. Carbon dioxide and GHG emissions are negative because 50,400 Btu (14.8 

kWh) electricity is produced for every GGE hydrogen distributed, and that electricity 

displaces grid electricity with higher GHG emissions. Electricity displacement is also the 

reason why WTW natural gas and petroleum use are negative.

Table 9.7.7. Well-to-Wheels Results for central coal with CCS–pipeline pathway with 

advanced technology

Coal Input from "Well" 2330 Btu / mi

Natural Gas Input from "Well" -360 Btu / mi

Petroleum Input from "Well" -40 Btu / mi

Fossil Energy Input from "Well" 1900 Btu / mi

WTW CO2 Emissions -79 g / mi

WTW CH4 Emissions 0.21 g / mi

WTW N2O Emissions -0.002 g / mi

WTW GHG Emissions -74 g / mi

Levelized Cost of Hydrogen ($/kg) $3.53 2005 $/kg

Levelized Cost of Hydrogen ($/mi) $0.0543 2005 $/mi
157

10.0 Pathway Results Comparison

In this section, results from the individual pathways are compared. Each pathway’s 

current estimated levelized cost, WTW petroleum use, and WTW GHG emissions are 

shown for comparison to the other pathways, several crude oil-based transportation 

options, and ethanol as E85. The crude oil–based options are gasoline in a standard 

spark-ignition ICE; gasoline in a spark-ignition HEV; and diesel in a compressionignition direct-injection ICE. 

Fuel economies used for each option are shown in Table 10.0.1. GREET-default fuel 

economies and upstream parameters were used for the crude oil–based transportation 

options and E85 from corn grain. The gasoline ICE fuel economy is based on data 

presented by the Environmental Protection Agency (2005). The fuel economies for other, 

non-hydrogen vehicles are based on PSAT results (Elgowainy, 2009). The GREET yield 

for corn stover–based E85 was modified to 72.6 gal / dry ton to match the 2008 status in 

Table B-5 of the Biomass Program Plan (Office of the Biomass Program, 2009). Other 

key parameters are shown in Table 10.0.2. 

Table 10.0.1. Fuel Economies for Vehicle Options 

Vehicle Type Fuel Economy

Hydrogen FCV 45 mpgge

Gasoline ICE 23.2 mpg

Gasoline HEV 34.3 mpg

Diesel ICE 27.8 mpgge (equivalent to 30.8 mpg diesel)

E85 Flex-Fuel FCV 23.2 mpgge (equivalent to 16.4 mpg E85)

Table 10.0.2. Key Analysis Parameters

Parameter Value and Section with Description

Technology status Current technology (Section 2.2). Technology is described 

in Sections 6.0 and 7.0, and parameters are shown in the 

appendices.

City size 553 mi2 and 1,247,364 people (equivalent to Indianapolis, 

IN) (Section 2.2)

Market penetration 50% of hydrogen vehicles (Section 2.2)

Analysis boundaries Includes feedstock recovery, transportation, and storage; 

fuel production, transportation, storage, and distribution; 

and vehicle operation (Section 2.3)

Monetary value 2005 dollars (Section 8.0)

Equity financing 100% (Section 8.0)

After tax internal rate of 

return

10% (Section 8.0)

Effective total tax rate 38.9%

Carbon capture efficiency 

in coal with CCS case

90% (Section 9.7)
158

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Current Coal

Gasification

w/CCS -

Pipelines

Levelized Cost($/kg)

Losses Share ($/GGE)

Delivery Share ($/GGE)

Production Share ($/GGE)

Figure 10.0.1. Levelized cost of hydrogen for seven pathways

Figure 10.0.1 shows the levelized cost of hydrogen for all seven hydrogen pathways with 

the parameters described in Section 9 and referenced in Appendices A–G. Some of the 

most important parameters are shown in Table 10.0.2, and additional parameters are in 

sections 2–8. Sensitivities on parameters in each hydrogen pathway are reported in 

Section 9. 

The levelized cost of hydrogen is calculated directly in the H2A model for the distributed 

hydrogen production cases because the H2A distributed hydrogen production model 

includes the forecourt station capital and operating costs. For central production cases, 

the levelized cost of hydrogen is the sum of levelized production cost, levelized delivery 

cost, and the cost of excess production due to losses in delivery. 

The Program has set a hydrogen levelized cost target of $2.00–$3.00/gge delivered at the 

pump (Hydrogen, Fuel Cells and Infrastructure Technology Program, 2007), and the 

comparison in Figure 10.0.1 shows that the target has not been met. Niche opportunities 

with low-cost feed or capital costs, different financing options, or higher capacities may 

meet the target. Otherwise, additional research is necessary to meet them. Other analysts 

have used different parameters and reached slightly different levelized costs of hydrogen 

in their studies. One example of an analysis that showed that the $2.00–$3.00/gge 

levelized cost has been met for the distributed natural gas reforming pathway is Fletcher 
159

and Callaghan (2007). The primary difference between their analysis and this one is a 

lower cost for CSD (They estimated $0.88/kg, and the estimate in this study is $1.88/kg.).

Figure 10.0.2 shows a comparison hydrogen pathway energy use. Pathway energy 

includes only the energy used directly by the pathway. It differs from the WTW energy 

in that WTW energy includes upstream energy requirements. For example, while 

electricity is reported as a pathway energy source, the primary energy sources used to 

generate the electricity (coal, natural gas, etc.) are included in the WTW calculations. As 

expected, the dominant pathway energy source is the one named in the title of each 

pathway. 

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Current Coal

Gasification

w/CCS -

Pipelines

Pathway Energy Requirements (Btu / GGE)

Pathway Diesel Use (Btu / GGE)

Pathway Nat Gas Use (Btu / GGE)

Pathway Electricity Use (Btu / GGE)

Pathway Coal Use (Btu / GGE)

Pathway Biomass Use (Btu / GGE)

Figure 10.0.2. Pathway energy use for seven pathways 

The pathway efficiency can be considered the inverse of the energy use; Figure 10.0.3 

shows those efficiencies. The yellow bars show the production efficiencies that are 

calculated as the LHV of the hydrogen produced divided by the LHV of all the 

production inputs reported in Section 9. 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 10.0.2. 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. 
160

As an example, Figure 10.0.3 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 68% for the distributed natural gas reforming pathway. Some 

additional energy is required to produce and delivery the natural gas and electricity to the 

facility, so the WTP efficiency is lower yet at 58% for the distributed natural gas 

reforming pathway. 

The pathways with the highest efficiency are the natural gas pathways followed by 

electrolysis and coal, and those with the lowest efficiency are the biomass pathways. 

 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

Energy Efficiency (LHV basis)

Production Efficiency

Pathway Efficiency

Well-to-Pump Efficiency

Figure 10.0.3. WTW, pathway, and production efficiencies for seven hydrogen pathways, 

three crude oil–based fuel options, and two E85 options 

Figure 10.0.4 shows the WTW petroleum use for the seven hydrogen pathways, the three 

crude oil–based pathways, and two E85 pathways. Because the petroleum use is so high 

for the crude oil pathway, Figure 10.0.5 shows the WTW petroleum use for the seven 

hydrogen pathways alone. Most of the petroleum use is for electricity generation for the 

pathways’ grid electricity requirements (2.9% of the grid mix is electricity generated 

from residual oil.). The largest grid-electricity user is distributed electrolysis (requiring

55 kWh/kg H2 produced), and if the grid mix did not include residual oil, its WTW 

petroleum use would be reduced by 410 Btu/mile. 
161

0

1,000

2,000

3,000

4,000

5,000

6,000

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid

Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

WTW Petroleum Energy Use (Btu / mile)

Figure 10.0.4. WTW petroleum energy use for seven hydrogen pathways, three crude oil–

based fuel options, and two E85 options 
162

0

100

200

300

400

500

600

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid Trucks

Central

Biomass

Gasification -

Pipelines

Central Natural

Gas Reforming

- Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Current Coal

Gasification

w/CCS -

Pipelines

WTW Petroleum Energy Use (Btu / mile)

Figure 10.0.5. WTW petroleum energy use for seven hydrogen pathways

Figure 10.0.6 shows the comparative WTW GHG emissions for the seven pathways, the 

crude oil–based pathways, and two E85 pathways. Well-to-pump (WTP) emissions are 

colored green, and pump-to-wheels (i.e., tailpipe) emissions are colored blue. Hydrogen 

FCVs have no tailpipe GHG emissions because reacting hydrogen forms water. The corn 

stover E85 FFV pathway has negative WTP emissions because more carbon dioxide is 

removed from the atmosphere while the plants are growing than is released in growing 

the plants, harvesting and transporting the biomass, producing ethanol, and delivering 

ethanol. 

All the hydrogen pathways except distributed electrolysis have estimated GHG emissions 

lower than the crude oil options. The primary source (89%) 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 electrolysis requires 55 kWh electricity per kg H2 produced, and the current 

grid mix produces 800 g CO2 eq./kWh, so electricity generation is the primary emitter of 

its 980 g CO2 eq./mile traveled. In the biomass / liquid pathway, the GHGs removed 

from the atmosphere to grow biomass are essentially equivalent to the GHGs generated in 

producing hydrogen (see Section 9.3 for details). In that pathway, most of the net GHGs 

emitted (97%) are from liquefaction and transport of the liquid hydrogen. Likewise, in 

the biomass pipeline pathway, most of the net GHGs emitted (92%) are from electricity 

generation for CSD of the hydrogen. Central natural gas reforming generates GHGs in 

both hydrogen production and in CSD. All the GHGs emitted from the central 
163

electrolysis of wind electricity are from electricity generation for CSD, which is assumed 

to be purchased from the grid without wind energy credits. Fifty-five 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 remainder emitted 

during coal mining, transport and hydrogen CSD. 

 

-250

0

250

500

750

1,000

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid

Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

WTW GHG Emissions (g / mile)

Well-to-Pump Pump-to_Wheels

Net

Figure 10.0.6. WTW GHG emissions for seven hydrogen pathways, three crude oil–based 

fuel options, and two E85 options 

As seen in Figure 10.0.6, all the pathways except distributed electrolysis result in lower 

GHG emissions (on a g/mile basis) than a comparable ICE vehicle fueled by gasoline 

because of the increased efficiency fuel cells provide. Distributed electrolysis has both 

high GHG emissions and high petroleum use when compared to the other hydrogen 

pathways because of the 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 a slightly higher petroleum use than the natural gas pathways because 

petroleum-fueled rail is used to deliver coal to the hydrogen production facility and has

lower GHG emissions because of the efficient sequestration system that is assumed. The 

biomass cases have higher petroleum use than all but the distributed electrolysis pathway 

because the biomass is delivered using trucks. 
164

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 10.0.7 shows both. 

Central Natural Gas - 

Pipeline

Distributed Natural Gas

Central Coal - Pipeline

Distributed Electrolysis

Wind Electricity 

Electrolysis - Pipeline

Central Biomass - 

Pipeline

Central Biomass - Liquid 

Trucks

0

100

200

300

400

500

600

700

800

900

1,000

0 100 200 300 400 500 600

WTW Petroleum Energy Use (Btu / mile)

WTW Greenhouse Gas Emissions (g / mile)

Natural Gas

Coal

Grid Electricity

Wind Electricity

Biomass

Gasoline ICE

 5300 Btu/mile Petroleum Use

 480 g/mile GHG emissions

Gasoline Hybrid

 3600 Btu/mile Petroleum Use

 330 g/mile GHG emissions

Diesel ICE

 4500 Btu/mile Petroleum Use

 410 g/mile GHG emissions

Corn E85 Flex-Fuel ICE

 1700 Btu/mile Petroleum Use

 390 g/mile GHG emissions

Stover E85 Flex-Fuel ICE

 1700 Btu/mile Petroleum Use

 170 g/mile GHG emissions

Figure 10.0.7. Comparison of pathways’ petroleum use and GHG emissions

Figure 10.0.8 shows the levelized fuel cost per mile and the WTW GHG emissions. For 

comparison, it also shows the market price per mile and GHG emissions for gasoline and 

diesel vehicles. The levelized fuel cost was put onto a per-mile basis to simplify the 

comparison with other fuel/vehicle combinations that have different vehicle fuel 

economies. Ideally, the vehicle’s purchase, maintenance, and insurance costs would also 

be put onto a per-mile basis, and the totals would be summed; however, those values are 

outside the scope of this analysis. 

Gasoline, diesel, and corn-based E85 prices are based on projected market prices unlike 

the reported costs for hydrogen- and stover-based E85, which are based on calculated 

levelized costs. Projected market prices are used because they are available for 

technologies that are mature and commercialized. Levelized costs are not available for 

most of those technologies because capital and operating costs are separated for longterm commercial products with multiple improvements. For gasoline, the projected 

market price used in this analysis is $2.535/gal based on the 2009 high-energy case in the 

2007 Annual Energy Outlook (Energy Information Administration, 2007). The estimated 

taxes are $0.391/gal (Federal Highway Administration, 2009), so a tax-free price of 
165

$2.14/gal is used. For diesel, the reported market price is $2.536/gal (Energy Information 

Administration, 2007) with taxes of $0.452/gal (Federal Highway Administration, 2009), 

resulting in a tax-free price of $2.08/gal. The diesel price was converted to $1.88/gge 

using the lower heating values reported in GREET (Wang, 1999) because the vehicles’ 

fuel economy is on a gge basis. The corresponding projected crude oil prices that match 

the gasoline and diesel prices are $67.70/bbl for imported low-sulfur light crude oil and 

$60.71/bbl for imported crude oil (Energy Information Administration, 2007). The crude 

oil prices include delivery to refineries. Corn grain–based E85 is also based on the 2009 

high-energy case in the 2007 Annual Energy Outlook (Energy Information 

Administration, 2007). It is $2.505/gal ethanol and is reported to have 74% ethanol. 

Reduction by the gasoline tax of $0.391/gal and conversion to the common basis bring 

the price to $2.83/gge. 

Central Biomass - Liquid 

Trucks

Central Biomass - Pipelines

Central Coal - Pipeline

Distributed Electrolysis

Central Natural Gas - 

Pipeline

Distributed Natural Gas

Wind Electricity 

Electrolysis - Pipeline

Gasoline HEV

Gasoline ICE

Diesel

E85-Stover

E85-Corn

0

100

200

300

400

500

600

700

800

900

1,000

$0.000 $0.020 $0.040 $0.060 $0.080 $0.100 $0.120 $0.140 $0.160 $0.180

Levelized Cost of Hydrogen and Market Price of Gasoline, Diesel, and E85 ($ / mile without fuel taxes)

WTW Greenhouse Gas Emissions (g / mile)

Biomass

Coal

Grid Electricity

Natural Gas

Wind Electricity

Gasoline

Diesel

E85

Figure 10.0.8. Comparison of pathways’ levelized costs/market and GHG emissions

Figure 10.0.9 shows the levelized cost of hydrogen and the gasoline and diesel market 

prices on a per-mile-traveled basis with two possible levels of carbon taxation. The tops 

of the red bars indicate the wholesale, levelized costs including a $50/ton CO2-equivalent 

tax, and the tops of the yellow bars indicate the wholesale, levelized costs including a 

$100/ton CO2-equivalent tax. The tax 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. A $100/ton CO2 equivalent tax increases the per-mile levelized 

cost of hydrogen from electrolysis by 81%, the central and distributed natural gas cases 

by 40% and 43%, respectively, and all the other cases by less than 20%. 
166

$0.000

$0.050

$0.100

$0.150

$0.200

$0.250

$0.300

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification

- Liquid

Trucks

Central

Biomass

Gasification

- Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation)

- Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline

ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

Levelized Cost of Hydrogen and Market Price of Gasoline & Diesel ($ / mile 

without fuel taxes)

$100 / ton CO2 Eq Carbon Tax

$50 / ton CO2 eq Carbon Tax

$0 / ton CO2 eq Carbon Tax

Figure 10.0.9. Levelized costs/market prices with possible carbon taxes for seven 

hydrogen pathways, three crude oil–based fuel options, and two E85 options 
167

11.0 Analysis Gaps

FPITT of the FreedomCAR and Fuel Partnership is composed of representatives of four 

energy companies (ConocoPhillips, ExxonMobil, Chevron, and Shell), NREL, and the 

Hydrogen Systems Analyst of the U.S. Department of Energy. The energy company 

representatives on this team have conducted peer reviews of the hydrogen pathway 

analyses with the intention of identifying gaps in the analysis and opportunities for 

additional analysis. Some of the gaps that were identified have been addressed in 

analyses performed to date, and the results are incorporated in this report. Some gaps, 

however, have not yet been addressed or are beyond the scope of this effort; these gaps 

are noted below. 

All Pathways

• One gap that was identified was the lack of consensus on the amount of hydrogen 

storage required at the forecourt site. Since identification of this gap, considerable

effort has been directed toward understanding the on-site hydrogen storage needs for 

forecourt hydrogen stations. The amount of on-site storage assumed in this study for 

the distributed hydrogen production cases is 797 kg H2 (62% of the design 

distribution capacity of the station). For the central hydrogen production pathways 

with gaseous hydrogen delivery via pipeline, on-site storage is assumed to be 1,052 

kg H2 (69% of the design distribution capacity of the station). For the central 

biomass–liquid truck delivery pathway, on-site storage is assumed to be 6,920 kg 

liquid H2 plus 453 kg gaseous H2 (486% of the design distribution capacity of the 

station).

• Additional analysis is needed to determine the ideal size and siting of hydrogen 

distribution stations.

• The on-board storage pressure for all the analyses in this report is 5,000 psi, which 

requires a pressure at distribution of 6,250 psi. Some organizations are considering 

on-board storage of compressed hydrogen at 10,000 psi and are interested in the 

effect of higher pressure on pathway cost, energy use, and emissions. 

• The tradeoffs between hydrogen quality and fuel cell performance (i.e., durability, 

reliability, and efficiency) are not well understood. 

Distributed Natural Gas and Distributed Electrolysis Pathways

• 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 less-than-full-time need 

to be understood, and a study over 8,760 hours/year is needed. 

• The cascade storage volumes may need to be different for distributed production than 

for central production cases. The necessary volumes need more investigation. 
168

All Centralized Production Pathways

• Hydrogen losses during both pipeline and liquid hydrogen delivery as estimated by 

HDSAM appear to be higher than those for natural gas delivery and may be higher 

than actual losses. Additional analysis is necessary to determine if the loss estimates 

are appropriate.

• Caverns may not be available in most locations for hydrogen storage; thus, alternative 

options for storing volumes of hydrogen necessary for seasonal variations, including 

storage as a liquid, need to be identified and characterized. The potential storage 

capacity for hydrogen should be compared to that for the current natural gas 

infrastructure.

• 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.

• The contribution of hydrogen distribution (service) pipelines to the cost of hydrogen 

is uncertain. The sensitivity of the hydrogen cost to the length of the distribution 

pipelines should be examined. 

• 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. 

Central Biomass Pathways 

• 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 

woody biomass. Empirical kinetic models on biomass gasification exist and may be 

used. 

• The accuracy of the GREET default value for CO2 emissions from gasification of 

woody biomass needs to be determined. 

• There does not appear to be consensus in the scientific community on the best way to 

determine and communicate CO2 emissions/absorption resulting from biomass 

production. Thus, this analysis does not include representation of the emissions from 

biomass production. 

• The low-pressure gasifier currently used in the analysis may not be the optimal 

technology for hydrogen production. The results may be significantly different if a 

high-pressure gasifier is used because a high-pressure gasifier may increase 

conversion efficiency enough to overcome additional capital costs. A better 

understanding of the optimal gasifier technology for hydrogen production from 

biomass is needed. 

• The effects of land use changes are not captured in this analysis. 

• The land area required to support a specific size of gasifier needs to be calculated to 

determine if biomass transportation distance is a constraint to hydrogen production 

plant size. Road capacity is a potential constraint as well. While corn can be barged 

to some ethanol plants sited on rivers, not all crops and/or geographies will be 
169

amenable to large-scale import of biomass feedstock. A statistical analysis is needed 

to evaluate the sensitivity of the hydrogen cost to transport distance. 

• Using trucks to deliver biomass requires more petroleum than other potential options. 

Investigations of smaller conversion facilities, distributed gasification facilities with 

centralized hydrogen production and purification, and other conversion technologies 

(e.g., cold pyrolysis) are warranted. 

• The sensitivity of the biomass/pipeline and biomass/truck pathway costs to power 

purchase prices should be examined. Producing power on-site using biomass 

feedstock would reduce the requirement for natural gas and electricity, as well as 

GHG emissions, to the extent that sufficient biomass is available at a viable cost. It 

may be worthwhile to configure the model to represent power production from 

biomass for internal gasification plant use (including liquefaction). 

Central Natural Gas Pathway

• Natural gas costs may be different for central natural gas reforming facilities than for 

distributed reforming facilities. These costs should be compared. The cost of natural 

gas for the central natural gas pathway should also be compared to the price that 

utilities pay for natural gas at power plants.

Central Electrolysis Using Wind-Generated Electricity

• The actual price of wind-generated electricity is time-dependent and different than a 

grid-electricity price. This analysis used a single price of electricity that matched the 

grid price. Using the time-dependent price is a gap in this analysis. 

• This analysis was 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 were not included 

in this analysis.

