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Hydrogen storage technology options for fuel cell vehicles:Well-to-wheel costs, energy efficiencies, and greenhousegas emissions

M.D. Paster e,*, R.K. Ahluwalia a, G. Berry b, A. Elgowainy a, S. Lasher c, K. McKenney c,M. Gardiner d

aArgonne National Laboratory, 9700 S. Cass Ave., Argonne, IL 60439, USAb Lawrence Livermore National Laboratory, 7000 East Ave., Livermore, CA 94550, USAcTIAX LLC, 15 Acorn Park, Cambridge, MA 02140, USAdU.S. Department of Energy, 1000 Independence Ave. SW, Washington D.C., 20585, USAeConsultant, 10113 Farrcroft Dr., Fairfax, VA 22030, USA

a r t i c l e i n f o

Article history:

Received 4 May 2011

Received in revised form

12 July 2011

Accepted 14 July 2011

Available online 3 September 2011

Keywords:

Hydrogen on-board storage

Hydrogen fuel efficiency

Hydrogen delivery infrastructure

Hydrogen greenhouse gas emissions

* Corresponding author.E-mail addresses: mrkpstr0@gmail.com, m

0360-3199/$ e see front matter Copyright ªdoi:10.1016/j.ijhydene.2011.07.056

a b s t r a c t

Five different hydrogen vehicle storage technologies are examined on a Well-to-Wheel

basis by evaluating cost, energy efficiency, greenhouse gas (GHG) emissions, and perfor-

mance. The storage systems are gaseous 350 bar hydrogen, gaseous 700 bar hydrogen, Cold

Gas at 500 bar and 200 K, Cryo-Compressed Liquid Hydrogen (CcH2) at 275 bar and 30 K, and

an experimental adsorbent material (MOF 177) -based storage system at 250 bar and 100 K.

Each storage technology is examined with several hydrogen production options and

a variety of possible hydrogen delivery methods. Other variables, including hydrogen

vehicle market penetration, are also examined. The 350 bar approach is relatively cost-

effective and energy-efficient, but its volumetric efficiency is too low for it to be a prac-

tical vehicle storage system for the long term. The MOF 177 system requires liquid

hydrogen refueling, which adds considerable cost, energy use, and GHG emissions while

having lower volumetric efficiency than the CcH2 system. The other three storage tech-

nologies represent a set of trade-offs relative to their attractiveness. Only the CcH2 system

meets the critical Department of Energy (DOE) 2015 volumetric efficiency target, and none

meet the DOE’s ultimate volumetric efficiency target. For these three systems to achieve

a 480-km (300-mi) range, they would require a volume of at least 105e175 L in a mid-size

FCV.

Copyright ª 2011, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights

reserved.

1. Introduction of more energy-efficient systems, to reduce dependence on

Energy security and global climate change are key issues for the

United States. These concerns have led to significant efforts to

reduce our energy intensity through the development and use

ark.paster@cox.net (M.D2011, Hydrogen Energy P

imported petroleum, and to replace high-carbon-emitting

energy sources with renewable and other low-carbon-emitting

energy sources.

. Paster).ublications, LLC. Published by Elsevier Ltd. All rights reserved.

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14535

Transportation accounts for 28% of U.S. energy needs.

Of that, 94% is based on petroleum. Highway vehicles

consume 80% of the transportation energy [1]. New, more

energy-efficient and lower-carbon-intensity vehicle technol-

ogies are being developed, demonstrated, and in some cases

commercialized. These include hybrid vehicles, the use of

biofuels, hydrogen-based vehicles, plug-in hybrids, and all-

electric vehicles. Plug-in technology will only be environ-

mentally effective after the U.S. electricity grid is substantially

greener than it is today.

Hydrogen fuel cell vehicles (FCVs) have the potential to be

the most energy-efficient vehicles and to have the lowest

carbon emission and other harmful emissions on a Well-to-

Wheel (WTW) basis. Hydrogen can be produced from

a variety of domestic resources and with near-zero green-

house gas (GHG) emissions. Fuel cell technology has been

advancing rapidly and has made significant progress toward

meeting the necessary performance and cost targets for

commercialization in highway vehicles [2]. There are over 150

demonstration hydrogen FCVs on the road in the United

States today [3].

One of the biggest remaining challenges for hydrogen FCV

technology is storing a sufficient amount of hydrogen on

board the vehicle for an acceptable vehicle range in a practical

amount of space. A variety of types of hydrogen storage

technologies are being researched and developed. These

include physical storage approaches: modest-pressure gas

(350 bar), high-pressure gas (700 bar), cryo-compressed

hydrogen (CcH2), and material-based storage systems. Mate-

rial approaches include metal hydrides, sorbents such as

carbon and metal-organic frameworks (MOFs), and chemical

hydrides. Some of these technologies can be combined. For

example, high-pressure cold gas storage is being considered,

while MOF technology is used at cryogenic temperatures and

under pressure.

The storage system technology used directly impacts the

WTW energy efficiency, GHG emissions, and costs of

hydrogen and FCVs. To better understand these impacts and

to help set directions for future research on vehicle storage

technologies, a WTW analysis of the current physical storage

options and one of the material storage technologies (MOF

177) was performed. This analysis included several hydrogen

Table 1 e Technologies and variables studied.

Central ProductionTechnologies

Delivery Pathways VT

Steam Methane

Reforming

Electrolysis

Biomass

Gasification

Gaseous Hydrogen (GH2): All pipeline

GH2: Pipeline to city gate terminal, tube

trailerb to refueling station

GH2: All tube trailerb

Liquid Hydrogen (LH2): All LH2 truck

LH2: GH2 pipeline to city gate terminal,

liquefaction at the terminal, LH2 truck

to the refueling station.

