Hydrogen Supply

November 2002 • NREL/SR-540-32525
Hydrogen Supply: Cost

Estimate for Hydrogen
PathwaysScoping Analysis
January 22, 2002July 22, 2002
D. Simbeck and E. Chang

SFA Pacific, Inc.
Mountain View, California
National Renewable Energy Laboratory

1617 Cole Boulevard
Golden, Colorado 80401-3393
NREL is a U.S. Department of Energy Laboratory
Operated by Midwest Research Institute • Battelle • Bechtel
Contract No. DE-AC36-99-GO10337
November 2002 • NREL/SR-540-32525
Hydrogen Supply: Cost

Estimate for Hydrogen
PathwaysScoping Analysis
January 22, 2002July 22, 2002

SFA Pacific, Inc.
Mountain View, California
NREL Technical Monitor: Wendy Clark

Prepared under Subcontract No. ACL-2-32030-01
National Renewable Energy Laboratory

1617 Cole Boulevard
Golden, Colorado 80401-3393
NREL is a U.S. Department of Energy Laboratory
Operated by Midwest Research Institute • Battelle • Bechtel
Contract No. DE-AC36-99-GO10337
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Table of Contents
Table of Contents............................................................................................................................. i
Acronyms and Abbreviations ......................................................................................................... ii
Introduction..................................................................................................................................... 1
Summary ......................................................................................................................................... 3
Consistency and Transparency ....................................................................................................... 5
Ease of Comparison .................................................................................................................... 5
Flexibility Improvements............................................................................................................ 6
Potential Improvements for Hydrogen Economics......................................................................... 6
Central Plant Hydrogen Production ............................................................................................ 6
Hydrogen Distribution ................................................................................................................ 6
Hydrogen Fueling Stations ..................................................................................................... 7
Hydrogen Economic Module Basis ................................................................................................ 7
Hydrogen Production Technology.................................................................................................. 8
Reforming ................................................................................................................................... 9
Gasification ................................................................................................................................. 9
Electrolysis................................................................................................................................ 10
Central Plant Hydrogen Production .............................................................................................. 11
Hydrogen Handling and Storage............................................................................................... 13
Hydrogen Liquefaction ......................................................................................................... 13
Gaseous Hydrogen Compression.......................................................................................... 14
Hydrogen Storage ..................................................................................................................... 14
Hydrogen Distribution .............................................................................................................. 15
Road Delivery (Tanker Trucks and Tube Trailers)............................................................... 16
Pipeline Delivery .................................................................................................................. 17
Hydrogen Fueling Station ......................................................................................................... 17
Liquid Hydrogen Based Fueling........................................................................................... 19
Gaseous Hydrogen Based Fueling ........................................................................................ 19
Forecourt Hydrogen Production ............................................................................................... 19
Sensitivity ..................................................................................................................................... 21
Special Acknowledgement............................................................................................................ 22
References..................................................................................................................................... 22
General...................................................................................................................................... 22
Gasification ............................................................................................................................... 22
Large Steam Methane Reforming............................................................................................. 23
Small Steam Methane Reforming............................................................................................. 26
Electrolysis................................................................................................................................ 26
Pipeline ..................................................................................................................................... 27
High Pressure Storage............................................................................................................... 27
High Pressure Compression...................................................................................................... 27
Delivery..................................................................................................................................... 27
i
Acronyms and Abbreviations
ASU air separation unit
ATR autothermal reforming
BDT bone-dry ton
Btu British thermal unit
EOR enhanced oil recovery
FC fuel cell
gal gallon
GPS global positioning system
H2 molecular hydrogen
ICE internal combustion engine
IHIG International Hydrogen Infrastructure Group
kg kilogram
kg/d kilograms per day
O&M operating and maintenance
PO partial oxidation
PSA pressure swing adsorption
psig pounds per square inch gauge
SMR steam methane reforming
ii
Introduction
The International Hydrogen Infrastructure Group (IHIG) requested a comparative “scoping”
economic analysis of 19 pathways for producing, handling, distributing, and dispensing
hydrogen for fuel cell (FC) vehicle applications. Of the 19 pathways shown in Table 1, 15 were
designated for large-scale central plants and the remaining four pathways focus on smaller
modular units suitable for forecourt (fueling station) on-site production. Production capacity is
the major determinant for these two pathways. The central hydrogen conversion plant is sized to
supply regional hydrogen markets, whereas the forecourt capacity is sized to meet local service
station demand.
Table 1
IHIG Hydrogen Pathways
Original Feedstocks Revised Feedstocks Location of H2 Production

Biomass Biomass Central
Natural gas Natural gas Central and forecourt
Water Water Central and forecourt
Coal Coal Central
Petroleum coke Petroleum coke Central
Methanol Methanol Forecourt
Gasoline Gasoline Forecourt
H2 from ethylene or refinery Residue/pitch Central
The by-product source of hydrogen defined by IHIG in the original proposal has been replaced
with residue/pitch. For all practical purposes, by-product hydrogen from ethylene plants and
naphtha reforming is fully utilized by petrochemical and refining processes. In the future, the
demand for hydrogen will increase at a higher rate than the growth of by-product production.
Since the mid-1990s, the demand for hydrogen in refineries has been growing at an annual rate
of 5%-10%. More hydroprocessing treatment of feedstocks and products are required to meet
increasingly stringent clean fuel specifications for gasoline and diesel. Meanwhile, by-product
hydrogen production has been declining during the same period. Specifically:
• Hydrogen yields from naphtha reforming have been declining as refineries adjust their
operational severity downward to reduce the aromatic content in the reformat; a major
gasoline blending stock.
• Most of the new ethylene capacities are based on less hydrogen-rich liquid feedstocks
such as naphtha.
Hydrogen could be extracted from the eight feedstocks listed in Table 3 using the following five
commercially proven technologies.
Steam methane reforming

Methanol reforming
Gasoline reforming
Gasification/partial oxidation
Electrolysis
1
Table 2 shows feedstocks, associated conversion technologies, and distribution methods for the
14 central facility pathways. For central production plants, there are several intermediate steps
before the hydrogen could be dispensed into FC vehicles. The purified hydrogen has to be either
liquefied or compressed before it can be transported by cryogenic trucks, pipelines, or tube
trailers. In the base case, the delivered hydrogen has to be pressurized to 400 atmospheres (6,000
psig) to be dispensed into FC vehicles outfitted with 340 atmospheres (5,000 psig) on-board
cylinders.
Table 5 shows four forecourt hydrogen production pathways. On-site production eliminates the
need for intermediate handling steps and distribution infrastructure.
Table 2
Central Hydrogen Production Pathways
Case No. Feedstock Conversion Process Method of Distribution

C4 Natural gas Steam methane reforming Liquid H2 via truck
C11 Natural gas Steam methane reforming Gaseous H2 via tube trailer
C3 Natural gas Steam methane reforming Gaseous H2 via Pipeline
C9 Coal Partial oxidation Liquid H2 via truck
C15 Coal Partial oxidation Gaseous H2 via tube trailer
C8 Coal Partial oxidation Gaseous H2 via Pipeline
C6 Water Electrolysis Liquid H2 via truck
C12 Water Electrolysis Gaseous H2 via tube trailer
C5 Water Electrolysis Gaseous H2 via Pipeline
C2 Biomass Gasification Liquid H2 via truck
C10 Biomass Gasification Gaseous H2 via tube trailer
C1 Biomass Gasification Gaseous H2 via Pipeline
C7 Petroleum coke Gasification Gaseous H2 via Pipeline
C13 Residue Gasification Gaseous H2 via Pipeline
Table 3
Forecourt Hydrogen Production Pathways
Case No. Feedstock Conversion Process

F1 Methanol Methanol reforming
F2 Natural gas Steam methane reforming
F3 Gasoline Gasoline reforming
F4 Water Electrolysis
2
Summary
SFA Pacific has developed consistent and transparent infrastructure cost modules for producing,
handling, distributing, and dispensing hydrogen from a central plant and forecourt (fueling
station) on-site facility for fuel cell (FC) vehicle applications. The investment and operating costs
are based on SFA Pacific’s extensive database and verified with three industrial gas companies
(Air Products, BOC, and Praxair) and hydrogen equipment vendors.
The SFA Pacific cost module worksheets allow users to provide alternative inputs for all the
cells that are highlighted in light gray boxes. Flexibilities are provided for assumptions that
include production capacity, capital costs, capital build-up, fixed costs, variable costs,
distribution distance, carrying capacity, fueling station sales volume, dispensing capacity, and
others. Figure 1 compares the costs of hydrogen produced from a 150,000 kg/d central plant
based on natural gas, coal, biomass, and water, delivered to forecourt by either liquid truck, gas
tube trailer, or pipeline with a 470 kg/d forecourt production based on natural gas and water. The
base case capacity was chosen at the beginning of the project to represent infrastructure
requirements for the New York/New Jersey region.
Figure 1
Central Plant and Forecourt Hydrogen Costs
Pipeline
Water Gas Trailer
Liquid Tanker
Forecourt
Biomass Pipeline
Gas Trailer
Liquid Tanker
Pipeline
Coal Gas Trailer
Liquid Tanker
Production
Pipeline
Delivery
Gas Trailer
Natural Gas
Liquid Tanker Dispensing
Forecourt
0 2 4 6 8 10 12 14
Hydrogen Cost, $/kg
Source: SFA Pacific, Inc.
3
Generally, the higher costs of commercial rates for feedstock and utilities coupled with lower
operating rates lead to higher hydrogen costs from forecourt production. Regardless of the
source for hydrogen, the above comparison shows the following trends for central plant
production.
• The energy intensive liquefaction operation leads to the highest production cost, but
incurs the lowest transportation cost
• The high capital investment required for pipeline construction makes it the most
expensive delivery method
• The cost for gas tube trailer delivery is also high, slightly less than the pipeline cost,
because the low hydrogen density limits each load to about 300 kg.
Other findings from this evaluation could facilitate the formulation of hydrogen infrastructure
development strategies from the initial introductory period through ramp-up to a fully developed
market.
• Advantages of economy of scale and lower industrial rates for feedstock and power
compensate for the additional handling and delivery costs needed for distributing
hydrogen to fueling stations from central plants.
• Hydrocarbon feedstock-based pathways have economic advantages in both investment
and operating costs over renewable feedstocks such as water and biomass.
• Economics of forecourt production suffer from low utilization rates and higher
commercial rates for feedstock and electricity. For natural gas based feedstock, the
hydrogen costs from forecourt production are comparable to those of hydrogen produced
at a central plant and distributed to fueling stations by tube trailer, and are 20% higher
than the liquid tanker truck delivery pathway.
• To meet the increasing demand during the ramp-up period, a “mix and match” of the
three delivery systems (tube trailers, tanker trucks, and pipelines) is a likely scenario.
Tube trailers, which haul smaller quantities of hydrogen, are probably best suited for the
introductory period. As the demand grows, cryogenic tanker trucks could serve larger
markets located further from the central plant. As the ramp-up continues, additional
production trains would be added to the existing central plants, and ultimately a few
strategically placed hydrogen pipelines could connect these plants to selected stations and
distribution points.
• On-board liquid (methanol or naphtha) reforming or direct FC technology could leverage
the existing liquids infrastructure. It would eliminate costly hydrogen delivery and
dispensing infrastructures, as well as avoid regulatory issues regarding hydrogen
handling.
4
Consistency and Transparency
The SFA Pacific cost modules are “living documents.” The flexible inputs allow revisions for
infrastructure adjustments and future improved capital and operating cost bases.
Ease of Comparison
Table 4 shows that, at comparable capacity, SFA Pacific’s models yield cost estimates similar to
those developed by Air Products for the Hydrogen Infrastructure Report [1] sponsored by Ford
and the U.S. Department of Energy (DOE). Key findings from the Air Products evaluation were
also published in the International Journal of Hydrogen Energy [2].
Table 4
Comparison of Hydrogen Costs Developed by SFA Pacific and Air Products
Investment ($million) Hydrogen Cost ($/kg)

H2 Capacity SFA Air SFA Air
Feedstock (t/d) H2 Source Pacific Products Pacific Products
Natural Gas 27 Liquid 102 63 4.34 3.35
Natural Gas 27 Pipeline a 71 82 3.08 2.91
Natural Gas 2.7 Forecourt 6.2 9.6 3.30 3.57
Methanol 2.7 Forecourt 6.0 6.8 3.46 3.76
a
To be consistent with the estimates from Air Products, SFA Pacific excluded fueling state investment and
operating costs in this comparison.
The differences between SFA Pacific and Air Products costs for hydrogen delivered by
cryogenic tanker trucks could be attributed to a large discrepancy shown in the capital
investment for fueling station infrastructure (Table 5).
Table 5
Capital Investment Allocations for Methane Based Liquefied Hydrogen
($Million)
SFA Pacific Air Products

Steam Methane Reformer 21 19
Liquefier 44 41
Tanker Trucks 7 n/a
Fueling Stations 30 3
Total 102 63
5
Flexibility Improvements
Currently, the central plant storage matches the form of hydrogen for a designated delivery
option. A separate and independent module for handling and storing purified gaseous hydrogen
would increase the model’s flexibility in evaluating mix-match storage and delivery options to
meet the rising demand during the ramp-up period.
Potential Improvements for Hydrogen Economics

All hydrogen pathways were developed based on conventional technology and infrastructure
deployment. However, new technologies and novel operating options could potentially reduce
the cost of hydrogen, thus making it a more attractive fuel option.
Central Plant Hydrogen Production

• Polygeneration (a term referring to the co-production of electric power for sale to the
grid) would improve the hydrogen economics. Central gasification units have advantages
of economy of scale and lower marginal operating and maintenance costs compared with
the same option for forecourt production.
• Installing a liquefaction unit would lower the central storage costs and provide greater
flexibility. It is more practical to store large amounts of liquid than gaseous hydrogen.
More storage capacity would allow the hydrogen plant to operate at a higher utilization
rate. If the hydrogen is to be transported either by pipelines or tube trailers, a slipstream
from the boil-off could supply the gaseous hydrogen for distribution.
• Using a hybrid technology or heat-exchange design improves steam reforming operation
and increases conversion. Autothermal reforming (ATR), which combines partial
oxidation with reforming, improves heat and temperature management. Instead of a
single-step process, ATR is a two-step process in hydrogen plants—the partially
reformed gases from the primary reformer feed a secondary oxygen blown reformer with
additional methane. The exothermic heat release from the oxidation reaction supplies the
endothermic heat needs of the reforming reactions. Including reforming reactions allows
co-feeding of CO2 or steam to achieve a wider range of H2/CO ratios in the syngas.
• Capturing CO2 for enhanced oil recovery (EOR) or for future CO2 trading could improve
the economics of hydrogen production if CO2 mitigation is mandated and supported by
trading.
Hydrogen Distribution
• Hydrogen pipeline costs could be reduced by placing the pipelines in sewers, securing
utility status, or converting existing natural gas pipelines to carry a mixture of
hydrogen/natural gas (town gas).
• Using ultra high-pressure (10,000 psig) tube trailers could potentially triple the carrying
load.
6
Hydrogen Fueling Stations
The infrastructure investment for fueling stations could reach 60% of the total capital costs. By
using the global positioning system (GPS), which has gained wide consumer acceptance, we
could significantly lower the traditional strategy of 25% urban and 50% rural area hydrogen
service station penetration. The GPS system would enable FC vehicle drivers to locate fueling
stations more efficiently. Additional strategies for reducing infrastructure investment include:
• Using ultra high-pressure (about 800 to 900 atmospheres) vessels to increase forecourt
hydrogen storage capacity. It may be possible to have large vertical vessels underground
or to use them as canopy supports to minimize land usage.
• Replacing on-board hydrogen cylinders with pre-filled ones instead of the traditional fill-
up option could eliminate fueling station infrastructure investment.
• Dispensing liquid hydrogen into FC vehicles (an idea brought up by BMW during the
April 4, 2002 meeting) could eliminate the need for expensive compression and storage
costs at forecourts. However, an innovative on-board liquid hydrogen storage design is
needed to prevent boil-off when the FC vehicle is not in use.
Hydrogen Economic Module Basis