Central Coal with CCS Pathway

• The availability of carbon sequestration sites and the cost of monitoring at and 

upkeep of those sites were not included in this analysis. A single cost for 

sequestration was included. 
170

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176

Appendix A — Distributed Natural Gas Supporting Tables 

and Figures

Table A.1. Worldwide Distributed SMR Hydrogen Fueling Stations 

Location Name Date Opened

Auburn, CA PG&E Service Center and Division Office 2004

Chino, CA Kia-Hyundai America Technical Center 2006

Oakland, CA AC Transit Oakland 2005

Torrance, CA Honda Home Energy 2003

Orlando, FL Orlando International Airport 2006

Selfridge, MI Selfridge Air National Guard Base (Chevron) 2007

Las Vegas, NV Las Vegas Energy Station 2002

Latham, NY Home Energy Station 2004

Topton, PA East Penn Manufacturing Distribution Center 2007

Austin, TX University of Texas 2007

Perth, Australia Sustainable Transport Energy for Perth 2004

Berlin, Germany Second Clean Energy Partnership Project 2006

Stuttgart, Germany CUTE Bus Demonstration 2003

Mantova, Italy AGIP MultiEnergy Public Service Station 2007

Milan, Italy Milan-Bicocca Project 2004

Nagoya, Japan Central Japan International Airport 2006

Osaka, Japan WE-NET Hydrogen Refueling Station 2002

Senju, Japan Senju Hydrogen Station 2002

Takamatsu, Japan WE-NET Hydrogen Refueling Station 2002

Tokai, Japan Toho Gas Research Laboratory 2002

Stavanger, Norway HyNor Stavangar Hydrogen Station 2006

Porto, Portugal CUTE Bus Demonstration 2003

Daejeon, S. Korea Korean Gas Technology Corporation 2006

Madrid, Spain CUTE Bus Demonstration 2003
Distributed Hydrogen Production

00

11,000 Btu Electricity Hydrogen Gas

159,000 Btu Natural Gas 116,000 Btu

00

0

54,000 Btu Energy Lost

Case DefinitionYear: 2005Hydrogen as GasForecourt Production

58% Natural Gas Feedstock

Sequestration: NoTransport for Delivery: NoneVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

Production Process Energy Efficiency 71%WTP Efficiency

Levelized Cost of H2 at Pump ($/kg) 3.50Well-to-Wheels Total Energy Use (Btu/mile) 4,432Well-to-Wheels Petroleum Energy Use (Btu/mile) 45Well-to-Wheels Greenhouse Gas Emissions (g/mile)

305

Pathway Efficiency 68%WTP Emissions (lb CO2 Equivalent / GGE fuel available): 

30

Distributed Production

Storage and 

Compression for 

Dispensing

177
NG Delivery Pressure Average of gas companies

NG Quality at Delivery Average of gas companies

NG Recovery Efficiency 97.2%

NG emitted & combusted during recovery 0.35%

NG processing energy efficiency 97.2% NG Cost $0.243 2005 $ / Nm^3

NG emitted & combusted during processin 0.15% NG Cost $0.907 2005$ / kg H2 distributed

NG emitted & combusted during transport 0.14 g / MMBtu

NG transport distance 500 miles WTG CO2 Emissions 636 g / 116000Btu to Pump

Coal Input from "Well" 322 Btu / 116000Btu to Pump WTG CH4 Emissions 28 g / 116000Btu to Pump

Natural Gas Input from "Well" 124,113 Btu / 116000Btu to Pump Compression Reqs (stages & eff) average of gas companies WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 497 Btu / 116000Btu to Pump WTG GHG Emissions 1,331 g CO2 eq./ 116000 Btu

Natural Gas consumption 4.5 N m^3/kg H2 produced Hydrogen Output Pressure 300 psi

Electricity consumption 1.11 kWh / kg H2 Hydrogen Outlet Quality 1

Process Water Consumption 5.77 L / kg H2

Electricity price $0.0816 2005 $/kWh Design Capacity 1,500 kg/day Total capital investment $2.44 2005$ / annual kg H2 (effective

Capacity factor 85% Electricity cost $0.09 2005$ / kg H2 produced

Process energy efficiency 71.3% Other operating costs $0.36 2005$ / kg H2 produced

Total Capital Investment $1,138,995 2005$ Electricity Mix US Mix Levelized Cost of Prod (excl feedst $0.71 2005$ / kg H2 distributed

After-tax IRR 10%

Assumed Plant Life 20 years

SMR CO2 Emissions 10,523 g / 116000Btu to Pump

Coal Input from "Well" 6,572 Btu / 116000Btu to Pump SMR CH4 Emissions 11 g / 116000Btu to Pump

Natural Gas Input from "Well" 47,754 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 664 Btu / 116000Btu to Pump SMR GHG Emissions 10,815 g CO2 eq./ 116000 Btu

Electricity consumption 1.96 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $8.56 2005$ / annual kg H2 (effective

Number of Distribution Stations 270 Electricity cost $0.16 2005$ / kg H2

Total Capital Investment $3,993,763 2005$ Energy efficiency 94%

Number of Compression Stages 6 Levelized Cost of Distribution $1.88 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 62% capacity CSD CO2 Emissions 1,502 g / 116000Btu to Pump

Coal Input from "Well" 11,382 Btu / 116000Btu to Pump CSD CH4 Emissions 2 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,269 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 848 Btu / 116000Btu to Pump CSD GHG Emissions 1,558 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 18,276 Btu / 116000 Btu

Natural Gas Input from "Well" 175,136 Btu / 116000 Btu

Petroleum Input from "Well" 2,009 Btu / 116000 Btu

Fossil Energy Input from "Well" 195,421 Btu / 116000 Btu

WTP CO2 Emissions 12,667 g / 116000 Btu

WTP CH4 Emissions 41 g / 116000 Btu

WTP N2O Emissions 0 g / 116000 Btu

WTP GHG Emissions 13,710 116000 Btu

Levelized Cost of Hydrogen ($/kg) $3.50 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 406 Btu / mi

Natural Gas Input from "Well" 3,895 Btu / mi

Petroleum Input from "Well" 45 Btu / mi

Fossil Energy Input from "Well" 4,346 Btu / mi

WTW CO2 Emissions 282 g / mi

WTW CH4 Emissions 1 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 305 g / mi

Levelized Cost of Hydrogen ($/mi) $0.0777 2005 $/mi

Inputs Outputs

Vehicle

NG Recovery, Processing, & Transport

Graphic Depiction & Assumptions

Hydrogen Production

Compression, Storage, & Dispensing

Dist-SMR Pathway Details R090219C 090817 v09.xls

178
Conversion Distribution

Coal 6,572 Btu/116000 Btu Coal 11,382 Btu/116000 Btu

Natural Gas 47,754 Btu/116000 Btu Natural Gas 3,269 Btu/116000 Btu

Petroleum 664 Btu/116000 Btu Petroleum 848 Btu/116000 Btu

Total Energy 56,381 Btu/116000 Btu Total Energy 17,910 Btu/116000 Btu

CO2 Emissions 10,523 g/116000 Btu CO2 Emissions 1,502 g/116000 Btu

CH4 Emissions 11 g/116000 Btu CH4 Emissions 2 g/116000 Btu

N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu

GHG Emissions 10,815 g/116000 Btu GHG Emissions 1,558 g/116000 Btu

Feedstock Total to Deliver 11

Coal 322 Btu/116000 Btu Coal 18,

Natural Gas 124,113 Btu/116000 Btu Natural Gas 175,

Petroleum 497 Btu/116000 Btu Conversion Compression, Storage, & Dist Petroleum 2,

Total Energy 124,998 Btu/116000 Btu Total Energy 199,

CO2 Emissions 636 g/116000 Btu Distribution Losses 0.00% CO2 Emissions 12,

CH4 Emissions 28 g/116000 Btu CH4 Emissions 

N2O Emissions 0 g/116000 Btu N2O Emissions 

GHG Emissions 1,331 g/116000 Btu GHG Emissions 13,

Dist-SMR Pathway Details R090219C 090817 v09.xls

179
Parameter Value Units Reference Comments

Case Definition

Base Year 2005 None Default for Dist-SMR Pathway studyProduction Technology Woody Biomass None Default for Dist-SMR Pathway studyForm of H2 During Delivery Liquid None Default for Dist-SMR Pathway studyDelivery Mode Liquid Truck None Default for Dist-SMR Pathway studyForecourt Station Size 1278 kg/day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas basis version 2.0

Vehicle Type passenger cars None Default for Dist-SMR Pathway studyVehicles' Fuel Economy 45.0 mile / gge

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles. Argonne National Laboroatory presentation, Chicago, IL. Retreived from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel economy for todaPowertrain Simulation Analysis Toolkit V 6.2 SP1, Summer 2008 (Phttp://www.transportation.anl.gov/modeling_simulation/PSAT/index.economy which was determined by multiplying the projected EPA la

Market Definition

City Population 1,247,364 people Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN, cell B9

Market penetration 50% (% vehicles in city) U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Pla . Basis for posture plan

Number of H2 vehicles in city 462,772 H2 vehicles / city Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Demand calculation by HDSAM version 2.02; Scenario tab; Number 

Miles driven per vehicle 12,000 mile / vehicle year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Key delivery input in HDSAM version 2.02; Scenario tab; Miles drive

City hydrogen use 344,451 kg / d Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; City H2 

Number of H2 refueling stations in city 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Number Number of H2 stations/Number of gasoline stations 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Number Average distance between stations (mi) 1.46 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Average 

Feedstock Recovery, Processing, & Transport

Biomass

Percentage of Woody Biomass (Remainder is Herbaceous) 100%

Mann, M & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory

Current central H2A production via biomass gasification version 2.1

Biomass Moisture Content 25% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. Page 66

Grams of Nitrogen / short ton biomass 709

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

Equivalent to 75 lb N / ac in the maintenance year Year 3 or 4) whicassuming 6 dry tons biomass per acre, and harvesting once every 8 used for traditional crops.

Grams of P2O5 / short ton biomass 189 g / dry ton M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998). Equivalent to 20 lb P / ac in the maintenance year (Year 3) which is 

Ugarte, 2003, App 3.1, assuming 6 dry tons biomass per acre and h

Grams of K2O / short ton biomass 331 g / dry ton M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998). Equivalent to 35 lb K / ac in the maintenance year (Year 3) which is 

Ugarte, 2003, App 3.1, assuming 6 dry tons biomass per acre and h

Grams of herbicide / short ton biomass 24

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

Equivalent to 2.0 lb herbicide / ac in the planting year which similar tUgarte, 2000, App 3.2, assuming 6 dry tons biomass per acre and hTrifluralin (5 L/ha) and Metribuzin (395 g/ha). App 3.2 is for planting used for pasture.

Grams of insecticide / short ton biomass 2

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

As a check, looked at Chastagner: Up to 56% of acreage annually sacre); up to 56% of acreage annually sprayed with Permethrin 2LB (annually sprayed with Endosulfan 3 EC (24c WA-990025, 2 qts per 

Grams of CO2 removed from atmosphere per dry ton woody biomass produced -112,500 g / dry ton GREET model default based on ANL personal communications

Average distance from farm to hydrogen production facility 40 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET basis: distance could be limited by transport costs?

Natural Gas

NG recovery efficiency 97.2% Wang, 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% which is comparable to several other models (Ta

NG used & lost during recovery 0.35% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET basisNG processing energy efficiency 97.2% Wang, 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 (TNG used & lost during processing 0.15%

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pd

Volume lost from EPA/GRI paper and DOE/EIA-0573; future marginaverage.

NG used & lost during transport 0.14

g / (MM Btu mil)

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pd

Volume lost from EPA/GRI paper and DOE/EIA-0573; future marginaverage.

NG transport distance 500 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET basis

Electricity

Grid mix for production US Mix Default

Biomass Fraction

1.2%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Coal Fraction

51.7%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Natural Gas Fraction

15.7%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Nuclear Fraction

20.3%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Residual Oil Fraction

2.9%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Bio-Liquid Pathway Details R090219B 090818 v09.xls

180
Parameter Value Units Reference Comments

Others (Carbon Neutral)

8.2%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & Dfrom total generation values reported with all renewables except biocategory 

Grid mix for liquefaction with biomass production US Mix None Default for Bio-Liquid Pathway studyGrid mix for liquefaction with coal production US Mix None Default for Bio-Liquid Pathway studyGrid mix for liquefaction with central natural gas production NGCC None Default for Bio-Liquid Pathway studyGrid mix for liquefaction with nuclear production Nuclear Power None Default for Bio-Liquid Pathway studyGrid mix for pipeline compressors US Mix None Default for Bio-Liquid Pathway study

Grid mix for compression at distribution US Mix None Default for Bio-Liquid Pathway study

H2 Production

CO2 Captured for Sequestration 0% Not available in this case study

Production Facility Average Output 139,712 kg / facility d (after capacity factor is included)

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 3.0. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Design feed rate for current design plant of 2000 bone dry metric ton

Corresponding capacity factor 90%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; Icell C21

Total Capital Investment $154,644,297 2005 $

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 10. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Total installed capital cost of $102M ($2002) (see Table 10, Current for additional compression was removed to maintain consistency wit

Biomass feedstock consumption 12.8 kg (dry) / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Biomass usage calculated from plant efficiency of 45.6%. The LHV f(8406 Btu/lb v. 8060 Btu/lb) than used in Spath. Appendix A - Desigdry US ton feedstock

Biomass feedstock cost $37.96 2005$ / dry short ton

Hess, R., Denney, K., Wright, C., Radtke, C., Perlack, W. (2007, April 18-19). Cellulosic Biomass Feedstocks for Renewable Bioenergy. EERE presentation to the National Academy of Sciences Commettee on Resource Needs for Fuel Cell and Hydrogen, Washington, D.C. 

Feedstock price is taken from the Biomass Program 2012 Target pr

Natural gas feedstock consumption 0.00 normal m^3 / kg H2 produced

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; R

Natural Gas feedstock cost N/A None N/ANatural Gas LHV 34,714 Btu / normal m^3. Hydrogen Analysis Resource Center. (2008, September 5). Lower and Higher Heating Values of Hydrogen and Fuels. Retrieved from http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/401 LHV of Natural Gas; 983 Btu/ft3Natural gas utility consumption 0.17 normal m^3 / kg H2 produced

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Natural gas usage from overall energy balance; Appendix C, A401: 424 = 14260 lb/hr; conversion vields 0.15 (not 0.17)

Natural gas utility price $0.340 2005$ / Nm^3 Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. AEO 2005 High A Case - Commercial price; Escalated from 2003 do

http://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls) 

Natural gas utility pressure N/A kPa None Not in H2A or GREET

#VALUE! psi Conversion calculation conversion calculation

Electricity feedstock consumption 0.00

kWh / kg H2

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; R

Electricity utility consumption (both production and compression) 0.98

kWh / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Electricity usage from overall energy balance with energy usage for A, Total Plant Electricity = 5.54 kWh/kg H2 - 

Electricity utility consumption (production only) 0.98

kWh / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Electricity usage from overall energy balance with energy usage for A, Total Plant Electricity = 5.54 kWh/kg H2. Electricity consumption at 360 psi and H2A's standard is 300 psi.

Electricity Utility Price 0.0555

2005 $/kWh

Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy.

AEO 2005 High A Case - Industrial price; Escalated from 2003 dollahttp://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls) 

Process Water Consumption

1.32

gal / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Appendix C, A202: stream 218 = 738 lb/hr; Appendix C, A601: strea= 131921 lb/hr

Water Consumption for Cooling

0.00008

gal / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Assume all make-up water is process water

Electricity co-product production 0.00 kWh / kg H2 None All electricity co-product used internallyOxygen co-product production 0.0 kg / kg H2 None N/ASteam co-product production 0.0 kg / kg H2 None N/A

Total Annual Fixed Operating Costs $10,391,486 2005$ / yr

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 9.2. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Section 9.2 Fixed Operating Costs. Costs were escalated from $20

Total Annual Variable Operating Costs $43,162,900 2005$ / yr

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 13. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Table 13: Variable Operating Costs. Costs were escalated from $20

Total Annual Operating Costs $53,554,386 2005$ / yr None Addtion of Annual Total Fixed Operating Costs and Total Annual Va

Production energy efficiency (does not include electricity for forecourt compress 46.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - biomass 93.1% Calculated from H2A values Calculated from H2A values

Share of process fuel - coal 0.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - natural gas 2.5% Calculated from H2A values Calculated from H2A values

Share of process fuel - ethanol 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - electricity 4.4% Calculated from H2A values Calculated from H2A values

Bio-Liquid Pathway Details R090219B 090818 v09.xls

181
Parameter Value Units Reference Comments

Hydrogen outlet pressure (before CSD) 300

psi

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Final compression step modeled in the analysis was removed for the default value. Spath's compression was to 360 psi and H2A standaelectricity use.

Hydrogen quality before transport 98 minimum

% H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Page 5, product purity of 99.9 vol%

Financial Parameters

After-tax Real IRR 10%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

Plant Life 40

years

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

Federal Tax Rate 35.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

State Tax Rate 6.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

Total Tax Rate 38.9%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

Frection Equity 100%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty

Current central H2A production from biomass basis version 2.1.2; I

Transport, Delivery, and Storage Energy Requirements

Liquid Truck Delivery

Hydrogen entering liquefaction 382,396 kg / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input parameters: city se

Liquefaction electricity requirement 1,136,394,945

kW hr / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Sections 2.2.7.3 and 2.2.7.5. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland (Nexant Repor

Liquefaction electricity requirement 8.2 kW hr / kg H2 None Calculation

Hydrogen lost in liquefier 0.5%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.7.2. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland (Nexant Repor

Liquefaction efficiency 80.3%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.7.2. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (Ne

Liquefaction System total capital investment $559,414,686

2005$

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.7.4. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (Ne

Liquefaction System electricity cost $60,690,228

2005$ / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.7.4. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (Ne

Liquefaction System labor cost $592,895

2005$ / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Liquefaction System total operating cost $83,647,930 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, H2 Liquifer tab, cell B135: sum of 

fixed costs

Terminal Storage Design Capacity 3,532,139 kg H2 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B73: bHydrogen lost in terminal 2.8%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction witNREL (Nexant Report- Section 2.2.14)

Terminal total capital investment $191,649,060

2005$

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.11.1. DE-FG36-05GO15032.

CB&I (Nexant Report - Section 2.2.11.1)

Terminal electricity cost $565,492 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B187: 

Terminal labor cost $588,708

2005$ / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Terminal total operating cost $8,842,213 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B201: 

other fixed costs

Truck Payload leaving terminal 4,372

kg / truckload

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.1.8. DE-FG36-05GO15032.

HDSAM calculation; default value (Nexant Report- Section 2.1.8)

Truck Trips 31,009 per year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B66

efficiency(H2out/H2 in) / H2 delivered per trip (kg)

One-way distance per trip 49 miles / trip (one way) Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B39Diesel for Truck Trips 3,837

m^3 / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.1.8. DE-FG36-05GO15032.

HDSAM calculation, fuel consumption data from Nexant in conjuctioand NREL (Nexant Report - Section 2.1.8)

Hydrogen Losses during loading / transport / unloading 6.1%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction witNREL (Nexant Report- Section 2.2.14)

Hydrogen Losses during liquefaction/loading / transport / unloading 10.08%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction witNREL (Nexant Report- Section 2.2.14)

Truck/trailer total capital investment $49,000,000

2005$

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report. DE-FG36-05GO15032.

$625,000 per each tank trailer and $75,00 per each truck cab; recomLiquide, GTI, Chevron, TIAX, ANL, PNNL and NREL

Truck/trailer electricity cost $0 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation, electricity prices are from EIA AEO 2005 and 2

Bio-Liquid Pathway Details R090219B 090818 v09.xls

182
Parameter Value Units Reference Comments

Truck/trailer Diesel cost $1,692,270 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B116

AEO 2005 and 2007

Truck/trailer labor cost $15,193,193

2005$ / yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Truck/trailer total operating cost $21,691,089 2005$ / yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B137

fixed costs

Distribution Station

Liquid Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input: dispensing rate

Electricity Required by Forecourt Station 116,673 kWh / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on pump power requiremenDesign Capacity 1,516

kg H2 / day

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.1.4. DE-FG36-05GO15032.

HDSAM calculation based on Chevron fueling profiles (Nexant Reposurge)*(1+Friday surge)

Operating Capacity 1,278 kg H2 / day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas basis version 2.0

Capacity Factor 84% None Calculation

Site storage (liquid) 6,920

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.11.2. DE-FG36-05GO15032.

HDSAM calculation based on number of deliveries per day (Nexant 

Site storage (gaseous) 453

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.3.2.4. DE-FG36-05GO15032.

HDSAM calculation (Nexant Report - Section 2.3.2.4)

Site storage 486% % of design H2 distribution None Calculation

Dispensing Pressure 6,250

psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.3.2. DE-FG36-05GO15032.

HDSAM default (see Nexant Report-Section 2.3.2)

Hydrogen Losses due to leaks 1.34%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction witNREL (Nexant Report - Section 2.2.14)

Distribution System total capital investment $2,073,185

2005$ / station

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.4.2. DE-FG36-05GO15032.

Data from CP Industries, McMaster-Carr, Bechtel, Nexant manufact

Section 2.2.4.2)

Distribution System electricity cost $9,512

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.4.2. DE-FG36-05GO15032.

Data from CP Industries, McMaster-Carr, Bechtel, Nexant manufact

Section 2.2.4.2)

Distribution Labor Required 3,951

hr / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

HDSAM calculation (Nexant Report -Section 2.2.1.3)

Distribution System labor cost $39,513

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Distribution System total O&M cost $189,192

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results. Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM calculations (Nexant Report - Section 2.2.1.2)

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Pla . Basis for posture plan

Type of Oxygenate in RFG None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Pla . Basis for posture plan

O2 Content in RFG 0% wt % U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Pla . Basis for posture plan

Ratio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, page 197: vehicles within the same weight class haRatio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:well-known fuel cell emissions (no PM2.5)

Ratio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:reasonable to assume FCV has same driving patter

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Pla . Basis for posture plan

Results

Levelized Cost $4.88 $ / kg Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 100 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

Bio-Liquid Pathway Details R090219B 090818 v09.xls

183
Parameter Value Units Reference Comments

WTW Natural Gas Input 3,911 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Petroleum Input 249 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 2,044 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 8,170 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 151 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 160 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

Bio-Liquid Pathway Details R090219B 090818 v09.xls

184
185

Appendix B — Distributed Electrolysis Supporting Tables 

and Figures
Distributed Hydrogen Production

00

192,000 Btu Electricity Hydrogen Gas

0 116,000 Btu00

0

76,000 Btu Energy Lost

Case DefinitionYear: 2005Hydrogen as GasForecourt Production

23% Electrolysis Feedstock

Sequestration: NoTransport for Delivery: NoneVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

Production Process Energy Efficiency 62%WTP Efficiency

Levelized Cost of H2 at Pump ($/kg) 6.05Well-to-Wheels Total Energy Use (Btu/mile) 11,310Well-to-Wheels Petroleum Energy Use (Btu/mile) 536Well-to-Wheels Greenhouse Gas Emissions (g/mile)

984

Pathway Efficiency 60%WTP Emissions (lb CO2 Equivalent / GGE fuel available): 

98

Distributed Production

Storage and 

Compression for 

Dispensing

186
Grid Mix

Biomass Fraction 1.20% Electricity Cost $0.055 2005 $ / kWh

Coal Fraction 51.70% Electricity Cost $2.804 2005$ / kg H2 distributed

Natural Gas Fraction 15.70%

Nuclear Fraction 20.30% WTG CO2 Emissions 41,009 g / 116000Btu to Pump

Coal Input from "Well" 310,710 Btu / 116000Btu to Pump Residual Oil Fraction 2.90% WTG CH4 Emissions 54 g / 116000Btu to Pump

Natural Gas Input from "Well" 89,250 Btu / 116000Btu to Pump Others (Carbon Neutral) 8.20% WTG N2O Emissions 1 g / 116000Btu to Pump

Petroleum Input from "Well" 23,152 Btu / 116000Btu to Pump WTG GHG Emissions 42,520 g CO2 eq./ 116000 Btu

Natural Gas consumption 0.0 N m^3/kg H2 produced Hydrogen Output Pressure 435 psi

Electricity consumption 53.48 kWh / kg H2 Hydrogen Outlet Quality 1

Process Water Consumption 2.94 L / kg H2

Design Capacity 1,500 kg/day Total capital investment $5.87 2005$ / annual kg H2 (effective

Capacity factor 85% Other operating costs $0.60 2005$ / kg H2 produced

Process energy efficiency 62.3% Levelized Cost of Prod (excl feedst $1.42 2005$ / kg H2 distributed

Total Capital Investment $2,738,292 2005$ After-tax IRR 10%

Assumed Plant Life 20

SMR CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump SMR CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump SMR GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption 1.73 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $8.55 2005$ / annual kg H2 (effective

Number of Distribution Stations 270 Electricity cost $0.10 2005$ / kg H2

Total Capital Investment $3,989,011 2005$ Energy efficiency 95%

Number of Compression Stages 5 Levelized Cost of Distribution $1.82 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 62% capacity CSD CO2 Emissions 1,647 g / 116000Btu to Pump

Coal Input from "Well" 12,477 Btu / 116000Btu to Pump CSD CH4 Emissions 2 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,584 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 930 Btu / 116000Btu to Pump CSD GHG Emissions 1,707 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 323,186 Btu / 116000 Btu

Natural Gas Input from "Well" 92,834 Btu / 116000 Btu

Petroleum Input from "Well" 24,082 Btu / 116000 Btu

Fossil Energy Input from "Well" 440,102 Btu / 116000 Btu

WTP CO2 Emissions 42,684 g / 116000 Btu

WTP CH4 Emissions 56 g / 116000 Btu

WTP N2O Emissions 1 g / 116000 Btu

WTP GHG Emissions 44,256 116000 Btu

Levelized Cost of Hydrogen ($/kg) $6.05 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 7,187 Btu / mi

Natural Gas Input from "Well" 2,065 Btu / mi

Petroleum Input from "Well" 536 Btu / mi

Fossil Energy Input from "Well" 9,788 Btu / mi

WTW CO2 Emissions 949 g / mi

WTW CH4 Emissions 1 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 984 g / mi

Levelized Cost of Hydrogen ($/mi) $0.1344 2005 $/mi

Inputs Outputs

Vehicle

Electrolysis Electricity Generation & Transport

Graphic Depiction & Assumptions

Hydrogen Production

Compression, Storage, & Dispensing

Includes Resource Recovery, Processing, & Transport

Dist-Elec Pathway Details R090304D 090827 v10.xls

187
Distribution

Coal 12,477 Btu/116000 Btu

Natural Gas 3,584 Btu/116000 Btu

Petroleum 930 Btu/116000 Btu

Total Energy 19,633 Btu/116000 Btu

CO2 Emissions 1,647 g/116000 Btu

CH4 Emissions 2 g/116000 Btu

N2O Emissions 0 g/116000 Btu

GHG Emissions 1,707 g/116000 Btu

Feedstock Total to Deliver 11

Coal 310,710 Btu/116000 Btu Coal 323,

Natural Gas 89,250 Btu/116000 Btu Natural Gas 92,

Petroleum 23,152 Btu/116000 Btu Conversion Compression, Storage, & Dist Petroleum 24,

Total Energy 488,927 Btu/116000 Btu Total Energy 508,

CO2 Emissions 41,009 g/116000 Btu Distribution Losses 0.00% CO2 Emissions 42,

CH4 Emissions 54 g/116000 Btu CH4 Emissions 

N2O Emissions 1 g/116000 Btu N2O Emissions 

GHG Emissions 42,520 g/116000 Btu GHG Emissions 44,

Dist-Elec Pathway Details R090304D 090827 v10.xls

188
Parameter Value Units

Referenced 

Value Reference Comment

Case Definition

Base Year 2005 2005 None Default for Dist-Elec Pathway study

Production Technology Electrolysis Woody Biomass None Default for Dist-Elec Pathway study