GH

GH

Co

Cc

M

a Defined as the percent of light-duty passenger vehicles on the road tha

b Tube trailers operating at ambient temperatures and 250 bar (3625 psi),

trailer operating at 90 K and 340 bar was also studied.

production technologies and a variety of hydrogen delivery

options to identify the key issues and drivers along the WTW

pathway.

This effort took advantage of, and was done in concert

with, other work funded by the Department of Energy (DOE)

on the analysis of storage options [4,5]. It also utilized the

DOE’s Hydrogen Analysis (H2A) Central Production analysis

tool and published H2A production cases, as well as the DOE’s

H2A Hydrogen Delivery Scenario Analysis Model (HDSAM)

[6,7]. Use of the H2A models helped ensure that the analyses

were done on a consistent and comparable basis.

2. Technologies and variables studied

Table 1 shows the vehicle storage technologies, hydrogen

production options, delivery pathways and the other variables

included in this study. Not all combinations of variables were

run, but a sufficient number were studied to show all of the

important trends.

2.1. Market penetration and refueling station size

The WTW analysis models hydrogen production, delivery,

and use in light-duty passenger vehicles (LDVs) in an urban

setting. The particular city modeled in HDSAM was Sacra-

mento, CA, but similar results and trendswould be obtained in

any urban market.

The largest hydrogen refueling station size examined is

1000 kg H2 per day. This equates to the average size of existing

gasoline stations but is smaller than most new stations being

built [7]. Two other variables in the study limit the stations to

smaller sizes in certain scenarios. People will not purchase

a hydrogen FCV unless they can refuel conveniently. There

have been a number of studies on this issue [8]. If stations are

well placed in an urban area, it is believed that hydrogen

stations that number 5e10% of the existing number of gaso-

line stations could be sufficient. In this study, the station sizes

were reduced at low market penetrations (<10%) to have

a sufficient number for 5% coverage. The smallest station used

is 400 kg H2/day. The impact of station size was analyzed (see

below).

ehicle Storageechnologies

Electricity Types Urban MarketPenetrationa

2: 350 bar

2: 700 bar

ld Gas: 500 bar

H2: 275 bar

OF 177: 250 bar

Average U.S. Grid Mix

100% Natural Gas Sourced

100% Renewable Electricity

5%

15%

40%

t are hydrogen FCVs; based on Sacramento, CA.

340 bar (5000 psi), and 540 bar (8000 psi) were studied. A cold gas tube

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114536

Station size can also be limited by the manner of delivery.

Gasoline stations only allow one truck delivery per day, to

minimize station congestion. Liquid hydrogen trucks can

carry up to 4000 kg of hydrogen, more than the daily

requirement of a 1000-kg/day station. High-pressure gas tube

trailers hold varying amounts of hydrogen depending on

their size, temperature and pressure capability, as shown in

Table 2.

In this study, all of the tube trailers and the liquid hydrogen

trailer shown in Table 2 were examined.

2.2. Hydrogen production options

All three production options in Table 1 are for large central

plants. It is assumed that they are located 100 km (62 mi) from

the city gate, except when renewable-based electricity is used

(see below). Steammethane reforming (SMR) is used for nearly

all the hydrogen that is produced today [9]. Hydrogen

production through electrolysis is also commercial, but is only

done at small scale. Biomass gasification has been demon-

strated at semi-commercial scale for the production of electric

power. Its use for the production of hydrogen would combine

biomass gasification with the reforming, water gas shift, and

hydrogen recovery technology used in SMR hydrogen

production.

2.3. Electricity source

Three different electricity sources were examined: the current

average U.S. grid electricity mix (48% coal, 21% natural gas,

20% nuclear and 9% renewable [10]), 100% natural-gas-based

electricity, and 100% renewable-energy-based electricity. In

the latter case, it was assumed that there were no GHG

emissions from the production of electricity (e.g. from

hydropower, wind or solar energy). Nuclear-based electricity

would also have near-zero GHG emissions.

Hydrogen production and, when used, hydrogen liquefac-

tion utilizemost of the electricity in theseWTWhydrogen FCV

pathways. Renewable-electricity (e.g. hydroelectric, wind and

solar energy) plants are likely to be some distance from major

urban centers. The 100%-renewable-electricity cases are

meant to represent a situation where hydrogen production

(and when applicable, liquefaction) would be co-located with

a renewable-electricity generation plant. For these cases, it

was assumed that the hydrogen plants were 484 km (300 mi)

Table 2 e Hydrogen trailers.

Trailer Type, Pressure,and Temperature

Capacity:Hydrogen

Delivered (kg)

Station SizeUsed

(kg H2/day)

GH2: 250 bar (3625 psi), ambient 550 500

GH2: 340 bar (5000 psi), ambient 740 700

GH2: 540 bar (8000 psi), ambient 1080 1000

Cold Gas: 340 bar (5000 psi), w90 K 1500 1000

LH2: 1 bar, 20 K 4000 1000

a Estimated from discussions with tube-trailer vendors and developers a

b Estimated from the cost of the other tube trailers and accounting for r

from the city gate. All other cases were evaluated with the

hydrogen production plant located 100 km (62 mi) from the

city gate. This does increase the transport cost portion for

the renewable-electricity-basedWTW pathways. (Note: It was

assumed that the cost of electricity is the same whether it

comes from the average U.S. grid electricity mix, all natural

gas, or renewable resources.)

It will be some time before the U.S. grid is substantially

renewable-based. The natural-gas-based grid represents

a transition of the electricity grid to a lower-GHG-emitting

grid, on average. Electricity use plays a major role in the

GHG emissions for these WTW pathways because of the low

energy efficiency of electricity production from fossil sources.