SFA Pacific developed simplified energy, material balance, capital investment, and operating
costs to achieve transparency and consistency. Cost estimates are presented in five workbooks
(Appendix A) include central plant, distribution, fueling station, forecourt, and overall summary.
Each worksheet includes a simplified block flow diagram and major line items for capital and
operating costs. Capital investment and operating costs are based on an extensive proprietary
SFA Pacific database, which has been verified with industrial gas producers and hydrogen
equipment vendors. The database contains reliable data for large and small-scale steam methane
reforming and gasification units. Although SFA has confirmed the estimates for electrolyzers
with industrial gas companies, they could probably be improved further. There are many
advocates and manufacturers giving quotes that are significantly lower than those used in this
analysis. Some of these discrepancies could be attributed to the manufacturers’ exclusion of a
processing step to remove contaminants, and others could result from optimistic estimates based
on projected future breakthroughs.
The investment and operating costs modules are developed based upon commonly accepted cost
estimating practices. Capital build-up is based on percentages of battery limit process unit costs.
Variable non-fuel and fixed operating and maintenance (O&M) costs are estimated based on
percentages of total capital per year. Capital charges are also estimated as percentages of total
capital per year assumptions for capital investment. Operating costs (variable and fixed) and
capital charges are listed in Table 6. For ease of comparison, all unit costs are shown in $/million
Btu, $/1,000 scf, and $/kg ($/gal gasoline energy equivalent).
The capital cost estimates are based on U.S. Gulf Coast costs. A location factor adjustment is
provided to facilitate the evaluation of costs for three targeted states: high cost urban areas such
as New York/New Jersey and California and low-cost lower population density Texas. Two
provisions are made at forecourt/fueling stations to allow “what-if” analysis: (1) road tax input
accommodates possible government subsidies to jump-start the hydrogen economy and (2) gas
station mark-ups permit incentives for lower revenue during initial stages of low hydrogen
demand.
7
Table 6
Capital and Operating Costs Assumptions
Capital Build-up % of Process Unit Typical Range

General Facilities 20 20-40 a
Engineering, Permitting, and 15 10-20
Startup
Contingencies 10 10-20
Working Capital, Land, and 7 5-10
Others
Operating Costs Build-up %/yr of Capital Typical Range

Variable Non-Fuel O&M 1.0 0.5-0.5
Fixed O&M 5.0 4-7
Capital Charges 18.0 20-25 for refiners
14-20 for utilities
a
20%-40% for steam methane reformer and an additional 10% for gasification.
Hydrogen Production Technology

Three distinct types of commercially proven technologies were selected to extract hydrogen from
the eight feedstocks. Fundamental principles for each technology apply regardless of the unit
size. A brief technical review of reforming, gasification, and electrolysis describes the major
processing steps required for each hydrogen production pathway.
• Reforming is the technology of choice for converting gaseous and light liquid
hydrocarbons
• Gasification or partial oxidation (PO) is more flexible than reforming—it could process a
range of gaseous, liquid, and solid feedstocks.
• Electrolysis splits hydrogen from water.
8
Reforming
Steam methane reforming (SMR), methanol reforming, and gasoline reforming are based on the
same fundamental principles with modified operating conditions depending on the hydrogen-to-
carbon ratio of the feedstock.
SMR is an endothermic reaction conducted under high severity; the typical operating conditions
are 30 atmospheres and temperatures exceeding 870°C (1,600°F). Conventional SMR is a fired
heater filled with multiple tubes to ensure uniform heat transfer.
CH4 + H2O <=> 3H2 + CO (1)
Typically the feedstock is pretreated to remove sulfur, a poison which deactives nickel reforming
catalysts. Guard beds filled with zinc oxide or activated carbon are used to pretreat natural gas
and hydrodesulfurization is used for liquid hydrocarbons. Commercially, the steam to carbon
ratio is between 2 and 3. Higher stoichiometric amounts of steam promote higher conversion
rates and minimize thermal cracking and coke formation.
Because of the high operating temperatures, a considerable amount of heat is available for
recovery from both the reformer exit gas and from the furnace flue gas. A portion of this heat is
used to preheat the feed to the reformer and to generate the steam for the reformer. Additional
heat is available to produce steam for export or to preheat the combustion air.
Methane reforming produces a synthesis gas (syngas) with a 3:1 H2/CO ratio. The H2/CO ratio
decreases to 2:1 for less hydrogen-rich feedstocks such as light naphtha. The addition of a CO
shift reactor could further increase hydrogen yield from SMR according to Equation 2.
CO + H2O => H2 + CO2 (2)
The shift conversion may be conducted in either one or two stages operating at three temperature
levels. High temperature (660°F or 350°C) shift utilizes an iron-based catalyst, whereas medium
and low (400°F or 205°C) temperature shifts use a copper based catalyst. Assuming 76% SMR
efficiency coupled with CO shift, the hydrogen yield from methane on a volume is 2.4:1.
There are two options for purifying crude hydrogen. Most of the modern plants use multi-bed
pressure swing adsorption (PSA) to remove water, methane, CO2, N2, and CO from the shift
reactor to produce a high purity product (99.99%+). Alternatively, CO2 could be removed by
chemical absorption followed by methanation to convert residual CO2 in the syngas.
Gasification
Traditionally, gasification is used to produce syngas from residual oil and coal. More recently, it
has been extended to process petroleum coke. Although not as economical as SMR, there are a
number of natural gas-based gasifiers. Other feedstocks include refinery wastes, biomass, and
municipal solid waste. Gasification of 100% biomass feedstock is the most speculative
technology used in this project. Total biomass based gasification has not been practiced
9
commercially. However, a 25/75 biomass/coal has been commercially demonstrated by Shell at
their Buggenm refinery. The biomass is dried chicken waste.
In addition to the primary reaction shown by Equation 3, a variety of secondary reactions such as
hydrocracking, steam gasification, hydrocarbon reforming, and water-gas shift reactions also
take place.
CaHb + a/2O2 => b/2H2 + aCO (3)
For liquid and solids gasification, the feedstocks react with oxygen or air under severity
operating conditions (1,150°C -1,425°C or 2,100°F -2,600°F at 400-1,200 psig). In hydrogen
production plant, there is an air separation unit (ASU) upstream of the gasifier. Using oxygen
rather than air avoids downstream nitrogen removal steps.
In some designs, the gasifiers are injected with steam to moderate operating temperatures and to
suppress carbon formation. The hot syngas could be cooled directly with a water quench at the
bottom of the gasifier or indirectly in a waste heat exchanger (often referred to as a syngas
cooler) or a combination of the two. Facilitating the CO shift reaction, a direct quench design
maximizes hydrogen production. The acid gas (H2S and CO2) produced has to be removed from
the hydrogen stream before it enters the purification unit.
When gasifying liquids, it is necessary to remove and recover soot (i.e., unconverted feed
carbon), ash, and any metals (typically vanadium and nickel) that are present in the feed. The
recovered soot can be recycled to the gasifier, although such recycling may be limited when the
levels of ash and metals in the feed are high. Additional feed preparation and handling steps
beyond the basic gasification process are needed for coal, petroleum coke, and other solids such
as biomass.
Electrolysis
Electrolysis is decomposition of water into hydrogen and oxygen, as shown in Equation 4.
H2O + electricity => H2 + ½ O (4)
Alkaline water electrolysis is the most common technology used in larger production capacity
units (0.2 kg/day). In an alkaline electrolyzer, the electrolyte is a concentrated solution of KOH
in water, and charge transport is through the diffusion of OH- ions from cathode to anode.
Hydrogen is produced at the cathode with almost 100% purity at low pressures. Oxygen and
water by-products have to be removed before dispensing.
Electrolysis is an energy intensive process. The power consumption at 100% efficiency is about
40 kWh/kg hydrogen; however, in practice it is closer to 50 kWh/kg. Since electrolysis units
operate at relatively low pressures (10 atmospheres), higher compression is needed to distribute
the hydrogen by pipelines or tube trailers compared to other hydrogen production technologies.
10
Central Plant Hydrogen Production
Figure 2 shows that each central production hydrogen pathway consists of four steps: hydrogen
production, handling, distribution, and dispensing.
Figure 2
Central Plant Hydrogen Production Pathway
H2 Production H2 Handling H2 Distribution H2 Dispensing

Biomass Coal Liquefaction Cryogenic Truck Vaporized liquid
Water Residue Compression Tube Trailer Compressed gas
Natural gas Coke Pipeline
Table 7 lists feedstocks and utility costs used in this analysis. Central plant hydrogen production
benefits from lower industrial rates, whereas the fueling stations are charged with the higher
commercial rates.
Table 7
Central Hydrogen Production Feedstock and Utility Costs
Unit Cost
Natural gas (industrial) $3.5/MMBtu HHV
Electricity (industrial) $0.045/kW
Electricity (commercial) $0.070/kW
Biomass $57/bone dry ton
Coal $1.1/MMBtu dry HHV
Petroleum coke $0.2/MMBtu dry HHV
Residue (Pitch) $1.5/MMBtu dry HHV
Source: Annual Energy Outlook 2002 Reference Case Tables, EIA.
The design production capacity for each central plant ranges from 20,000 kg/d to 200,000 kg/d
hydrogen with a 90% utilization rate. An arbitrary design capacity of 150,000 kg/d has been
chosen for discussion purposes. Table 8 shows that the cost of hydrogen for hydrocarbon based
feedstock is lower than renewables. For each feedstock, the cost of hydrogen via cryogenic liquid
tanker truck delivery pathway is 10%-25% lower than by tube trailer and 15%-30% less than by
pipeline. Since the cost of liquid delivery is relatively small (less than 5%), the costs for
hydrocarbon based feedstock, production, and fueling account for close to 67% and 33% of the
total hydrogen costs, respectively. For renewables (biomass and water), the production cost
accounts for 70%-80% of the total hydrogen cost. With high investment costs, the tube trailer
and pipeline delivery account for 50% of the total cost.
11
Table 8
Summary of Central Plant Based Hydrogen Costs
(1,000 kg/d hydrogen)
Liquid Tanker Gas Tube Pipeline,

Delivery Pathway Truck, $/kg Trailer, $/kg $/kg
Natural Gas
Production 2.21 1.30 1.00
Delivery 0.18 2.09 2.94
Dispensing 1.27 1.00 1.07
Total 3.66 4.39 5.00
Coal
Delivery 0.18 2.09 2.94
Total 4.51 5.18 5.62
Biomass
Delivery 0.18 2.09 2.94
Total 4.98 5.77 6.29
Water
Delivery 0.18 2.09 2.94
Total 7.62 8.39 9.13
Petroleum Coke
Production 1.35
Delivery 2.94
Dispensing 1.07
Total 5.35
Residue
Production 1.27
Delivery 2.94
Dispensing 1.07
Total 5.27
12
Numerous studies have been conducted to evaluate the economics of using renewable feedstocks
to produce energy and fuels. Waste biomass and co-product biomass are very seasonal and have
high moisture content, except for field-dried crop residues. As a result, they require more
expensive storage and extensive drying before gasification. Furthermore, very limited supplies
are available and quantities are not large or consistent enough to make them a viable feedstock
for large-scale hydrogen production. Cultivated biomass is the only guaranteed source of
biomass feedstock, and as a crop, the yield is relatively low (10 ton/hectare). As a result, large
land mass is required to provide a steady supply of feedstock. This dedicated renewable biomass
comes at a cost of $57/bone dry ton (BDT), which includes $500/hectare/yr and $7/BTD delivery
cost. However, available biomass could supplement other solid feeds to maximize the utilization
of the gasification unit. Finally, biomass gasification processes are not effective for pure
hydrogen production due to their air-blown operations or a product gas that is high in methane
and requires additional reforming to produce hydrogen.
Water is another feedstock commonly referred to as a renewable energy source. Although

hydrogen occurs naturally in water, the extraction costs are still considerably higher than
conventional hydrocarbon based energy sources.
Hydrogen Handling and Storage

Purified hydrogen has to be either liquefied for cryogenic tanker trucks or compressed for
pipeline or tube trailer delivery to fueling stations.
Hydrogen Liquefaction
Liquefaction of hydrogen is a capital and energy intensive option. The battery limit investment is
$700/kg/d for a 100,000 kg/d hydrogen plant, and compressors and brazed aluminum heat
exchanger cold boxes account for most of the cost. The total installed capital cost for the
liquefier, excluding land and working capital is $1,015 kg/d, which agrees well with the $1,125
estimate from Air Products. Multi-stage compression consumes about 10-13 kWh/kg hydrogen.
Gaseous crude hydrogen from the PSA unit undergoes multiple stages of compression and
cooling. Nitrogen is used as the refrigerant to about 195°C (-320°F). Ambient hydrogen is a
mixture 75% ortho- and 25% para-hydrogen, whereas liquid hydrogen is almost 100% para-
hydrogen. Unless ortho-hydrogen is catalytically converted to para-hydrogen before the
hydrogen is liquefied, the heat of reaction from the exothermic conversion of ortho-hydrogen to
para-hydrogen, which doubles the latent heat of vaporization, would cause excessive boil-off
during storage. The liquefier feed from the PSA unit mixes with the compressed hydrogen and
enters a series of ortho/para-hydrogen converters before entering the cold end of the liquefier.
Further cooling to about -250°C (-420°F) is accomplished in a vacuum cold box with brazed
aluminum flat plate cores. The remaining 20% ortho-hydrogen is converted to achieve 99%+
para-hydrogen in this section.
13
Gaseous Hydrogen Compression
Gaseous hydrogen compressors are major contributors to capital and operating costs. To deliver
high-pressure hydrogen, 3-5 stages of compression are required because water-cooled positive-
displacement compressors could only achieve 3 compression ratios per stage. Compression
requirements depend on the hydrogen production technology and the delivery requirements. For
pipeline delivery, the gas is compressed to 75 atmospheres for 30 atmospheres delivery. Higher
pressures are used to compensate for frictional loss in pipelines without booster compressors
along the pipeline system. The gaseous hydrogen has to be compressed to 215 atmospheres to fill
tube trailers. In this study, the unit capital cost is between $2,000/kW and $3,000/kW and the
power requirement ranged from 0.5 kW/kg/hr to 2.0 kW/kg/hr.
Hydrogen Storage
On-site storage allows continuous hydrogen plant operation in order to achieve higher utilization
rates. It is more practical to store large amounts of hydrogen as liquid. At less than $5/gallon
(physical volume) capital cost, liquid hydrogen storage is relatively inexpensive compared to
compressed gaseous hydrogen. Table 9 shows that hydrogen is the lowest energy density fuel on
earth. It would take 3.73 gallons of liquid hydrogen to provide equivalent energy of one gallon of
gasoline. Gaseous hydrogen has to be pressurized for storage. At the base case pressure of 400
atmospheres (6,000 psig), it would require about 8 gallons of gaseous hydrogen to have the same
energy content as one gallon of gasoline. The higher the gas pressure, the lower the storage
volume needed. However, the tube becomes weight limited as the thickness of the steel wall
increases to prevent embrittlement (cracking caused by hydrogen migrating into the metal).
Table 9
Density of Vehicle Fuel
Fuel Type Density (kg/l)