Form of H2 During Delivery Gas Gas None Default for Dist-Elec Pathway study

Delivery Mode None Pipeline None Default for Dist-Elec Pathway studyForecourt Station Size 1278 kg/day 1278 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versi

C23

Vehicle Type passenger cars passenger cars None Default for Dist-Elec Pathway studyVehicles' Fuel Economy 45.0 mile / gge 45.0

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles. Argonne National Laboroatory presentation, Chicago, IL. Retreived

from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel economy for todPowertrain Simulation Analysis Toolkit V 6.2 SP1, Summer 2008 (Phttp://www.transportation.anl.gov/modeling_simulation/PSAT/indexeconomy which was determined by multiplying the projected EPA l

Market Definition

City Population 1,247,364 people 1,247,364 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN, cell B9

Market penetration 50% (% vehicles in city) 50% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Number of H2 vehicles in city 462,772 H2 vehicles / city 462,772 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Numbe

Miles driven per vehicle 12,000 mile / vehicle year 12,000 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Key delivery input in HDSAM version 2.02; Scenario tab; Miles drivCity hydrogen use 344,451 kg / d 344,451 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; City H2 Number of H2 refueling stations in city 270 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumbeNumber of H2 stations/Number of gasoline stations 41% 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumbeAverage distance between stations (mi) 1.46 miles 1.46 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Averag

Feedstock Recovery, Processing, & Transport

Electricity

Grid mix for production US Mix US Mix None Default for Dist-Elec Pathway study

Biomass Fraction

1.2% 1.2%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Coal Fraction

51.7% 51.7%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Natural Gas Fraction

15.7% 15.7%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Nuclear Fraction

20.3% 20.3%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Residual Oil Fraction

2.9% 2.9%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Others (Carbon Neutral)

8.2% 8.2%

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.htm

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

H2 Production

Production Facility Average Output 1,278 kg / facility d (after capacity factor is included) 1,278

Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. And Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options 

Analysis Results. Interim Report Section 2.1.5. DE-FG36-05GO15032

Current forecourt H2A production from grid electrolysis basis versioC23. Calculated based on 1500kg/day and capacity factor; Nexant forecourt is linked, so daily production related to daily dispensing p

Corresponding capacity factor 85% 85% Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versio

Capacity, cell C21

Total Capital Investment (both production and CSD) $6,727,303 2005 $ $6,727,303 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Sum of row 63 and row 227Total Capital Investment (production only) $2,738,292 2,738,292 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versio

Costs, cell C71

Electricity feedstock consumption 53.48 kWh / kg H2 53.48 None 62% Efficiency on LHV basis from Norsk Hydro Quote

Electricity Feedstock Price (if Industrial Electricity is used) $0.0555

2005 $/kWh

$0.0555 Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. Industrial electricity price from AEO 2005 "High A" case for startup 

dollars. File downloaded from http://www.eia.doe.gov/oiaf/aeo/inde

Electricity utility consumption (both production and compression) 1.73

kWh / kg H2

1.73

Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. And Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options 

Analysis Results. Interim Report Section 2.2.5. DE-FG36-05GO15032

Compression elec use based on H2A Delivery Components and H2production, default compressor values are from Nexant, et al, (200

Electricity utility consumption (production only) 0.00 kWh / kg H2 0.00 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory All electricity for production is considered "feedstock." Current cent

2.1.2; Results tab; Energy Data

Process Water Consumption

2.94

gal / kg H2

2.94 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current forecourt H2A production from grid electrolysis basis versio

from Norsk Hydro Quote (2002) 1L per Nm3 H2 At 89.9 g H2/Nm3 

Water Consumption for Cooling 0.10832 gal / kg H2 0.11 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versio

ASPEN modeling - see ProcessFlow sheet for details (Mike Penev

Compressed Inert Gas 0.023 Nm^3 / kg H2 0.023 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versioTotal Annual Fixed Operating Costs $183,949 2005$ / yr $183,949 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory

Total Annual Variable Operating Costs $1,404,888 2005$ / yr $1,404,888 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy LaboratoryTotal Annual Operating Costs $1,588,838 2005$ / yr $1,588,838 None Total Annual Fixed Operating Costs plus Total Annual Variable OpProduction energy efficiency (does not include electricity for forecourt compress 62.3% 62.3% Calculated from H2A values Calculated from H2A values based on Electricity requirement which Share of process fuel - biomass 0.0% 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - coal 0.0% 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - natural gas 100.0% 100.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - ethanol 0.0% 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - electricity 0.0% 0.0% Calculated from H2A values Calculated from H2A values

Dist-Elec Pathway Details R090304D 090827 v10.xls

189
Parameter Value Units

Referenced 

Value Reference Comment

Hydrogen outlet pressure (before CSD) 435 psi 435 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Final compression step modeled in the analysis was removed for th

default value. 

Hydrogen quality before transport 99.990% % H2 99.990% D. Steward (personal communication).

Financial Parameters

After-tax Real IRR 10% 10% Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

cell C47

Plant Life 20

years

40 Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

Federal Tax Rate 35.0% 35.0% Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

C49

State Tax Rate 6.0% 6.0% Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

C48

Total Tax Rate 38.9% 38.9% Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

C50

Frection Equity 100% 100% Ramsden, T. (2008, May 28). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratoty Current central H2A production from grid electrolysis basis version 

cell C38

Distribution Station

Distribution Stations for Forecourt Production

Compressor Efficiency at Forecourt production stations 94.8% 94.8% Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version 

hydrogen loss. This calculation only includes electricity

Electricity Required by Forecourt Station 808,030 kWh / station year 808,030 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version Electricity required for forecourt compressors 1.73 kWh / kg H2 1.96 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version Number of Compressor Stages 5 Stages in compressor 4 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version 

B205

Compressor Isentropic Efficiency 65% 65% Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version Site storage (Low Pressure - includes heel) 472

kg H2

472

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM calculation, see description in Nexant Report - Section 2.2compressor suction side to meet hourly demand (including heel) + 

outages.

Site storage (Cascade) 325

kg H2

325

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4. DE-FG36-05GO15032.

HDSAM calculations, see description in Nexant Report - Section 2.

Site storage 62% % of design H2 distribution per day 62% Calculation Calculation of total storage (LP + cascade) divided by design hydro

Dispensing Pressure 6,250

psi

6,250

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM default, see Nexant Report - Section 2.3.2

Hydrogen Losses due to leaks in forecourt production station 0.50% 0.00% Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current central H2A production from grid electrolysis basis version 

Compression, cell B90

Distribution System total capital investment $3,989,011 2005 $ / station $3,993,763 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versi

Investment, cell B162

Distribution System electricity cost $44,770 2005$ / station yr $74,512 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versio

F35

Distribution Labor Required 3,958 hr / station yr 3,951 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory Current forecourt H2A production from grid electrolysis basis versioDistribution System labor cost $39,583

2005$ / station yr

$39,513

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics, Nexant Report - Section 2.2.1.3

Distribution System total O&M cost $215,265

2005$ / station yr

$215,353

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM calculations, see recommendations in Nexant Report -Se

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Type of Oxygenate in RFG None None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planO2 Content in RFG 0% wt % 0% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, page 197: vehicles within the same weight class hRatio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:well-known fuel cell emissions (no PM2.5)

Ratio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:reasonable to assume FCV has same driving patte

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $6.05 $ / kg $6.05 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 7,187 Btu / mile 7,187 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 2,065 Btu / mile 2,065 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

Dist-Elec Pathway Details R090304D 090827 v10.xls

190
Parameter Value Units

Referenced 

Value Reference Comment

WTW Petroleum Input 536 Btu / mile 536 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Fossil Energy Input 9,788 Btu / mile 9,788 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 11,310 Btu / mile 11,310 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 949 g / mile 949 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 1 g / mile 1 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile 0 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 984 g / mile 984 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

Dist-Elec Pathway Details R090304D 090827 v10.xls

191
192

Appendix C — Biomass–Liquid Truck Supporting Tables 

and Figures
Hydrogen Produced In Central Plant and Transported as Liquid via Truck

31,000 Btu Electricity 1,000 Btu

1,000 Btu Diesel Electricity for

Forecourt

271,000 Btu Biomass

0

4,000 Btu Electricity Hydrogen Gas Hydr7,000 Btu Natural Gas 129,000 Btu 116

00

0

152,000 Btu Energy Lost 13,000 Btu 33,000 Btu Energy Lost

HydrogenLost

Known Issue: Forecourt electricity in HDSAM but not in GREET

Case DefinitionYear: 2005Hydrogen as LiquidCentral Production

32% Woody Biomass Feedstock

Sequestration: NoTransport for Delivery: Liquid TruckVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

Well-to-Wheels Greenhouse Gas Emissions (g/mile)

160 WTP Emissions (lb 

CO2 Equivalent / GGE fuel available): 

16

Levelized Cost of H2 at Pump ($/kg) 4.88

8,170 Production Process Energy Efficiency 46%

Well-to-Wheels Petroleum Energy Use (Btu/mile) 249 Pathway Efficiency 37%Well-to-Wheels Total Energy Use (Btu/mile)

WTP Efficiency

Central Production Liquefaction & Transport Storage and Compression for Dispensing

193
Biomass moisture content 25%

Woody biomass LHV 16,811,019 Btu / dry ton

Fraction of Woody Biomass (Remaining is Herbaceous) 100%

Grams of Nitrogen / dry ton biomass 709

Grams of P2O5 / dry ton biomass 189 Biomass price at H2 production $37.96 2005 $ / dry ton

Grams of K2O / dry ton biomass 331 Levelized Cost of Biomass $0.61 2005$ / kg H2 distributed

Herbicide use 24 g / dry ton

Insecticide use 2 g / dry ton WTG CO2 Emissions -26,911 g / 116000Btu to Pump

Coal Input from "Well" 269 Btu / 116000Btu to Pump Average dist from farm to H2 production 40 miles WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 427 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 2,832 Btu / 116000Btu to Pump WTG GHG Emissions -26,867 g CO2 eq./ 116000 Btu

Biomass consumption 12.8 kg (dry) / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.17 N m^3/kg H2 produced Hydrogen Outlet Quality 98 minimum

Electricity consumption 0.98 kWh / kg H2

Process Water Consumption 5.00 L / kg H2 Central plant design capacity 155,236 kg/day Total capital investment $3.03 2005$ / annual kg H2 (effective

Natural gas price $0.340 2005$ / N m^3 Capacity factor 90% Levelized Electricity cost $0.05 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 46.0% Levelized Natural Gas Cost $0.06 2005$ / kg H2 produced

Total Capital Investment $154,644,297 2005$ Electricity Mix US Mix Levelized Other operating costs $0.32 2005$ / kg H2 produced

After-tax IRR 0 Levelized Cost of Prod (excl feedst $1.18 2005$ / kg H2 distributed

Assumed Plant Life 40

SMR CO2 Emissions 26,979 g / 116000Btu to Pump

Coal Input from "Well" 6,356 Btu / 116000Btu to Pump SMR CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 9,009 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 3,570 Btu / 116000Btu to Pump SMR GHG Emissions 27,091 g CO2 eq./ 116000 Btu

Liquefaction electricity consumption 8.2 kWh / kg H2 Total capital investment $6.37 2005$/annual kg delivered

Diesel consumption 7.3 gal / 1000 kg H2 Levelized Electricity cost $0.49 2005$ / kg H2 delivered

Levelized Diesel cost $0.01 2005$ / kg H2 delivered

City Population 1,247,364 people Levelized Labor cost $0.13 2005$ / kg H2 delivered

Hydrogen Vehicle Penetration 50% Levelized Other operating costs $0.28 2005$ / kg H2 delivered

Total Capital Investment $800,063,746 City hydrogen use 125,810,766 kg / yr

Liquefaction efficiency 80.3%

Terminal Design Capacity 3,532,139 kg H2 Levelized Cost of Distribution $2.04 2005$ / kg H2 distributed

Number of truck-trips required 31,009 per year

Truck hydrogen capacity 4,372 kg / truckload

One-way distance for delivery 49 miles Delivery CO2 Emissions 6,708 g / 116000Btu to Pump

Coal Input from "Well" 50,184 Btu / 116000Btu to Pump Hydrogen losses 10.1% Delivery CH4 Emissions 9 g / 116000Btu to Pump

Natural Gas Input from "Well" 14,462 Btu / 116000Btu to Pump Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 4,778 Btu / 116000Btu to Pump Delivery GHG Emissions 6,955 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $5.85 2005$/annual kg

Number of Distribution Stations 270 Levelized Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.05 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 52% capacity CSD CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump CSD GHG Emissions 0 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 56,809 Btu / 116000 Btu

Natural Gas Input from "Well" 23,898 Btu / 116000 Btu

Petroleum Input from "Well" 11,180 Btu / 116000 Btu

Fossil Energy Input from "Well" 91,887 Btu / 116000 Btu

WTP CO2 Emissions 58,489 g / 116000 Btu

WTP CH4 Emissions 101 g / 116000 Btu

WTP N2O Emissions 3 g / 116000 Btu

WTP GHG Emissions 61,963 116000 Btu

Levelized Cost of Hydrogen ($/kg) $4.88 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 100 Btu / mi

Natural Gas Input from "Well" 3,911 Btu / mi

Petroleum Input from "Well" 249 Btu / mi

Fossil Energy Input from "Well" 2,044 Btu / mi

WTW CO2 Emissions 151 g / mi

WTW CH4 Emissions 0 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 160 g / mi

Levelized Cost of Hydrogen ($/mi) $0.1086 2005 $/mi

Inputs Outputs

Vehicle

Biomass Production & Delivery

Graphic Depiction & Assumptions

Liquefaction and Truck-Delivery

Hydrogen Production

Forecourt Distribution

Bio-Liquid Pathway Details R090219B 090818 v09.xls

194
Gasification Liquefaction Transport Storage 

Coal 6,356 Btu/mmBtu Coal 50,159 Btu/mmBtu Coal 26 Btu/mmBtu Coal 0 Btu/mmBtu

Natural Gas 9,009 Btu/mmBtu Natural Gas 14,408 Btu/mmBtu Natural Gas 54 Btu/mmBtu Natural Gas 0 Btu/mmBtu

Petroleum 3,570 Btu/mmBtu Petroleum 3,735 Btu/mmBtu Petroleum 1,042 Btu/mmBtu Petroleum 0 Btu/mmBtu

CO2 Emissions 26,979 g/mmBtu CO2 Emissions 6,620 g/mmBtu CO2 Emissions 88 g/mmBtu CO2 Emissions 0 g/mmBtu

CH4 Emissions 3 g/mmBtu CH4 Emissions 9 g/mmBtu CH4 Emissions 0 g/mmBtu CH4 Emissions 0 g/mmBtu

N2O Emissions 0 g/mmBtu N2O Emissions 0 g/mmBtu N2O Emissions 0 g/mmBtu N2O Emissions 0 g/mmBtu

GHG Emissions 27,091 g/mmBtu GHG Emissions 6,864 g/mmBtu GHG Emissions 91 g/mmBtu GHG Emissions 0 g/mmBtu

Feedstock 

Coal 269 Btu/mmBtu 

Natural Gas 427 Btu/mmBtu 

Petroleum 2,832 Btu/mmBtu Gasification & Conversion Liquefaction Transport Storage 

CO2 Emissions -26,911 g/mmBtu 

CH4 Emissions 0 g/mmBtu Liquefaction Losses 0.50% Transport Losses 1.28% Storage Losses 4.06% 

N2O Emissions 0 g/mmBtu 

GHG Emissions -26,867 g/mmBtu 

Bio-Liquid Pathway Details R090219B 090818 v09.xls

195
Parameter Value Units

Referenced 

Value Reference Comment

Case Definition

Base Year 2005 2005 None Default for Dist-SMR Pathway study

Production Technology Woody Biomass Woody Biomass None Default for Dist-SMR Pathway study

Form of H2 During Delivery Liquid Gas None Default for Dist-SMR Pathway studyDelivery Mode Liquid Truck Pipeline None Default for Dist-SMR Pathway studyForecourt Station Size 1278 kg/day 1278 James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas basis version 2

Vehicle Type passenger cars passenger cars None Default for Dist-SMR Pathway studyVehicles' Fuel Economy 45.0 mile / gge 45.0

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles. Argonne National Laboroatory presentation, Chicago, IL. Retreived

from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel economy for todPowertrain Simulation Analysis Toolkit V 6.2 SP1, Summer 2008 (Phttp://www.transportation.anl.gov/modeling_simulation/PSAT/indexeconomy which was determined by multiplying the projected EPA l

Market Definition

City Population 1,247,364 people 1,247,364 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN, cell B9

Market penetration 50% (% vehicles in city) 50% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Number of H2 vehicles in city 462,772 H2 vehicles / city 462,772 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Demand calculation by HDSAM version 2.02; Scenario tab; Numbe

Miles driven per vehicle 12,000 mile / vehicle year 12,000 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Key delivery input in HDSAM version 2.02; Scenario tab; Miles driv

City hydrogen use 344,451 kg / d 267,247 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; City H2 

Number of H2 refueling stations in city 270 210 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumbeNumber of H2 stations/Number of gasoline stations 41% 32% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumbeAverage distance between stations (mi) 1.46 miles 1.65 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Averag

Feedstock Recovery, Processing, & Transport

Biomass

Percentage of Woody Biomass (Remainder is Herbaceous) 100% 100%

Mann, M & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory

Current central H2A production via biomass gasification version 2.1

Biomass Moisture Content 25% 25% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory Page 66Grams of Nitrogen / short ton biomass 709

g / dry ton

709 M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh 1998). Equivalent to 75 lb N / ac in the maintenance year Year 3 or 4) whi

assuming 6 dry tons biomass per acre, and harvesting once every just used for traditional crops.

Grams of P2O5 / short ton biomass 189 g / dry ton 189 M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh 1998). Equivalent to 20 lb P / ac in the maintenance year (Year 3) which is 

Torre Ugarte, 2003, App 3.1, assuming 6 dry tons biomass per acre 

Grams of K2O / short ton biomass 331 g / dry ton 331 M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh 1998). Equivalent to 35 lb K / ac in the maintenance year (Year 3) which is 

Torre Ugarte, 2003, App 3.1, assuming 6 dry tons biomass per acre 

Grams of herbicide / short ton biomass 24

g / dry ton

24 M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh 1998).

Equivalent to 2.0 lb herbicide / ac in the planting year which similar Ugarte, 2000, App 3.2, assuming 6 dry tons biomass per acre and Trifluralin (5 L/ha) and Metribuzin (395 g/ha). App 3.2 is for planting used for pasture.

Grams of insecticide / short ton biomass 2

g / dry ton

2 M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh 1998). As a check, looked at Chastagner: Up to 56% of acreage annually 

acre); up to 56% of acreage annually sprayed with Permethrin 2LB annually sprayed with Endosulfan 3 EC (24c WA-990025, 2 qts per 

Grams of CO2 removed from atmosphere per dry ton woody biomass produced -112,500 g / dry ton -112,500

Average distance from farm to hydrogen production facility 40 miles 40 Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET basis: distance could be limited by transport costs?

Natural Gas

NG recovery efficiency 97.2% Wang, 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% which is comparable to several other models (Ta

NG used & lost during recovery 0.35% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET basisNG processing energy efficiency 97.2% Wang, 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 (NG used & lost during processing 0.15%

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry , EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pdf

Volume lost from EPA/GRI paper and DOE/EIA-0573; future margiaverage.

NG used & lost during transport 0.14

g / (MM Btu mil)

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry , EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pdf

Volume lost from EPA/GRI paper and DOE/EIA-0573; future margiaverage.

NG transport distance 500 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET basis

Electricity

Grid mix for production US Mix US Mix Default

Biomass Fraction

1.2% 1.2%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Coal Fraction

51.7% 51.7%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Natural Gas Fraction

15.7% 15.7%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Nuclear Fraction

20.3% 20.3%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Residual Oil Fraction

2.9% 2.9%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Others (Carbon Neutral)

8.2% 8.2%

Annual Energy Outlook 2007 -- www.eia.doe.gov/oiaf/archive/aeo07/index.html

US grid mix. National electricity generation data from tables D-7 & calculated from total generation values reported with all renewables Neutral)" category 

Grid mix for liquefaction with biomass production US Mix US Mix None Default for Bio-Liquid Pathway study

Grid mix for liquefaction with coal production US Mix US Mix None Default for Bio-Liquid Pathway study

Grid mix for liquefaction with central natural gas production NGCC NGCC None Default for Bio-Liquid Pathway study

Grid mix for liquefaction with nuclear production Nuclear Power Nuclear Power None Default for Bio-Liquid Pathway studyGrid mix for pipeline compressors US Mix US Mix None Default for Bio-Liquid Pathway study

Bio-Liquid Pathway Details R090219B 090818 v09.xls

196
Parameter Value Units

Referenced 

Value Reference Comment

Grid mix for compression at distribution US Mix US Mix None Default for Bio-Liquid Pathway study

H2 Production

CO2 Captured for Sequestration 0% 0% Not available in this case study

Production Facility Average Output 139,712 kg / facility d (after capacity factor is included) 139,712

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 3.0. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Design feed rate for current design plant of 2000 bone dry metric to

Corresponding capacity factor 90% 90%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; cell C21

Total Capital Investment $154,644,297 2005 $ $154,644,297

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 10. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Total installed capital cost of $102M ($2002) (see Table 10, Currenfor additional compression was removed to maintain consistency w

Biomass feedstock consumption 12.8 kg (dry) / kg H2 12.8

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Biomass usage calculated from plant efficiency of 45.6%. The LHV higher (8406 Btu/lb v. 8060 Btu/lb) than used in Spath. Appendix A 70.4 kg/ dry US ton feedstock

Biomass feedstock cost $37.96 2005$ / dry short ton $37.96

Hess, R., Denney, K., Wright, C., Radtke, C., Perlack, W. (2007, April 18-19). Cellulosic Biomass Feedstocks for Renewable Bioenergy. EERE presentation to the National Academy of Sciences Commettee on Resource Needs for Fuel Cell and Hydrogen, Washington, D.C. 

Feedstock price is taken from the Biomass Program 2012 Target p

Natural gas feedstock consumption 0.00 normal m^3 / kg H2 produced 0.00

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Natural Gas feedstock cost N/A N/A None N/ANatural Gas LHV 34,714 Btu / normal m^3. 36,692 Hydrogen Analysis Resource Center. (2008, September 5). Lower and Higher Heating Values of Hydrogen and Fuels. Retrieved from http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/401 LHV of Natural Gas; 983 Btu/ft3

Natural gas utility consumption 0.17 normal m^3 / kg H2 produced 0.17

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Natural gas usage from overall energy balance; Appendix C, A401424 = 14260 lb/hr; conversion vields 0.15 (not 0.17)

Natural gas utility price $0.340 2005$ / Nm^3 $0.340 Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. AEO 2005 High A Case - Commercial price; Escalated from 2003 d

http://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls

Natural gas utility pressure N/A kPa N/A None Not in H2A or GREET

#VALUE! psi #VALUE! Conversion calculation conversion calculation

Electricity feedstock consumption 0.00

kWh / kg H2

0.00

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Electricity utility consumption (both production and compression) 0.98

kWh / kg H2

0.98

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Electricity usage from overall energy balance with energy usage foAppendix A, Total Plant Electricity = 5.54 kWh/kg H2 - 

Electricity utility consumption (production only) 0.98

kWh / kg H2

0.98

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Electricity usage from overall energy balance with energy usage foAppendix A, Total Plant Electricity = 5.54 kWh/kg H2

Electricity Utility Price 0.0555

2005 $/kWh

0.0555 Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025. DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. AEO 2005 High A Case - Industrial price; Escalated from 2003 doll

http://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls

Process Water Consumption

1.32

gal / kg H2

1.32

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Appendix C, A202: stream 218 = 738 lb/hr; Appendix C, A601: stre710 = 131921 lb/hr

Water Consumption for Cooling

0.00008

gal / kg H2

0.00

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Assume all make-up water is process water

Electricity co-product production 0.00 kWh / kg H2 0.00 None All electricity co-product used internally

Oxygen co-product production 0.0 kg / kg H2 0.0 None N/A

Steam co-product production 0.0 kg / kg H2 0.0 None N/A

Total Annual Fixed Operating Costs $10,391,486 2005$ / yr $10,391,486

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 9.2. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Section 9.2 Fixed Operating Costs. Costs were escalated from $20

Total Annual Variable Operating Costs $43,162,900 2005$ / yr $44,917,200

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 13. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Table 13: Variable Operating Costs. Costs were escalated from $2

Total Annual Operating Costs $53,554,386 2005$ / yr $55,308,686 None Addtion of Annual Total Fixed Operating Costs and Total Annual V

Production energy efficiency (does not include electricity for forecourt compress 46.0% 45.6% Calculated from H2A values Calculated from H2A valuesShare of process fuel - biomass 93.1% 91.4% Calculated from H2A values Calculated from H2A values

Share of process fuel - coal 0.0% 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - natural gas 2.5% 4.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - ethanol 0.0% 0.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - electricity 4.4% 4.6% Calculated from H2A values Calculated from H2A values

Hydrogen outlet pressure (before CSD) 300

psi

300

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Final compression step modeled in the analysis was removed for thdefault value. 