2.4. Hydrogen production, delivery, and vehicle storagepathways

Figs. 1, 2 and 3 depict the primary hydrogen production and

delivery pathways studied for the various vehicle hydrogen

storage systems. In all pathways, any of the three production

options can be used.

Fig. 1 shows the gaseous-pipeline delivery pathway, which

can be used for 350 bar and 700 bar vehicle storage. Large-scale

bulk storage to handle production plant outages and the

summer peak LDV fuel demand is provided using geologic

storage, as is done for bulk storage in the natural-gas supply

infrastructure for similar needs (Note: There are currently

a few hydrogen geologic storage facilities in Texas. There may

not be appropriate geological formations for gaseous

hydrogen storage conveniently located for all urban areas. The

potential for geologic storage of hydrogen in the U.S. is

currently under study by the DOE. The alternative would be to

liquefy and store sufficient liquid hydrogen for this purpose.

This would be about 10% of the hydrogen used. Although not

examined in this paper, this approach would add significantly

to the cost, energy use, and GHG emissions.). The refueling

station includes modest-pressure (170 bar) storage for about

a half-day supply to handle the station’s hourly demand

variations and a high-pressure cascade system for vehicle

refueling.

Fig. 2 shows a combined pipeline and high-pressure tube-

trailer delivery pathway (designated “P-Tx,” where x is the

tube-trailer pressure in bars) suitable for 350 bar, 700 bar, and

Cold Gas 500 bar vehicle storage technologies. In this case,

pipelines are used to transport the hydrogen to a city-gate

TechnologyStatus

Capital Costof the

Tube Trailer

Capital Costper kg H2

Capacity

Available $520,000a $950

Being developed and tested $635,000a $860

Projected to be possible $1,200,000a $1100

Projected to be possible $705,000b $470

Available $625,000a $160

nd industrial gas companies, and used in HDSAM.

equired insulation.

Fig. 1 e Gaseous-pipeline delivery and distribution (i.e. Pipeline).

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14537

terminal. The terminal provides some modest storage. Tube

trailers are loaded at the terminal for delivery to the refueling

station. The tube trailer is dropped off at the refueling station,

providing at least a day’s worth of storage for the station. A

high-pressure cascade system is used to charge the vehicle

with hydrogen from the tube trailer. All of the types of gaseous

tube trailers are options for this pathway. Other cases where

the terminal was co-located with the production plant, thus

eliminating the pipeline transport, were also examined.

The Cold Gas pathway is a relatively new concept. In this

case, hydrogen gas is cooled to about 90 K at a terminal using

liquid nitrogen refrigeration. The tube trailers are specially

designed and heavily insulated to be able to handle this cold

gas and keep it cold during delivery and storage at the refu-

eling station. The gas in the tube trailer cools as the trailer

empties, owing to expansion. The gas from the tubes is

compressed and charged to a high-pressure cascade system

for charging the vehicle. The cascade system is also heavily

insulated. The gas temperature increases owing to the heat of

compression and isoenthalpic expansion between the tube

trailer and the end point of fill in the vehicle tank. For the case

studied, the vehicle tank temperature at the end of refueling is

193 K. The vehicle tank is designed for high pressure (500 bar

fill pressure) and is vacuum-insulated to keep the hydrogen

cold when the vehicle is not in use. The 500 bar fill pressure

was chosen as a compromise between having sufficient gas

density for improved volumetric efficiency and the still higher

tank costs that would result from a higher pressure.When the

vehicle is in use, the vehicle tank temperature decreases

owing to the expansion of the hydrogen in the tank. This

pathway and system were not designed, modeled or opti-

mized to the same degree as the other vehicle storage-system

cases. Therefore, the results for this storage systemneed to be

Fig. 2 e Pipeline transport with tube-

considered less accurate than those for the other systems

studied.

Fig. 3 shows the liquid hydrogen delivery pathway for the

CcH2 and MOF 177 vehicle hydrogen storage systems. In this

case, all the hydrogen produced is liquefied and charged as

a liquid to the vehicle. The required bulk hydrogen storage is

provided by large liquid hydrogen storage vessels co-located

with the liquefaction plant and terminal. The liquid

hydrogen is transported in near-atmospheric-pressure cryo-

genic trucks to the refueling station, where it is discharged

from the trucks and stored in cryogenic tanks. It is then

pumped into the vehicle hydrogen storage system with

a cryogenic pump. For the CcH2 system analyzed in this study,

the final vehicle tank temperature and pressure are 30K and

275 bar, and the hydrogen in the tank exists as compressed

liquid hydrogen.

MOF 177 is a metal-organic framework solid adsorbent

material that has been studied for hydrogen storage along

with other similar materials. It must be used at 100 K or below

in order to adsorb a meaningful amount of hydrogen at

a reasonable pressure. The adsorption is mildly exothermic

and this heat of adsorption must also be removed. Studies

have shown that the most effective way to employ MOF 177

for hydrogen storage is to charge it with liquid hydrogen [4].

The liquid hydrogen turns to gas when charged to theMOF 177

tank. The final full-tank condition is hydrogen adsorbed on

the MOF 177 particle surfaces and gaseous hydrogen in the

macroscopic pore space inside and between the individual

MOF particles, all at100 K and 250 bar. The use of liquid

nitrogen at the refueling station to cool gaseous hydrogen to

charge to the MOF 177 tank is more costly than large-scale

hydrogen liquefaction at a central location and transport of

the liquid hydrogen to the refueling station.

trailer distribution (e.g., P-T340).

Fig. 3 e Liquid-Hydrogen truck distribution (i.e., LH2 Truck).