Compressed Hydrogen 0.016
Gasoline 0.8
Methanol 0.72
Figure 3 shows how the cost of gaseous storage tubes increases with pressure. The cost could
increase from less than $400/kg hydrogen at 140 atmospheres to $2100/kg hydrogen at 540
atmospheres. Companies such as Lincoln Composites and Quantum Technologies are developing
new synthetic materials to withstand high pressures at a larger range of temperatures.
14
Figure 3
Hydrogen Storage Container Costs
2500
2000
Storage Container, $/kg H2
1500
1000
500
0
0 100 200 300 400 500 600
Hydrogen Storage Pressure, Atmospheres
Hydrogen Distribution
This study includes three hydrogen distribution pathways: cryogenic liquid trucks, compressed
tube trailers, and gaseous pipelines. Figure 4 shows that each option has a distinct range of
practical application.
Figure 4
Hydrogen Distribution Options
Pipeline
Liquid Truck
Tube Trailer
0.1 1 10 100
Million SCF/D
0.2 2.4 24 241
Ton Per Day
Source: Air Products.
15
A combination of these three options could be used during various stages of hydrogen fuel
market development.
• Tube trailers could be used during the initial introductory period because the demand
probably will be relatively small and it would avoid the boil-off incurred with liquid
hydrogen storage.
• Cryogenic tanker trucks could haul larger quantities than tube trailers to meet the
demands of growing markets.
• Pipelines could be strategically placed to transport hydrogen to high demand areas as
more production capacities are placed on-line.
Road Delivery (Tanker Trucks and Tube Trailers)

Based on the assumptions shown in Table 10, the cost of liquid tanker truck delivery is about
10% of tube trailer delivery ($0.18/kg vs. $2.09/kg).
Table 10
Road Hydrogen Delivery Assumptions
Cryogenic Truck Tube Trailer

Load, kg 4,000 300
Net delivery, kg 4,000 250
Load/unload, hr/trip 4 2
Boil-off rate, %/day 0.3 na
Truck utilization rate, % 80 80
Truck/tube, $/module 450,000 100,000
Undercarriage, $ 60,000 60,000
Cab, $ 90,000 90,000
Delivery by cryogenic liquid hydrogen tankers is the most economical pathway for medium
market penetration. They could transport relatively large amounts of hydrogen and reach markets
located throughout large geographic areas. Tube trailers are better suited for relatively small
market demand and the higher costs of delivery could compensate for losses due to liquid boil-
off during storage. However, high-pressure tube trailers are limited to meeting small hydrogen
demands. Typically, the tube-to-hydrogen weight ratio is about 100-150:1. A combination of low
gaseous hydrogen density and the weight of thick wall, high quality steel tubes (80,000 pounds
or 36,000 kilograms) limit each load to 300 kilograms of hydrogen. In reality, only 75%-85% of
each load is dispensable, depending on the dispensing compressor configuration. Unlike tanker
trucks that discharge their load, the tube and undercarriage are disconnected from the cab and left
at the fueling station. Tube trailers are used not only as transport container, but also as on-site
16
storage. As a result, the total number of tubes provided equals the number of tubes left at the
fueling stations and those at the central plants to be picked up by the returning cabs.
Liquid hydrogen flows into and out of the tanker truck by gravity and it takes about two hours to
load and unload the contents. SFA Pacific estimates the physical delivery distance for
truck/trailers is 40% longer than the assumed average distance of 150 kilometers between the
central facility and fueling stations.
Pipeline Delivery
Pipelines are most effective for handling large flows. They are best suited for short distance
delivery because pipelines are capital intensive ($0.5 to $1.5 million/mile). Much of the cost is
associated with acquiring right-of-way. Currently, there are 10,000 miles of hydrogen pipelines
in the world. At 250 miles, the longest hydrogen pipeline connects Antwerp and Normandy.
Operating costs for pipelines are relatively low. To deliver hydrogen to the fueling stations at 30
atmospheres, the pressure drop could be compensated with either booster compressors or by
compressing the hydrogen at the central plant. In this study, the pipeline investment is based on
four pipelines radiating from the central plant.
Hydrogen Fueling Station

The conceptual hydrogen fueling station for this study is designed based on equivalent
conventional internal combustion engine (ICE) requirements as shown in Table 11.
Table 11
Assumed FC Vehicle Requirements
ICE-gasoline FC requirement
Vehicle mileage 23 km/liter 23 km/liter
Vehicle annual mileage 12,000 miles 218 kg H2 or 12,000 miles
Fuel sales per station 150,000 gal/month 10,000 kg H2/monthor 10,000 gal
gasoline equivalent
Table 12 shows that the key fueling station design parameters. At a 70% operating rate, each
service station dispenses about 329 kg/d, assuming a daily average of 4.0 kg per fill-up and five
fill-ups an hour. Each fueling hose is sized to meet daily peak demand.
17
Table 12
Fueling Dispenser Design Basis
Design capacity 470 kg/d

Operating rate 70%
Operating capacity 329 kg/d
Number of dispenser 2
Average fill-up rate 4 kg
Average number of fill-up 5 /hr
Peak fill-up rate (3 times daily average) 48 kg/hr
Dispensing pressure, psig 6,000
Sizing hydrogen dispensers is no different than sizing gasoline dispensers; they must be designed
to meet peak demands. As shown in Figure 5, the peak demand could be triple that of the daily
average.
Figure 5
Fueling Station Dispensing Utilization Profile
0.12
Fractional Load/Hr
0.1
0.08
0.06
0.04
0.02
0
0 2 4 6 8 10 12 14 16 18 20 22 24
Time of Day
Source: Praxair.
This study developed analyses for two types of high-pressure gaseous fueling stations: one to
handle liquid based hydrogen and the other for gaseous hydrogen. Components handling
compressed hydrogen (6,000 psig) are the same regardless of the form of hydrogen delivered to
the fueling station. Since positive displacement pumps and compressors cannot provide
instantaneous load or meet the high-rate demand for dispensing hydrogen directly to FC vehicles,
each filling station is provided with three hours of peak demand high-pressure hydrogen buffer
storage. The dispenser meters the hydrogen into a FC vehicle fitted with 5,000 psig cylinders.
18
Liquid Hydrogen Based Fueling
Liquid hydrogen from storage (15,000 gallons) is pressurized to 6,000 psig with variable speed
reciprocating positive displacement pumps. An ambient or natural convection vaporizer, which
uses ambient air and condensed water to supply the heat requirement for vaporizing and warming
the high-pressure gas, does not incur additional utility costs.
Gaseous Hydrogen Based Fueling

Gaseous hydrogen could be delivered either by pipeline at 30 atmospheres or by tube trailer at
215 atmospheres to the fueling station. To minimize the high cost of hydrogen storage, both
pipeline and tube trailer gases are compressed to 6,000 psig and held in a buffer storage. Two
other possible options (multi-stage cascade system and booster system) require considerably
more expensive hydrogen storage.
Forecourt Hydrogen Production

Forecourt production pathways were developed to evaluate the potential economic advantages of
placing small modular units at fueling stations to avoid the initial investment of under utilized
large central facilities and delivery infrastructures. The forecourt hydrogen facility is sized to
supply and dispense the same amount of hydrogen as each fueling station in the central plant
pathways. Each unit is designed to produce 470 kg/d of hydrogen with a 70% utilization rate.
Figure 6 shows that forecourt hydrogen production is a self-contained operation. Ideally,
hydrogen is compressed to 400 atmospheres (6,000 psig) after purification and dispensed directly
into the FC vehicle with 340 atmosphere (5,000 psig) cylinders.
Figure 6
Forecourt Hydrogen Production Pathways
H2 Production Dispensing
Water High pressure gas
Natural gas
Methanol
Gasoline
Table 13 lists commercial rates for feedstocks and power. The commercial rates charged to small
local service stations are consistently 50%-70% higher than industrial rates for large production
plants. Natural gas delivered to forecourt costs 70% more than that delivered to a central facility
($6/million Btu vs. $3.5/million Btu) and the power cost is 55% higher (7¢/kWh vs. 4.5¢/kWh).
Often, proponents of a hydrogen economy provide cost estimates based on off-peak power rates
(~$0.04/kWh). Off-peak is only available for 12 hours, after which the forecourt would be
charged with peak rates ($0.09/kWh). To circumvent peak power rates, forecourt plants have to
19
be built with oversized units operated at low utilization rates with large amounts of storage. This
option would require considerable additional capital investment.
Instead of developing a complete production and delivery infrastructure for methanol, this
evaluation uses market prices for methanol. Methanol prices are based on current supplies to
chemical markets, and distribution costs per gallon of methanol are twice that of gasoline per
gallon or four times that of gasoline on an energy basis.
Table 13
Forecourt Hydrogen Production Feedstock and Utility Costs
Unit Cost
Natural gas (commercial) $5.5/MMBtu HHV
Electricity (commercial) $0.07/kW
Methanol $7.0/MMBtu HHV
Gasoline $6.0/MMBtu HHV
Source: Annual Energy Outlook 2002 Reference Case Tables, EIA.

Current Methanol Price, Methanex, February, 2002.
Table 14 shows that the costs for forecourt production of hydrogen from hydrocarbon based
feedstocks are within 10%-15% of each other, ranging from $4.40/kg to $5.00/kg hydrogen. The
cost for electrolysis based hydrogen is two to three times that of the other three feedstocks. The
high cost of electrolytic hydrogen is attributable to high power usage and high capital costs—
electricity and capital charges account for 30% and 50% of the total cost, respectively.
Table 14
Summary of Forecourt Hydrogen Costs
(470 kg/d Hydrogen)
Feedstock $/kg
Methanol 4.53
Natural Gas 4.40
Gasoline 5.00
Water 12.12
For the two feedstocks common to both the central and forecourt plant, Table 15 shows that the
lower infrastructure requirements of forecourt production do not compensate for the higher
operating costs.
20
Table 15
Hydrogen Costs: Central Plant vs. Forecourt
($/kg Hydrogen)
Central Plant a Forecourt

Natural Gas 3.66 4.40
Water 7.62 12.12
a
Liquid hydrogen delivery pathway.
The proposed option of utilizing the hydrogen produced at the forecourt to fuel on-site power
generation during initial low hydrogen demand does not make economic sense. Excluding the
high capital cost of fuel cell power generation and commercial scale grid connections for
exporting electricity, the marginal load dispatch cost of power alone would make this strategy
non-competitive. As a result, this pathway was eliminated from our analysis during the kick-off
meeting on January 23, 2002.
Sensitivity
SFA Pacific developed a 700 atmospheres (10,000 psig) FC vehicle sensitivity case. This ultra
high pressure would allow the vehicle to meet ICE vehicle standards (equal or greater distance
between fill ups). Similarly detailed worksheets for the ultra high-pressure case are presented in
Appendix B.
Between 1920 and 1950, the process industry had extensive commercial operating experience
with 10,000 psig operation in ammonia synthesis and the German coal hydrogenations plants.
Improvements in catalytic activity had lowered the operating pressures for these processes,
which in turn significantly reduced capital and operating costs. Even though there is less demand
for equipment to handle very high-pressure hydrogen, several companies still manufacture ultra
high-pressure compressors and vessels. The cost of hydrogen compressors capable of handling
875 atmospheres (13,000 psig) is significantly more than the base case ($4,000/kW vs.
$3,000/kW). The higher cost could be attributed mostly to expensive premium-steels to avoid
hydrogen stress cracking at ultra high pressures. However, data on these costs are not readily
available and are also inconsistent due to the lack of common use, small sizes, and the special
fabrication requirements. Until a time when composite material becomes economically viable for
high-pressure storage, it is may be best to develop the fueling infrastructure for 5,000 psig FC
vehicle cylinders.
21
Special Acknowledgement
SFA Pacific would like to express our gratitude to the following three industrial gas companies
for their insightful discussion and comments after reviewing our draft cost estimates for the
hydrogen production, delivery, and dispensing infrastructure.
Air Products and Chemicals

BOC
Praxair
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24
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25
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26
Pipeline
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27
Appendix A
Complete Set of Spreadsheets
For Base Case Input
Summary of Natural Gas Based Hydrogen Production
Final Version June 2002 IHIG Confidential
Design hydrogen production 150,000 kg/d H2 and 90% Annual ave. load facor
Supporting 225,844 FC Vehicles at 411 Filling station
Hydrogen per filling station 10,000 kg/mo H2 or 329 kg/d H2
Capital Investment Liquid H2 Pipeline Tube Trailer

Million $/yr Million $/yr Million $/yr
H2 production 230 79 133
H2 delivery 13 603 141
H2 fueling 279 212 212
Total 522 894 486
Annual Operating Costs Liquid H2 Pipeline Tube Trailer

$ million/yr $ million/yr $ million/yr
H2 fueling 63 53 49
Total 180 246 216
Unit H2 Cost in $/kg which is the same as $/gallon gasoline energy equivalent
Liquid H2 Pipeline Tube Trailer Forecourt
$/kg $/kg $/kg $/kg
H2 production 2.21 1.00 1.30
H2 delivery 0.18 2.94 2.09
H2 fueling 1.27 1.07 1.00
Total 3.66 5.00 4.39 4.40

Summary of Resid Hydrogen Production
Capital Investment Pipeline

Million $/yr
H2 production 185
H2 delivery 603
H2 fueling 212
1,000
Annual Operating Costs Pipeline

$ million/yr
H2 production 62
H2 delivery 145
H2 fueling 53
Total 260
Pipeline
$/kg
H2 production 1.27
H2 delivery 2.94
H2 fueling 1.07
Total 5.27

Summary of Petroleum Coke Based Hydrogen Production
Capital Investment Pipeline

Million $/yr
H2 production 238
H2 delivery 603
H2 fueling 212
1,053
Annual Operating Costs Pipeline

$ million/yr
H2 production 66
H2 delivery 145
H2 fueling 53
Total 264
Pipeline
$/kg
H2 production 1.35
H2 delivery 2.94
H2 fueling 1.07
Total 5.35

Summary of Coal Based Hydrogen Production

H2 fueling 279 212 212
740 1,074 692

H2 fueling 63 53 49
Total 222 277 255
Liquid H2 Pipeline Tube Trailer
$/kg $/kg $/kg
H2 production 3.06 1.62 2.09
H2 delivery 0.18 2.94 2.09
H2 fueling 1.27 1.07 1.00
Total 4.51 5.62 5.18