Hydrogen quality before transport 98 minimum

% H2

98 minimum

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Page 5, product purity of 99.9 vol%

Financial Parameters

After-tax Real IRR 10% 10%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; C47

Plant Life 40

years

40

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Bio-Liquid Pathway Details R090219B 090818 v09.xls

197
Parameter Value Units

Referenced 

Value Reference Comment

Federal Tax Rate 35.0% 35.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

State Tax Rate 6.0% 6.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Total Tax Rate 38.9% 38.9%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Frection Equity 100% 100%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from biomass basis version 2.1.2; 

Transport, Delivery, and Storage Energy Requirements

Liquid Truck Delivery

Hydrogen entering liquefaction 382,396 kg / day 382,396 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input parameters: city se

Liquefaction electricity requirement 1,136,394,945

kW hr / yr

1,136,394,945

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Sections 2.2.7.3 and 2.2.7.5. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland (Nexant Repo

Liquefaction electricity requirement 8.2 kW hr / kg H2 1,136,394,945 None Calculation

Hydrogen lost in liquefier 0.5% 0.5%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.7.2. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland (Nexant Repo

Liquefaction efficiency 80.3% 80.3%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.7.2. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (N

Liquefaction System total capital investment $559,414,686

2005$

$559,414,686

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.7.4. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (N

Liquefaction System electricity cost $60,690,228

2005$ / yr

$60,690,228

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.7.4. DE-FG36-05GO15032.

Discussions with Linde Kryotechnic AG, Switzerland and Praxair (N

Liquefaction System labor cost $592,895

2005$ / yr

$592,895

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Liquefaction System total operating cost $83,647,930 2005$ / yr $83,647,930 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, H2 Liquifer tab, cell B135: sum of 

fixed costs

Terminal Storage Design Capacity 3,532,139 kg H2 3,532,139 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B73: 

flow

Hydrogen lost in terminal 2.8% 2.8%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction wNREL (Nexant Report- Section 2.2.14)

Terminal total capital investment $191,649,060

2005$

$191,649,060

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.11.1. DE-FG36-05GO15032.

CB&I (Nexant Report - Section 2.2.11.1)

Terminal electricity cost $565,492 2005$ / yr $565,492 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B187

Terminal labor cost $588,708

2005$ / yr

$588,708

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Terminal total operating cost $8,842,213 2005$ / yr $8,842,213 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Liquid H2 Terminal tab, cell B201

other fixed costs

Truck Payload leaving terminal 4,372

kg / truckload

4,372

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.8. DE-FG36-05GO15032.

HDSAM calculation; default value (Nexant Report- Section 2.1.8)

Truck Trips 31,009 per year 31,009 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B66

efficiency(H2out/H2 in) / H2 delivered per trip (kg)

One-way distance per trip 49 miles / trip (one way) 157,840 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B39Diesel for Truck Trips 3,837

m^3 / yr

3,837

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.8. DE-FG36-05GO15032.

HDSAM calculation, fuel consumption data from Nexant in conjuctiand NREL (Nexant Report - Section 2.1.8)

Hydrogen Losses during loading / transport / unloading 6.1% 6.1%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction wNREL (Nexant Report- Section 2.2.14)

Hydrogen Losses during liquefaction/loading / transport / unloading 10.08% 10.08%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction wNREL (Nexant Report- Section 2.2.14)

Truck/trailer total capital investment $49,000,000

2005$

$49,000,000 Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report. DE-FG36-05GO15032. $625,000 per each tank trailer and $75,00 per each truck cab; reco

Liquide, GTI, Chevron, TIAX, ANL, PNNL and NREL

Truck/trailer electricity cost $0 2005$ / yr $0 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation, electricity prices are from EIA AEO 2005 and 2

Truck/trailer Diesel cost $1,692,270 2005$ / yr $1,692,270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B11

EIA AEO 2005 and 2007

Truck/trailer labor cost $15,193,193

2005$ / yr

$15,193,193

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Truck/trailer total operating cost $21,691,089 2005$ / yr $21,691,089 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Truck - LH2 Delivery tab, cell B13

fixed costs

Distribution Station

Liquid Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year 465,647 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input: dispensing rate

Electricity Required by Forecourt Station 116,673 kWh / station year 116,673 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on pump power requiremenDesign Capacity 1,516

kg H2 / day

1,516

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.4. DE-FG36-05GO15032.

HDSAM calculation based on Chevron fueling profiles (Nexant Repsurge)*(1+Friday surge)

Operating Capacity 1,278 kg H2 / day 1,278 James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas basis version 2

Capacity Factor 84% 84% None Calculation

Bio-Liquid Pathway Details R090219B 090818 v09.xls

198
Parameter Value Units

Referenced 

Value Reference Comment

Site storage (liquid) 6,920

kg H2

6,920

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.11.2. DE-FG36-05GO15032.

HDSAM calculation based on number of deliveries per day (Nexan

Site storage (gaseous) 453

kg H2

323

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4. DE-FG36-05GO15032.

HDSAM calculation (Nexant Report - Section 2.3.2.4)

Site storage 486% % of design H2 distribution None Calculation

Dispensing Pressure 6,250

psi

6,250

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2. DE-FG36-05GO15032.

HDSAM default (see Nexant Report-Section 2.3.2)

Hydrogen Losses due to leaks 1.34% 1.34%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

HDSAM parameter, recommendations from Nexant in conjuction wNREL (Nexant Report - Section 2.2.14)

Distribution System total capital investment $2,073,185

2005$ / station

$2,073,185

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.4.2. DE-FG36-05GO15032.

Data from CP Industries, McMaster-Carr, Bechtel, Nexant manufac

Section 2.2.4.2)

Distribution System electricity cost $9,512

2005$ / station yr

$9,621

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.4.2. DE-FG36-05GO15032.

Data from CP Industries, McMaster-Carr, Bechtel, Nexant manufac

Section 2.2.4.2)

Distribution Labor Required 3,951

hr / station yr

3,942

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

HDSAM calculation (Nexant Report -Section 2.2.1.3)

Distribution System labor cost $39,513

2005$ / station yr

$39,416

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Section 2.2.1.3)

Distribution System total O&M cost $189,192

2005$ / station yr

$181,989

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM calculations (Nexant Report - Section 2.2.1.2)

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Type of Oxygenate in RFG None None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planO2 Content in RFG 0% wt % 0% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, page 197: vehicles within the same weight class hRatio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:well-known fuel cell emissions (no PM2.5)

Ratio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b. Argonne, IL: Argonne National Laboratory.GREET default:reasonable to assume FCV has same driving patte

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results. Argonne, IL: Argonne National Laboratory GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $4.88 $ / kg $4.38 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 100 Btu / mile 534 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 3,911 Btu / mile 284 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Petroleum Input 249 Btu / mile 144 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 2,044 Btu / mile 963 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 8,170 Btu / mile 5,302 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 151 g / mile 58 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 0 g / mile 0 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile 0 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 160 g / mile 63 Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1 44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

Bio-Liquid Pathway Details R090219B 090818 v09.xls

199
200

Appendix D — Biomass–Pipeline Supporting Tables and 

Figures
Hydrogen Produced In Central Plant and Transported as Gas via Pipeline

2,000 Btu 11,000 Btu

Electricity for Electricity forCompression Forecourt

245,000 Btu Biomass

0

3,000 Btu Electricity Hydrogen Gas Hydr

6,000 Btu Natural Gas 117,000 Btu 116

00

0

138,000 Btu Energy Lost 1,000 Btu 13,000 Btu Energy Lost

HydrogenLost

Known Issue: Hydrogen losses are estimated in HDSAM but are not included in GREET

Case DefinitionYear: 2005Hydrogen as GasCentral Production

39% Woody Biomass Feedstock

Sequestration: NoTransport for Delivery: PipelineVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

WTP Emissions (lb CO2 Equivalent / GGE fuel available): 

7

WTP Efficiency

Levelized Cost of H2 at Pump ($/kg) 4.23Well-to-Wheels Total Energy Use (Btu/mile)Well-to-Wheels Petroleum Energy Use (Btu/mile)Well-to-Wheels Greenhouse Gas Emissions (g/mile)

6,69518070

Production Process Energy EfficiencyPathway Efficiency

46%43%

Central Production Compression & Pipeline Compression, Storage, & Dispensing

201
Biomass moisture content 25%

Woody biomass LHV 16,811,019 Btu / dry ton

Fraction of Woody Biomass (Remaining is Herbaceous) 100%

Grams of Nitrogen / dry ton biomass 709

Grams of P2O5 / dry ton biomass 189 Biomass price at H2 production $37.96 2005 $ / dry ton

Grams of K2O / dry ton biomass 331 Levelized Cost of Biomass $0.56 2005$ / kg H2 distributed

Herbicide use 24 g / dry ton

Insecticide use 2 g / dry ton WTG CO2 Emissions -25,632 g / 116000Btu to Pump

Coal Input from "Well" 261 Btu / 116000Btu to Pump Average dist from farm to H2 production 40 miles WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 418 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 2,900 Btu / 116000Btu to Pump WTG GHG Emissions -25,590 g CO2 eq./ 116000 Btu

Biomass consumption 12.8 kg (dry) / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.17 N m^3/kg H2 produced Hydrogen Outlet Quality 1

Electricity consumption 0.98 kWh / kg H2

Process Water Consumption 5.00 L / kg H2 Central plant design capacity 155,236 kg/day Total capital investment $3.03 2005$ / annual kg H2 (effective

Natural gas price $0.340 2005$ / N m^3 Capacity factor 90% Electricity cost $0.05 2005$ / kg H2 produced

Electricity price $0.055 2005 $/kWh Process energy efficiency 46.0% Natural Gas Cost $0.06 2005$ / kg H2 produced

Total Capital Investment $154,644,297 2005$ Electricity Mix US Mix Other operating costs $0.38 2005$ / kg H2 produced

After-tax IRR 0 Levelized Cost of Prod (excl feedst $1.07 2005$ / kg H2 distributed

Assumed Plant Life 40

SMR CO2 Emissions 25,733 g / 116000Btu to Pump

Coal Input from "Well" 6,063 Btu / 116000Btu to Pump SMR CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 8,598 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 3,623 Btu / 116000Btu to Pump SMR GHG Emissions 25,839 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69% capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 27,308 Btu / 116000 Btu

Natural Gas Input from "Well" 15,043 Btu / 116000 Btu

Petroleum Input from "Well" 8,087 Btu / 116000 Btu

Fossil Energy Input from "Well" 50,437 Btu / 116000 Btu

WTP CO2 Emissions 2,875 g / 116000 Btu

WTP CH4 Emissions 7 g / 116000 Btu

WTP N2O Emissions 0 g / 116000 Btu

WTP GHG Emissions 3,127 116000 Btu

Levelized Cost of Hydrogen ($/kg) $4.23 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 607 Btu / mi

Natural Gas Input from "Well" 335 Btu / mi

Petroleum Input from "Well" 180 Btu / mi

Fossil Energy Input from "Well" 1,122 Btu / mi

WTW CO2 Emissions 64 g / mi

WTW CH4 Emissions 0 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 70 g / mi

Levelized Cost of Hydrogen ($/mi) $0.0941 2005 $/mi

Inputs Outputs

Vehicle

Biomass Production & Delivery

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

Bio-Pipe Pathway Details R090209A 090806 v09.xls

202
Gasification Transport Distribution

Coal 6,063 Btu/116000 Btu Coal 3,306 Btu/116000 Btu Coal 17,677 Btu/116000 Btu

Natural Gas 8,598 Btu/116000 Btu Natural Gas 950 Btu/116000 Btu Natural Gas 5,078 Btu/116000 Btu

Petroleum 3,623 Btu/116000 Btu Petroleum 246 Btu/116000 Btu Petroleum 1,317 Btu/116000 Btu

Total Energy 147,677 Btu/116000 Btu Total Energy 5,938 Btu/116000 Btu Total Energy 27,816 Btu/116000 Btu

CO2 Emissions 25,733 g/116000 Btu CO2 Emissions 436 g/116000 Btu CO2 Emissions 2,333 g/116000 Btu

CH4 Emissions 3 g/116000 Btu CH4 Emissions 1 g/116000 Btu CH4 Emissions 3 g/116000 Btu

N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu

GHG Emissions 25,839 g/116000 Btu GHG Emissions 452 g/116000 Btu GHG Emissions 2,419 g/116000 Btu

Feedstock 

Coal 261 Btu/116000 Btu 

Natural Gas 418 Btu/116000 Btu 

Petroleum 2,900 Btu/116000 Btu Gasification & Conversion Transport Distribution 

Total Energy 3,628 Btu/116000 Btu 

CO2 Emissions -25,632 g/116000 Btu Transport Losses 0.63% Distribution Losses 0.50% CO

CH4 Emissions 0 g/116000 Btu CH

N2O Emissions 0 g/116000 Btu N2

GHG Emissions -25,590 g/116000 Btu GH

Bio-Pipe Pathway Details R090209A 090806 v09.xls

203
Parameter Value Units Reference 

Case Definition

Base Year 2005 N/A Default for Bio-Pipe Pathway studyProduction Technology Woody Biomass N/A Default for Bio-Pipe Pathway studyForm of H2 During Delivery Gas N/A Default for Bio-Pipe Pathway study

Delivery Mode Pipeline N/A Default for Bio-Pipe Pathway study

Forecourt Station Size 1278 kg/day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas b

Vehicle Type passenger cars N/A Default for Bio-Pipe Pathway studyVehicles' Fuel Economy 45.0 mile / gge

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles . Argonne National Laboroatory presentation, Chicago, IL. Retreived from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel ePowertrain Simulation Analysis Toolkit V 6.2 SP1, Shttp://www.transportation.anl.gov/modeling_simulatioeconomy which was determined by multiplying the p

Market Definition

City Population 1,247,364 people U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. HDSAM City Selection; Scenario tab; Indianapolis, IN

Market penetration 50% (% vehicles in city) U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planNumber of H2 vehicles in city 462,772 H2 vehicles / city Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Demand calculation by HDSAM version 2.02; Scena

Miles driven per vehicle 12,000 mile / vehicle year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Key delivery input in HDSAM version 2.02; Scenario City hydrogen use 344,451 kg / d Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scena

vehicles and miles/veh yr.

Number of H2 refueling stations in city 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenaNumber of H2 stations/Number of gasoline stations 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenaAverage distance between stations (mi) 1.46 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scena

Feedstock Recovery, Processing, & Transport

Biomass

Percentage of Woody Biomass (Remainder is Herbaceous) 100% Mann, M & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.Current central H2A production via biomass gasifica

Biomass Moisture Content 25% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. Page 66

Grams of Nitrogen / short ton biomass 709

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

Equivalent to 75 lb N / ac in the maintenance year Yassuming 6 dry tons biomass per acre, and harvestinused for traditional crops.

Grams of P2O5 / short ton biomass 189 g / dry ton M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998). Equivalent to 20 lb P / ac in the maintenance year (Y

Ugarte, 2003, App 3.1, assuming 6 dry tons biomass 

Grams of K2O / short ton biomass 331 g / dry ton M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998). Equivalent to 35 lb K / ac in the maintenance year (Y

Ugarte, 2003, App 3.1, assuming 6 dry tons biomass 

Grams of herbicide / short ton biomass 24

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

Equivalent to 2.0 lb herbicide / ac in the planting yeaUgarte, 2000, App 3.2, assuming 6 dry tons biomass 

(5 L/ha) and Metribuzin (395 g/ha). App 3.2 is for plapasture.

Grams of insecticide / short ton biomass 2

g / dry ton

M. Walsh (personal communication via telephone and meeting between M. Wang and M. Walsh, 1998).

As a check, looked at Chastagner: Up to 56% of acreup to 56% of acreage annually sprayed with Permethannually sprayed with Endosulfan 3 EC (24c WA-990

Grams of CO2 removed from atmosphere per dry ton woody biomass produced -112,500 g / dry ton GREET model default based on ANL personal comm

Average distance from farm to hydrogen production facility 40 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET basis: distance could be limited by transport 

Natural Gas

NG recovery efficiency 97.2% Wang, 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% which is comparable to several ot

NG used & lost during recovery 0.35% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET basisNG processing energy efficiency 97.2% Wang, 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 NG used & lost during processing 0.15%

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.p

Volume lost from EPA/GRI paper and DOE/EIA-0573

NG used & lost during transport

0.137 g / (MM Btu mil)

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.p

Volume lost from EPA/GRI paper and DOE/EIA-0573

NG transport distance 500 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET basis

Electricity

Grid mix for production US Mix Default

Biomass Fraction

1.20%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Coal Fraction

51.70%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Natural Gas Fraction

15.70%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Nuclear Fraction

20.30%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Bio-Pipe Pathway Details R090209A 090806 v09.xls

204
Parameter Value Units Reference 

Residual Oil Fraction

2.90%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Others (Carbon Neutral)

8.20%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

H2 Production

Production Facility Average Output 139,712 kg / facility d (after capacity factor is included)

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 3.0. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Design feed rate for current design plant of 2000 bon

Corresponding capacity factor 90% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

cell C21

Total Capital Investment $154,644,297 2005 $

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 10. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Total installed capital cost of $102M ($2002) (see Tafor additional compression was removed to maintain 

Biomass feedstock consumption 12.8 kg (dry) / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Biomass usage calculated from plant efficiency of 45(8406 Btu/lb v. 8060 Btu/lb) than used in Spath. AppUS ton feedstock

Biomass feedstock cost $37.96 2005$ / dry short ton

Hess, R., Denney, K., Wright, C., Radtke, C., Perlack, W. (2007, April 18-19). Cellulosic Biomass Feedstocks for Renewable Bioenergy . EERE presentation to the National Academy of Sciences Commettee on Resource Needs for Fuel Cell and Hydrogen, Washington, D.C. 

Feedstock price is taken from the Biomass Program 

Biomass LHV 16,811,019 Btu / dry ton Hydrogen Analysis Resource Center. (2008, September 5). Lower and Higher Heating Values of Hydrogen and Fuels . Retrieved from http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/401 LHV of Farmed Trees (dry basis); 19.551 MJ/kgNatural gas feedstock consumption 0.00 normal m^3 / kg H2 produced Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Natural Gas LHV 34,714 Btu / normal m^3 Hydrogen Analysis Resource Center. (2008, September 5). Lower and Higher Heating Values of Hydrogen and Fuels . Retrieved from http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/401 LHV of Natural Gas; 983 Btu/ft3

Natural gas utility consumption 0.17 normal m^3 / kg H2 produced

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Appendex A. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Natural gas usage from overall energy balance; App424 = 14260 lb/hr; conversion vields 0.15 (not 0.17)

Natural gas utility price $0.340 2005$ / Nm^3 Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. Commercial natural gas price from AEO 2005 "High 

dollars. File downloaded from http://www.eia.doe.go

Natural gas utility pressure N/A kPa None Not in H2A or GREET

#VALUE! psi conversion calculation

Electricity feedstock consumption 0.00

kWh / kg H2

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Electricity utility consumption (both production and compression) 0.98 kWh / kg H2 Sum of feedstock + utility

Electricity utility consumption (production only) 0.98

kWh / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory.

Electricity usage from overall energy balance with enA, Total Plant Electricity = 5.54 kWh/kg H2. Electriciat 360 psi and H2A's standard is 300 psi.

Electricity Utility Price 0.0555

2005 $/kWh

Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy.

Industrial electricity price from AEO 2005 "High A" cadollars. File downloaded from http://www.eia.doe.go

Process Water Consumption

1.32

gal / kg H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory.

Appendix C, A202: stream 218 = 738 lb/hr; Appendix = 131921 lb/hr

Water Consumption for Cooling

0.00008

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory.

Assume all make-up water is process water

Electricity co-product production 0.00 kWh / kg H2 None All electricity co-product used internally

Oxygen co-product production 0.0 kg / kg H2 None N/ASteam co-product production 0.0 kg / kg H2 None N/A

Total Annual Fixed Operating Costs $10,391,486 2005$ / yr

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Section 9.2. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Section 9.2 Fixed Operating Costs. Costs were esca

Total Annual Variable Operating Costs $43,162,900 2005$ / yr

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 13. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Table 13: Variable Operating Costs. Costs were esc

Total Annual Operating Costs $53,554,386 2005$ / yr N/A Addition of Annual Total Fixed Operating Costs and Production energy efficiency (does not include electricity for forecourt compressio 46.0% N/A Calculated from H2A values

Share of process fuel - biomass 93.1% N/A Calculated from H2A values

Share of process fuel - coal 0.0% N/A Calculated from H2A valuesShare of process fuel - natural gas 2.5% N/A Calculated from H2A valuesShare of process fuel - ethanol 0.0% N/A Calculated from H2A valuesShare of process fuel - electricity 4.4% N/A Calculated from H2A valuesHydrogen outlet pressure (before CSD) 300

psi

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory.

Final compression step modeled in the analysis was default value. Spath's compression was to 360 psi aelectricity use.

Bio-Pipe Pathway Details R090209A 090806 v09.xls

205
Parameter Value Units Reference 

Hydrogen quality before transport 99.9%

% H2

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to 

Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory.

Page 5, product purity of 99.9 vol%

Financial Parameters

After-tax Real IRR 10% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Plant Life 40

years

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Federal Tax Rate 35.0% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

State Tax Rate 6.0% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Total Tax Rate 38.9% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Fraction Equity 100% Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratoty.Current central H2A production from biomass basis 

Transport, Delivery, and Storage Energy Requirements

Pipeline Delivery

Average Hydrogen Flowrate (Entering System) 348,364 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

THRU TRANSMISSION SYSTEM=CITY PEAK DEMEFFICIENCY/REF.STATION MASS EFFICIENCY)

Average Hydrogen Flowrate (Distributed) 344,451 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

DAILY USE/TOTAL PIPELINE MASS EFFICIENCY/

Summer Surge: % above the System Average Daily Demand 10% % above Average Daily Demand Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Scenario Parameters tab, cell B90Friday Peak 8% % above Average Daily Demand Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Scenario Parameters tab, cell B92Peak Hydrogen Flowrate 381,192 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

THRU DISTRIBUTION SYSTEM=CITY PEAK DEMAEFFICIENCY/REF.STATION MASS EFFICIENCY)

Total Capital Investment for Compressors $27,199,794

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Disscussions with Bechtel and Air Liquide (Nexant re

Hydrogen Losses from Compressors 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Refueling Station - Gaseous H2 tabCompressor Electricity Demand 70,343,075 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Based on vendor data from Neuman&Esser, BurckhSection 2.2.5)

Compressor Electricity Demand 0.5591 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Based on vendor data from Neuman&Esser, Burckhreport - Section 2.2.5)

Compressor Electricity Cost $0.056 2005$ / kWh

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.htm

EIA AEO 2005 and 2007

Total Capital Investment for Pipeline System $377,283,372

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.2. DE-FG36-05GO15032.