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114538

3. Data sources

All results of this study are expressed in 2005 reference-year

dollars. The DOE H2A Central Production Model and case

studies [11] were used as the data source for the central

production options. The current-technology cases used in the

study represent 2005 technology. The DOE H2A HDSAM [6]

model was used as the data source for the hydrogen delivery

portion of the WTW pathways. The HDSAM data also repre-

sent 2005 technology [7]. All the upstream energy uses and

GHG emissions are from the Argonne National Laboratory

Greenhouse Gases, Regulated Emissions, and Energy Use in

Transportation (GREET) model [10]. These data are directly

imbedded in the H2A models.

A few of the cases examined employed data not available

in the public versions of the H2A Production and Delivery

Models:

� The 250, 340, and 540 bar GH2 tube-trailer designs, capac-

ities, and capital costs were estimated by talking with tube

trailer and hydrogen high-pressure tank vendors and

developers (see Table 2).

� The design and capital cost for the Cold Gas refrigeration

cooling needs, tube trailer, cascade charging system and

tanks, and vehicle storage tank were estimated by TIAX LLC

personnel on the basis of their experience in estimating the

capital costs for all of the other vehicle hydrogen storage

systems and related equipment.

The designs and capital-cost estimates for the vehicle

hydrogen storage systems were based on the work done at

Argonne National Laboratory and TIAX LLC, as referenced

earlier.

In order to do the full WTW analysis, assumptions about

the vehicle and its performance were needed. The perfor-

mance projected for a 2020 FCV was used to represent a more

developed vehicle than today’s demonstration FCV. The

HDSAM model requires input for the fleet average perfor-

mance (combined LDV fleet average for cars and light trucks).

The specific results presented are for a mid-size vehicle. For

this analysis, the 2020 projected fuel economy of an individual

mid-sized FCV and the composite FCV LDV fleet were esti-

mated to be 110 km (68 mi)/kg H2 [12] and 89 km (55 mi)/kg H2,

respectively. There are some mid-size demonstration FCVs

achieving 110 km/kg today. The values were derived using the

Hydrogen Storage System Simulator (HSSIM), a National

Renewable Energy Laboratory FCV model developed for the

DOE Hydrogen Program [13]. Each fuel-economy value repre-

sents an EPA adjusted combined value based on the values

obtained on the Urban Dynamometer Driving Schedule and

the Highway Fuel Economy Test driving cycles. To approxi-

mate 2020 fuel-economy values, the current-technology FCVs

were firstmodeled and validated within 10% of published data

on demonstration FCV fuel economy. The 2020 fuel-economy

values were then approximated by assuming a 50% glider

mass reduction e based on U.S. FreedomCAR targets [14] e

from the baseline. Maximum drive-train power resizing was

also applied in order to maintain reasonable performance

levels. The city and highway cycles were then re-run and the

results were adjusted and combined on the basis of EPA

guidelines.

The composite fleet fuel-economy value considers the U.S.

Energy Information Administration (EIA)-projected 2020 car/

light-duty truck sales fraction of 62%/38% [15]. On the basis

of its size and performance attributes, the previously

mentioned mid-sized FCV was deemed representative of the

car classification and thus its 2020 projected fuel economy of

110 km/kgH2was used. The light-duty truck classificationwas

represented by a hypothetical 2020 fuel-cell SUVmatching the

performance of today’s average light-duty truck and with

a projected fuel economy of 68 km/kg H2. To estimate the

composite fleet fuel economy, these values were converted to

fuel consumption, multiplied by the appropriate weighting

factor, summed, and finally converted back to a fuel-economy

equaling a value of 89 km/kg H2.

The fuel-economy values for gasoline conventional

(internal-combustion engine) and hybrid vehicles were

derived using a similar methodology. The conventional and

hybrid mid-sized vehicles having the best-in-class fuel-

economy values were first modeled and validated against

published data. As with the FCVs, a 50% reduction in glider

mass was then assumed to estimate 2020 conventional and

hybrid fuel-economy values of 34 and 56 mpg, respectively.

The H2A Central Production and HDSAM cost, energy use,

and GHG emissions are combined to obtain the pathwayWTW

results. Any losses of hydrogen in the pathway are also

accounted for in terms of the cost, energy and GHG emissions

resulting from the need to produce and deliver this extra

amount of hydrogen. The fuel efficiency of the vehicle is used

to calculate the final WTW results in terms of cost, energy use

and GHG emissions on a per-kilometer-driven basis. The

WTW ownership cost on a $/km basis is also calculated. This

cost ismade up of two components added together. The first is

the cost of the hydrogen from production through delivery,

expressed as $/km using the vehicle fuel efficiency. The

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14539

second part accounts for the capital cost of the vehicle

hydrogen storage system, converted to $/km by using a fixed

capital charge rate of 15%, a factor of 1.74 for the combined

manufacturer and dealer markup, and 19,350 km/yr

(12,000 mi/yr) driven. [Note that this ownership cost includes

the cost of the hydrogen and vehicle hydrogen storage system,

but not the cost of the rest of the vehicle.]

4. Storage-system analysis results

Table 3 shows the performance and cost results for the vehicle

hydrogen storage systems. All of these systems have 5.6 kg of

usable hydrogen capacity, resulting in a mid-size vehicle

range of 615 km (381mi), which is greater than the DOE goal of

at least 480 km (300 mi). Only the CcH2 systemmeets the DOE

2015 storage-systemweight percent hydrogen and volumetric

efficiency (g H2/L) targets and none meets the DOE ultimate

targets. Since the storage-system weight is a very small frac-

tion of the total vehicle weight, it does not significantly impact

the vehicle fuel efficiency unless the storage weight percent of

hydrogen is very low (less than w2.5%). The storage-system

volumetric efficiency, however, is very important for the

design and overall weight of the vehicle. Although DOE is re-

evaluating the cost target, cost is important. The storage

system cannot add too much to the price of the vehicle if high

sales volumes are to be expected. In comparison, fuel storage

systems for gasoline vehicles cost about $33.