Summary of Biomass Based Hydrogen Production

H2 fueling 279 212 212
744 1,110 715

H2 fueling 63 53 49
Total 246 310 284
Liquid H2 Pipeline Tube Trailer
$/kg $/kg $/kg
H2 production 3.53 2.29 2.69
H2 delivery 0.18 2.94 2.09
H2 fueling 1.27 1.07 1.00
Total 4.98 6.29 5.77

Summary of Electrolysis Based Hydrogen Production

H2 fueling 279 212 212
980 1,382 955

H2 fueling 63 53 49
Total 376 450 413
Liquid H2 Pipeline Tube Trailer Forecourt
$/kg $/kg $/kg $/kg
H2 production 6.17 5.13 5.30
H2 delivery 0.18 2.94 2.09
H2 fueling 1.27 1.07 1.00
Total 7.62 9.13 8.39 12.12

Forecourt Summary of Inputs and Outputs
Inputs Boxed in yellow are the key input variables you must choose, current inputs are just an example
design basis
Key Variables Inputs Notes
Hydrogen Production Inputs 1 kg H2 is the same energy content as 1 gallon of gasoline
Design hydrogen production 470 kg/d H2 194,815 scf/d H2 100 to 10,000 kg/d range for forecourt
Annual average load factor 70% /yr of design 10,007 kg/month actual or 120,085 kg/yr actual
High pressure H2 storage 3 hr at peak surge rate "plug & play" 24 hr process unit replacements for availability
FC Vehicle gasoline equiv mileage 55 mpg (U.S. gallons) or 23 km/liter 329 kg/d average
FC Vehicle miles per year 12,000 mile/yr thereby requires 218 kg/yr H2 for each FC vehicle
Capital Cost Buildup Inputs from process unit costs All major utilities included as process units
General Facilities 20% of process units 20-40% typical, should be low for small forecourt
Engineering, Permitting & Startup 10% of process units 10-20% typical, assume low eng. of multiple standard designs
Contingencies 10% of process units 10-20% typical, should be low after the first few
Working Capital, Land & Misc. 9% of process units 5-10% typical, high land costs for forecourt
Site specific factor 110% above US Gulf Coast 90-130% typical; sales tax, labor rates & weather issues
Product Cost Buildup Inputs
Road tax or (subsidy) $ - /gal gasoline equivalent may need subsidy like EtOH to get it going
Gas Station mark-up $ - /gal gasoline equivalent may be needed if H2 sales drops total station revenues
Non-fuel Variable O&M 1.0% /yr of capital 0.5-1.5% is typical
Fuels Methanol $ 7.15 /MM Btu HHV $7-9/MM Btu typical chemical grade delivered rate
Natural Gas $ 5.50 /MM Btu HHV $4-7/MM Btu typical commercial rate, see www.eia.doe.gov
Gasoline $ 6.60 /MM Btu HHV $5-7/MM Btu typical tax free rate go to www.eia.doe.gov
Electricity $ 0.070 /kWh $0.06-.0.09/kWh typical commercial rate, see www.eia.doe.gov
Fixed Operating Cost 5.0% /yr of capital 4-7% typical for refiners: labor, overhead, insurance, taxes, G&A
Capital Charges 18.0% /yr of capital 20-25%/yr CC typical for refiners & 14-20%/yr CC for utilities
20%/yr CC is about 12% IRR DCF on 100% equity where as
15%/yr CC is about 12% IRR DCF on 50% equity & debt at 7%
Outputs 329 kg/d H2 that supports 550 FC vehicles or 10,007 kg/month for this station
actual annual average 79 fill-ups/d if 1 fill-up/week @ 4.2 kg/fill-up
Capital Costs Operating Cost Product Costs
Absolute Unit cost Unit cost Fixed Variable Including capital charges
Case No. Description $ millions design rate design rate Unit cost Unit cost Unit cost Note
$/scf/d H2 $ kg/d H2 $/kg H2 $/kg H2 $/kg H2 same as $/gal gaso equiv
F1 Methanol Reforming 1.57 8.08 3,350 0.66 1.51 4.53 into vehicles at 340 atm
F2 Natural Gas Reforming 1.63 8.35 3,460 0.68 1.28 4.40 into vehicles at 340 atm
F3 Gasoline Reforming 1.78 9.14 3,789 0.74 1.59 5.00 into vehicles at 340 atm
F4 Water Electrolysis 4.15 21.28 8,821 1.73 4.18 12.12 into vehicles at 340 atm
Click on specific Excel worksheet tabs below for details of cost buildups for each case

Path F1
Forecourt Hydrogen via Steam Reformer of Methanol plus High Pressure Gas Storage
Color codes variables via summary inputs key outputs
gasoline equivalent
Design per station Design LHV energy equivalent Assuming 55 mpg and 12,000 mile/yr
Hydrogen gasoline million requires 218 kg/yr H2/vehicle or gal/yr gaso equiv
Size range kg/d H2 gal/d Btu/hr scf/d H2 MW t Assuming 70% Annual average load factor
Maximum 10,000 10,000 47.422 4,145,000 13.894 actual H2 120,085 kg/y H2 /station or gal/y gaso equiv
This run 470 470 2.229 194,815 0.653 or 10,007 kg/month H2 or gal/mo. gaso equiv
Minimum 100 100 0.474 41,450 0.139 thereby 550 FC vehicles can be supported at
79 fill-ups/d @ 4.2 kg or gal equiv/fill-up
H2 HP H2 or each vehicle fills up one a week
Electric Power Compress 19.6 kg/hr H2 storage
Compress 38 2.0 400 atm 3 123 kg H2 max storage or
SMR & misc. 4 kW/kg/h hr at peak 1,052 gal phy vol at 400 atm
Total 42 kW 20
/1 compression ratio surge
3
stages maximum surge fill/up rate per hr at
8,117scf/hr H2 at 3 times average kg/hr H2 production rate
20
atm
MeOH ref 4.0 HP H2
Methanol 75.0% kg/ fill-up dispenser High Pressure (340 atm) Hydrogen
2.972 MM Btu/h LHV LHV effic 5 48 Gas into Vehicles
3.363 MM Btu/h HHV min/fill-up kg/hr/dis 470 design kg/d H2 or gal/d
52 gal/hr @ 64,771 Btu/gal 366 Btu LHV/scf H2 2 dispenser gasoline equivalent
5 day MeOH storage = 6,230 gallons max. design storage 329 actual kg/d annual ave.
215 kg/hr CO2, however in dilute N2 rich SMR flue gas
at 0.75 kg CO2/kWh current U.S. average = 32 kg/hr CO2 equivalent at power plants
12.6 kgCO2/kg H2
Unit cost basis at cost/size Unit cost at millions of $
Capital Costs 1,000 kg/d H2 factors 470 kg/d H2 for 1 station Notes
Methanol storage 5 /gal 70% $ 6 /gal 0.04 same as gasoline tank cost
Methanol reformer $ 2.70 /scf/d 75% $ 3.26 /scf/d 0.64 assume 90% of SMR
H2 Compressor $ 3,000 /kW 80% $ 3,489 /kW 0.13 $ 285 /kg/d H2
HP H2 gas storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.12 $ 991 /kg high press H2 gas
HP H2 gas dispenser $ 15,000 /dispenser 100% $ 15,000 /dispenser 0.03 $ 13 /kg/d dispenser design
Total process units 0.96
General Facilities 20% of process units 0.19 20-40% typical, should be low for this
Engineering Permitting & Startup 10% of process units 0.10 10-20% typical, low eng after first few
Contingencies 10% of process units 0.10 10-20% typical, low after the first few
Working Capital, Land & Misc. 9% of process units 0.09 5-10% typical, high land costs for this
U.S. Gulf Coast Capital Costs 1.43
Site specific factor 110% above US Gulf Coast Total Capital Costs 1.57
Unit Capital Costs of 8.08 /scf/d H2 or 3,350 /kg/d H2 or 3,350 /gal/d gaso equiv
million $/yr $/million $/1,000 $/kg H2 or

Hydrogen Costs at 70% ann load factor of 1 station Btu LHV scf H2 $/gal gaso equiv Notes
Road tax or (subsidy) $ - /gal gaso equiv. - - - - can be subsidy like EtOH
Gas Station mark-up $ - /gal gaso equiv. - - - - if H2 drops total station revenues
Non-fuel Variable O&M 1.0% /yr of capital 0.016 1.15 0.32 0.13 0.5-1.5% is typical
Methanol $ 7.15 /MM Btu HHV 0.147 10.79 2.96 1.23 see below - chemical grade
Electricity $ 0.070 /kWh 0.018 1.33 0.37 0.15 $0.06-.09/kWh EIA commercial rate
Variable Operating Cost 0.181 13.27 3.64 1.51
Fixed Operating Cost 5.0% /yr of capital 0.079 5.76 1.58 0.66 4-7% typical for refining
Capital Charges 18.0% /yr of capital 0.283 20.74 5.69 2.36 20-25% typical for refining
Total HP Hydrogen Cost from Methanol 0.544 39.77 10.92 4.53 including return on investment
in vehicle
$ 0.061 /kWh electricity for only H2 fuel (no capital charges or other O&M) to high capital cost fuel cell @ 60% LHV effic
$ 0.068 /kWh electricity for only MeOH fuel (no capital charges or other O&M) to Solar 4 MWe Mercury 50 GT @ 40% LHV effic
$ 0.067 /kWh electricity for only MeOH fuel (no capital charges or other O&M) to Solar 9 MWe STAC70 CC @ 41% LHV effic
H2-fuel cell power sales during H2 vehicle ramp-up is questionable relative to lower capital & non-fuel O&M
of small NG or MeOH fired GT/CC or the much lower NG costs and higher efficiency, 60% of large industrial NGCC
note: requires $ 0.462 /gal MeOH delivered price back calculated for above $/MM Btu price
assuming $ 0.100 /gal delivery cost at 2 times assumed special reformer gasoline delivery costs
$ 0.362 /gal Feb. 2002 Methanex U.S. reference price was $ 0.360 /gal
Fuel grade MeOH & large scale GTL with low cost NG, like the new Trinidad 5,000 t/d MeOH unit should be cheaper
Source SFA Pacific, Inc

Path F2
Forecourt Hydrogen via Steam Reformer of Natural Gas plus High Pressure Gas Storage
gasoline equivalent
Design for 1 station Design LHV energy equivalent Assuming 55 mpg and 12,000 mile/yr
Hydrogen gasoline million requires 218 kg/yr H2/vehicle or gal/yr gaso equiv.
Maximum 10,000 10,000 47.422 4,145,000 13.894 actual H2 120,085 kg/y H2 /station or gal/y gaso equiv.
This run 470 470 2.229 194,815 0.653 or 10,007 kg/month H2 or gal/mo. gaso equiv.
79 fill-ups/d @ 4.2 kg or gal equiv./fill-up
Total 43 kW 20/1 compression ratio surge
3stages maximum surge fill/up rate per hr at
8,117 scf/hr H2 at 3 times average kg/hr H2 production rate
20atm
SMR 4.0 HP H2
Natural Gas 70.0% kg/ fill-up dispenser High Pressure (340 atm) Hydrogen
3,534 scf/hr @ 1,000 Btu/scf 392 Btu LHV/scf H2 2 dispenser gasoline equivalent
70 kg/hr @23,000 Btu/lb 329 actual kg/d annual ave.
11.4 kgCO2/kg H2
NG Reformer (SMR) $ 3.00 /scf/d 75% $ 3.62 /scf/d 0.71 $ 1,502 /kg/d H2
HP H2 gas storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.12 $ 991 /kg high press H2 gas
Unit Capital Costs 8.35 /scf/d H2 or 3,460 /kg/d H2 or 3,460 /gal/d gaso equiv.

Hydrogen Costs at 70% ann load factor of 1 station Btu LHV scf H2 $/gal gaso equiv. Notes
Variable Non-fuel O&M 1% /yr of capital 0.016 1.19 0.33 0.14 0.5-1.5% is typical
Natural Gas $ 5.50 /MM Btu HHV 0.119 8.72 2.39 0.99 $4-7/MM Btu EIA commercial rate
Fixed Operating Cost 5% /yr of capital 0.081 5.95 1.63 0.68 4-7% typical for refining
Capital Charges 18% /yr of capital 0.293 21.42 5.88 2.44 20-25% typical of refining
Total HP Hydrogen Costs from Natural Gas 0.528 38.64 10.61 4.40 including return on investment
in vehicle
$ 0.052 /kWh electricity for only NG fuel (no capital charges or other O&M) to Solar 4 MWe Mercury 50 GT @ 40% LHV effic
$ 0.051 /kWh electricity for only NG fuel (no capital charges or other O&M) to Solar 9 MWe STAC70 CC @ 41% LHV effic
of small NG fired GT/CC or the much lower NG costs and higher efficiency, 60% of large industrial NGCC
note: Assume gas station has existing natural gas pipeline infrastructure, if not more capital or higher NG price

Path F3
Forecourt Hydrogen via Steam Reformer of Gasoline plus High Pressure Gas Storage
gasoline equivalent
Maximum 10,000 10,000 47.422 4,145,000 13.894 actual H2 120,085 kg/y H2 /station or gal/y gaso equiv
Total 44 kW 20 /1 compression ratio surge
3 stages maximum surge fill/up rate per hr at
Special ultra-low 20 atm
sulfur & aromatics Gaso ref 4.0 HP H2
Gasoline 65.0% kg/ fill-up dispenser High Pressure (340 atm) Hydrogen
32 gal/hr @ 120,000 Btu/gal 422 Btu LHV/scf H2 2 sides 2 dispenser gasoline equivalent
5 day Gaso storage = 3,806 gallons max. design storage 329 actual kg/d annual ave.
17.2 kgCO2/kg H2
Special gasoline storage 5 /gal 70% $ 6.27 gal storage 0.02 could use with existing tanks
Gasoline reformer $ 3.30 /scf/d 75% $ 3.99 per scf/d 0.78 assume 110% of SMR
H2 Compressor $ 3,000 /kW 80% $ 3,489 per kW 0.13 $ 285 /kg/d H2
HP H2 gas storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.12 $ 991 $/kg high press H2 gas
HP H2 gas dispenser $ 15,000 /dispenser 100% $ 15,000 per dispenser 0.03 $ 13 /kg/d dispenser design

Non-fuel Variable O&M 1% /yr of capital 0.018 1.30 0.36 0.15 0.5-1.5% is typical
Special gasoline $ 6.60 /MM Btu HHV 0.154 11.27 3.09 1.28 see below
Fixed Operating Cost 5% /yr of capital 0.089 6.52 1.79 0.74 4-7% typical for refining
Capital Charges 18% /yr of capital 0.321 23.46 6.44 2.67 20-25% typical of refining
Total HP Hydrogen Costs from Gasoline 0.600 43.93 12.06 5.00 including return on investment
in vehicle
$ 0.059 /kWh electricity for only gaso fuel (no capital charges or other O&M) to Solar 4 MWe Mercury 50 GT @ 40% LHV effic
$ 0.058 /kWh electricity for only gaso fuel (no capital charges or other O&M) to Solar 9 MWe STAC70 CC @ 41% LHV effic
of small NG or gasoline fired GT/CC or the much lower NG costs and higher efficiency, 60% of large industrial NGCC
note: assume special ultra-low sulfur & aromatics gasoline is 100% of current regular reformulated gasoline price
requires $ 0.792 /gal gasoline delivered price back calculated for above $/MM Btu price input
assuming $ 0.050 /gal delivery cost (assume use of existing delivery system)
$ 0.742 /gal refinery price or 100% of $ 0.742 /gal O&G Journal price in Feb 2002