HDSAM version 2.02 calculations based on data from 

Hydrogen Losses from Pipelines 0.10% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

Number of transmission pipelines 1 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Default in HDSAM version 2.02

Transmission pipeline diameter 11.00 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equaTransmission pipeline inlet pressure 999 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline outlet pressure 705 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline length 62 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

Number of trunk pipelines 4 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input data 

cell B58

Trunk #1 pipeline diameter 7.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equaTrunk #1 pipeline inlet pressure 603 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #1 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #1 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #1 pipeline length 17 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input data 

Electric Company, San Francisco), Scenario Parame

Bio-Pipe Pathway Details R090209A 090806 v09.xls

206
Parameter Value Units Reference 

Trunk #2 pipeline diameter 10.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #2 pipeline inlet pressure 588 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #2 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #2 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #2 pipeline length 40 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Parameters tab, cell F169

Trunk #3 pipeline diameter 12.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #3 pipeline inlet pressure 573 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #3 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #3 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #3 pipeline length 65 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Parameters tab, cell F170

Trunk #4 pipeline diameter 10.75 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #4 pipeline inlet pressure 558 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #4 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #4 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #4 pipeline length 90 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Parameters tab, cell F171

Number of service pipelines 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Electric Company, San Francisco), H2 Pipeline tab, 

Service pipeline diameter 1 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Service pipeline inlet pressure 382 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Service pipeline outlet pressure 294 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Service pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Service pipeline length 1.1 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Electric Company, San Francisco), H2 Pipeline tab, 

Pipeline Geologic Storage Total Capital Investment $36,988,376

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report - Section 2.2.12)

Hydrogen Losses from Geologic Storage 0.02% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

Geologic Storage Capacity 41,864,765 m^3 CalculationGeologic Storage Design Capacity 3,762,787 kg H2 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Gaseous H2 Geolo

Geologic Storage Electricity Demand 961,465 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report- Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Demand 0.0076 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report- Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Cost $0.052 2005$ / kWh

Energy Information Administration. (2005, January). Annual Energy Outlook 2005 with Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C. Retreived from http://www.eia.doe.gov/oiaf/archive/aeo05/index.htm

EIA AEO 2005

Distribution Station

Gaseous Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - 

Electricity Required by Forecourt Station 1,416,755 kWh / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - Number of Compressor Stages 4 Stages in compressor Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaCompressor Isentropic Efficiency 65% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaDesign Capacity 1,516

kg H2 / day

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.4. DE-FG36-05GO15032.

HDSAM version 2.02 calculation based on Chevron Rate*(1+summer surge)*(1+Friday surge), Refueling 

Operating Capacity 1,278 kg H2 / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Adjusted dispensing rate=city use/number of stations

Bio-Pipe Pathway Details R090209A 090806 v09.xls

207
Parameter Value Units Reference 

Capacity Factor 84% N/A calculationSite storage (Low Pressure) 470

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (Nexant Report - Se

Site storage (Cascade) 582

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4 DE-FG36-05GO15032.

HDSAM calculations (Nexant Report - Section 2.3.2.

Site storage 69% % of design H2 distribution N/A calculationDispensing Pressure 6,250

psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 default (see Nexant Report-Se

Hydrogen Losses due to leaks 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - Ga

Electrical Voltage Supply Requirement 480

Volts

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (see Nexant ReporB137

Distribution System total capital investment $3,117,483

2005$ / station

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5.2. DE-FG36-05GO15032.

Nexant Report - Section 2.2.5.2

Distribution System electricity cost $115,508 2005$ / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - 

Distribution Labor Required 3,951 hr / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - Distribution System labor cost $39,513

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Sec

Distribution System total O&M cost $298,898

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (Nexant Report - S

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Type of Oxygenate in RFG None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planO2 Content in RFG 0% wt % U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, page 197: vehicles within the same Ratio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:well-known fuel cell emissions (no PRatio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:reasonable to assume FCV has sam

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $4.23 $ / kg Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 607 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 335 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Petroleum Input 180 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 1,122 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 6,695 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 64 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 70 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

Bio-Pipe Pathway Details R090209A 090806 v09.xls

208
209

Appendix E — Natural Gas–Pipeline Supporting Tables and 

Figures
Hydrogen Produced In Central Plant and Transported as Gas via Pipeline

2,000 Btu 11,000 Btu

Electricity for Electricity forCompression Forecourt

00

2,000 Btu Electricity Hydrogen Gas Hydr

161,000 Btu Natural Gas 117,000 Btu 116

00

0

46,000 Btu Energy Lost 1,000 Btu 13,000 Btu Energy Lost

HydrogenLost

Known Issue: Hydrogen losses are estimated in HDSAM but are not included in GREET

Case DefinitionYear: 2005Hydrogen as GasCentral Production

55% Natural Gas Feedstock

Sequestration: NoTransport for Delivery: PipelineVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

Production Process Energy EfficiencyPathway Efficiency

72%66%

Levelized Cost of H2 at Pump ($/kg) 3.95Well-to-Wheels Total Energy Use (Btu/mile)Well-to-Wheels Petroleum Energy Use (Btu/mile)Well-to-Wheels Greenhouse Gas Emissions (g/mile)

4,65955318 WTP Emissions (lb 

CO2 Equivalent / GGE fuel available): 

31

WTP Efficiency

Central Production Compression & Pipeline Compression, Storage, & Dispensing

210
NG Delivery Pressure Average of gas companies

NG Quality at Delivery Average of gas companies

NG Recovery Efficiency 97.2%

NG emitted & combusted during recovery 0.35%

NG processing energy efficiency 97.2% NG Cost $0.243 2005 $ / Nm^3

NG emitted & combusted during processin 0.15% NG Cost $0.958 2005$ / kg H2 distributed

NG emitted & combusted during transport 0.14 g / MMBtu

NG transport distance 500 miles WTG CO2 Emissions 589 g / 116000Btu to Pump

Coal Input from "Well" 252 Btu / 116000Btu to Pump WTG CH4 Emissions 16 g / 116000Btu to Pump

Natural Gas Input from "Well" 122,927 Btu / 116000Btu to Pump Compression Reqs (stages & eff) average of gas companies WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 492 Btu / 116000Btu to Pump WTG GHG Emissions 994 g CO2 eq./ 116000 Btu

Natural gas consumption 4.50 N m^3/kg H2 produced Hydrogen Output Pressure Not Available psi

Electricity consumption 0.57 kWh / kg H2 Hydrogen Outlet Quality 1

Process (De-Ionized) Water Consumptio 12.70 L / kg H2

Cooling Water Consumption 5.66 L / kg H2 Central plant design capacity 379,387 kg/day Total capital investment $1.45 2005$ / annual kg H2 (effective

Capacity factor 90% Electricity cost $0.03 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 71.9% Other operating costs $0.08 2005$ / kg H2 produced

Total Capital Investment $180,543,901 2005$ Electricity Mix US Mix Levelized Cost of Prod (excl feedst $0.38 2005$ / kg H2 distributed

After-tax IRR 10%

Assumed Plant Life 40 years

SMR CO2 Emissions 10,233 g / 116000Btu to Pump

Coal Input from "Well" 3,440 Btu / 116000Btu to Pump SMR CH4 Emissions 7 g / 116000Btu to Pump

Natural Gas Input from "Well" 47,416 Btu / 116000Btu to Pump SMR N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 433 Btu / 116000Btu to Pump SMR GHG Emissions 10,410 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69% capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 24,676 Btu / 116000 Btu

Natural Gas Input from "Well" 176,371 Btu / 116000 Btu

Petroleum Input from "Well" 2,489 Btu / 116000 Btu

Fossil Energy Input from "Well" 203,535 Btu / 116000 Btu

WTP CO2 Emissions 13,599 g / 116000 Btu

WTP CH4 Emissions 26 g / 116000 Btu

WTP N2O Emissions 0 g / 116000 Btu

WTP GHG Emissions 14,283 116000 Btu

Levelized Cost of Hydrogen ($/kg) $3.95 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 549 Btu / mi

Natural Gas Input from "Well" 3,922 Btu / mi

Petroleum Input from "Well" 55 Btu / mi

Fossil Energy Input from "Well" 4,527 Btu / mi

WTW CO2 Emissions 302 g / mi

WTW CH4 Emissions 1 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 318 g / mi

Levelized Cost of Hydrogen ($/mi) $0.0878 2005 $/mi

Inputs Outputs

Vehicle

NG Recovery, Processing, & Transport

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

NG-Pipe Pathway Details R090304E 090821 v09.xls

211
Gasification Transport Distribution

Coal 3,440 Btu/116000 Btu Coal 3,306 Btu/116000 Btu Coal 17,677 Btu/116000 Btu

Natural Gas 47,416 Btu/116000 Btu Natural Gas 950 Btu/116000 Btu Natural Gas 5,078 Btu/116000 Btu

Petroleum 433 Btu/116000 Btu Petroleum 246 Btu/116000 Btu Petroleum 1,317 Btu/116000 Btu

Total Energy 52,018 Btu/116000 Btu Total Energy 5,938 Btu/116000 Btu Total Energy 27,816 Btu/116000 Btu

CO2 Emissions 10,233 g/116000 Btu CO2 Emissions 436 g/116000 Btu CO2 Emissions 2,333 g/116000 Btu

CH4 Emissions 7 g/116000 Btu CH4 Emissions 1 g/116000 Btu CH4 Emissions 3 g/116000 Btu

N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu

GHG Emissions 10,410 g/116000 Btu GHG Emissions 452 g/116000 Btu GHG Emissions 2,419 g/116000 Btu

Feedstock 

Coal 252 Btu/116000 Btu 

Natural Gas 122,927 Btu/116000 Btu 

Petroleum 492 Btu/116000 Btu Reforming & Purification Transport Distribution 

Total Energy 7,723 Btu/116000 Btu 

CO2 Emissions 589 g/116000 Btu Transport Losses 0.63% Distribution Losses 0.50% CO

CH4 Emissions 16 g/116000 Btu CH

N2O Emissions 0 g/116000 Btu N2

GHG Emissions 994 g/116000 Btu GH

NG-Pipe Pathway Details R090304E 090821 v09.xls

212
Parameter Value Units Reference C

Case Definition

Base Year 2005 None Default for NG-Pipe Pathway study

Production Technology Natural Gas None Default for NG-Pipe Pathway studyForm of H2 During Delivery Gas None Default for NG-Pipe Pathway studyDelivery Mode Pipeline None Default for NG-Pipe Pathway studyForecourt Station Size 1278 kg/day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas ba

Vehicle Type passenger cars None Default for NG-Pipe Pathway studyVehicles' Fuel Economy 45.0 mile / gge

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles . Argonne National Laboroatory presentation, Chicago, IL. Retreived from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel ecoPowertrain Simulation Analysis Toolkit V 6.2 SP1, Suhttp://www.transportation.anl.gov/modeling_simulationwhich was determined by multiplying the projected EP

Market Definition

City Population 1,247,364 people Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN

Market penetration 50% (% vehicles in city) U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Number of H2 vehicles in city 462,772 H2 vehicles / city Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenari

Miles driven per vehicle 12,000 mile / vehicle year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Key delivery input in HDSAM version 2.02; Scenario tCity hydrogen use 344,451 kg / d Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenariNumber of H2 refueling stations in city 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenariNumber of H2 stations/Number of gasoline stations 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenariAverage distance between stations (mi) 1.46 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenari

Feedstock Recovery, Processing, & Transport

Natural Gas

NG recovery efficiency 97.2% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. Table 4.11

NG used & lost during recovery 0.35% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory.NG processing energy efficiency 97.2% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory.NG used & lost during processing 0.15%

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pdf.

Volume lost from EPA/GRI paper by Kirchgessner er 

less than current average

NG used & lost during transport 0.14

g / (MM Btu mil)

Kirchgessner, D. A., Lott, R. A., Cowgill, R. M., Harrison, M. R. & Shires, T. M. (1996). Estimate of Methane Emissions from the U.S. Natural Gas Industry, EPA/Gas Research Institute paper. Retrieved from http://www.epa.gov/ttn/chief/ap42/ch14/related/methane.pdf.

GREET 97% is comparable to several other models; vDOE/EIA-0573; future marginal increase is assumed t

NG transport distance 500 miles Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory.

Electricity

Grid mix for production US Mix None Default for NG-Pipe Pathway study

Biomass Fraction

1.2%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Coal Fraction

51.7%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Natural Gas Fraction

15.7%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Nuclear Fraction

20.3%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Residual Oil Fraction

2.9%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Others (Carbon Neutral)

8.2%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewabcategory 

Grid mix for pipeline compressors US Mix None Default for NG-Pipe Pathway study

Grid mix for compression at distribution US Mix None Default for NG-Pipe Pathway study

H2 Production

Production Facility Average Output 341,448 kg / facility d (after capacity factor is included) Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version 

Corresponding capacity factor 90% H2A Production model default

Total Capital Investment $180,543,901 2005 $ Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version 

turnkey quotation from Krupp-Uhde, updated to 2005

NG-Pipe Pathway Details R090304E 090821 v09.xls

213
Parameter Value Units Reference C

Natural gas feedstock consumption 4.50 normal m^3 / kg H2 produced Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty.

Current central H2A production from NG basis version energy/material balances; "To arrive at a cost estimattechnology obtained from verifiable sources. The planscale Conoco-Phillips (EGas) gasifier, conventional gacommercial sulfuric acid technology, and commercial choice for this study since it has been operated on boHaldor Topsoe commercial catalyst spec., UOP comm

Natural Gas feedstock cost $ 0.243 2005$ / Nm^3

Industrial natural gas price from AEO 2005 "High A" case for startup year (2005). Escalated from 2003 dollars to 2005 dollars. File downloaded from http://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls) 

AEO 2005 High A Case - Industrial price; Escalated frhttp://www.eia.doe.gov/oiaf/aeo/index.html (file name 

Natural Gas LHV 34,714 Btu / normal m^3 - review units Hydrogen Analysis Resource Center. (2008, September 5). Lower and Higher Heating Values of Hydrogen and Fuels . Retrieved from http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/401 LHV of Natural Gas; 983 Btu/ft3

Natural gas utility consumption 0.00 normal m^3 / kg H2 produced Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty.

Electricity feedstock consumption 0.00 kWh / kg H2 Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty.

Electricity utility consumption (both production and compression) 0.57 kWh / kg H2 Calculation Sum of production and CSD consumption of "utility" e

Electricity utility consumption (production only) 0.57 kWh / kg H2 Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version Electricity Utility Price 0.0555

2005 $/kWh

Industrial electricity price from AEO 2005 "High A" case for startup year (2005). Escalated from 2003 dollars to 2005 dollars. File downloaded from http://www.eia.doe.gov/oiaf/aeo/index.html (file name aeo_hw-3.xls) 

AEO 2005 High A Case - Industrial price; Escalated frhttp://www.eia.doe.gov/oiaf/aeo/index.html (file name 

Process Water Consumption 3.36 gal / kg H2 Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version Water Consumption for Cooling 1.50 gal / kg H2 Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version Electricity co-product production 0.00 kWh / kg H2 N/A

Oxygen co-product production 0.0 kg / kg H2 N/A

Steam co-product production 0.0 kg / kg H2 N/A

Total Annual Fixed Operating Costs $6,916,975 2005$ / yr Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version Total Annual Variable Operating Costs $144,393,400 2005$ / yr Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from NG basis version Total Annual Operating Costs $151,310,375 2005$ / yr None Addtion of Annual Total Fixed Operating Costs and ToProduction energy efficiency (does not include electricity for forecourt compressio 71.9% Calculated from H2A values Calculated from H2A values

Share of process fuel - biomass 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - coal 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - natural gas 4.4% Calculated from H2A values Calculated from H2A values

Share of process fuel - ethanol 0.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - electricity 95.6% Calculated from H2A values Calculated from H2A values

Hydrogen outlet pressure (before CSD) Not Available psi None

Hydrogen quality before transport 99.6% % H2 Rutkowski, M. (2008, Sept 22). Current (2005) Hydrogen from Natural Gas without CO2 Capture and Sequestration . Golden, CO: National Renewable Energy Laboratoty. discussed in the process description

Financial Parameters

After-tax Real IRR 10% James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versi

Plant Life 40

years

James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versi

Federal Tax Rate 35.0% James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versiState Tax Rate 6.0% James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versiTotal Tax Rate 38.9% James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versiFrection Equity 100% James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current central H2A production from SMR basis versi

Transport, Delivery, and Storage Energy Requirements

Pipeline Delivery

Average Hydrogen Flowrate (Entering System) 348,364 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, m

TRANSMISIIION SYSTEM=CITY PEAK DEMAND/TRMASS EFFICIENCY)

Average Hydrogen Flowrate (Distributed) 344,451 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, m

USE/TOTAL PIPELINE MASS EFFICIENCY/REF.STA

Summer Surge: % above the System Average Daily Demand 10% % above Average Daily Demand

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.9. DE-FG36-05GO15032.

Nexant Report - Section 2.1.9

Friday Peak 8% % above Average Daily Demand

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.9. DE-FG36-05GO15032.

Nexant Report - Section 2.1.9

Peak Hydrogen Flowrate 381,192 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, m

DISTRIBUTION SYSTEM=CITY PEAK DEMAND/DISEFFICIENCY)

Total Capital Investment for Compressors $27,199,794 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations, data from disscussions with BecHydrogen Losses from Compressors 0.50%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

Table 2.26

Compressor Electricity Demand 70,343,075 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM calculations - data from Nexant recommendaCompression, Ariel Compressors, Dresser-Rand - see 

Compressor Electricity Demand 0.5591 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM calculations - data from Nexant recommendaCompression, Ariel Compressors, Dresser-Rand - see 

NG-Pipe Pathway Details R090304E 090821 v09.xls

214
Parameter Value Units Reference C

Compressor Electricity Cost $0.056 2005$ / kWh

Energy Information Administration. (2005, January). Annual Energy Outlook 2005 with 

Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C. Retreived from http://www.eia.doe.gov/oiaf/archive/aeo05/index.htm

EIA AEO 2005 and 2007

Total Capital Investment for Pipeline System $377,283,372

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.2. DE-FG36-05GO15032.

HDSAM calculations based on data from GTI, Bechte

Hydrogen Losses from Pipelines 0.10%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

Calculated based upon natural gas pipelines; Nexant 

Number of transmission pipelines 1 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Default in HDSAM

Transmission pipeline diameter 11.00 in Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Transmission pipeline inlet pressure 999 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Transmission pipeline outlet pressure 705 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Transmission pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Transmission pipeline length 62 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Based on input parameter: city

Number of trunk pipelines 4 Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . DE-FG36-05GO15032.

HDSAM calculations based on input data and HDSAM to four trunk lines within a given metropolitan area witThe model iterates on the number and location of trunconfiguration is obtained at a minimum cost." Nexant 

Trunk #1 pipeline diameter 7.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Trunk #1 pipeline inlet pressure 603 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #1 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #1 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #1 pipeline length 17 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM 

San Francisco)

Trunk #2 pipeline diameter 10.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Trunk #2 pipeline inlet pressure 588 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #2 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #2 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #2 pipeline length 40 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM Trunk #3 pipeline diameter 12.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Trunk #3 pipeline inlet pressure 573 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #3 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #3 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Repor t- Section 2.1.6)

Trunk #3 pipeline length 65 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM Trunk #4 pipeline diameter 10.75 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Trunk #4 pipeline inlet pressure 558 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #4 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #4 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Trunk #4 pipeline length 90 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM Number of service pipelines 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM 

San Francisco)

Service pipeline diameter 1 in Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM Calculation: Panhandle B equation (Gas Proc

1998, http://gpsa.gasprocessors.com)

Service pipeline inlet pressure 382 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

NG-Pipe Pathway Details R090304E 090821 v09.xls

215
Parameter Value Units Reference C

Service pipeline outlet pressure 294 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Service pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Report - Section 2.1.6)

Service pipeline length 1.1 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM 

San Francisco)

Pipeline Geologic Storage Total Capital Investment $36,988,376

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM calculations (cost data from ConocoPhilips aSection 2.2.12)

Hydrogen Losses from Geologic Storage 0.02% H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural Resources CanadaGeologic Storage Capacity 41,864,765 m^3 H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural Resources CanadaGeologic Storage Design Capacity 3,762,787 kg H2 H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural Resources Canada

Geologic Storage Electricity Demand 961,465 kWh / year Nexant (2008) Section 2.2.12, 2.2.5 HDSAM calculations (cost data from ConocoPhilips a

Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Demand 0.0076 kWh / kg H2 Nexant (2008) Section 2.2.12, 2.2.5 HDSAM calculations (cost data from ConocoPhilips a

Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Cost $0.052 2005$ / kWh

Energy Information Administration. (2005, January). Annual Energy Outlook 2005 with Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C. Retreived from http://www.eia.doe.gov/oiaf/archive/aeo05/index.htm

EIA AEO 2005

Distribution Station

Gaseous Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - G

Electricity Required by Forecourt Station 1,416,755 kWh / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - GNumber of Compressor Stages 4 Stages in compressor Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaseCompressor Isentropic Efficiency 65% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaseDesign Capacity 1,516

kg H2 / day

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.4. DE-FG36-05GO15032.

HDSAM version 2.02 calculation based on Chevron fuRate*(1+summer surge)*(1+Friday surge), Refueling S

Operating Capacity 1,278 kg H2 / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Adjusted dispensing rate=city use/number of stations/Capacity Factor 84% calculationSite storage (Low Pressure) 470

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (Nexant Report - Sec

Site storage (Cascade) 582

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4 DE-FG36-05GO15032.

HDSAM calculations (Nexant Report - Section 2.3.2.4

Site storage 69% % of design H2 distribution calculationDispensing Pressure 6,250

psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 default (see Nexant Report-Sec

Hydrogen Losses due to leaks 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaseElectrical Voltage Supply Requirement 480

Volts

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (see Nexant Report B137

Distribution System total capital investment $3,117,483

2005$ / station

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5.2. DE-FG36-05GO15032.