The key aspects of each of these hydrogen storage systems

are as follows:

� 350 bar: This is a Type III uninsulated carbon-fiber two-tank

configuration, designed with a safety factor of 2.25. (The

Table 3 e Results for vehicle hydrogen storage systems.

350 bar 700 bar ColdGas-500 bar

Storage Mediuma (wt% H2) 100% 100% 100%

Storage Systemb (wt% H2) 4.0% 4.8% 3.8%

Storage Mediuma (g H2/L) 23.3 39.0 40

Storage Systemb (g H2/L) 17.2 25.6 27.1

Storage-System Hydrogen

Losses or Use (kg/kg to

the fuel cell

0.00 0.00 0.00

Storage-System Volume (L) 326 219 207

Storage-System Weight

(Incl. H2 after Fill-up) (kg)

139 117 149

Total Hydrogen (kg) 6.0 5.8 5.9

Usable Hydrogen (kg) 5.6 5.6 5.6

Storage Temperature at the

End of Fill (K)

290e360 290e360 193

Dormancy Time (W-d)c N/A N/A �12

Storage-System Cost ($/kWh of

usable capacity)

$16.60 $18.80 $18.40

Storage-System Cost ($/vehicle) $3096 $3506 $3431

a Storage Medium: This refers to only the volume and weight of the stor

the hydrogen, such as MOF 177.

b Storage System: This refers to the entire storage system, including the st

system to function properly, as well as the storage medium.

c The para/ortho conversion endotherm was not included in this analys

tank is designed so that the burst pressure is at least a factor

of 2.25 times the working pressure which in this case is

350 bar) Modest-pressure ambient-temperature gas storage

results in very low volumetric efficiency but also relatively

low capital cost [16].

� 700 bar: This is a Type IV uninsulated carbon-fiber two-tank

configuration, designed with a safety factor of 2.25. A

refrigeration system is placed at the refueling station to cool

the hydrogen gas to 233 K during refueling so that the

vehicle tank temperature does not exceed 350 K as a result

of the heat of compression and Joule-Thomson expansion.

For this storage system, higher pressure improves volu-

metric efficiency, but it is still well below DOE targets. The

high-pressure results in the highest capital cost of all

systems studied [16].

� Cold Gas-500 bar: The performance and cost of this system

was estimated on the basis of the detailed design and cost of

the 350 bar, 700 bar, and CcH2-275 bar tank systems. It is

based on a Type III vacuum-insulated carbon-fiber

composite tank, rated for a 500 bar working pressure with

a safety factor of 2.25. It is designed to operate atw200 K and

other anticipated temperatures during filling, use, and

dormancy. Its capacity will depend on the initial tank

temperature and fill level (pressure). It is designed to hold

5.6 kg of usable hydrogen, assuming a starting condition of

44 K, 14 bar, and a one-quarter-full tank (1.4 kg of hydrogen),

a typical condition for refueling. At the end of refueling the

temperature and pressure would be 193 K and 500 bar.

Setting the pressure relief valve at 1.25 times the working

pressure allows for at least 12 W-d of dormancy prior to any

hydrogen venting immediately after filling the tank to full

capacity. This value is based on a system design that limits

heat leakage to 5 W. Dormancy times after the vehicle has

CcH2-275 bar MOF177e250 bar

DOE 2015Targets [17]

DOE UltimateTargets [17]

100% 16.1%

5.5% 4.8% 5.5% 7.5

71.0 50.2

41.8 33.9 40 70

0.00 0.00

134 165

101 116

5.7 5.9

5.6 5.6

30.0 100

�4 �16

$11.90 $16.00 TBD TBD

$2219 $2984

ed hydrogen itself and any material or medium used for storage with

orage vessel, piping, valves, and anything else required by the storage

is. It would increase the dormancy time.

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

0% 10% 20% 30% 40%

Hyd

roge

n C

ost (

$/kg

)

Market Penetration

350 bar Pipeline350 bar P-T340CcH2 LH2 Truck700 bar P-T340

Fig. 4 e Impact of market penetration on hydrogen cost.

SMR hydrogen production, average U.S. grid electricity

mix, Sacramento, CA.

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114540

been driven, or if the tank is not filled completely, would be

significantly longer (Note: this analysis did not include the

para/ortho conversion endotherm which would increase

the dormancy time.). This storage system approach has

higher volumetric efficiency than the 700 bar system but

does not meet the 2015 DOE target. The combination of

500 bar tank pressure and tank insulating requirements for

w200 K results in a relatively high capital cost.

� CcH2-275 bar [18]: This is a Type III vacuum-insulated

carbon-fiber composite tank rated for 275 bar working

pressurewith a safety factor of 2.25. It is designed to operate

over a wide range of temperatures (20e350 K). The system

could be used for gaseous hydrogen storage, liquid hydrogen

storage, and supercritical hydrogen storage. For the

purposes of this study, the system was examined in the

CcH2 mode, where the tank is filled with liquid hydrogen

and can be pressurized up to 275 bar. The final temperature

of the tank will depend on the initial tank temperature and

fill level. When the tank conditions exceed the critical point

(12.9 bar, 33 K), the tank contents will be in a supercritical

state. The amount of hydrogen that the tank can hold

depends on its starting temperature. If the tank starts at

50 K, it can be filled to hold 5.4 kg of hydrogen at a pressure

of 1 bar. Pressurization to 275 bar increases its capacity to

6.4 kg. For the purposes of this study, we assumed a usable

capacity of 5.6 kg. Setting the pressure relief valve at 1.25

times the working pressure allows for 5 W-d of dormancy

prior to any hydrogen venting immediately after filling the

tank from empty to full capacity at 275 bar. This value is

based on a system design that limits heat leakage to 5 W.