Path F4
Forecourt Hydrogen via Electrolysis of Water plus High Pressure Gas Storage
gasoline equivalent
Maximum 1,000 1,000 4.742 414,500 1.389 actual H2 120,085 kg/y H2 /station or gal/y gaso equiv
Electric Power H2 HP H2 or each vehicle fills up one a week
Compress 46 Compress 19.6 kg/hr H2 gas storage
Misc. 6 2.3 400 atm 3 123 kg H2 max storage or
Electrolysis 1,028 kW/kg/h hr at peak 1,052 gal phy vol at 400 atm
Total 1,074 kW 40 /1 compression ratio surge
3 stages maximum surge fill/up rate per hr at
10 atm
Electrolysis 4.0 HP H2
156.7 kg/hr O2 75.0% 63.5% kg/ fill-up dispenser High Pressure (340 atm) Hydrogen
Water electric LHV H2 5 48 Gas into Vehicles
176.3 kg/hr efficiency effeciency min/fill-up kg/hr/dis 470 design kg/d H2 or gal/d
2 dispenser gasoline equivalent
theoretical power 39.37 kWh/kg H2 at 100% electric efficiency 329 actual kg/d annual ave.
actual power 52.49 kWh/kg or 4.73 kWh/Nm3 H2
41.1 kgCO2/kg H2
Electrolyser $ 2,000 /kW 90% $ 2,157 /kW 2.22 $ 11.4 /scf/d H2
H2 Compressor $ 3,000 /kW 80% $ 3,489 /kW 0.16 $ 340 $/kg/d H2
HP H2 gas storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.12 $ 991 $/kg high press H2 gas

Non-fuel Variable O&M 1.0% /yr of capital 0.041 3.03 0.83 0.35 0.5-1.5% is typical
Variable Operating Cost 0.502 36.76 10.09 4.18 mostly electricity costs
Capital Charges 18.0% /yr of capital 0.746 54.60 14.99 6.21 20-25% typical of refining
Total HP Hydrogen Costs from Electrolysis 1.456 106.52 29.25 12.12 including return on investment
in vehicle
Note: if 12 hr/d at $ 0.040 /kWh lower off-peak rate and Daliy average rate could be
12 hr/d at $ 0.090 /kWh higher peak rate $ 0.065 /kWh
If only operated during low off-peak rate times would have low ann load factor & need more expensive H2 storage
Assume Hydrogn Systems Electrolysis at 150 psig pressure, Norsk Hydro & Stuard systems are low pressure
Assumed oxygen recovery for by-product sales with large central plant case, but only minor economic impact

Central Hydrogen Plant Summary of Inputs and Outputs
design basis
Key Variables Inputs Notes
Hydrogen Production Inputs 1 kg H2 is the same energy content as 1 gallon of gasoline
Design hydrogen production 150,000 kg/d H2 62,175,000 scf/d H2 size range of 20,000 to 900,000 kg/d
Annual average load factor 90% /yr of design 4,106,250 kg/month actual or 49,275,000 kg/yr actual
Distribution distance to forecourt 43 miles average distance 25-200 miles is typical
FC Vehicle gasoline equiv mileage 55 mpg (U.S. gallons) or 23 km/liter
FC Vehicle miles per year 12,000 mile/yr thereby requires 218 kg/yr H2 for each FC vehicle
Typical gasoline sales/month/station 150,000 gallons/month per station 100,000 - 250,000 gallons/month is typical or 4,932 gal/d
Hydrogen as % of gasoline/station 6.7% of gasoline/station or 10,000 kg H2/month per stations or 329 kg/d/station
Capital Cost Buildup Inputs from process unit costs All major utilities included as process units
General Facilities 20% of process units 20-40% typical for SMR + 10% more for gasification
Engineering, Permitting & Startup 15% of process units 10-20% typical
Contingencies 10% of process units 10-20% typical, should be low after the first few
Working Capital, Land & Misc. 7% of process units 5-10% typical
Site specific factor 110% above US Gulf Coast 90-130% typical; sales tax, labor rates & weather issues
Non-fuel Variable O&M 1.0% /yr of capital 0.5-1.5% is typical
Fuels Natural Gas $ 3.50 /MM Btu HHV $2.50-4.50/MM Btu typical industrial rate, see www.eia.doe.gov
Electricity $ 0.045 /kWh $0.04-0.05/kWh typical industrial rate, see www.eia.doe.gov
Biomass production costs $ 500 /ha/yr gross revenues $400-600/hr/yr typical in U.S. .lower in developing nations or wastes
Biomass yield 10 tonne/ha/yr bone dry 8-12 ton/hr/yr typical if farmed, 3-5 ton/hr/yr if forestation or wastes
Coal $ 1.10 /million Btu dry HHV $0.75-1.25/million Btu coal utility delivered go to www.eia.doe.gov
Petroleum Coke $ 0.20 /million Btu dry HHV $0.00-0.50/million Btu refinery gate
Residue (Pitch) $ 1.50 /million Btu dry HHV $1.00-2.00/million Btu refinery gate (solid at room temperature)
Fixed O&M Costs 5.0% /yr of capital 4-7% typical for refiners: labor, overhead, insurance, taxes, G&A
Capital Charges 18.0% /yr of capital 20-25%/yr CC typical for refiners & 14-20%/yr CC typical for utilities
Outputs 135,000 kg/d H2 that supports 225,844 FC vehicles 10,000 kg H2/month/station supports 411 stations
actual annual average 32,263 fill-ups/d if 1 fill-up/week @ 4.2 kg/fill-up 79 fill-ups/d per station or 329 kg/d/station
Capital Costs Operating Cost Product Costs
Absolute Unit cost Unit cost Fixed Variable Including capital charges
Case No. Description $ millions design rate design rate Unit cost Unit cost Unit cost Note
$/scf/d H2 $/kg/d H2 $/kg H2 $/kg H2 $/kg H2 same as $/gal gaso equiv
C1 Biomass-H2 Pipeline 295 4.74 1,966 0.30 0.92 2.29 216 sq mi land
C2 Biomass-Liquid H2 452 7.28 3,017 0.46 1.42 3.53 216 sq mi land
C3 Natural gas-H2 Pipeline 79 1.27 527 0.08 0.63 1.00 into pipeline @ 75 atm
C4 Natural gas-Liquid H2 230 3.70 1,534 0.23 1.13 2.21 into liquid H2 tanker truck
C5 Electrolysis-H2 Pipeline 566 9.11 3,776 0.57 2.49 5.13 into pipeline @ 75 atm
C6 Electrolysis-Liquid H2 688 11.07 4,586 0.70 2.96 6.17 into liquid H2 tanker truck
C7 Pet Coke-H2 Pipeline 238 3.82 1,585 0.24 0.24 1.35 into pipeline @ 75 atm
C8 Coal-H2 pipeline 259 4.16 1,723 0.26 0.42 1.62 into pipeline @ 75 atm
C9 Coal-Liquid H2 448 7.21 2,989 0.46 0.97 3.06 into liquid H2 tanker truck
C10 Biomass-HP Tube H2 362 5.82 2,411 0.37 1.00 2.69 216 sq mi land
C11 Natural Gas-HP Tube H2 133 2.13 884 0.13 0.69 1.30 into tube trailer @ 400 atm
C12 Electrolysis-HP Tube H2 602 9.67 4,010 0.61 2.49 5.30 into tube trailer @ 400 atm
C13 Residue-H2 Pipeline 185 2.97 1,231 0.19 0.41 1.27 into pipeline @ 75 atm
C15 Coal-HP Tube H2 339 5.46 2,263 0.34 0.51 2.09 into tube trailer @ 400 atm

Path C1
Central Hydrogen via Biomass Gasification, Shipped by Pipeline
gasoline equivalent
1 Central Plant Design Design LHV energy equivalent Assuming 55 mpg and 12,000 mile/yr
Size range kg/d H2 gal/d Btu/hr scf/d H2 MW t Assuming 90% annual load factor at
Maximum 200,000 200,000 948 82,900,000 278 actual H2 49,275,000 kg/y H2 /station or gal/y gaso equiv
This run 150,000 150,000 711 62,175,000 208 or 4,106,250 kg/month H2 or gal/mo. gaso equiv
Minimum 20,000 20,000 95 8,290,000 28 thereby 225,844 vehicles can be serviced at
32,263 fill-ups/d @ 4.2 kg or gal equiv/fill-up
Shell gasifier to avoid high CH4 & secondary SMR or ATR or each vehicle fills up one a week
Biomass biomass CO shift
1,169 MM Btu/h LHV gasifier 795 MM Btu/hr cool & clean 24.2 kg CO2/kg H2
1,239 MM Btu/h HHV 80.0% hot raw syngas 5% 109,501 kg/hr CO2 plus 15 % from dryer
70,268 kg/hr @8,000 Btu/lb dry LHV effic 50% CO/(H2+CO) syngas
PSA loses 40 MM Btu/hr PSA fuel gas for superheating
1,686 tons/d biomass bone dry before drying 35 atm 60 MM Bur/h CO to H2 shifting LHV loses
553,995 tons/yr biomass bone dry 56,215 kg/hr O2 6,250 kg/hr H2
55,400 hectares of land for biomass 711 MM Btu/hr H2 61% overall effic raw bio to H2
216 square miles of land to grow biomass 2,590,625 scf/hr H2 @ 30 atm LHV efficiency
H2
Electric Power ASU compress Hydrogen in Gas Pipeline @ 75 atm
ASU 20,799 0.370 0.5
H2 compres 3,125 kWh/kg O2 kWh/kg H2 150,000 design kg/d H2 or gal/d
Misc. 6,253 1,349 metric tons/d O2 2.5 compression ratio gasoline equivalent
Total 30,177 kW 0.80 tons O2/ton dry feed 135,000 actual kg/d annual ave.
15% of biomass fired in FBC to dry gasifier biomass feed 1,902 Btu/lb water vaporized
1,433 tons/day bone dry biomass to gasifier 1,500 Btu/lb water vaporized minimum
at 0.75 kg CO2/kWh current U.S. average for all electricity = 22,633 kg/hr CO2 equivalent at power plants

Capital Costs 100,000 kg/d H2 factors 150,000 kg/d H2 for 1 plant Notes
Biomass handling & drying $ 25 /kg/d dry bio $75% 23 /kg/d dry bio 38.1 11 /kg/d green (wet) biomass
Shell gasifier $ 20 /kg/d dry bio $80% 18 /kg/d dry bio 52.9 100% spare unit
Air separation unit (ASU) $ 27 /kg/d oxygen $75% 24 /kg/d oxygen 32.9 $ 1,583 /kW power
CO shift, cool & cleanup $ 15 /kg/d CO2 $75% 14 /kg/d CO2 35.6 $ 0.6 /scf/d H2 MDEA & PSA
H2 Compressor $ 2,000 /kW $90% 1,921 /kW 6.0 $ 40 /kg/d H2
General Facilities 30% of process units 49.7 20-40% typical, SMR + 10%
Engineering Permitting & Startup 15% of process units 24.8 10-20% typical
Working Capital, Land & Misc. 7% of process units 11.6 5-10% typical
Site specific factor 110% of US Gulf Coast costs Total Capital Costs 294.9
Unit Capital Costs 4.74 /scf/d H2 or 1,966 /kg/d H2 or 1,966 /gal/d gaso equiv

Hydrogen Costs at 90% ann load factor of 1 plant Btu LHV scf H2 $/gal gaso equiv Notes
Variable Non-fuel O&M 1.0% /yr of capital 2.9 0.53 0.14 0.06 0.5-1.5% typical
Delivered biomass $ 3.22 /MM Btu HHV 31.5 5.61 1.54 0.64 based on costs below
Electricity $ 0.045 /kWh 10.7 1.91 0.52 0.22 0.04-0.05/kWh typical industrial rates
Capital Charges 18% /yr of capital 53.1 9.47 2.60 1.08 20% typical of refining
Total Gaseous Hydrogen Costs from Biomass 113.0 20.14 5.53 2.29 including return on investment
into pipeline still requires distribution
Delivered biomass @ $ 56.82 /bone dry ton (BDT) or $ 3.22 /million Btu LHV based on below:
$ 500 /hectare per yr gross total revenues or $ 200 /acre per yr gross total revenues If waste bio or coproduct
10 ton biomass/yr per ha - bone dry basic or 4.0 tons biomass/yr per acre - bone dry lower gross revenue needs
8,000 Btu/lb HHV bone dry and 50% moisture of green biomass but much lower yield/ha
$ 2.08 /mile round trip for typical 25 ton truck hauling green biomass
41 miles round trip haul = $ 3.41 /ton green or $ 6.82 /ton bone dry equivalent transportation

Path C2
Central Hydrogen via Biomass Gasification, Shipped by Cryogenic Tanker Truck
gasoline equivalent
Biomass biomass CO shift 32.1 kg CO2/kg H2 12 hr liq H2 stor
1,169 MM Btu/h LHV gasifier 935 MM Btu/hr cool & clean 109,501 kg/hr CO2 75,000 kg liq H2 stor
1,239 MM Btu/h HHV 80.0% hot raw syngas 5% plus 15% from dryer 279,975 gal phy liq H2
PSA loses 47 MM Btu/hr PSA fuel gas
1,686 tons/d biomass bone dry 35 atm 70 MM Bur/h CO to H2 shifting storage
LHV loses
553,995 tons/yr biomass bone dry 56,215 kg/hr O2 6,250 kg/hr H2
55,400 hectares of land for biomass 711 MM Btu/hr H2 61% overall effic raw bio to H2
216 square miles of land to grow biomass 2,590,625 scf/hr H2 @ 30 atm
4,000 /liq H2 truck H2
Electric Power ASU 4,000 kg liq H2/dis Liquefaction Liquid Hydrogen in Tanker Trucks
ASU 20,799 0.370 2 dispenser 11 38 Cryo tanker fill-ups/d at
H2 Liqu 68,750 kWh/kg O2 kWh/kg 150,000 design kg/d H2 or gal/d
Misc. 6,253 1,349 metric tons/d O2 gasoline equivalent

Biomass handling & drying $ 25 /kg/d dry bio 75%
$ 23 /kg/d dry bio 38.1 11 /kg/d green (wet) biomass
Shell gasifer $ 20 /kg/d dry bio 80%
$ 18 /kg/d dry bio 52.9 100% spare unit H2O quench
Air separation unit (ASU) $ 27 /kg/d oxygen 75%
$ 24 /kg/d oxygen 32.9 $ 1,583 /kW power
CO shift, cool & cleanup $ 15 /kg/d CO2 75%
$ 14 /kg/d CO2 35.6 $ 0.6 /scf/d H2 MDEA & PSA
H2 Cryo Liquefaction $ 700 /kg/d H2 70%
$ 620 /kg/d H2 93.0 $ 1,352 /kW power
Liquid H2 storage $ 5 /gal phy vol 70%
$ 4 /gal phy vol 1.2 $ 17 kg of H2 liquid storage
Liquid H2 dispenser $ 100,000 /dispenser 100%
$ 100,000 /dispenser 0.2 $ 1 /kg/d dispenser design