Nexant Report - Section 2.2.5.2

Distribution System electricity cost $115,508 2005$ / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - GDistribution Labor Required 3,951 hr / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - GDistribution System labor cost $39,513

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Secti

Distribution System total O&M cost $298,898

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (Nexant Report - Se

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Type of Oxygenate in RFG None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planO2 Content in RFG 0% wt % U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

NG-Pipe Pathway Details R090304E 090821 v09.xls

216
Parameter Value Units Reference C

Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, page 197: vehicles within the same wRatio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:well-known fuel cell emissions (no PM

Ratio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:reasonable to assume FCV has same Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $3.95 $ / kg Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 549 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 3,922 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Petroleum Input 55 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 4,527 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 4,659 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 302 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 1 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 318 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

NG-Pipe Pathway Details R090304E 090821 v09.xls

217
218

Appendix F — Coal–Pipeline with Carbon Capture and 

Sequestration Supporting Tables and Figures
Hydrogen Produced In Central Plant and Transported as Gas via Pipeline

2,000 Btu 11,000 Btu

Electricity for Electricity forCompression Forecourt

0

213,000 Btu Coal

6,000 Btu Electricity Hydrogen Gas Hydr

0 117,000 Btu 116

00

0

101,000 Btu Energy Lost 1,000 Btu 13,000 Btu Energy Lost

HydrogenLost

Known Issue: Hydrogen losses are estimated in HDSAM but are not included in GREET

Case DefinitionYear: 2005Hydrogen as GasCentral Production

44% Coal Feedstock

Sequestration: YesTransport for Delivery: PipelineVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

Production Process Energy EfficiencyPathway Efficiency

54%50%

Levelized Cost of H2 at Pump ($/kg) 4.68Well-to-Wheels Total Energy Use (Btu/mile)Well-to-Wheels Petroleum Energy Use (Btu/mile)Well-to-Wheels Greenhouse Gas Emissions (g/mile)

5,85980166 WTP Emissions (lb 

CO2 Equivalent / GGE fuel available): 

16

WTP Efficiency

Central Production Compression & Pipeline Compression, Storage, & Dispensing

219
Energy Recovery 99.3%

Energy Used 7049 Btu / MMBtu Coal Delivered

Diesel Used 3948 Btu / MMBtu Coal Delivered Coal price at H2 production $33.98 2005 $ / short ton

Electricity Used 1692 Btu / MMBtu Coal Delivered Levelized Cost of Coal $0.31 2005$ / kg H2 distributed

WTG CO2 Emissions 114 g / 116000Btu to Pump

Coal Input from "Well" 116,427 Btu / 116000Btu to Pump WTG CH4 Emissions 14 g / 116000Btu to Pump

Natural Gas Input from "Well" 145 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 712 Btu / 116000Btu to Pump WTG GHG Emissions 462 g CO2 eq./ 116000 Btu

Coal consumption 7.8 kg / kg H2 produced Hydrogen Output Pressure 300 psi

Natural gas consumption 0.00 N m^3/kg H2 produced

Electricity consumption 1.72 kWh / kg H2

Process Water Consumption 11.02 L / kg H2 Central plant design capacity 307,673 kg/day Total capital investment $6.84 2005$ / annual kg H2 (effective

Capacity factor 90% Electricity cost $0.10 2005$ / kg H2 produced

Electricity price $0.0555 2005 $/kWh Process energy efficiency 53.6% Natural Gas Cost $0.00 2005$ / kg H2 produced

Total Capital Investment $691,377,851 2005$ Electricity Mix US Mix Other operating costs $0.38 2005$ / kg H2 produced

After-tax IRR 10% Levelized Cost of Prod (excl feedst $1.76 2005$ / kg H2 distributed

Assumed Plant Life 40

CO2 Captured for sequestration 90% H2 Prod CO2 Emissions 3,803 g / 116000Btu to Pump

Coal Input from "Well" 105,782 Btu / 116000Btu to Pump CO2 Pipeline Length 100 miles H2 Prod CH4 Emissions 13 g / 116000Btu to Pump

Natural Gas Input from "Well" 3,022 Btu / 116000Btu to Pump Number of injection wells 1 H2 Prod N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,332 Btu / 116000Btu to Pump Injection well depth 1524 m H2 Prod GHG Emissions 4,136 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,306 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 950 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 452 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69% capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,677 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,078 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 243,192 Btu / 116000 Btu

Natural Gas Input from "Well" 9,194 Btu / 116000 Btu

Petroleum Input from "Well" 3,608 Btu / 116000 Btu

Fossil Energy Input from "Well" 255,994 Btu / 116000 Btu

WTP CO2 Emissions 6,694 g / 116000 Btu

WTP CH4 Emissions 31 g / 116000 Btu

WTP N2O Emissions 0 g / 116000 Btu

WTP GHG Emissions 7,477 116000 Btu

Levelized Cost of Hydrogen ($/kg) $4.68 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 5,408 Btu / mi

Natural Gas Input from "Well" 204 Btu / mi

Petroleum Input from "Well" 80 Btu / mi

Fossil Energy Input from "Well" 5,693 Btu / mi

WTW CO2 Emissions 149 g / mi

WTW CH4 Emissions 1 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 166 g / mi

Levelized Cost of Hydrogen ($/mi) $0.1040 2005 $/mi

Inputs Outputs

Vehicle

Coal Mining & Delivery

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production & CCS

Forecourt Distribution

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

220
Gasification Transport Distribution

Coal 105,782 Btu/116000 Btu Coal 3,306 Btu/116000 Btu Coal 17,677 Btu/116000 Btu

Natural Gas 3,022 Btu/116000 Btu Natural Gas 950 Btu/116000 Btu Natural Gas 5,078 Btu/116000 Btu

Petroleum 1,332 Btu/116000 Btu Petroleum 246 Btu/116000 Btu Petroleum 1,317 Btu/116000 Btu

Total Energy 112,337 Btu/116000 Btu Total Energy 5,938 Btu/116000 Btu Total Energy 27,816 Btu/116000 Btu

CO2 Emissions 3,803 g/116000 Btu CO2 Emissions 436 g/116000 Btu CO2 Emissions 2,333 g/116000 Btu

CH4 Emissions 13 g/116000 Btu CH4 Emissions 1 g/116000 Btu CH4 Emissions 3 g/116000 Btu

N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu

GHG Emissions 4,136 g/116000 Btu GHG Emissions 452 g/116000 Btu GHG Emissions 2,419 g/116000 Btu

Feedstock 

Coal 116,427 Btu/116000 Btu 

Natural Gas 145 Btu/116000 Btu 

Petroleum 712 Btu/116000 Btu Gasification, Conversion, Transport Distribution 

Total Energy 1,357 Btu/116000 Btu & CCS 

CO2 Emissions 114 g/116000 Btu Transport Losses 0.63% Distribution Losses 0.50% CO

CH4 Emissions 14 g/116000 Btu CH

N2O Emissions 0 g/116000 Btu N2

GHG Emissions 462 g/116000 Btu GH

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

221
Parameter Value Units Reference C

Case Definition

Base Year 2005 None Default for Coal-Pipe Pathway studyProduction Technology Coal None Default for Coal-Pipe Pathway studyForm of H2 During Delivery Gas None Default for Coal-Pipe Pathway study

Delivery Mode Pipeline None Default for Coal-Pipe Pathway study

Forecourt Station Size 1278 kg/day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day . Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas b

Vehicle Type passenger cars None Default for Coal-Pipe Pathway studyVehicles' Fuel Economy 45.0 mile / gge

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles . Argonne National Laboroatory presentation, Chicago, IL. Retreived from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel ePowertrain Simulation Analysis Toolkit V 6.2 SP1, Shttp://www.transportation.anl.gov/modeling_simulatioeconomy which was determined by multiplying the p

Market Definition

City Population 1,247,364 people Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN

Market penetration 50% (% vehicles in city) U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Number of H2 vehicles in city 462,772 H2 vehicles / city Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Demand calculation by HDSAM version 2.02; Scena

Miles driven per vehicle 12,000 mile / vehicle year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model Key delivery input in HDSAM version 2.02; Scenario City hydrogen use 344,451 kg / d Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scena

Number of H2 refueling stations in city 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenaNumber of H2 stations/Number of gasoline stations 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; ScenaAverage distance between stations (mi) 1.46 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scena

Feedstock Recovery, Processing, & Transport

Electricity

Grid mix for production US Mix None Default for Coal-Pipe Pathway study

Biomass Fraction

1.2%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Coal Fraction

51.7%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Natural Gas Fraction

15.7%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Nuclear Fraction

20.3%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Residual Oil Fraction

2.9%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Others (Carbon Neutral)

8.2%

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.htm

US grid mix. National electricity generation data from from total generation values reported with all renewacategory 

Grid mix for pipeline compressors US Mix None Default for Coal-Pipe Pathway studyGrid mix for compression at distribution US Mix None Default for Coal-Pipe Pathway study

Coal

Energy efficiency of coal mining and delivery 99.3% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B18

Energy requirement for coal mining and delivery 7049 Btu / MMBtu None Calculated from energy efficiency of coal mining and Share of Resid Oil for coal mining & delivery 7.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B22Share of Diesel for coal mining & delivery 56.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B23Share of Gasoline for coal mining & delivery 3.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B24Share of Natural Gas for coal mining & delivery 1.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B25Share of Coal for coal mining & delivery 9.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B26Share of Electricity for coal mining & delivery 24.0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Coal Tab B27Resid Oil requirement for coal mining and delivery 493 Btu / MMBtu None Calculated from share of reisd oil for coal mining and 

delivery (cell D54)

Diesel requirement for coal mining and delivery 3948 Btu / MMBtu None Calculated from share of diesel for coal mining & del

(cell D54)

Gasoline requirement for coal mining and delivery 211 Btu / MMBtu None Calculated from share of gasoline for coal mining an

delivery (cell D54)

Natural Gas requirement for coal mining and delivery 70 Btu / MMBtu None Calculated from share of reisd oil for natural gas min

and delivery (cell D54)

Coal requirement for coal mining and delivery 634 Btu / MMBtu None Calculated from share of coal for coal mining and de

(cell D54)

Electricity requirement for coal mining and delivery 1692 Btu / MMBtu None Calculated from share of electricity for coal mining a

delivery (cell D54)

H2 Production

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

222
Parameter Value Units Reference C

Production Facility Average Output 276,906 kg / facility d (after capacity factor is included) Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Corresponding capacity factor 90% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

C21

Total Capital Investment $691,377,851 2005 $

Spath, P., Aden, A., Eggeman, T., Ringer, M., Wallace, B. & Jechura, J. (2005, May) Biomass to Hydrogen Production Detailed Design and Economics Utilizing the Battelle Columbus Laboratory Indirectly-Heated Gasifier. Table 10. NREL/TP-510-37408. Golden, CO: National Renewable Energy Laboratory

Total installed capital cost of $102M ($2002) (see Tafor additional compression was removed to maintain 

Pittsburgh #8 coal feedstock consumption 7.8 kg / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Pittsburgh #8 coal feedstock cost $33.98 2005 $/ton Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty.

Pittsburgh #8 coal LHV 23,824,506 Btu / ton Coal Composition for Coal Gasification to Hydrogen in Central Plants: Pittsburgh No. 8 Bituminous Coal (from M. Rutkowski of Parsons, December 2003). 

Natural gas feedstock consumption 0.00 normal m^3 / kg H2 produced Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Natural gas utility consumption 0.00 normal m^3 / kg H2 produced Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty.

Electricity feedstock consumption 0.00 kWh / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Electricity utility consumption (both production, carbon capture & transport, and co 1.72 kWh / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versElectricity utility consumption (production only) 0.00 kWh / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versProcess Water Consumption 2.91 gal / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versWater Consumption for Cooling 0.00000 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. N/AElectricity co-product production 0.00 kWh / kg H2 None N/A

Oxygen co-product production 0.0 kg / kg H2 None N/ASteam co-product production 0.0 kg / kg H2 None N/A

Total Annual Fixed Operating Costs $28,653,073 2005$ / yr Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Total Annual Variable Operating Costs $37,340,700 2005$ / yr Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Data

Total Annual Operating Costs (includes CCS) $79,129,540 2005$ / yr None Addtion of Annual Total Fixed Operating Costs and T

Production energy efficiency (does not include electricity for forecourt compressio 53.6% Calculated from H2A values Calculated from H2A values

Share of process fuel - biomass 0.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - coal 94.0% Calculated from H2A values Calculated from H2A values

Share of process fuel - natural gas 6.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - ethanol 0.0% Calculated from H2A values Calculated from H2A valuesShare of process fuel - electricity 0.0% Calculated from H2A values Calculated from H2A values

Hydrogen outlet pressure (before CSD) 300 psi Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. From comments in Current central H2A production fr

Hydrogen quality before transport 99.8% % H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. From comments in Current central H2A production fr

Carbon Capture and Sequestration

CO2 Captured for Sequestration 90% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Electricity utility consumption (carbon capture, transport, & sequestration only) 1.72 kWh / kg H2 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versElectricity Utility Price for carbon capture and transport $0.055 2005 $/kWh Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versTotal Annual Fixed Operating Costs $3,492,544 2005$ / yr Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versTotal Annual Variable Operating Costs $9,643,224 2005$ / yr Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versCompressor electricity requirement 22,044 kW Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versPressure required to flow to sequestration site and be sequestered 15.0 Mpa Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versIsentropic Efficiency 74.0% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versCO2 Pipeline Length 100 miles Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versTerrain Type for Pipeline <20% Mountainous Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versNumber of injection wells 1 Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versWell depth 1524 m Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Financial Parameters

After-tax Real IRR 10% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Plant Life 40

years

Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Federal Tax Rate 35.0% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from biomass basis vState Tax Rate 6.0% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versTotal Tax Rate 38.9% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis versFrection Equity 100% Rutkowski, M. (2008, May 28). Current (2005) Hydrogen from Coal with CO2 Capture and Storage . Golden, CO: National Renewable Energy Laboratoty. Current central H2A production from coal basis vers

Transport, Delivery, and Storage Energy Requirements

Pipeline Delivery

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

223
Parameter Value Units Reference C

Average Hydrogen Flowrate (Entering System) 348,364 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

THRU TRANSMISSION SYSTEM=CITY PEAK DEMEFFICIENCY/REF.STATION MASS EFFICIENCY)

Average Hydrogen Flowrate (Distributed) 344,451 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

HDSAM version 2.02 calculation based on input paraDAILY USE/TOTAL PIPELINE MASS EFFICIENCY/

Summer Surge: % above the System Average Daily Demand 10% % above Average Daily Demand Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Scenario Parameters tab, cell B90

Friday Peak 8% % above Average Daily Demand Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Scenario Parameters tab, cell B92

Peak Hydrogen Flowrate 381,192 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

THRU DISTRIBUTION SYSTEM=CITY PEAK DEMAEFFICIENCY/REF.STATION MASS EFFICIENCY)

Total Capital Investment for Compressors $27,199,794

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Disscussions with Bechtel and Air Liquide (Nexant re

Hydrogen Losses from Compressors 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM default, Refueling Station - Gaseous H2 tab

Compressor Electricity Demand 70,343,075 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Based on vendor data from Neuman&Esser, BurckhSection 2.2.5)

Compressor Electricity Demand 0.5591 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

Based on vendor data from Neuman&Esser, Burckhreport - Section 2.2.5)

Compressor Electricity Cost $0.056 2005$ / kWh

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.htm

EIA AEO 2005 and 2007

Total Capital Investment for Pipeline System $377,283,372

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.2. DE-FG36-05GO15032.

HDSAM version 2.02 calculations based on data from 

Hydrogen Losses from Pipelines 0.10% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

Number of transmission pipelines 1 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Default in HDSAM version 2.02

Transmission pipeline diameter 11.00 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equaTransmission pipeline inlet pressure 999 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline outlet pressure 705 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Transmission pipeline length 62 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation based on input para

Number of trunk pipelines 4 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

HDSAM version 2.02 calculation based on input data cell B58

Trunk #1 pipeline diameter 7.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equaTrunk #1 pipeline inlet pressure 603 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #1 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #1 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #1 pipeline length 17 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

HDSAM version 2.02 calculation based on input data Electric Company, San Francisco), Scenario Parame

Trunk #2 pipeline diameter 10.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #2 pipeline inlet pressure 588 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #2 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #2 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #2 pipeline length 40 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

HDSAM version 2.02 calculations based on input daParameters tab, cell F169

Trunk #3 pipeline diameter 12.25 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #3 pipeline inlet pressure 573 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #3 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #3 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #3 pipeline length 65 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model 

(HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

HDSAM version 2.02 calculations based on input daParameters tab, cell F170

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

224
Parameter Value Units Reference C

Trunk #4 pipeline diameter 10.75 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Trunk #4 pipeline inlet pressure 558 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #4 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Trunk #4 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Trunk #4 pipeline length 90 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Parameters tab, cell F171

Number of service pipelines 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Electric Company, San Francisco), H2 Pipeline tab, 

Service pipeline diameter 1 in Gas Processors Supplier Association. (2004). GPSA Engineering Data Book, 12th Edition. Tulsa, OK. Retrieved from http://gpaglobal.org/gpsa/book.php HDSAM version 2.02 calculation: Panhandle B equa

Service pipeline inlet pressure 382 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Service pipeline outlet pressure 294 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Ai

Section 2.1.6)

Service pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with AiSection 2.1.6)

Service pipeline length 1.1 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculations based on input da

Electric Company, San Francisco), H2 Pipeline tab, 

Pipeline Geologic Storage Total Capital Investment $36,988,376

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report - Section 2.2.12)

Hydrogen Losses from Geologic Storage 0.02% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory

Geologic Storage Capacity 41,864,765 m^3 Calculation

Geologic Storage Design Capacity 3,762,787 kg H2 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model HDSAM version 2.02 calculation, Gaseous H2 Geolo

Geologic Storage Electricity Demand 961,465 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report- Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Demand 0.0076 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (cost data from Co(Nexant Report- Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Cost $0.052 2005$ / kWh Energy Information Administration. (2005, January). Annual Energy Outlook 2005 with Projections EIA AEO 2005

Distribution Station

Gaseous Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - 

Electricity Required by Forecourt Station 1,416,755 kWh / station year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - Number of Compressor Stages 4 Stages in compressor Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaCompressor Isentropic Efficiency 65% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaDesign Capacity 1,516

kg H2 / day

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.4. DE-FG36-05GO15032.

HDSAM version 2.02 calculation based on Chevron Rate*(1+summer surge)*(1+Friday surge), Refueling 

Operating Capacity 1,278 kg H2 / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Adjusted dispensing rate=city use/number of stationsCapacity Factor 84% calculationSite storage (Low Pressure) 470

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (Nexant Report - Se

Site storage (Cascade) 582

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4 DE-FG36-05GO15032.

HDSAM calculations (Nexant Report - Section 2.3.2.

Site storage 69% % of design H2 distribution calculationDispensing Pressure 6,250

psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM version 2.02 default (see Nexant Report-Se

Hydrogen Losses due to leaks 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 default, Refueling Station - GaElectrical Voltage Supply Requirement 480

Volts

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM version 2.02 calculation (see Nexant ReporB137

Distribution System total capital investment $3,117,483

2005$ / station

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5.2. DE-FG36-05GO15032.

Nexant Report - Section 2.2.5.2

Distribution System electricity cost $115,508 2005$ / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - 

Distribution Labor Required 3,951 hr / station yr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM version 2.02 calculation, Refueling Station - Distribution System labor cost $39,513

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics (Nexant Report - Sec

Distribution System total O&M cost $298,898

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM version 2.02 calculations (Nexant Report - S

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

225
Parameter Value Units Reference C

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Type of Oxygenate in RFG None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planO2 Content in RFG 0% wt % U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, page 197: vehicles within the same Ratio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:well-known fuel cell emissions (no PRatio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:reasonable to assume FCV has sam

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2Marginal Electricity Generation Mix for Transportation Use US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $4.68 $ / kg Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 5,408 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 204 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Petroleum Input 80 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 5,693 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 5,859 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 149 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 1 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 166 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799 Golden, CO: National Renewable Energy Laboratory. MSM Results

Coal-Pipe Pathway Details R090819G2C 090827 v09.xls

226
227

Appendix G — Wind Electrolysis–Pipeline Supporting 

Tables and Figures
Hydrogen Produced In Central Plant and Transported as Gas via Pipeline

2,000 Btu 11,000 Btu

Electricity for Electricity forCompression Forecourt

00

188,000 Btu Electricity Hydrogen Gas Hydr

0 117,000 Btu 116

00

0

71,000 Btu Energy Lost 1,000 Btu 13,000 Btu Energy Lost

HydrogenLost

Known Issue: Hydrogen losses are estimated in HDSAM but are not included in GREET

Case DefinitionYear: 2005Hydrogen as GasCentral Production

52% Wind Feedstock

Sequestration: NoTransport for Delivery: PipelineVehicle Efficiency: 45.0 mile / GGECity Hydrogen Use: 344451 kg/day

WTP Emissions (lb CO2 Equivalent / GGE fuel available): 

6

WTP Efficiency

Levelized Cost of H2 at Pump ($/kg) 7.16Well-to-Wheels Total Energy Use (Btu/mile)Well-to-Wheels Petroleum Energy Use (Btu/mile)Well-to-Wheels Greenhouse Gas Emissions (g/mile)

4,9213564

Production Process Energy EfficiencyPathway Efficiency

62%58%

Central Production Compression & Pipeline Compression, Storage, & Dispensing

228
Wind-generated electricity on the grid is assumed.

The electrolyzers are not necessarily co-located with the wind farm.

Electricity price at H2 production $0.055 2005 $ / short ton

Levelized Cost of Wind Electricity $2.99 2005$ / kg H2 distributed

WTG CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump WTG CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump WTG N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump WTG GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption 53.48 kWh / kg H2 Hydrogen Output Pressure 450 psi

Process Water Consumption 11.1 L / kg H2 Central plant design capacity 52,300 kg/day Total capital investment $5.96 2005$ / annual kg H2 (effective

Cooling Water Consumption 1112 L / kg H2 Capacity factor 97% Electricity cost $2.96 2005$ / kg H2 produced

Process energy efficiency 62.3% Other operating costs $0.38 2005$ / kg H2 produced

Electrolyzer Cost 675 $ / kW Electricity Mix Wind Electricity Levelized Cost of Prod (excl feedst $1.56 2005$ / kg H2 distributed

Total Capital Investment $110,432,050 2005$ After-tax IRR 10%

Assumed Plant Life 40

H2 Prod CO2 Emissions 0 g / 116000Btu to Pump

Coal Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod CH4 Emissions 0 g / 116000Btu to Pump

Natural Gas Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 0 Btu / 116000Btu to Pump H2 Prod GHG Emissions 0 g CO2 eq./ 116000 Btu

Electricity consumption for compressor 0.56 kWh / kg H2 Total capital investment $3.51 2005$/annual kg distributed

Electricity consumption for geo storage 0.01 kWh / kg H2 Electricity cost $0.03 2005$ / kg H2

Total electricity consumption 0.57 kWh / kg H2

Electricity price for compressor $0.056 2005$ / kWh City Population 1,247,364 people

Electricity price for geologic storage $0.052 2005$ / kWh Hydrogen Vehicle Penetration 50% Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

City hydrogen use 125,810,766 kg / yr

Distance from City to Production Facility 62 miles

Geologic storage capacity 3,762,787 kg H2

Trunk #1-line length 17 miles

Trunk #2-line length 40 miles

Service-line length 1.1 miles / line Delivery CO2 Emissions 436 g / 116000Btu to Pump

Coal Input from "Well" 3,307 Btu / 116000Btu to Pump Number of service lines 270 Delivery CH4 Emissions 1 g / 116000Btu to Pump

Natural Gas Input from "Well" 949 Btu / 116000Btu to Pump Hydrogen losses 1.12% Delivery N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 246 Btu / 116000Btu to Pump Hydrogen loss factor 1.011 Delivery GHG Emissions 453 g CO2 eq./ 116000 Btu

Electricity consumption 3.04 kWh / kg H2 Hydrogen outlet pressure 6,250 psi

Electricity price $0.082 2005$ / kWh Basis -- Hydrogen Quantity 116,000 Btu (116,000 Btu/gal non-oxyg

Total capital investment $6.69 2005$/annual kg

Number of Distribution Stations 270 Electricity cost $0.25 2005$ / kg H2

Energy efficiency 92%

Number of Compression Steps 4 Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Isentropic Efficiency 65%

Site storage 69% capacity CSD CO2 Emissions 2,333 g / 116000Btu to Pump

Coal Input from "Well" 17,681 Btu / 116000Btu to Pump Hydrogen losses 0.50% CSD CH4 Emissions 3 g / 116000Btu to Pump

Natural Gas Input from "Well" 5,076 Btu / 116000Btu to Pump Hydrogen loss factor 1.005 CSD N2O Emissions 0 g / 116000Btu to Pump

Petroleum Input from "Well" 1,317 Btu / 116000Btu to Pump CSD GHG Emissions 2,419 g CO2 eq./ 116000 Btu

Well-to-Pump Results

Coal Input from "Well" 20,988 Btu / 116000 Btu

Natural Gas Input from "Well" 6,026 Btu / 116000 Btu

Petroleum Input from "Well" 1,564 Btu / 116000 Btu

Fossil Energy Input from "Well" 28,577 Btu / 116000 Btu

WTP CO2 Emissions 2,772 g / 116000 Btu

WTP CH4 Emissions 4 g / 116000 Btu

WTP N2O Emissions 0 g / 116000 Btu

WTP GHG Emissions 2,874 116000 Btu

Levelized Cost of Hydrogen ($/kg) $7.16 2005 $/ kg

Fuel Economy 45.0 mi / GGE

Ratio of FCV VOCs (emissions) to GVs 

fueled with CG & RFG 0%

Ratio of FCV VOCs (evaporative) to GVs 

fueled with CG & RFG 0%

Ratio of FCV CO emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV NOx emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV Exhaust PM10 emissions to 

GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM10 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV Exhaust PM2.5 emissions 

to GVs fueled with CG & RFG 0%

Ratio of FCV Brake & Tire Wear PM2.5 

emissions to GVs fueled with CG & RFG 100%

Ratio of FCV CH4 emissions to GVs 

fueled with CG & RFG 0%

Ratio of FCV N2O emissions to GVs 

fueled with CG & RFG 0%

Well-to-Wheel Results

Coal Input from "Well" 467 Btu / mi

Natural Gas Input from "Well" 134 Btu / mi

Petroleum Input from "Well" 35 Btu / mi

Fossil Energy Input from "Well" 636 Btu / mi

WTW CO2 Emissions 62 g / mi

WTW CH4 Emissions 0 g / mi

WTW N2O Emissions 0 g / mi

WTW GHG Emissions 64 g / mi

Levelized Cost of Hydrogen ($/mi) $0.1591 2005 $/mi

Inputs Outputs

Vehicle

Wind Electricity

Graphic Depiction & Assumptions

Pipelines for Delivery

Hydrogen Production

Forecourt Distribution

Wind-Pipe Pathway Details R090603B 090821 v09.xls

229
Transport Distribution

Coal 3,307 Btu/116000 Btu Coal 17,681 Btu/116000 Btu

Natural Gas 949 Btu/116000 Btu Natural Gas 5,076 Btu/116000 Btu

Petroleum 246 Btu/116000 Btu Petroleum 1,317 Btu/116000 Btu

Total Energy 5,204 Btu/116000 Btu Total Energy 27,820 Btu/116000 Btu

CO2 Emissions 436 g/116000 Btu CO2 Emissions 2,333 g/116000 Btu

CH4 Emissions 1 g/116000 Btu CH4 Emissions 3 g/116000 Btu

N2O Emissions 0 g/116000 Btu N2O Emissions 0 g/116000 Btu

GHG Emissions 453 g/116000 Btu GHG Emissions 2,419 g/116000 Btu

Feedstock 

Coal 0 Btu/116000 Btu 

Natural Gas 0 Btu/116000 Btu 

Petroleum 0 Btu/116000 Btu Electrolysis Transport Distribution 

Total Energy 188,245 Btu/116000 Btu 

CO2 Emissions 0 g/116000 Btu Transport Losses 0.63% Distribution Losses 0.50% CO

CH4 Emissions 0 g/116000 Btu CH

N2O Emissions 0 g/116000 Btu N2

GHG Emissions 0 g/116000 Btu GH

Wind-Pipe Pathway Details R090603B 090821 v09.xls

230
Parameter Value Units Reference Comme

Case Definition

Base Year 2005 None Default for Wind-Pipe Pathway study

Production Technology Wind None Default for Wind-Pipe Pathway studyForm of H2 During Delivery Gas None Default for Wind-Pipe Pathway study