Dormancy times after the vehicle has been driven, or if the

tank is not filled completely, would be significantly longer.

(Note: this analysis did not include the para/ortho conver-

sion endotherm which would increase the dormancy time.)

This CcH2-275 bar system has the best volumetric and

weight efficiencies of all storage systems studied and meets

the DOE 2015 targets in these areas. It is also the lowest-

capital-cost system. However, as will be seen in the WTW

analysis, hydrogen liquefaction is costly and energy-

intensive. This factor results in high hydrogen costs, lower

energy efficiency and relatively high GHG emissions.

� MOF 177-250 bar [4]: This is a Type III vacuum-insulated

carbon-fiber composite tank rated for 250 bar working

pressure with a safety factor of 2.25. This storage system is

very similar in design to the CcH2 tank system but has MOF

177 material at a packing volume fraction of 0.6 inside the

tank. Liquid hydrogen is pumped into the tank, where it

vaporizes owing to the MOF 177 heat of adsorption. At the

end of the fill cycle, the tank has hydrogen adsorbed on the

MOF 177 and hydrogen gas in the vapor space. The tank is

designed to contain 5.6 kg of usable hydrogen at 100 K and

250 bar pressure. Setting the pressure relief valve at 1.25

times the working pressure allows for 16 W-d of dormancy

prior to any hydrogen venting immediately after filling the

tank. This value is based on a system design that limits heat

leakage to 5 W. Dormancy times after the vehicle has been

driven, or if the tank is not filled completely, would be

significantly longer. Since this adsorption material requires

liquid hydrogen charged to the vehicle, it imposes the same

penalties associatedwith hydrogen liquefaction as the CcH2

technology. The MOF 177 hydrogen adsorption capability is

not high enough to result in a volumetric efficiency as high

as the CcH2 system, but it is higher than any of the other

gaseous systems. A material with a higher hydrogen

adsorption capacity is needed for this material approach to

be attractive. The cost of this system, shown in Table 3, is in

the middle of the costs of the storage systems studied.

However it should be noted that the cost of the MOF 177 was

estimated to be in the range of specialty carbon materials

such as AX-21. MOF 177 is currently an experimental

material and its potential manufacturing cost is not known.

It is a complex structure and might be significantly more

costly to produce than AX-21.

The WTW data presented below will provide far more

insight into these hydrogen storage technologies than these

storage-system results alone.

5. Impact of market penetration andrefueling station size

Fig. 4 shows the impact of market penetration on the cost of

hydrogen at the refueling station for the case of Sacramento,

CA, with some selected hydrogen storage systems and

delivery pathways. The general trend shown will be true for

any hydrogen production technology, delivery pathway, and

vehicle hydrogen storage technology. The trend is dominated

by the economy of scale for the delivery infrastructure,

resulting in very high costs at very low market penetrations

where stations and other delivery infrastructure elements are

relatively small. Once 10e15%market penetration is achieved

in a city as large and densely populated as Sacramento, CA,

most of the economy-of-scale advantage has occurred and the

hydrogen cost trend flattens out.

Fig. 5 plots the same results but uses hydrogen demand

density (kg H2/d/km2). This plot shows the same general trend

as Fig. 4. Hydrogen demand density, rather than a particular

market penetration and city, is the driver for the economy of

scale.

Energy efficiency and GHG emissions per kilometer driven

change negligibly as a function of market penetration

(hydrogen demand density) for all the gaseous hydrogen

$3.00

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$9.00

0 500 1,000 1,500 2,000

Hyd

roge

n C

ost (

$/kg

)

Market Demand (kg-H2/day/km2)

350 bar Pipeline

350 bar P-T340

700 bar Pipeline

700 bar P-T340

CcH2 LH2 Truck

Fig. 5 e Impact of demand density on hydrogen Cost. SMR

hydrogen production, average U.S. grid electricity mix.

$3.00

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$7.00

$8.00

$9.00

0 200 400 600 800 1000

Hyd

roge

n Co

st ($

/kg)

Station Size (kg H2/day)

350 bar P-T340

CcH2 LH2 Truck

Fig. 6 e Impact of refueling station size on hydrogen cost.

SMR hydrogen production, Sacramento, 15% market

penetration, average U.S. grid electricity mix.

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14541

delivery pathways studied. The energy efficiency of the

components in these pathways is not scale-dependent. For

the liquid-hydrogen delivery pathways, the energy efficiency

improves and thus the GHG emissions decrease to some

degree up to about 15% market penetration, where the trend

levels off. This observation is a result of the improvement in

energy efficiency of the liquefaction process as the scale of the

process increases. For example, the WTW energy efficiency

increases from 38% to 43%, and the GHG emissions decrease

by 14%, going from 2% market penetration to 15% market

penetration for the CcH2 storage system using the average

U.S. grid electricity mix and SMR hydrogen production.

Most of the results in the rest of this paper will focus on

a market demand density equivalent to 15% market penetra-

tion in Sacramento (120 kg H2/d/km2). This level represents

a significant but realistic market demand density once

hydrogen FCVs are in the mainstream for LDV transportation.

Costs decrease only marginally at higher market demand

densities.

A fewadditionalconclusionscanbedrawnfromFigs. 4and5:

� Storage at 350 bar generally results in lower hydrogen cost

than storage at 700 bar, since less compression and no

refrigeration are needed at the refueling station.

� For gaseous delivery, all-pipeline delivery results in slightly

lower cost than tube-trailer delivery except at very low

hydrogen demand density. The difference depends on the

tube-trailer capacity (temperature and pressure capability);

it is smaller with higher-capacity tube trailers.