Capital Charges 18% /yr of capital 81.4 14.52 3.99 1.65 20-25% typical for refining
Total Liquid Hydrogen Costs from Biomass 174.1 31.04 8.52 3.53 including return on investment
plant gate still requires distribution

Path C3
Central Hydrogen via Steam Reformer of Natural Gas, Shipped by Gas Pipeline
gasoline equivalent
Maximum 1,000,000 1,000,000 4,742 414,500,000 1,389 actual H2 49,275,000 kg/y H2 /station or gal/y gaso equiv
H2 or each vehicle fills up one a week
Electric Power Compress 6,250 kg/hr H2
Compress 3,125 0.5 75 atm
SMR & misc. 1,295 kW/kg/h
Total 4,420 kW 2.5 compression ratio
2,590,625 scf/hr H2
30 atm
SMR
Natural Gas 76.2% Hydrogen in Gas Pipeline @ 75 atm
934 MM Btu/h LHV LHV effic
1,036 MM Btu/h HHV 150,000 design kg/d H2 or gal/d
1,036,186 scf/hr @ 1,000 Btu/scf 360 Btu LHV/scf H2 gasoline equivalent
20,435 kg/hr @23,000 Btu/lb 135,000 actual kg/d annual ave.
56,197 kg/hr CO2, however in dilute N2 rich SMR flue gas
at 0.75 kg CO2/kWh current U.S. average = 3,315 kg/hr CO2 equivalent at power plants
9.5 kg CO2/kg H2
SMR $ 0.75 /scf/d 70% $ 0.66 /scf/d 41.3 $ 275 /kg/d H2
General Facilities 20% of process units 9.5 20-40% typical
Unit Capital Costs 1.27 /scf/d H2 or 527 /kg/d H2 or 527 /gal/d gaso equiv

Natural Gas $ 3.50 /MM Btu HHV 28.6 5.10 1.40 0.58 $2.50-4.50/MM Btu industrial rate
Electricity $ 0.045 /kWh 1.6 0.28 0.08 0.03 $0.04-0.05/kWh industrial rate
Total Gaseous Hydrogen Costs from Natural Gas 49.1 8.76 2.41 1.00 including return on investment
note: Assume no central plant storage or compression of hydrogen due to pipeline volume & SMR at 30 atm pressure

Path C4
Central Hydrogen via Steam Reformer of Natural Gas, Shipped by Cryogenic Liquid Trucks
gasoline equivalent
H2 Liquid H2 or each vehicle fills up one a week
Electric Power Liquefaction 6,250 kg/hr lig H2 storage
Liquefaction 68,750 11.0 at 2 atm 12 75,000 kg H2
SMR & misc. 1,295 kW/kg/h hr installed max storage
Total 70,045 kW 279,975 gal physical vol of liq H2 at 2 atm press
2,590,625 scf/hr H2
at 30 atm. 20 max tanker trucks/hr at this production & storage
SMR 4,000 Liquid H2

Natural Gas 76.2% kg/tanker dispenser Liquid Hydrogen in Tanker Trucks
934 MM Btu/h LHV LHV effic 60 5,000 38 Cryo tanker fill-ups/d at
1,036 MM Btu/h HHV min/fill-up kg/hr/dis 150,000 design kg/d H2 or gal/d
1,036,186 scf/hr @ 1,000 Btu/scf 360 Btu LHV/scf H2 2 dispenser gasoline equivalent
17.4 kg CO2/kg H2
Unit cost basis at cost/size Unit cost at

millions of $
SMR $ 0.75 /scf/d H2 $70% 0.66 /scf/d H2 41.3 $ 275 /kg/d H2
H2 Cryo Liquefaction $ 700 /kg/d H2 $75% 633 /kg/d H2 94.9 $ 1,380 /kW power
Liquid H2 storage $ 5 /gal phy vol $70% 4 /gal phy vol 1.2 $ 17 kg of H2 liquid storage
Total process units137.6

Total Liquid Hydrogen Costs from Natural Gas 108.7 19.38 5.32 2.21 including return on investment
note: Assuming all storage liquid boil-off is recycled back to hydrogen liquefaction units, thereby no hydrogen losses

Path C5
Central Hydrogen via Electrolysis of Water, Shipped by Gas Pipeline
gasoline equivalent
Electric Power H2 HP hydrogen or each vehicle fills up one a week
Compress 12,343 Compress 6,250 kg/hr H2
Misc. 1,875 2.0 75 at 75 atm
Electrolysis 328,083 kW/kg/h
3
2,590,625 scf/hr H2 at
10 atm
Electrolysis
50,000 kg/hr O2 75.0% 63.5% Hydrogen in Gas Pipeline @ 75 atm
Water electric LHV H2
56,250 kg/hr efficiency efficiency 150,000 design kg/d H2 or gal/d
gasoline equivalent
theoretical power 39.37 kWh/kg H2 at 100% electric efficiency 135,000 actual kg/d annual ave.
40.9 kgCO2/kg H2
Electrolyser $ 1,000 /kW 90% $ 960 /kW 315.0 $ 5.1 /scf/d H2

Non-fuel Variable O&M 1.0% /yr of capital 5.664 1.01 0.28 0.11 0.5-1.5% typical
Oxygen byproduct $ (10) /ton O2 (3.942) (0.70) (0.19) (0.08) large amount could create min. value
Total Gaseous Hydrogen Costa from Electrolysis 252.769 45.07 12.38 5.13 including return on investment
Note: if 12 hr/d at only $ 0.020 /kWh lower off-peak rate and

12 hr/d at $ 0.060 /kWh higher peak rate daily average rate is $ 0.040 /kWh
If only operated during low off-peak rates times would have low ann load factor & expensive H2 storage

Path C6
Central Hydrogen via Electrolysis of Water, Shipped by Cryogenic Liquid Tankers
gasoline equivalent
Electric Power H2 Liq hydrogen Liquid H2 or each vehicle fills up one a week
Liquefaction 75,000 Liquefaction 6,250 kg/hr H2 storage
Misc. 1,875 12.0 2 atm 12 75,000 kg H2
Electrolysis 328,083 kW/kg/h hr installed max storage
Total 403,083 kW 279,750 gal physical vol of liq H2 at 2 atm press
2,590,625 scf/hr H2 at 20 max trucks/hr at this production & storage

10 atm
Electrolysis 4,000 Liquid H2
50,000 kg/hr O2 75.0% 63.5% kg/tanker dispenser Liquid Hydrogen in Tanker Trucks
Water electric LHV H2 60 4,000 38 Cryo tanker fill-ups/d at
56,250 kg/hr efficiency efficiency min/fill-up kg/hr/dis 150,000 design kg/d H2 or gal/d
48.4 kgCO2/kg H2
H2 Cryo Liquefaction $ 700 /kg/d H2 75% $ 633 /kg/d H2 94.9 $ 1,265 /kW power
Liquid H2 storage $ 5 /gal phy vol 70% $ 4 /gal phy vol 1.2 $ 17 kg of H2 liquid storage
Liquid H2 dispenser $ 150,000 /dispenser 100% $ 150,000 /dispenser 0.3 $ 2 /kg/d dispenser design
Site specific factor 110% of US Gulf Coast costs Total Capital Costs $ 688.0

Total Liquid Hydrogen Costs from Electrolysis 304.176 54.24 14.89 6.17 including return on investment

If only operated during low off-peak rates times would have low ann load factor & need more H2 storage

Path C7
Central Hydrogen via Petroleum Coke Gasification, Shipped by Pipeline
gasoline equivalent
Petroleum Coke pet coke CO shift or each vehicle fills up one a week
1,118 MM Btu/h HHV 75.0% hot raw syngas 5% 117,087 kg/hr CO2 + 45 ton/d sulfur
902 tons/d dry pet coke 75 atm 79 MM Bur/h CO to H2 shifting LHV loses
5% sulfur coke 39,446 kg/hr O2 6,250 kg/hr H2
711 MM Btu/hr H2 66% overall effic coke to H2
2,590,625 scf/hr H2 @ 30 atm
Electric Power ASU Hydrogen in Gas Pipeline @ 75 atm

ASU 15,779 0.40
Misc. 5,210 kWh/kg O2 150,000 design kg/d H2 or gal/d
Total 20,989 kW 947 metric tons/d O2 gasoline equivalent
1.05 tons O2/ton dry feed 135,000 actual kg/d annual ave.

Capital Costs 100,000 kg/d H2 factors
150,000 kg/d H2 for 1 plant Notes
Coke handling & prep $ 20 /kg/d coke $75% 18 /kg/d coke 16.3
Texaco coke gasifers $ 25 /kg/d coke $85% 24 /kg/d coke 42.4 100% spare unit HP quench
Air separation unit (ASU) $ 28 /kg/d oxygen $75% 25 /kg/d oxygen 24.0 $ 1,518 /kW ASU power
Sulfur recovery $ 330 /kg/d sulfur $80% 304 /kg/d sulfur 13.7 lower unit cost that coal due to high S

Pet Coke $ 0.20 /MM Btu HHV 1.8 0.31 0.09 0.04 $0.00-0.50/MM Btu typical at refinery
Total Gaseous Hydrogen Costs from Pet Coke 66.3 11.82 3.25 1.35 including return of investment
note $ 5.95 /tonne pet coke price from above $/MM Btu input at 13,500 Btu/lb HHV

Path C8
Central Hydrogen via Coal Gasification, Shipped by Pipeline
gasoline equivalent
Maximum 1,000,000 1,000,000 4,742 414,500,000 1,389 actual H2
49,275,000 kg/y H2 /station or gal/y gaso equiv
This run 150,000 150,000 711 62,175,000 208 or
4,106,250 kg/month H2 or gal/mo. gaso equiv
Minimum 20,000 20,000 95 8,290,000 28 thereby225,844 vehicles can be serviced at
21 ton/d sulfur or each vehicle fills up one a week
Coal Coal CO shift
1,141 MM Btu/h HHV 73.0% hot raw syngas 5% 118,626 kg/hr CO2 21 ton/d sulfur
1,035 tons/d dry bit coal 75 atm 70 MM Bur/h CO to H2 shifting LHV loses
2% sulfur 43,137 kg/hr O2 6,250 kg/hr H2
711 MM Btu/hr H2 64% overall effic coal to H2
2,590,625 scf/hr H2 @ 30 atm

ASU 17,255 0.40
Total 22,465 kW 1,035 metric tons/d O2 gasoline equivalent

Coal handling & prep $ 20 /kg/d coal $75% 18 /kg/d coal 18.7 solids & slurry prep
Texaco coal gasifers $ 25 /kg/d coal $85% 24 /kg/d coal 48.7 100% spare unit HP quench
Air separation unit (ASU) $ 28 /kg/d oxygen $75% 25 /kg/d oxygen 26.2 $ 1,518 /kW ASU power
Sulfur recovery $ 400 /kg/d sulfur $80% 369 /kg/d sulfur 7.6 O2 Claus & tailgas treat

Coal $ 1.10 /MM Btu HHV 9.9 1.76 0.48 0.20 $0.75-1.25/MM Btu typical
Total Gaseous Hydrogen Costs from Coal 79.9 14.25 3.91 1.62 including return of investment
note $ 29.11 /tonne coal price from above $/MM Btu input at 12,000 Btu/lb HHV

Path C9
Central Hydrogen via Coal Gasification, Shipped by Cryogenic Tanker Truck
gasoline equivalent
Coal Coal CO shift 12 hr liq H2 storage
1,108 MM Btu/h LHV gasifier 809 MM Btu/hr cool & clean 30.3 kg CO2/kg H2 75,000 kg liq H2 stor
1,141 MM Btu/h HHV 73.0% hot raw syngas 5% 118,626 kg/hr CO2 279,975 gal phy liq H2
2,590,625 scf/hr H2 @ 30 atm
4,000 /liq H2 truck H2
Electric Power ASU 4,000 kg liq H2/dis Liquefaction Liquid Hydrogen in Tanker Trucks
ASU 18,980 0.40 2 dispenser 11 38 Cryo tanker fill-ups/d at
H2 Liqu 68,750 kWh/kg O2 kWh/kg 150,000 design kg/d H2 or gal/d
Misc. 6,253 1,139 metric tons/d O2 gasoline equivalent

Coal handling & prep $ 20 /kg/d coal 75%
$ 18 /kg/d coal 18.7 solids & slurry prep
Texaco coal gasifers $ 25 /kg/d coal 85%
$ 24 /kg/d coal 48.7 100% spare unit HP quench
$ 25 /kg/d oxygen 28.8 $ 1,518 /kW ASU power
Sulfur recovery $ 400 /kg/d sulfur 80%
$ 369 /kg/d sulfur 7.6 O2 Claus & tailgas treat
H2 Cryo Liquefaction $ 700 /kg/d H2 75%
$ 633 /kg/d H2 94.9 $ 1,380 /kW power
Liquid H2 storage $ 5 /gal phy vol 70%
$ 4 /gal phy vol 1.2 $ 4 kg of H2 liquid storage

Total Liquid Hydrogen Costs from Coal 150.9 26.90 7.39 3.06 including return of investment

Path C10
Central Hydrogen via Biomass Gasification, Shipped by High Pressure Gas Tube Trailers
gasoline equivalent
Biomass biomass CO shift 25.4 kg CO2/kg H2 12 h gas H2 stor
1,169 MM Btu/h LHV gasifier 935 MM Btu/hr cool & clean 109,501 kg/hr CO2 75,000 kg liq H2 stor
1,239 MM Btu/h HHV 80.0% hot raw syngas 5% plus 15% from dryer 1,081,395 gal phy store
1,686 tons/d biomass bone dry 35 atm 70 MM Bur/h CO to H2 shifting storage
LHV loses
553,995 tons/yr biomass bone dry 56,215 kg/hr O2 6,250 kg/hr H2 61% overall effic raw bio to H2
55,400 hectares of land for biomass 711 MM Btu/hr H2
216 square miles of land to grow biomass 2,590,625 scf/hr H2 @ 30 atm
200 HP H2 HP Hydrogen Gas in Tube Trailers
Electric Power ASU kg/trailer compress at 165 atm pressure
ASU 20,799 0.370 60 2.0 750 Trailer fill-ups/d at
Compress 12,500 kWh/kg O2 min/fill-up kWh/kg 150,000 design kg/d H2 or gal/d
Misc. 6,253 1,349 metric tons/d O2 215 atm gasoline equivalent
Total 39,552 kW 0.80 tons O2/ton dry feed 21 dispenser 135,000 actual kg/d annual ave.