Delivery Mode Pipeline None Default for Wind-Pipe Pathway study

Forecourt Station Size 1278 kg/day James, B.D. (2008, May 23). Current (2005) Steam Methan Reformer (SMR) at Forecourt 1500kg/day. Arlington, VA: Directed Technologies Inc. Current forecourt H2A production from natural gas basis versio

C23

Vehicle Type passenger cars None Default for Wind-Pipe Pathway study

Vehicles' Fuel Economy 45.0 mile / gge

Rousseau, A. & Wallner, T. (2008, October 7). Prospects on Fuel Efficiency Improvements for Hydrogen Powered Vehicles . Argonne National Laboroatory presentation, Chicago, IL. Retreived from http://www.transportation.anl.gov/pdfs/HV/530.pdf

Calculated from data in the presentation. The fuel economy for Powertrain Simulation Analysis Toolkit V 6.2 SP1, Summer 200http://www.transportation.anl.gov/modeling_simulation/PSAT/ineconomy which was determined by multiplying the projected EP

Market Definition

City Population 1,247,364 people Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM City Selection; Scenario tab; Indianapolis, IN, cell B9Market penetration 50% (% vehicles in city) U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planNumber of H2 vehicles in city 462,772 H2 vehicles / city Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumMiles driven per vehicle 12,000 mile / vehicle year Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Key delivery input in HDSAM version 2.02; Scenario tab; Miles City hydrogen use 344,451 kg / d Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; City Number of H2 refueling stations in city 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumNumber of H2 stations/Number of gasoline stations 41% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; NumAverage distance between stations (mi) 1.46 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0. Argonne, IL: Argonne National Laboratory Demand calculation by HDSAM version 2.02; Scenario tab; Ave

Feedstock Recovery, Processing, & Transport

Electricity (Utility)

Grid mix for production & delivery utility electricity US Mix

Biomass Fraction

1.2%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Coal Fraction

51.7%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Natural Gas Fraction

15.7%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Nuclear Fraction

20.3%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Residual Oil Fraction

2.9%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Others (Carbon Neutral)

8.2%

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

US grid mix. National electricity generation data from tables D-calculated from total generation values reported with all renewaNeutral)" category 

Grid mix for pipeline compressors US Mix None Default for Wind-Pipe Pathway study

Grid mix for compression at distribution US Mix None Default for Wind-Pipe Pathway study

Electricity (Feedstock)

Grid mix for production Wind Electricity None Default for Wind-Pipe Pathway study

H2 Production

Production Facility Average Output 50,731

kg / facility d (after capacity factor is included)

Ramsden, T. (2008, May 28). Current (2005) Hydrogen from Central Grid Electrolysis . Golden, 

CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

Corresponding capacity factor 97% Ramsden, T. (2008, May 28). Current (2005) Hydrogen from Central Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

technology is higher than others due to its simplicity

Total Capital Investment $110,432,050 2005 $ Ramsden, T. (2008, May 28). Current (2005) Hydrogen from Central Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

Electricity feedstock consumption 53.5 kWh / kg H2 Ramsden, T. (2008, May 28). Current (2005) Hydrogen from Central Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

on LHV basis from Norsk Hydro Quote

Electricity feedstock cost $0.055 2005 $/kWh Energy Information Administation. (2005, February). Annual Energy Outlook 2005 With Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C.: U.S. Department of Energy. Assumed that wind electricity price would match industrial elect

(2005). Escalated from 2003 dollars to 2005 dollars. File down(file name aeo_hw-3.xls) 

Electricity utility consumption (both production, carbon capture & transport, and co 0.00 kWh / kg H2 All electricity is considered feedstock.

Electricity utility consumption (production only) 0.00 kWh / kg H2 All electricity is considered feedstock.

Process Water Consumption

2.94

gal / kg H2

Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from electricity basis version 2.Norsk Hydro Quote (2002) 1L per Nm3 H2 At 89.9 g H2/Nm3 a

Water Consumption for Cooling 294 gal / kg H2 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

modeling - see ProcessFlow sheet for details (Mike Penev) in R

Wind-Pipe Pathway Details R090603B 090821 v09.xls

231
Parameter Value Units Reference Comme

Compressed Inert Gas 0.023 Nm^3 / kg H2 Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.Electricity co-product production 0.00 kWh / kg H2 N/AOxygen co-product production 0.0 kg / kg H2 N/A

Steam co-product production 0.0 kg / kg H2 N/A

Electrolyzer Equipment Cost (Uninstalled) $675 $ / kW Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.

Hydro Quote

Total Annual Fixed Operating Costs $5,413,991 2005$ / yr Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.Total Annual Variable Operating Costs $55,873,500 2005$ / yr Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Current central H2A production from electricity basis version 2.Total Annual Operating Costs $61,287,491 2005$ / yr Calculation Sum of fixed and variable operating costsProduction energy efficiency (does not include electricity for CSD) 62.3% Calculated from H2A values Calculated from H2A values based on Electricity requirement w

Hydrogen outlet pressure (before CSD) 450 psi Ramsden, T. (2008, July 2). Current (2005) Hydrogen Production from Distributed Grid Electrolysis . Golden, CO: National Renewable Energy Laboratory. Discussion on Description tab

Hydrogen quality before transport 99.990% % H2 D. Steward (personal communication).

Financial Parameters

After-tax Real IRR 10%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1C47

Plant Life 40

years

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1

Federal Tax Rate 35.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1

State Tax Rate 6.0%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1

Total Tax Rate 38.9%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1

Frection Equity 100%

Mann, M., & Steward, D.M. (2008, May 28). Current (2005) Hydrogen from Biomass via Gasification and Catalytic Steam Reforming. Golden, CO: National Renewable Energy Laboratory.

Current central H2A production from biomass basis version 2.1

Transport, Delivery, and Storage Energy Requirements

Pipeline Delivery

Average Hydrogen Flowrate (Entering System) 348,364 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, market pe

TRANSMISIIION SYSTEM=CITY PEAK DEMAND/TRANSMISMASS EFFICIENCY)

Average Hydrogen Flowrate (Distributed) 344,451 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, market pe

USE/TOTAL PIPELINE MASS EFFICIENCY/REF.STATION MA

Summer Surge: % above the System Average Daily Demand 10% % above Average Daily Demand Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.9. DE-FG36- 05GO15032. Nexant Report - Section 2.1.9

Friday Peak 8% % above Average Daily Demand Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.9. DE-FG36- 05GO15032. Nexant Report - Section 2.1.9Peak Hydrogen Flowrate 381,192 kg/hr Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on input parameters: city, market pe

DISTRIBUTION SYSTEM=CITY PEAK DEMAND/DISTRIBUTIOEFFICIENCY)

Total Capital Investment for Compressors $27,199,794 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations, data from disscussions with Bechtel and AHydrogen Losses from Compressors 0.50%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

Table 2.26

Compressor Electricity Demand 70,343,075 kWh / year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM calculations - data from Nexant recommendations (basCompression, Ariel Compressors, Dresser-Rand - see Nexant r

Compressor Electricity Demand 0.5591 kWh / kg H2 

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM calculations - data from Nexant recommendations (basCompression, Ariel Compressors, Dresser-Rand - see Nexant r

Compressor Electricity Cost $0.056 2005$ / kWh

Energy Information Administration. (2005, January). Annual Energy Outlook 2005 with Projections to 2025 . DOE/EIA-0383(2005). Washington, D.C. Retreived from http://www.eia.doe.gov/oiaf/archive/aeo05/index.html

EIA AEO 2005 and 2007

Total Capital Investment for Pipeline System $377,283,372

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.2. DE-FG36-05GO15032.

HDSAM calculations based on data from GTI, Bechtel, Air Liqui

Hydrogen Losses from Pipelines 0.10%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.14. DE-FG36-05GO15032.

Calculated based upon natural gas pipelines; Nexant report - Se

Number of transmission pipelines 1 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Default in HDSAMTransmission pipeline diameter 11.00 in Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com)

Transmission pipeline inlet pressure 999 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Transmission pipeline outlet pressure 705 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Wind-Pipe Pathway Details R090603B 090821 v09.xls

232
Parameter Value Units Reference Comme

Transmission pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Transmission pipeline length 62 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory Based on input parameter: cityNumber of trunk pipelines 4 Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . DE-FG36-05GO15032.

HDSAM calculations based on input data and HDSAM distributiup to four trunk lines within a given metropolitan area with servistations. The model iterates on the number and location of trunk distribution configuration is obtained at a minimum cost." Nexan

Trunk #1 pipeline diameter 7.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com) Equations and explanati

Trunk #1 pipeline inlet pressure 603 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #1 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #1 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #1 pipeline length 17 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM distr

Company, San Francisco)

Trunk #2 pipeline diameter 10.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com) Equations and explanati

Trunk #2 pipeline inlet pressure 588 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #2 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #2 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #2 pipeline length 40 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM distributiTrunk #3 pipeline diameter 12.25 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com) Equations and explanati

Trunk #3 pipeline inlet pressure 573 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #3 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #3 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #3 pipeline length 65 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM distributiTrunk #4 pipeline diameter 10.75 in Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2; H2A Delivery Components User Guide (2006) sect 5.15.4 HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com) Equations and explanati

Trunk #4 pipeline inlet pressure 558 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #4 pipeline outlet pressure 397 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #4 pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Trunk #4 pipeline length 90 miles Nexant (2008) Section 2.4.3, 2.1.6, 2.2.2 HDSAM calculations based on input data and HDSAM distributiNumber of service pipelines 270 Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM distributi

Company, San Francisco)

Service pipeline diameter 1 in Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM Calculation: Panhandle B equation (Gas Processors S

1998, http://gpsa.gasprocessors.com)

Service pipeline inlet pressure 382 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Service pipeline outlet pressure 294 psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Service pipeline temperature 25 C

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.6. DE-FG36-05GO15032.

Recommendations from Nexant in conjuction with Air Liquide, GReport - Section 2.1.6)

Service pipeline length 1.1 miles Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculations based on input data and HDSAM distributi

Company, San Francisco)

Pipeline Geologic Storage Total Capital Investment $36,988,376

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.12. DE-FG36-05GO15032.

HDSAM calculations (cost data from ConocoPhilips and Saltville 

Section 2.2.12)

Hydrogen Losses from Geologic Storage 0.02% H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural 

Geologic Storage Capacity 41,864,765 m^3 H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural 

Wind-Pipe Pathway Details R090603B 090821 v09.xls

233
Parameter Value Units Reference Comme

Geologic Storage Design Capacity 3,762,787 kg H2 H2A Components Model User Guide, Section 6.5; Duke Energy, 2005; US EPA, 2003; Natural 

Geologic Storage Electricity Demand 961,465 kWh / year Nexant (2008) Section 2.2.12, 2.2.5 HDSAM calculations (cost data from ConocoPhilips and Saltville 

Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Demand 0.0076 kWh / kg H2 Nexant (2008) Section 2.2.12, 2.2.5 HDSAM calculations (cost data from ConocoPhilips and Saltville 

Sections 2.2.12 and 2.2.5)

Geologic Storage Electricity Cost $0.052 2005$ / kWh EIA AEO 2005

Distribution Station

Gaseous Receiving/Distributing Stations

Hydrogen Dispensed at Forecourt Station 465,647 kg / station year Nexant (2008) Section 2.1.3, 2.1.5 HDSAM calculation

Electricity Required by Forecourt Station 1,416,755

kWh / station year

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.6. DE-FG36-05GO15032.

HDSAM calculation

Number of Compressor Stages 4 Stages in 

compressor

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5. DE-FG36-05GO15032.

HDSAM default 

Compressor Isentropic Efficiency 65% Nexant 2008, Section 2.2.3.3, 2.2.5.2 HDSAM default;small compressor isentropic efficiency 65%, larDesign Capacity 1,516 kg H2 / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory HDSAM calculation based on Chevron fueling profiles (see Nex

Rate*(1+summer surge)*(1+Friday surge)

Operating Capacity 1,278 kg H2 / day Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National Laboratory adjusted dispensing rate=city use/numberof stations/utilization f

Capacity Factor 84%

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.1.5. DE-FG36-05GO15032.

Calculation; according to Nexant report the station does not havwhat the refers to.

Site storage (Low Pressure) 470

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.3. DE-FG36-05GO15032.

HDSAM calculation, see description in Nexant Report-Section 2

Site storage (Cascade) 582

kg H2

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2.4. DE-FG36-05GO15032.

HDSAM calculations (see description in Nexant Report-Section 

Site storage 69% % of design H2 distribution Nexant 2008, Section 2.1.9, 2.2.3.4 calculation

Dispensing Pressure 6,250

psi

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.3.2. DE-FG36-05GO15032.

HDSAM Default (see Nexant Report-Section 2.3.2)

Hydrogen Losses due to leaks 0.50% Elgowainy, A., Mintz, M. & Gillette, J. (2006). Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.0 . Argonne, IL: Argonne National LaboratoryElectrical Voltage Supply Requirement 480 Volts Nexant (2008) Section 2.2.5, 2.2.6 HDSAM calculation (see Nexant Report - Sections 2.2.5 and 2.2

Distribution System total capital investment $3,117,483

2005$ / station

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.5.2. DE-FG36-05GO15032.

See Nexant Report-Section 2.2.5.2)

Distribution System electricity cost $115,508

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.2.6. DE-FG36-05GO15032.

HDSAM calculation

Distribution Labor Required 3,951

hr / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and 

Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

HDSAM calculation

Distribution System labor cost $39,513

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.3. DE-FG36-05GO15032.

Bureau of Labor and Statistics, Nexant Report - Section 2.2.1.3

Distribution System total O&M cost $298,898

2005$ / station yr

Nexant, Inc. et al. (2008, May). H2A Hydrogen Delivery Infrastructure Analysis Models and Conventional Pathway Options Analysis Results . Interim Report Section 2.2.1.2. DE-FG36-05GO15032.

HDSAM calculations - see recommendations in Nexant Report-

Other Assumptions for WTW Calculations

Share of RFG in Total Gasoline Use 100% U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planType of Oxygenate in RFG None U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

O2 Content in RFG 0% wt % U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture planRatio of FCV VOCs (emissions) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV VOCs (evaporative) to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV CO emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV NOx emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV Exhaust PM10 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Ratio of FCV Brake & Tire Wear PM10 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, page 197: vehicles within the same weight clas

Ratio of FCV Exhaust PM2.5 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:well-known fuel cell emissions (no PM2.5)

Ratio of FCV Brake & Tire Wear PM2.5 emissions to GVs fueled with CG & RFG 100% Wang, M.Q. (2008, September 5). The Greenhouse Gases, Regualted Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . Argonne, IL: Argonne National Laboratory. GREET default:reasonable to assume FCV has same driving pa

Ratio of FCV CH4 emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Wind-Pipe Pathway Details R090603B 090821 v09.xls

234
Parameter Value Units Reference Comme

Ratio of FCV N2O emissions to GVs fueled with CG & RFG 0% Wang, M.Q. (1999, August). GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, development, Use and Results . Argonne, IL: Argonne National Laboratory. GREET default, Table 4.45 FCV: H2

Marginal Electricity Generation Mix for Transportation Use US Mix U.S. Department of Energy & U.S. Department of Transportation. (2006, December). Hydrogen Posture Plan An Inegrated Research, Development and Demonstration Plan. Basis for posture plan

Results

Levelized Cost $7.16 $ / kg Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

WTW Coal Input 467 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Natural Gas Input 134 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Petroleum Input 35 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Fossil Energy Input 636 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW Total Energy Input 4,921 Btu / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CO2 Emissions 62 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW CH4 Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW N2O Emissions 0 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM ResultsWTW GHG Emissions 64 g / mile Ruth, M. et al. (2009, March). Hydrogen Macro System Model User Guide. NREL/TP-6A1-44799. Golden, CO: National Renewable Energy Laboratory. MSM Results

Wind-Pipe Pathway Details R090603B 090821 v09.xls

235
236

Appendix H — Platinum Resource Availability and Cost

Although a lot of research is being done to reduce the platinum loading in proton 

exchange membrane (PEM) fuel cells, platinum catalyst is critical to the performance of 

current PEM fuel cell technology. Platinum catalyst was projected by TIAX (Kromer et. 

al, 2009) in 2008 to contribute 31% of the total fuel cell system factory cost. Current Pt 

loading in fuel cell vehicles (FCVs) is 32–45 g/vehicle. The DOE target is to reduce this 

loading to 15 g/FCV by 2015. The target for FCVs is still about fivefold greater than the 

Pt loading for internal combustion engine (ICE) vehicles: 2.5–3.3 g/vehicle (associated 

with the autocatalyst). At the 2007 average Pt price of $1,300/troy ounce, 15 g Pt will 

cost ~$750 (Rhodes and Kromer, 2008). 

An implicit assumption in this study is that PEM FCVs will achieve cost parity with 

internal combustion engine vehicles. Although the cost and availability of platinum will 

not affect the hydrogen cost directly for the pathways studied, it will impact the cost of 

the FCV and, therefore, the rate at which FCVs can be commercialized. Demand for 

hydrogen will depend on the rate of FCV deployment, and the viability of various 

hydrogen production and delivery pathways will depend on hydrogen demand. 

Availability and Utilization

The Stillwater and East Boulder mines in Montana are the only primary platinum group 

metal (PGM) mines in the United States. During 2008, those mines produced 3,700 kg of 

platinum, which was down from 3,860 kg in 2007. An estimated 26,000 kg of PGMs 

were recovered from new and old scrap in 2008. Platinum imports for consumption were 

181,000 and 195,000 kg for 2007 and 2008, respectively. The United States has a reserve 

of 900,000 kg and a reserve base of 2,000,000 kg of platinum (United States Geological 

Survey, 2009). The reserve base is the part of platinum that meets specified minimum 

physical and chemical criteria related to current mining and production practices, 

including grade, quality, thickness and depth. Reserves are the part of the reserve base 

that could be economically extracted or produced at the time of determination. 

TIAX, LLC (Rhodes and Kromer, 2008) projected that world resources for all PGMs are 

~160,000 Mg; platinum resources are ~76,000 Mg. South Africa produces ~80% of the 

world’s platinum supply of ~200 Mg per year (Figure H.0.1). The historical growth rate 

of primary Pt demand (from 1960 to 2007) is 3 Mg/yr; recent growth rates (1999–2007) 

have been closer to 6–7 Mg/yr. (Primary Pt refers to platinum that is directly mined in 

contrast to secondary Pt, which is recycled.) 
237

Figure H.0.1. World platinum supply (Rhodes and Kromer, 2008)

TIAX (Rhodes and Kromer, 2008) assessed worldwide platinum availability for FCVs 

and concluded that platinum resources are sufficient to meet significant FCV demand but 

that FCV demand growth may be constrained by primary platinum supply. Long-term 

projections for the global transportation sector were developed based on population 

projections, vehicle-per-capita scenarios, and projected ICE vehicle and FCV Pt 

requirements. Population projections and vehicle–per-capita projections were used to 

develop a total vehicle forecast, which included replacement demand and new demand. 

The total vehicle forecast and fuel cell and internal combustion powertrain Pt 

requirements were used to determine the FCV projection, which in turn was used to 

develop the Pt demand versus time. United Nations forecasts were used for the 

population projections. The EIA Annual Energy Outlook 2003 provided near-term 

annual vehicle per capita growth estimates. 

Two scenarios were considered: 1) FCVs achieve market share of 50% in the global 

light-duty vehicle market by 2050, and 2) FCVs achieve market share of 80% in the 

global light-duty vehicle market by 2050 (Figure H.0.2). A growth rate in primary Pt 

demand of 12 Mg/yr would be necessary for the 50% scenario, and 23 Mg/yr would be 

needed to achieve the 80% scenario (Figure H.0.3). Annual primary platinum supply 

increased by an average of 3 Mg/yr from 1960 to 2007 with average increases of 6.3 

Mg/yr from 1999 to 2004. The platinum industry developed plans in 2003 to expand 

production by 13 Mg/yr. Thus, the lower growth rate is considered achievable while the 

higher growth rate is considered beyond reasonable growth expectations (Rhodes and 

Kromer, 2008). 
238

Figure H.0.2. Projected worldwide vehicle sales (Kromer, Rhodes, and Guernsey, 2008)

Figure H.0.3. Projected primary platinum demand (Kromer, Rhodes, and Guernsey, 2008)

Resource Cost

In 2008, platinum reached its all-time highest annual average price of $1,680 per troy 

ounce. That price is up from $1,308 per troy ounce in 2007 (United States Geological 

Survey, 2009). 
239

Appendix I — Enlarged Graphics

The following figures from the previous sections are enlarged in this section for ease of 

viewing. 

• Figure 3.2.1. Efficiency in electricity generation from various sources (van Aart, 2004)

• Figure 3.2.2. Installed wind capacity as of April 2009 (National Renewable Energy 

Laboratory, 2009)

• Figure 3.2.3. U.S. wind resource map (National Renewable Energy Laboratory, 2009)

• Figure 3.5.2. Regional carbon sequestration partnerships and their respective validation 

carbon storage projects (National Energy Technology Laboratory, 2008)

• Table 4.1.1. Natural Gas Pipeline Mileage (Energy Information Administration, 2008e)

• Figure 4.1.3. Hypothetical pressures (psig) in distribution mains at maximum design flows 

(Vidas, 2007)

• Figure 5.1.1. Distributed natural gas reforming process flow diagram (James, 2008)

• Figure 5.2.1. Distributed electrolysis process flow diagram (Ramsden, 2008b)

• Figure 5.2.3. Distributed electrolysis process flow diagram cooling water detail (Ramsden, 

2008b)

• Figure 5.3.1. Central biomass gasification flow diagram (Mann and Steward, 2008)

• Figure 9.1.2. Cost analysis inputs and high-level results for distributed natural gas pathway

• Figure 9.1.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

distributed natural gas pathway

• Figure 9.1.9. Production sensitivities for distributed natural gas pathway

• Figure 9.1.10. Production sensitivities for distributed natural gas pathway with advanced 

technology

• Figure 9.2.2. Cost analysis inputs and high-level results for distributed electricity pathway

• Figure 9.2.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using 

distributed electricity pathway

• Figure 9.2.9. Production sensitivities for distributed electrolysis pathway

• Figure 9.3.2. Cost analysis inputs and high-level results for central biomass–liquid truck 

delivery pathway

• Figure 9.3.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central 

biomass–liquid truck delivery pathway

• Figure 9.3.9. Production sensitivities for central biomass–liquid truck delivery pathway

• Figure 9.4.2. Cost analysis inputs and high-level results for central biomass–pipeline delivery 

pathway

• Figure 9.4.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central 

biomass–pipeline delivery pathway

• Figure 9.4.9. Production sensitivities for central biomass–pipeline delivery pathway
240

• Figure 9.5.2. Cost analysis inputs and high-level results for central natural gas–pipeline 

delivery pathway

• Figure 9.5.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central 

natural gas–pipeline delivery pathway

• Figure 9.5.9. Production sensitivities for central natural gas–pipeline delivery pathway

• Figure 9.6.2. Cost analysis inputs and high-level results for central wind electricity–pipeline 

delivery pathway

• Figure 9.6.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central 

wind electricity–pipeline delivery pathway

• Figure 9.6.9. Production sensitivities for central wind electrolysis–pipeline delivery pathway

• Figure 9.7.2. Cost analysis inputs and high-level results for central coal with CCS–pipeline 

delivery pathway

• Figure 9.7.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central 

coal with CCS–pipeline delivery pathway

• Figure 9.7.9. Production sensitivities for central coal with CCS–pipeline delivery pathway

• Figure 10.0.3. WTW, pathway, and production efficiencies for seven hydrogen pathways, 

three crude oil–based fuel options, and two E85 options

• Figure 10.0.4. WTW petroleum energy use for seven hydrogen pathways, three crude oil–

based fuel options, and two E85 options

• Figure 10.0.6. WTW GHG emissions for seven hydrogen pathways, three crude oil–based 

fuel options, and two E85 options

• Figure 10.0.9. Levelized costs/market prices with possible carbon taxes for seven hydrogen 

pathways, three crude oil–based fuel options, and two E85 options 
241

Figure 3.2.1. Efficiency in electricity generation from various sources (van Aart, 2004)

0

10

20

30

40

50

60

70

80

90

100

Hydro power plant

Tidal power plant

Large gas fired CCGT power plant

Melted carbonates fuel cell (MCFC)

Pulverised coal boilers with ultra-critical steam parameters

Solid oxide fuel cell (SOFC)

Coal fired IGCC

Atmospheric Circulating Fluidised Bed Combustion (CFBC)

Pressurised Fluidised Bed Combustion (PFBC)

Large gas turbine (MW range)

Steam turbine coal-fired power plant

Steam turbine fuel-oil power plant

Wind turbine

Nuclear power plant

Biomass and biogas

Waste-to-electricity power plant

Diesel engine as decentralised CHP unit (electrical share)

Small and micro turbines (up to 100 kW)

Photovoltaic cells

Geothermal power plant

Solar power tower

Efficiency (%)
242

Figure 3.2.2. Installed wind capacity as of April 2009 (National Renewable Energy Laboratory, 2009)
243

. 