� CcH2-275 bar storage results in a higher hydrogen cost than

350 bar and 700 bar storage, except at very low hydrogen

demand density. The higher cost is due to the relatively high

cost of liquefaction.

Fig. 6 shows the impact of the refueling station size. This

trend is similar for any storage technology andmarket demand

density. It is the result of the economy of scale for the refueling

station itself. Above a station size of about 500 kg H2/d, the

curves flatten out.

Most of the WTW analyses done in this study utilized

station sizes of 700 or 1000 kg H2/d. The few that were done at

Sacramento market penetrations of 5% or below used 400 kg

H2/d to maintain station coverage of least at 5%.

6. Delivery pathway impacts

Figs. 7 and 8, and 9 show the impacts of the hydrogen delivery

pathway on all the vehicle storage technologies studied.

6.1. Delivery pathways for 350 bar and 700 bar vehiclehydrogen storage systems

For 350 and 700 bar storage systems, the trends are the same:

the hydrogen production cost is significant but accounts for

less than 50% of the total delivered hydrogen cost. All-pipeline

delivery is a lower-hydrogen-cost pathway. The pathway that

comprises pipeline to lowest-capacity tube trailer (P-T250) has

the highest hydrogen cost. This high cost is due to higher

trucking costs per kilogram of hydrogen delivered and

a smaller station size, resulting in higher station costs per

kilogram of hydrogen. The higher trucking costs are due to

several factors; the relatively high tube trailer capital cost per

kilogram of hydrogen capacity (see Table 2), the relatively low

hydrogen capacity of this tube trailer results in more tube

trailers needed to deliver the hydrogen, and the labor costs for

delivery go up proportionately with the number of tube

trailers needed. As the tube-trailer pressure and thus capacity

are increased (e.g., P-T540), this pathway becomes cost-

competitive with the all-pipeline pathway. The all-340-bar-

tube-trailer pathway (T-340) results in an intermediate

hydrogen cost, since pipeline transport of relatively large

volumes of hydrogen to the city gate is more cost-effective

than tube-trailer delivery. In all cases, the refueling station

costs are significant because of the required hydrogen storage

and cascade charging system and the cost of the compressor

and compression. The hydrogen cost difference within the

350 bar pathways (Fig. 7A) is about $0.50/kg.

The 700 bar pathways (Fig. 8A) result in a higher cost for

hydrogen compared to the 350 bar pathways (Fig. 7A) because

of the higher compression needed at the refueling station.

This difference is about $0.60/kg. The hydrogen cost differ-

ence within the 700 bar pathways is about $0.30/kg.

The ownership costs (Figs. 7B and 8B) mirror the hydrogen

costs, but the 700 bar ownership costs (Fig. 8B) include the

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114542

added penalty of a higher cost for the higher-pressure vehicle

hydrogen storage system. The higher cost for 700 bar vs.

350 bar vehicle storage system is somewhat compensated by

a higher volumetric efficiency on board the vehicle (see Table

3), but this efficiency is still well below targets. The well-to-

vehicle-tank energy efficiencies across all of the 350 and

700 bar pathways fall in a fairly narrow band of 52%e57%.

The majority of the energy consumption is from the

production process. The all-pipeline pathway uses somewhat

more energy that the other pathways. This difference results

from the fact that for this pathway, nearly all the compres-

sion needed occurs at the refueling stations. Small-scale

compression is less efficient than large-scale compression

done at the terminals for the tube-trailer cases. All the

700 bar pathways require more energy at the refueling

station because of the need to compress the hydrogen to

a higher pressure. The WTW GHG emissions mirror the

energy use for all these pathways, as expected. More than

half of the GHG emissions come from the SMR hydrogen

production.

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35

0 b

ar

P

ipel

ine

35

0 b

ar

P

-T2

50

35

0 b

ar

P

-T3

40

Hyd

roge

n C

ost (

$/kg

)

$0.00

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$0.04

$0.06

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$0.10

350

bar

Pipe

line

350

bar

P-T

250

350

bar

P-T

340

Ow

ners

hip

Cos

t ($

/km

)

A

B

Fig. 7 e A e Impact of delivery pathway on 350 bar vehicle hyd

hydrogen production, Sacramento, 15% market penetration, ave

pathway on 350 bar vehicle hydrogen storage system: ownersh

Sacramento, 15% market penetration, average U.S. grid electric

6.2. Delivery pathways for cold gas-500 bar, CcH2-275 bar, and MOF 177e250 bar vehicle hydrogen storagesystems

There are only a few delivery pathway options for the other

vehicle hydrogen storage systems studied. The important

ones are shown in Fig. 9.

The Cold Gas-500 bar system is shown with a pipeline to

the city gate and a 340 bar tube trailer to the refueling station

as the delivery pathway. There are a few other delivery

pathway options for this storage technology, but this one

represents the lowest-cost option. At 15% market share, this

Cold Gas case has the lowest hydrogen cost of all the storage

systems and pathways studied except the 350 bar all-pipeline

option. This is because the volumetric efficiency of the

hydrogen in this pathway is the highest, with the exception of

the liquid hydrogen pathways. This factor reduces the tube-

trailer trucking costs as well as the storage volumes needed

for gaseous tube-trailer delivery. The energy efficiency of

cooling hydrogen to 90 K is significantly higher than the

0

20

40

60

80

100

35

0 b

ar

P

-T5

40

35

0 b

ar

T

34

0

Ene

rgy

Con

sum

ptio

n (k

Wh/

kg)

/ Ene

rgy

Eff

icie

ncy

(%)

Station ($/kg) Transport ($/kg) Production ($/kg) Station (kWh/kg) Transport (kWh/kg) Production (kWh/kg) Energy Efficiency (%)

0

20

40

60

80

100

120

140

350

bar

P-T

540

350

bar

T34

0

GH

G E

mis

sion

s (g

m C

O 2 -

eq/k

m)

Vehicle Hydrogen Storage System Cost ($/km)

Fuel Cost($/km)

Station (GHG)

Transport (GHG)

Production (GHG)

rogen storage system: hydrogen cost and energy use SMR

rage U.S. grid electricity mix. B e impact of delivery

ip cost and GHG emissions SMR hydrogen production,

ity mix.