Biomass handling & drying $ 25 /kg/d dry bio 75%
$ 23 /kg/d dry bio 38.1 11 /kg/d green (wet) biomass
Shell gasifier $ 20 /kg/d dry bio 85%
$ 19 /kg/d dry bio 54.0 100% spare unit H2O quench
$ 24 /kg/d oxygen 32.9 $ 1,583 /kW power
H2 Compressor $ 2,000 /kWh 75%
$ 1,807 /kWh 22.6 $ 151 //kg/d H2
HP H2 gas storage $ 20 /gal phy vol 70%
$ 18 /gal phy vol 19.2 $ 255 /kg of HP H2 gas storage
HP H2 gas dispenser $ 30,000 /dispenser 100%

Total HP Gas Hydrogen Costs from Biomass 132.3 23.59 6.48 2.69 including return of investment

Path C11
Central Hydrogen via Steam Reformer of Natural Gas, Shipped by High Pressure Gas Tube Trailers
gasoline equivalent
Electric Power Compress 6,250 kg/hr lig H2 storage
Compress 9,572 1.5 215 atm 12 67,500 kg H2 max storage or
SMR & misc. 1,295 kW/kg/h hr 1,070,581 gal phy vol at 215 atm
Total 10,868 kW 7 compression ratio
2 stages
2,590,625 scf/hr H2 369 max tube trailers/hr at this production & storage
30 atm
SMR 200 HP H2 HP Hydrogen Gas in Tube Trailers
Natural Gas 76.2% kg/trailer dispenser at 165 atm pressure
934 MM Btu/h LHV LHV effic 60 300 750 Trailer fill-ups/d at
1,036 MM Btu/h HHV min/fill-up kg/hr/dis 150,000 design kg/d H2 or gal/d
1,036,186 scf/hr @ 1,000 Btu/scf 360 Btu LHV/scf H2 21 dispenser gasoline equivalent
10.3 kg CO2/kg H2
SMR $ 0.75 /scf/d H2 70% $ 0.66 /scf/d H2 41.3 $ 275 /kg/d H2
H2 Compressor $ 2,000 /kWh 90% $ 1,921 /kWh 18.4 $ 123 /kg/d H2
HP H2 gas storage $ 20 /gal phy vol 70% $ 18 /gal phy vol 19.0 $ 281 /kg of HP H2 gas storage
Unit Capital Costs 2.13 /scf/d H2 or 884 /kg/d H2 or 884 /gal/d gaso equiv

Total HP Hydrogen Costs from Natural Gas 64.3 11.46 3.15 1.30 including return of investment
note:

Path C12
Central Hydrogen via Electrolysis of Water, Shipped by High Pressure Gas Tube Trailers
gasoline equivalent
Electric Power H2 HP H2 gas or each vehicle fills up one a week
Compress 12,389 Compress 6,250 kg/hr gas H2 storage
Misc. 1,875 2.0 215 atm 12 67,500 kg H2 max storage or
Electrolysis 328,083 kW/kg/h hr 1,070,581 gal phy vol at 215 atm
3 stages
2,590,625 scf/hr H2 at 369 max tube trailers/hr at this production & storage
10 atm
Electrolysis 200 HP H2 HP Hydrogen Gas in Tube Trailers
50,000 kg/hr O2 75.0% 63.5% kg/trailer dispenser at 165 atm pressure
Water electric LHV H2 60 300 750 Trailer fill-ups/d at
56,250 kg/hr efficiency efficiency min/fill-up kg/hr/dis 150,000 design kg/d H2 or gal/d
40.9 kgCO2/kg H2
HP H2 gas storage $ 20 /gal phy vol 70% $ 18 /gal phy vol 19.0 $ 281 /kg of HP H2 gas storage
Site specific factor 110% of US Gulf Coast costs Total Capital Costs $ 601.5

Total HP Gas Hydrogen Costs from Electrolysis 261.219 46.58 12.79 5.30 including return on investment

If only operated during low off-peak rates times would have low ann load factor & need more H2 storage

Path C13
Central Hydrogen via Petroleum Residue Gasification, Shipped by Pipeline
gasoline equivalent
Maximum 900,000 900,000 4,268 373,050,000 1,251 actual H2 49,275,000 kg/y H2 /station or gal/y gaso equiv
Pet Residue Pitch residue CO shift or each vehicle fills up one a week
1,052 MM Btu/h HHV 80.0% hot raw syngas 5% 84,974 kg/hr CO2 + 33 ton/d sulfur
27,264 kg/hr LHV effic 50% CO/(H2+CO) syngas
654 tons/d pitch 80 atm 60 MM Bur/h CO to H2 shifting LHV loses
711 MM Btu/hr H2 71% overall effic residue to H2
2,590,625 scf/hr H2 @ 75 atm

ASU 10,906 0.40
Total 16,116 kW 654 metric tons/d O2 gasoline equivalent

Residue handling & prep $ 12 /kg/d residue 75%
$ 11 /kg/d residue 7.1
Texaco residue gasifiers $ 32 /kg/d residue 85%
$ 30 /kg/d residue 39.4 100% spare unit soot recycle
$ 304 /kg/d sulfur 10.0 lower unit cost that coal due to high S

Pitch $ 1.50 /MM Btu HHV 12.4 2.22 0.61 0.25 $1.00-2.00/MM Btu typical at refinery
Total Gaseous Hydrogen Costs from Residue 62.5 11.14 3.06 1.27 including return of investment
into pipelinestill requires distribution
note $ 57.88 /tonne pitch price from above $/MM Btu input at 17,500 Btu/lb HHV
$ 9.65 /barrel at 6.0 bbl/tonne

Path C15
Central Hydrogen via Coal Gasification, Shipped by High Pressure Gas Tube Trailers
gasoline equivalent
Coal Coal CO shift 12 hr high press H2 storage
1,108 MM Btu/h LHV gasifier 809 MM Btu/hr cool & clean 19.0 kg CO2/kg H2 75,000 kg liq H2 stor
1,141 MM Btu/h HHV 73.0% hot raw syngas 5% 118,626 kg/hr CO2 1,081,395 gal phy store
2,590,625 scf/hr H2 @ 30 atm
200 HP H2 HP Hydrogen Gas in Tube Trailers
Electric Power ASU kg/trailer compress at 165 atm pressure
ASU 17,255 0.40 60 1.5 750 Trailer fill-ups/d at
H2 Liqu 9,375 kWh/kg O2 min/fill-up kWh/kg 150,000 design kg/d H2 or gal/d
Misc. 6,253 1,035 metric tons/d O2 215 atm press gasoline equivalent
Total 32,882 kW 1.00 tons O2/ton dry feed 2.7 compr ratio 135,000 actual kg/d annual ave.
21 dispenser

Capital Costs 100,000 kg/d H2 factors150,000 kg/d H2 for 1 plant Notes
Coal handling & prep $ 20 /kg/d coal 75%
$ 18 /kg/d coal 18.7 solids & slurry prep
Texaco coal gasifers $ 25 /kg/d coal 85%
$ 24 /kg/d coal 48.7 100% spare unit direct quench
$ 369 /kg/d sulfur 7.6 O2 Claus & tailgas treat
H2 Compressor $ 2,000 /kWh 90%
$ 1,921 /kWh 18.0 $ 120 //kg/d H2
HP H2 gas storage $ 20 /gal phy vol 70%
$ 18 /gal phy vol 19.2 $ 255 /kg of HP H2 gas storage
HP H2 gas dispenser $ 30,000 /dispenser 100%

Total HP Gas Hydrogen Costs from Coal 103.0 18.37 5.04 2.09 including return of investment

Summary for Hydrogen Delivery Pathways
Hydrogen Production Inputs

Design hydrogen production 150,000 kg/d H2
Annual average load factor 90% /yr of design
Average distance to forecourt 150 km, key assumption for tube trailer & especially pipeline
Truck utilization 80%
Tube load 300 kg key imput for tube trailer
Tube pressure full 160 Atmosphere
Tube pressure (min) 30 Atmosphere
Pipeline 621,504 $/km
Gasoline sales/month/station 10,000 kg/month thereby supplying 411 stations
Fuel cost 1 $/gal
Capital Cost Buildup Inputs from process unit costs

General Facilities 20% 20-40% typical assume low for pipeline
Engineering, Permits & Startup 10% 10-20% typical assume low for pipeline
Contingencies 10% 10-20% typical, should be low after the first few
Working Capital, Land & Misc. 7% 5-10% typical
Site specific factor 110% of US Gulf Coast 90-130% typical; sales tax, labor rates & weather issues
Electricity cost 0.045 $/kwh $0.04-0.05/kWh typical industrial rate, see www.eia.doe.gov
Non-fuel Variable O&M 1.0% /yr of capital 0.5-1.5% typical but could be lower for pipeline
Fixed O&M Costs 5.0% /yr of capital 4-7% typical for refiners: labor, overhead, insurance, taxes, G&A
Capital Charges 18.0% /yr of capital 20-25%/yr CC typical for refiners & 14-20%/yr CC typical for utilities
Outputs 135,000 kg/d H2 that supports 226,032 FC vehicles 10,000 kg/month per station supports 411 stations
actual annual average 32,290 fill-ups/d if 1 fill-up/week @ 4.2 kg/fill-up with 329 kg/d H2
Operating Cost Product Costs
Capital Costs Fixed Variable including return on capital
Absolute Unit cost Unit cost Unit cost Unit cost Unit cost
Delivery Method $ millions $/scf/d H2 /kg/d H2 or $/kg H2 $/kg H2 $/kg H2
Liquid H2 via Tank Trucks 13.2 0.6 88.0 0.02 0.10 0.18
Gaseous H2 via Pipeline 603.0 29.5 4,019.9 0.61 0.61 2.94
Gaseous H2 via Tube Trailers 140.7 6.9 938.0 0.14 0.14 2.09
Liquid Hydrogen Distributed via Trucks
Maximum 1,000,000 1,000,000 4,742.186 414,500,000 1,389.448 actual H2 10,000 kg/month H2 or gal/mo. gaso equiv
This run 150,000 150,000 711.328 62,175,000 208.417 or 550 FC vehicles can be supported at
Minimum 20,000 20,000 94.844 8,290,000 27.789 thereby 78 fill-ups/d @ 4.2 kg or gal equiv/fill-up
411 station supported by this central faciltiy
Average delivery distance 150 km

Delivery distance 210 km 40% increase to represent physical distance
Capital costs Million $ Notes

Tank & undercarrage 11.2 $ 75 /kg/d H2
Cabe 2.0 $ 13 /kg/d H2
Total tube trailer cost 13.2
$/million $/kg H2 or
Variable Operating Cost Million $/yr Btu LHV $/k scf H2 $/gal gaso equiv
Labor 4.43 0.79 0.22 0.09
Fuel 0.54 0.10 0.03 0.01
Variable non-fuel O&M 1% /yr of capital 0.13 0.03 0.01 0.00 6,000 $/yr/truck
Total variable operating costs 5.10 0.91 0.25 0.10
Fixed Operating Cost 5% /yr of capital 0.66 0.12 0.03 0.02
Capital Charges 18% /yr of capital 2.38 0.42 0.12 0.06
Total operating costs 8.14 1.45 0.40 0.18
Assumptions
Truck costs
Tank unit 450,000 $/module 113 $/kg H2 stroage
Undercarrage 60,000 $/trailer
Cabe 90,000 $/cab
Truck boil-off rate 0.30 %/day
Truck capacity 4000 kg/truck
Fuel economy 6 mpg
Average speed 50 km/hr
Load/unload time 4 hr/trip could be lowered with a liquid H2 pump
Truck availability 24 hr/day
Hour/driver 12 hr/driver
Driver wage & benefits 28.75 $/hr
Fuel price 1 $/gal
Truck requirement calculations
Trips per year 12,319 34 trips per day
Total Distance 5,173,875 km/yr 235,176 km/yr per truck little high
Time for each trip 8.4 hr/trip
Trip length 12.4 hr/trip
Delivered product 48,658,030 kg/yr
Total delivery time 152,753 hr/yr
Total driving time 103,478 hr/yr
Total load/unload time 49,275 hr/yr
Truck availability 7008 hr/yr
Truck requirement 22 trucks
Driver time 3504 hr/yr
Drivers required 44 persons
Fuel usage 535,000 gal/yr

Gaseous Hydrogen Distributed via Pipeline
gasoline equivalent
55 mpg and 12,000 mile/yr
1 Central Plant Design Design LHV energy equivalent Assuming 218 kg/yr H2/vehicle or gal/yr gaso equiv
Hydrogen gasoline million requires 90% annual load factor at
Size range kg/d H2 gal/d Btu/hr scf/d H2 MW t Assuming 120,000 kg/y H2 /station or gal/y gaso equiv
Maximum 1,000,000 1,000,000 4,742 414,500,000 1,389 actual H2 10,000 kg/month H2 or gal/mo. gaso equiv
This run 150,000 150,000 711 62,175,000 208 or 550 vehicles can be serviced at
Minimum 20,000 20,000 95 8,290,000 28 thereby 78 fill-ups/d @ 4.2 kg or gal equiv/fill-up
Delivery distance 150 km key input

Number of arms 4 key input Radiate four directions or 600 km of total pipeline key issue
Delivery pressure 440 psia
Pipeline cost 621,504 $/km includes right of way costs which is the key cost issue in urban areas
Electricity cost 0.045 $/kwh if a booster compressor is required for long pipeline
Capital costs Million $

Pipeline 372.9
Capital cost 372.9
General Facilities & permitting 20% of unit cost 74.6 could be lower for pipelines
Eng. startup & contingencies 10% of unit cost 37.3
Contingencies 10% of unit cost 37.3
Working Capital, Land & Misc. 7% of unit cost 26.1 could be lower for pipelines
548.2
Location factor 110% of US Gulf Coast 603.0
$/million $/kg H2 or
Variable non-fuel O&M 1% /yr of capital 6.03 1.08 0.30 0.12 could be lower for pipelines
Fixed Operating Cost 5% /yr of capital 30.15 5.38 1.48 0.61 could be lower for pipelines

Gaseous Hydrogen Distributed via Tube Trailers
Maximum 1,000,000 1,000,000 4,742.186 414,500,000 1,389.448 actual H2 10,000 kg/month H2 or gal/mo. gaso equiv
This run 150,000 150,000 711.328 62,175,000 208.417 or 550 FC vehicles can be supported at
Minimum 20,000 20,000 94.844 8,290,000 27.789 thereby 78 fill-ups/d @ 4.2 kg or gal equiv/fill-up
Average delivery distance 150 km

Delivery distance 210 km 40% increase to represent physical distance
Capital costs Million $ Notes

Tubes & undercarrage 113.7 $ 758 /kg/d H2, high due to the 411 units left at stations
Cabe 27.0 $ 180 /kg/d H2
Total tube trailer cost 140.7
$/million
Operating costs
Labor 60.44 10.78 2.96 1.23
Fuel 8.79 1.57 0.43 0.18
Variable non-fuel O&M 1% /yr of capital 1.41 0.25 0.07 0.03 4,690 $/yr/truck
Fixed Operating Cost 5% /yr of capital 7.04 1.25 0.34 0.14
Assumptions
Truck costs
Tube unit 100,000 $/module 333 $/kg H2 design stoage @ 160 atm
Undercarrage 60,000 $/trailer
Cabe 90,000 $/cab
Truck capacity 300 kg/truck key issue
Pressure (max) 160 atmosphere
Pressure (min) 30 atmosphere
Net delivery 244 kg/truck key issue
Fuel economy 6 mpg
Average speed 50 km/hr
Hour/driver 12 hr/driver
Load/unload time 2 hr/trip this could be lower as just change tube trailers at stations
Truck availability 24 hr/day
Driver wage & benefits 28.75 $/hr
Fuel price 1 $/gal
Tube trailer requirement calculations
Trips per year 202,100 trips/yr or 554 trips per day