Figure 3.2.3. U.S. wind resource map (National Renewable Energy Laboratory, 2009)
244

Figure 3.5.2. Regional carbon sequestration partnerships and their respective validation carbon storage projects (National Energy 

Technology Laboratory, 2008)
245

Table 4.1.1. Natural Gas Pipeline Mileage (Energy Information Administration, 2008e)
246

Figure 4.1.3. Hypothetical pressures (psig) in distribution mains at maximum design flows (Vidas, 2007)
247

Figure 5.1.1. Distributed natural gas reforming process flow diagram (James, 2008)
248

 

Figure 5.2.1. Distributed electrolysis process flow diagram (Ramsden, 2008b)
249

Figure 5.2.3. Distributed electrolysis process flow diagram cooling water detail (Ramsden, 2008b)

Temperature (C)

Mass Flow Rate (kg/day)

Duty (Watt)

Q Duty (Watt)

80

1908

H2-WET

WATERHX

Q=20106.9

40

1908

H2-COLD

34

H2OCOLD 40000

45

40000

H2OHOT2

FLASH2

40

1561

H2-DRYER

40

CONDENS 347

EVAPHX

Q=20049.5

SPRAY

25

611

SPRAYH2O 18

21011

AIR3

37

21008

AIR4

FLASH3 37

20806

AIR5

37

202

H2OMIST1

45

H2OHOT 40000

25

20000

AIR1

AC

25

AIR2 20198

25

198

HUMIDITY

38

202

H2OMIST2
250

Figure 5.3.1. Central biomass gasification flow diagram (Mann and Steward, 2008)
251

Natural Gas @ Total capital investment $2.44 2005$ / annual kg H2 (effective capacity)

$6.81/MMBtu Electricity cost $0.09 2005$ / kg H2 produced

Natural gas cost $0.91 2005$ / kg H2 distributed

Other operating costs $0.36 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $0.71 2005$ / kg H2 distributed

Total capital investment $8.56 2005$ / annual kg H2 (effective capacity)

Electricity @ $0.082/kWh Electricity cost $0.16 2005$ / kg H2

Levelized Cost of Distribution $1.88 2005$ / kg H2 distributed

* 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.

Natural Gas Production Hydrogen Production: 

and Delivery*: Desulfurizer

Pipeline Transport PSA

Recovery SMR

Processing WGS

Dispensing

Hydrogen @ $3.50/kg

Electricity @

$0.082/kWh

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Figure 9.1.2. Cost analysis inputs and high-level results for distributed natural gas pathway
252

CO2 Emissions 600 g/116,000 Btu CO2 Emissions 10,500 g/116,000 Btu

CH4 Emissions 28 g/116,000 Btu CH4 Emissions 11 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 10,800 g CO2 eq./116,000 Btu

GHG Emissions 1,300 g CO2 eq./116,000 Btu

CO2 Emissions 1,500 g/116,000 Btu

Electricity CH4 Emissions 2 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 1,600 g CO2 eq./116,000 Btu

* 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.

Dispensing

116,000 Btu

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Recovery SMR

Processing WGS

and Delivery*: Desulfurizer

Electricity

Pipeline Transport PSA

Natural Gas Production Hydrogen Production: 

Figure 9.1.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using distributed natural gas pathway
253

$3.20 $3.30 $3.40 $3.50 $3.60 $3.70 $3.80 $3.90 $4.00 $4.10 $4.20

Operating Capacity

 Feedstock Cost ($/Nm^3)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($ / kg)

95% 85% 60%

$0.17 $0.24 $0.32

$0.5 M $1.5 M $2.5 M

80% 70% 60%

Figure 9.1.9. Production sensitivities for distributed natural gas pathway
254

$3.00 $3.10 $3.20 $3.30 $3.40 $3.50 $3.60 $3.70 $3.80 $3.90

 Operating Capacity

 Feedstock Cost ($/Nm^3)

Production Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($/kg)

87%

85%

$0.15 $0.18 $0.29

$400K $900K $1.4 mill

77% 67%

95% 60%

Figure 9.1.10. Production sensitivities for distributed natural gas pathway with advanced technology
255

Electricity @ Total capital investment $5.87 2005$ / annual kg H2 (effective capacity)

$0.055/kWh Other operating costs $0.60 2005$ / kg H2 produced

Electricity Cost $2.80 2005$ / kg H2 distributed

Levelized Cost of Prod (excl feedstock) $1.42 2005$ / kg H2 distributed

Total capital investment $8.55 2005$ / annual kg H2 (effective capacity)

Electricity @ $0.055/kWh Electricity cost $0.10 2005$ / kg H2

Gaseous H2 Storage Levelized Cost of Distribution $1.82 2005$ / kg H2 distributed

Dispensing

Hydrogen @ $3.50/kg

Transmission & Distribution

Forecourt 

Distribution:

Compressor

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Water @

$1.66/thousand gal

Electricity Generation Hydrogen Production: 

Figure 9.2.2. Cost analysis inputs and high-level results for distributed electricity pathway 
256

CO2 Emissions 41,000 g/116,000 Btu CO2 Emissions 0 g/116,000 Btu

CH4 Emissions 54 g/116,000 Btu CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 1 g/116,000 Btu GHG Emissions 0 g CO2 eq./116,000 Btu

GHG Emissions 42,500 g CO2 eq./116,000 Btu

CO2 Emissions 1,600 g/116,000 Btu

Electricity CH4 Emissions 2 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 1,700 g CO2 eq./116,000 Btu

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Electricity Generation, Scrubber

Transmission & Distribution

Forecourt 

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Figure 9.2.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using distributed electricity pathway
257

$5.20 $5.40 $5.60 $5.80 $6.00 $6.20 $6.40 $6.60 $6.80 $7.00 $7.20

Operating Capacity

Electricity Cost ($/kWh)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($ / kg)

95% 85% 60%

$0.070 $0.040 $0.055

$1.0 M $2.7 M $4.0 M

67% 62% 58%

Figure 9.2.9. Production sensitivities for distributed electrolysis pathway
258

Electricity @ Natural Gas @ 

$0.055/kWh $9.52/MMBtu

Biomass @ Total capital investment $3.03 2005$ / annual kg H2 (effective capacity)

$37.96/dry short ton Levelized Electricity cost $0.05 2005$ / kg H2 produced

Levelized Natural Gas Cost $0.06 2005$ / kg H2 produced

Levelized Cost of Biomass $0.61 2005$ / kg H2 distributed

Levelized Other operating costs $0.32 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.18 2005$ / kg H2 distributed

Total capital investment $6.37 2005$/annual kg delivered

Levelized Electricity cost $0.49 2005$ / kg H2 delivered

Electricity @ $0.055/kWh Levelized Diesel cost $0.01 2005$ / kg H2 delivered

Diesel @ $1.67/gallon Levelized Labor cost $0.13 2005$ / kg H2 delivered

Levelized Other operating costs $0.28 2005$ / kg H2 delivered

Levelized Cost of Delivery $2.04 2005$ / kg H2 delivered

Total capital investment $5.85 2005$/annual kg

Electricity @ $0.082/kWh Levelized Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.05 2005$ / kg H2 distributed

Harvesting

Truck Transport

Hydrogen @ $4.88/kg

Biomass Production

and Delivery:

Poplar Planting

Fertilization

Vaporizer

Compressor

Gaseous H2 Storage

Dispensing

Liquid H2 Storage

Liquid H2 Truck

Forecourt 

Distribution:

Hydrogen Production: 

Liquefaction &

Truck Delivery:

Liquefier

Gasifier

SMR

WGS

PSA

Figure 9.3.2. Cost analysis inputs and high-level results for central biomass–liquid truck delivery pathway
259

Electricity Natural Gas

CO2 Emissions -26,900 g/116,000 Btu CO2 Emissions 27,000 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 27,100 g CO2 eq./116,000 Btu

GHG Emissions -26,900 g CO2 eq./116,000 Btu

CO2 Emissions 6,700 g/116,000 Btu

Electricity CH4 Emissions 9 g/116,000 Btu

Diesel N2O Emissions 0 g/116,000 Btu

GHG Emissions 7,000 g CO2 eq./116,000 Btu

CO2 Emissions 0 g/116,000 Btu

Electricity CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 0 g CO2 eq./116,000 Btu

Hydrogen Gas

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting PSA

Truck Transport

Liquefaction &

Truck Delivery:

Liquefier

Liquid H2 Storage

Liquid H2 Truck

Gaseous H2 Storage

Dispensing

116,000 Btu

Forecourt 

Distribution:

Vaporizer

Compressor

Figure 9.3.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central biomass–liquid truck delivery pathway
260

$4.60 $4.70 $4.80 $4.90 $5.00 $5.10 $5.20

Staffing (FTE)

 Operating Capacity

 Feedstock Cost ($/dry ton)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

55%

25 54 70

95% 90% 80%

$26.30 $38.00 $49.00

$100 mill $154.6 mill $220 mill

46% 35%

Figure 9.3.9. Production sensitivities for central biomass–liquid truck delivery pathway
261

Electricity @ Natural Gas @ 

$0.055/kWh $9.52/MMBtu

Biomass @ Total capital investment $3.03 2005$ / annual kg H2 (effective capacity)

$37.96/dry short ton Electricity cost $0.05 2005$ / kg H2 produced

Natural Gas Cost $0.06 2005$ / kg H2 produced

Levelized Cost of Biomass $0.56 2005$ / kg H2 distributed

Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.07 2005$ / kg H2 distributed

Total capital investment $3.51 2005$/annual kg distributed

Electricity for compressor @ $0.056/kWh Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

@ $0.052/kWh

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

Dispensing

Hydrogen @ $4.88/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Harvesting PSA

Truck Transport

Compression &

Poplar Planting SMR

Fertilization WGS

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Figure 9.4.2. Cost analysis inputs and high-level results for central biomass–pipeline delivery pathway
262

Electricity Natural Gas

CO2 Emissions -25,600 g/116,000 Btu CO2 Emissions 25,700 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 25,800 g CO2 eq./116,000 Btu

GHG Emissions -25,600 g CO2 eq./116,000 Btu

CO2 Emissions 436 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 452 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

Biomass Production Hydrogen Production: 

and Delivery: Gasifier

Poplar Planting SMR

Fertilization WGS

Harvesting PSA

Truck Transport

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 9.4.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central biomass–pipeline delivery pathway
263

$4.00 $4.05 $4.10 $4.15 $4.20 $4.25 $4.30 $4.35 $4.40 $4.45 $4.50

Staffing (FTE)

 Operating Capacity Factor

 Feedstock Cost ($/dry ton)

 Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

55%

25 54 70

95% 90% 80%

$26.30 $38.00 $49.00

$100M $154.6M $220M

46% 35%

Figure 9.4.9. Production sensitivities for central biomass–pipeline delivery pathway
264

Natural Gas @ Total capital investment $1.45 2005$ / annual kg H2 (effective capacity)

$6.81/MMBtu Electricity cost $0.03 2005$ / kg H2 produced

Other operating costs $0.08 2005$ / kg H2 produced

Natural gas cost $0.95 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $0.38 2005$ / kg H2 produced

Total capital investment $3.51 2005$/annual kg distributed

Electricity for compressor @ $0.056/kWh Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

@ $0.052/kWh

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

* 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.

Hydrogen @ $3.95/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Geologic Storage

Pipeline

Dispensing

Compression &

Pipeline Delivery:

Compressor

Processing WGS

Pipeline Transport PSA

and Delivery*: Desulfurizer

Recovery SMR

Electricity @

$0.055/kWh

Natural Gas Production Hydrogen Production: 

Figure 9.5.2. Cost analysis inputs and high-level results for central natural gas–pipeline delivery pathway
265

CO2 Emissions 590 g/116,000 Btu CO2 Emissions 10,200 g/116,000 Btu

CH4 Emissions 16 g/116,000 Btu CH4 Emissions 7 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 10,400 g CO2 eq./116,000 Btu

GHG Emissions 1,000 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 500 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

* 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.

Electricity

Natural Gas Production Hydrogen Production: 

and Delivery: Desulfurizer

Recovery SMR

Processing WGS

Pipeline Transport PSA

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Hydrogen Gas

Figure 9.5.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central natural gas–pipeline delivery pathway
266

$3.60 $3.70 $3.80 $3.90 $4.00 $4.10 $4.20 $4.30 $4.40 $4.50 $4.60

 Operating Capacity Factor

 Feedstock Cost ($/Nm^3)

Production Total Capital Investment

 Production Energy Efficiency

H2 Levelized Cost ($)

81%

95% 90%80%

$0.17 $0.24 $0.32

$150M $181M $250M

72% 50%

Figure 9.5.9. Production sensitivities for central natural gas–pipeline delivery pathway
267

Electricity @ Total capital investment $5.96 2005$ / annual kg H2 (effective capacity)

$0.055/kWh Electricity cost $2.96 2005$ / kg H2 produced

Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Wind Electricity $2.99 2005$ / kg H2 distributed

Levelized Cost of Prod (excl feedstock) $1.56 2005$ / kg H2 distributed

Electricity for compressor @ $0.056/kWh Total capital investment $3.51 2005$/annual kg distributed

Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage 

@ $0.052/kWh Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

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 @ $7.16/kg

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Pipeline Delivery:

Figure 9.6.2. Cost analysis inputs and high-level results for central wind electricity–pipeline delivery pathway
268

CO2 Emissions 0 g/116,000 Btu CO2 Emissions 0 g/116,000 Btu

CH4 Emissions 0 g/116,000 Btu CH4 Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 0 g/116,000 Btu

GHG Emissions 0 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 450 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

Electricity Generation Hydrogen Production: 

and Transport: Demineralizer

Resource Recovery, Elec. Transformer/Rectifier

Processing & Delivery Electrolyzer

Electricity Generation, Scrubber

Transmission & Distribution

Compression &

Hydrogen Gas

Forecourt 

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

116,000 Btu

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Figure 9.6.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central wind electricity–pipeline delivery pathway
269

$6.00 $6.25 $6.50 $6.75 $7.00 $7.25 $7.50 $7.75 $8.00 $8.25 $8.50

Operating Capacity Factor

Electricity Cost ($/kWh)

Electrolyzer Cost ($/kW)

 Production Energy Efficiency (HHV)

H2 Levelized Cost ($)

79%

98% 97% 85%

$0.039 $0.055 $0.072

$575 $675 $775

74% 69%

Figure 9.6.9. Production sensitivities for central wind electrolysis–pipeline delivery pathway
270

Coal @ Total capital investment $6.84 2005$ / annual kg H2 (effective capacity)

$33.98/short ton Electricity cost $0.10 2005$ / kg H2 produced

Natural Gas Cost $0.00 2005$ / kg H2 produced

Electricity for CCS @ Levelized Cost of Coal $0.31 2005$ / kg H2 distributed

$0.055/kWh Other operating costs $0.38 2005$ / kg H2 produced

Levelized Cost of Prod (excl feedstock) $1.76 2005$ / kg H2 distributed

Electricity for compressor @ $0.056/kWh Total capital investment $3.51 2005$/annual kg distributed

Electricity cost $0.03 2005$ / kg H2

Electricity for geologic storage 

@ $0.052/kWh Levelized Cost of Delivery $0.92 2005$ / kg H2 distributed

Total capital investment $6.69 2005$/annual kg

Electricity @ $0.082/kWh Electricity cost $0.25 2005$ / kg H2

Levelized Cost of Distribution $1.69 2005$ / kg H2 distributed

* This box represents the coal that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include coal used as a heating fuel or to produce electricity.

Hydrogen @ $4.68/kg

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Compressor

Geologic Storage

Pipeline

Forecourt 

PSA

Compression &

Pipeline Delivery:

Rail Transport H2S Removal

CO2 Removal

& Delivery*: Gasifier

Mining/Recovery Shift Converter

Hydrogen Production 

Coal Mining & CCS: 

Figure 9.7.2. Cost analysis inputs and high-level results for central coal with CCS–pipeline delivery pathway
271

CO2 Emissions 110 g/116,000 Btu CO2 Emissions 3,800 g/116,000 Btu

CH4 Emissions 14 g/116,000 Btu CH4 Emissions 13 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu GHG Emissions 4,100 g CO2 eq./116,000 Btu

GHG Emissions 460 g CO2 eq./116,000 Btu

CO2 Emissions 440 g/116,000 Btu

Electricity CH4 Emissions 1 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 450 g CO2 eq./116,000 Btu

CO2 Emissions 2,300 g/116,000 Btu

Electricity CH4 Emissions 3 g/116,000 Btu

N2O Emissions 0 g/116,000 Btu

GHG Emissions 2,400 g CO2 eq./116,000 Btu

* This box represents the coal that is converted to hydrogen or otherwise consumed/lost as a process feedstock. 

It does not include coal used as a heating fuel or to produce electricity.

Hydrogen Production 

Coal Mining & CCS: 

& Delivery*: Gasifier

Mining/Recovery Shift Converter

Rail Transport H2S Removal

CO2 Removal

PSA

Compression &

Pipeline Delivery:

Compressor

Geologic Storage

Pipeline

Forecourt 

116,000 Btu

Hydrogen Gas

Distribution:

Compressor

Gaseous H2 Storage

Dispensing

Figure 9.7.7. WTW emissions resulting from delivery of 116,000 Btu hydrogen using central coal with CCS–pipeline delivery pathway
272

$4.50 $4.55 $4.60 $4.65 $4.70 $4.75 $4.80 $4.85 $4.90 $4.95 $5.00

Operating Capacity Factor

Coal Cost ($/short ton)

CCS Capital Cost

Production Total Direct Capital

Production Energy Efficiency (LHV)

H2 Levelized Cost ($)

60%

95% 90% 80%

$24 $34 $44

$350M $391M $500M

54% 45%

$75M $117M $175M

Figure 9.7.9. Production sensitivities for central coal with CCS–pipeline delivery pathway
273

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

Energy Efficiency (LHV basis)

Production Efficiency

Pathway Efficiency

Well-to-Pump Efficiency

Figure 10.0.3. WTW, pathway, and production efficiencies for seven hydrogen pathways, three crude oil–based fuel options, and two 

E85 options
274

0

1,000

2,000

3,000

4,000

5,000

6,000

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid

Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

WTW Petroleum Energy Use (Btu / mile)

Figure 10.0.4. WTW petroleum energy use for seven hydrogen pathways, three crude oil–based fuel options, and two E85 options
275

-250

0

250

500

750

1,000

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification -

Liquid

Trucks

Central

Biomass

Gasification -

Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation) -

Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

WTW GHG Emissions (g / mile)

Well-to-Pump Pump-to_Wheels

Net

Figure 10.0.6. WTW GHG emissions for seven hydrogen pathways, three crude oil–based fuel options, and two E85 options
276

$0.000

$0.050

$0.100

$0.150

$0.200

$0.250

$0.300

Distributed

Natural Gas

Reforming

Distributed

Electrolysis

Central

Biomass

Gasification

- Liquid

Trucks

Central

Biomass

Gasification

- Pipelines

Central

Natural Gas

Reforming -

Pipelines

Central

Electrolysis

(Wind

Generation)

- Pipelines

Central Coal

Gasification

w/CCS -

Pipelines

2009

Gasoline

ICE

2009

Gasoline

HEV

2009 Diesel

CIDI ICE

2009 Corn

E85 FFV

2008 Corn

Stover E85

FFV 

Levelized Cost of Hydrogen and Market Price of Gasoline & Diesel ($ / mile 

without fuel taxes)

$100 / ton CO2 Eq Carbon Tax

$50 / ton CO2 eq Carbon Tax

$0 / ton CO2 eq Carbon Tax

Figure 10.0.9. Levelized costs/market prices with possible carbon taxes for seven hydrogen pathways, three crude oil–based fuel 

options, and two E85 options 
277

Acronyms

°C degrees Celsius

°F degrees Fahrenheit

AC alternating current 

atm atmosphere 

BSCSP Big Sky Carbon Sequestration Partnership

Btu British thermal unit

CA California

CCS carbon capture and sequestration

CHP combined heat and power 

cm centimeter

CO carbon monoxide 

CO2 carbon dioxide 

CSD compression, storage, and dispensing 

DC direct current 

DOE Department of Energy 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

FAF2 Freight Analysis Framework 2 

FCV fuel cell vehicle

FL Florida

FPITT Fuel Pathway Integration Tech Team 

gal gallon 

gge gallon gasoline equivalent 

GHG greenhouse gas 

GREET Greenhouse Gases, Regulated Emissions, and Energy Use in 

 Transportation 

H2, H2 diatomic hydrogen 

HEV hybrid electric vehicle 

HDSAM H2A Delivery Scenario Analysis Model 

HFCIT Hydrogen, Fuel Cells and Infrastructure Technologies 

HOF hose occupied fraction 

hr hour 

ICE internal combustion engine 

IGCC integrated gasification combined cycle 

kg kilogram 

kWh kilowatt-hour 

L liter

lb pound 

MGSC Midwest Geological Sequestration Consortium 

mi mile

MI Michigan

MRCSP Midwest Regional Carbon Sequestration Partnership 

MSM Macro-System Model 

MT metric ton
278

MW megaWatt

MYPP Multi-Year Program Plan

NG natural gas 

NOx oxides of nitrogen 

NREL National Renewable Energy Laboratory 

NV Nevada 

NY New York

PA Pennsylvania 

PC pulverized coal 

PCOR Plains CO2 Reduction 

PGM platinum group metal 

PM particulate matter

ppm parts per million

PSA pressure swing adsorption 

PSAT Powertrain Simulation Analysis Toolkit 

psi pound per square inch 

psia pounds per square inch absolute 

psig pound per square inch gauge 

SECARB Southeast Regional Carbon Sequestration Partnership 

SMR steam methane reforming

SWP Southwest Regional Partnership 

TBW tire and brake wear

TLR transmission loading relief

TX Texas

U.S. United States 

VOC volatile organic compound 

WESTCARB West Coast Regional Carbon Sequestration Partnership 

WGS water-gas shift

wt% weight percent 

WTG well-to-plant gate 

WTP well-to-pump 

WTW well-to-wheels 
F1147-E(10/2008) 

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1. REPORT DATE (DD-MM-YYYY)

September 2009

2. REPORT TYPE

Technical Report

3. DATES COVERED (From - To)

 

4. TITLE AND SUBTITLE

Hydrogen Pathways: Cost, Well-to-Wheels Energy Use, and 

Emissions for the Current Technology Status of Seven Hydrogen 

Production, Delivery, and Distribution Scenarios

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

M. Ruth: NREL; 

M. Laffen and T.A. Timbario: Alliance Technical Services, Inc.

5d. PROJECT NUMBER

NREL/TP-6A1-46612

5e. TASK NUMBER

HS07.1002

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National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

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NREL/TP-6A1-46612

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NREL

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14. ABSTRACT (Maximum 200 Words)

Report of levelized cost in 2005 U.S. dollars, energy use, and GHG emission benefits of seven hydrogen production, 

delivery, and distribution pathways. 

15. SUBJECT TERMS

hydrogen pathways; well-to-wheels; hydrogen production; hydrogen delivery; hydrogen distribution; pathway 

scenarios; natural gas; electricity; biomass–liquid truck delivery; biomass–pipeline; natural gas–pipeline; wind 

electricity; coal 

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