Total distance 84,882,000 km/yr 282,940 km/yr per truck little high
Time for each trip 8.4 hr/trip
Total delivery time 2,101,840 hr/yr
Total driving time 1,697,640 hr/yr
Total load/unload time 404,200 hr/yr
Truck availability 7008 hr/yr
Truck & tube trailer requirement 300 trucks but 711 tube trailers due to 1 left at each station
Driver time, hr/yr 3504 hr/yr
Drivers required 600 persons
Fuel usage 8,790,000 gal/yr

Summary for Hydrogen Fueling Pathways
Hydrogen Production Inputs Notes

Design hydrogen production 150,000 kg/d H2 from central facility
Gasoline sales/month/station 10,000 kg/month thereyb supplying 411 stations
Forecourt loading factor 70% /yr of design "plug & play" 24 hr replacements for reasonable availability
High pressure gas storage buffer 3 hours at peak surge rate
Capital Cost Buildup Inputs from process unit costs

General Facilities 25%
Engineering, Permitting & Startup 10% Engineering costs spread over multiple stations
Contingencies 10%
Working Capital, Land & Misc. 7%
Road tax or (subsidy) $ - /gal gasoline equivalent may need subsidy like EtOH to get it going
Gas Station mark-up $ - /gal gasoline equivalent may be needed if H2 sales drops total station revenues
Electricity cost 0.07 $/kwh $0.06-.0.09/kWh typical commercial rate, see www.eia.doe.gov
Non-fuel Variable O&M 0.5% /yr of capital 0.5-1.5% is typical, assumed low here for "plug & play"
Fixed O&M Costs 3.0% /yr of capital 4-7% typicalfor insurance, taxes, G&A (may be low here)
Capital Charges 18.0% /yr of capital 20-25%/yr CC typical for refiners & 14-20%/yr CC for utilities
Outputs 135,000 kg/d H2 that supports 226,032 FC vehicles 10,000 kg/month per station supports 411 stations
actual annual average 32,290 fill-ups/d if 1 fill-up/week @ 4.2 kg/fill-up each with 329 kg/d H2
Operating Cost Product Costs
Capital Costs Fixed Variable including return on capital
Absolute Unit cost Unit cost Unit cost Unit cost Unit cost
Delivery Method $ millions $/scf/d H2 /kg/d H2 or $/kg H2 $/kg H2 $/kg H2
Liquid H2 Gaseous Fueling System 279 13.64 1,857 0.17 0.08 1.27
Gaseous H2 via Pipeline 212 10.39 1,415 0.13 0.16 1.07
Gaseous H2 via Tube Trailer 212 10.39 1,415 0.13 0.09 1.00

Liquid Hydrogen Based Fueling Stations
Central hydrogen production 150,000 kg/d

Size range kg/d/station H2 gal/d Btu/hr scf/d H2 MW t Assuming 70% Forecourt loading factor
actual H2 10,000 kg/month H2 or gal/mo. gaso equiv
This run 470 470 2.227 194,699 0.653 or 550 FC vehicles can be supported at
thereby 78 fill-ups/d @ 4.2 kg or gal equiv/fill-up
one of 411 stations 329 kg/d H2 average consumption
at 4,000 kg/load require one tanker every 12 days
Electric Power 123 kg

22 kw 986 gal physical vol at 400 atm
Liquid H2 Liquid H2 Buffer 4.0 HP H2
Storage Pump Storage kg/ fill-up dispenser
12,264 0.8 3 5 48
gal maximuum kw/kg/hr hours min/fill-up kg/hr/dis
3,288.04 kg H2 max liqiid H2 sotrage at surge rate 20 kg/hr daily average design at 24 hr/d
7 Days of liquid H2 storage at design rate 3 times averge at peak surge rate
2 Dispensers
411 Fueling stations served
17 hour operation

Capital Costs 1,000 kg/d H2 factors 470 kg/d H2 millions of $ Notes
Liquid H2 pump/vaporizer $ 250 /kg/d H2 70% $ 314 /kg/d H2 0.15 $ 314 /kg/d H2
Liquid H2 storage $ 10 /gal phy vol 70% $ 13 /gal phy vol 0.15 $ 47 /kg/d H2
H2 buffer storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.11 $ 931 /kg/d H2
Liquid H2 dispenser $ 15,000 /dispenser 100% $ 15,000 /dispenser 0.03 $ 64 /kg/d dispenser design
Unit cost 0.45
General Facilities & permitting 25% of unit cost 0.11
Eng. startup & contingencies 10% of unit cost 0.04
Contingencies 10% of unit cost 0.04
Working Capital, Land & Misc. 7% of unit cost 0.03
Capital Costs 0.68 for 1 of 411 stations
Total Capital Costs 279 for all 411 stations
$/yr $/million $/kg H2 or

Hydrogen Costs at 70% ann load factor of 1 station Btu LHV $/k scf H2 $/gal gaso equiv
Variable Non-fuel O&M 0.5% /yr of capital 3,389 0.25 0.07 0.03 0.5-1.5 typical many be low here
Electricity $ 0.070 /kWh 6,721 0.49 0.14 0.06 0.06-0.09 typical commercial rates
Variable Operating Cost 10,110 0.74 0.20 0.08
Fixed Operating Cost 3.0% /yr of capital 20,333 1.49 0.41 0.17 3-5% typical, may be lower here
Capital Charges 18.0% /yr of capital 121,996 8.93 2.45 1.02 20-25% typical for refiners
Fueling Station Cost 152,438 11.16 3.06 1.27
including return of investment
Hydrogen Fueling Station Costs

Delivery to 411 Stations
Million $/yr
Variable Operating Cost 4.16
Fixed Operating Cost 8.36
Capital Charges 50.14
Total Fueling Station Cost 62.65

Gaseous Hydrogen Based Fueling Stations - Pipeline Delivery

550 FC vehicles can be supported at
one of 411 stations 78 fill-ups/d @ 4.2 kg or gal equiv/fill-up
Electric Power
Commpress 56 kw
123 kg
986 gal physical vol at 400 atm
Hydrogen 4.0 HP H2
Pipeline Compressors Storage kg/ fill-up dispenser
2.0 3 5 48
kw/kg/h Hours min/fill-up kg/hr/dis
30 400 of daily ave rate 20 kg/hr daily average design at 24 hr/d
Atm Atm 3 times averge at peak surge rate
Smaller stations use cascade system 2 Dispensers
Larger stations use booster system 411 Fueling stations served
17 hour operation

Capital Costs 1,000 kg/d H2 factors 470 kg/d H2 for 1 fueling station
H2 Compressors $ 3,000 /kwh 80% $ 3,490 /kg/d H2 0.20 $ 415 /kg/d H2
H2 buffer storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.11 $ 931 /kg of HP H2 gas storage
Gaseous H2 dispenser $ 15,000 /dispenser 100% $ 15,000 /dispenser 0.03 $ 64 /kg/d dispenser design
Unit cost 0.34
General Facilities & permitting 25% 0.08
Eng. startup & contingencies 10% 0.03
Contingencies 10% 0.03
Working Capital, Land & Misc. 7% 0.02

Hydrogen Costs at 70% ann load factor of 1 station Btu LHV $/k scf H2 $/gal gaso equiv
Electricity $ 0.070 /kWh 16,800 1.23 0.34 0.14 0.06-0.09 typical commercial rates
Variable Operating Cost 19,383 1.42 0.39 0.16

Million $/yr

Gaseous Hydrogen Based Fueling Stations - Tube Trailer Delivery

550 FC vehicles can be supported at
one of 411 stations 329 kg/d H2 average consumption
at 244 kg/load require one tanker every 0.74 days or 18 hours
Electric Power 123 kg
Commpress 56 kw 986 gal physical vol at 400 atm
Booster Hydrogen 4.0 HP H2
Tube trailer Compressors Storage kg/ fill-up dispenser
2 3 5 48
kw/kg/h Hours min/fill-up kg/hr/dis
30 to 160 atm 400 atm of daily ave rate 20 kg/hr daily average design at 24 hr/d
3 times averge at peak surge rate
2 Dispensers
411 Fueling stations dispensers
17 hour operation

Capital Costs 1,000 kg/d H2 factors 470 kg/d H2 millions of $ Notes
Compressors $ 3,000 /kwh 80% $ 3,490 /kwh 0.20 $ 415 /kg/d H2
H2 buffer storage $ 100 /gal phy vol 80% $ 116 /gal phy vol 0.11 $ 931 /kg of HP H2 gas storage
Gaseous H2 dispenser $ 15,000 /dispenser 100% $ 15,000 /dispenser 0.03 $ 64 /kg/d dispenser design
0.34
General Facilities & permitting 25% of equipment cost 0.08
Eng. startup & contingencies 10% of equipment cost 0.03
Contingencies 10% of equipment cost 0.03
Working Capital, Land & Misc. 7% of equipment cost 0.02

Hydrogen Costs at 70% ann load factorof 1 station
Btu LHV $/k scf H2 $/gal gaso equiv
Electricity $ 0.070 /kWh 8,400 0.62 0.17 0.07 assume 50% of design power
Variable Operating Cost 10,983 0.80 0.22 0.09 due to tube pressrue

Million $/yr

Hydrogen Conversions
boxed yellow are key input variables Change below
Basis for any size
kg H2 1.000 10 100 1,000 10,000 2,413
Btu HHV 134,690 1,346,900 13,469,004 134,690,037 1,346,900,370 324,972,145
Btu LHV 113,812 1,138,125 11,381,248 113,812,475 1,138,124,750 274,600,000
H2 gas LHV/HHV 84.5% 84.5% 84.5% 84.5% 84.5% 84.5%
standard cubic feet (scf) @ 60°F & 1 atm 414.5 4,145 41,447 414,466 4,144,664 1,000,000
normal cubic meters (Nm3) @ 0°C & 1 atm 11.1 111 1,110 11,104 111,040 26,791
gallons @ standard conditions of 60°F & 1 atm 3,100 31,004 310,042 3,100,424 31,004,242 7,480,520
gallons gaseous H2 @ 400 atm & 60° F 8.53 85 853 8,526 85,262 20,571
gallons liquid H2 phy vol @ 2 atm & -430°F 3.73 37 373 3,733 37,330 9,007
kWh thermal equivalent LHV 33.3 333 3,335 33,347 333,468 80,457
Assumed gasoline Btu/gal HHV 121,335 121,335 121,335 121,335 121,335 121,335
Assumed gasoline LHV/HHV 93.8% 93.8% 93.8% 93.8% 93.8% 93.8%
Assumed gasoline Btu/gal LHV 113,812 113,812 113,812 113,812 113,812 113,812
gallons gasoline energy equiv LHV 1.000 10 100 1,000 10,000 2,413
Note: Essential to use LHV gasoline equivalent due to the 2.5 times larger water vapor energy losses of H2 vs gasoline
Source: SFA Pacific, Inc

Form Approved
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1. AGENCY USE ONLY (Leave blank) 2. REPORT DATE 3. REPORT TYPE AND DATES COVERED
November 2002 Subcontract Report, January 22, 2002 to July 22, 2002
4. TITLE AND SUBTITLE

5. FUNDING NUMBERS
Hydrogen Supply: Cost Estimate for Hydrogen Pathways—Scoping Analysis CF: ACL-2-32030-01
TA: FU232210
6. AUTHOR(S)
7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES) 8. PERFORMING ORGANIZATION

SFA Pacific, Inc. REPORT NUMBER
Mountain View, CA
9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSORING/MONITORING

National Renewable Energy Laboratory AGENCY REPORT NUMBER
1617 Cole Blvd.
Golden, CO 80401-3393 NREL/SR-540-32525
11. SUPPLEMENTARY NOTES
NREL Technical Monitor: Wendy Clark

12a. DISTRIBUTION/AVAILABILITY STATEMENT 12b. DISTRIBUTION CODE
National Technical Information Service
U.S. Department of Commerce
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13. ABSTRACT (Maximum 200 words)
A report showing a comparative scooping economic analysis of 19 pathways for producing, handling, distributing, and
dispensing hydrogen for fuel cell vehicle applications.
15. NUMBER OF PAGES

14. SUBJECT TERMS
fuel cell, hydrogen, International Hydrogen Infrastructure Group, SFA
16. PRICE CODE
17. SECURITY CLASSIFICATION 18. SECURITY CLASSIFICATION 19. SECURITY CLASSIFICATION 20. LIMITATION OF ABSTRACT
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November 2002 • NREL/SR-540-32525

Hydrogen Supply: Cost

January 22, 2002July 22, 2002

D. Simbeck and E. Chang

National Renewable Energy Laboratory

Hydrogen Supply: Cost

January 22, 2002July 22, 2002

D. Simbeck and E. Chang

NREL Technical Monitor: Wendy Clark

National Renewable Energy Laboratory

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy

Available for sale to the public, in paper, from:

Original Feedstocks Revised Feedstocks Location of H2 Production

Steam methane reforming

Case No. Feedstock Conversion Process Method of Distribution

Case No. Feedstock Conversion Process

Water Gas Trailer

Coal Gas Trailer

Source: SFA Pacific, Inc.

Investment ($million) Hydrogen Cost ($/kg)

Source: SFA Pacific, Inc.

SFA Pacific Air Products

Source: SFA Pacific, Inc.

Potential Improvements for Hydrogen Economics

Central Plant Hydrogen Production

Hydrogen Economic Module Basis

Capital Build-up % of Process Unit Typical Range

Operating Costs Build-up %/yr of Capital Typical Range

Source: SFA Pacific, Inc.

Hydrogen Production Technology

CH4 + H2O <=> 3H2 + CO (1)

CO + H2O => H2 + CO2 (2)

CaHb + a/2O2 => b/2H2 + aCO (3)

H2 Production H2 Handling H2 Distribution H2 Dispensing

Source: Annual Energy Outlook 2002 Reference Case Tables, EIA.

Liquid Tanker Gas Tube Pipeline,

Source: SFA Pacific, Inc.

Water is another feedstock commonly referred to as a renewable energy source. Although

Hydrogen Handling and Storage

Fuel Type Density (kg/l)

Source: SFA Pacific, Inc.

Road Delivery (Tanker Trucks and Tube Trailers)

Cryogenic Truck Tube Trailer

Source: SFA Pacific, Inc.

Hydrogen Fueling Station

Source: SFA Pacific, Inc.

Design capacity 470 kg/d

Gaseous Hydrogen Based Fueling

Forecourt Hydrogen Production

Source: SFA Pacific, Inc.

Source: Annual Energy Outlook 2002 Reference Case Tables, EIA.

Source: SFA Pacific, Inc.

Central Plant a Forecourt

Source: SFA Pacific, Inc.

Air Products and Chemicals

6. J.S. Falsetti (Texaco), “Gasification Process for Maximizing Refinery Profitability,”

7. “Texaco Gasification Process for Gaseous or Liquid Feedstocks,” Texaco Development

9. “Texaco Gasification Process for Solid Feedstocks,” Texaco Development Corporation