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14543

energy efficiency of liquefying it, so its energy use and cost are

significantly lower than for the pathways that need liquid

hydrogen. The higher capital costs for insulated storage and

tube trailers along the pathway add some cost, but overall the

hydrogen costs are still lower. However, the vehicle hydrogen

storage system for this pathway is estimated to be the most

costly of all the storage systems studied because of the need

for both vacuum insulation and high pressure. As a result, the

ownership cost is the highest of the systems examined, with

the exception of the 700 bar case. This disadvantage is

compensated by the vehicle hydrogen storage volumetric

efficiency, which is higher than that of the 350 bar and 700 bar

systems. In terms of energy usage, energy efficiency, and GHG

emissions, the Cold Gas-500 bar system is comparable to the

other gaseous systems andmuch better than the CcH2-275 bar

and MOF 177e250 bar systems because of their need for

hydrogen liquefaction.

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700

bar

Pipe

line

700

bar

P-T2

50

700

bar

P-T3

40

700

bar

Hyd

roge

n C

ost (

$/kg

)

$0.00

$0.02

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$0.08

$0.10

700

bar

Pipe

line

700

bar

P-T2

50

700

bar

P-T3

40

700

bar

Ow

ners

hip

Cos

t ($/

km)

A

B

Fig. 8 e A e Impact of delivery pathway on 700 bar vehicle hyd

hydrogen production, Sacramento, 15% market penetration, ave

pathway on 700 bar vehicle hydrogen storage system: ownersh

Sacramento, 15% market penetration, average U.S. grid electrici

The CcH2-275 bar system requires liquid hydrogen to be

delivered to the vehicle. The centralized liquefaction plant

could be co-located with the terminal and hydrogen produc-

tion, with all-liquid truck delivery. Alternatively, the hydrogen

could be pipelined to a large liquefaction plant co-located

within the terminal at the city gate. Both these pathways are

shown in Fig. 9. Any more-decentralized liquefaction would

be very inefficient because of its small scale. Liquefaction is

costly because of both the capital costs and the high energy

use; these factors add significantly to the cost of the delivered

hydrogen. On the other hand, the refueling station costs are

somewhat lower, since liquid-hydrogen storage costs less

than high-pressure gas storage, and liquid pumping uses

much less energy than compression. Overall, the hydrogen

costs for the two CcH2-275 bar delivery pathways are higher

than the 350 bar and Cold Gas delivery pathways and on par

with the 700 bar delivery pathways. The CcH2-275 bar vehicle

0

20

40

60

80

100P-

T540

700

bar

T340

Ener

gy C

onsu

mpt

ion

(kW

h/kg

)/ E

nerg

y E

ffici

ency

(%)

Station ($/kg)

Transport ($/kg)

Production ($/kg)

Station (kWh/kg)

Transport (kWh/kg)

Production (kWh/kg)

Energy Efficiency (%)

0

20

40

60

80

100

120

140

160

180

P-T5

40

700

bar-

T340

GH

G E

mis

sion

s (g

m C

O2

-eq/

km)

Vehicle Hydrogen Storage System Cost ($/km)

Fuel Cost($/km)

Station (GHG)

Transport (GHG)

Production (GHG)

rogen storage system: hydrogen cost and energy use. SMR

rage U.S. grid electricity mix. B e impact of delivery

ip cost and GHG emissions. SMR hydrogen production,

ty mix.

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114544

hydrogen storage system is the lowest-cost storage system

examined (see Table 3). The net result is that the CcH2

ownership costs are the lowest. The large energy penalty for

liquefaction has a very negative impact on the CcH2 energy

use and GHG emissions, resulting in a much lower energy

efficiency and higher GHG emissions than for any of the other

storage systems examined except MOF 177e250 bar.

The MOF 177e250 bar vehicle hydrogen storage system

suffers from the same requirement for liquid hydrogen as the

CcH2-275 bar system. This factor results in high hydrogen

costs, energy consumption, and GHG emissions identical to

those of the CcH2 storage system, as shown in Fig. 9. In

addition, the hydrogen is stored on the vehicle as adsorbed

hydrogen and cold pressurized gas, requiring a vacuum-

insulated, pressurized vehicle tank filled with a costly solid

adsorbentmaterial. Given these vehicle storage requirements,

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Col

d G

as-

500

bar P

ipe-

34

0 ba

r Tra

iler

CcH

2-

275

bar-

L

H2

Tru

ck

CcH

2-

275

bar P

ipe-

L

H2

Tru

ck

Hyd

roge

n C

ost (

$/kg

)

$0.00

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$0.10

Col

d G

as-

500

bar P

ipe-

34

0 ba

r Tra

iler

CcH

2-

275

bar-

L

H2

Tru

ck

CcH

2-

275

bar P

ipe-

L

H2

Tru

ck

Ow

ners

hip

Cos

t ($/

km)

A

B

Fig. 9 e A e Impact of delivery pathway on cold gas-500 bar, CcH

systems: hydrogen cost and energy use. SMR hydrogen product

electricity mix. B e impact of delivery pathway on cold gas-500

storage systems: ownership cost and GHG emissions. SMR hyd

average U.S. grid electricity mix.

the MOF 177e250 bar vehicle hydrogen storage system costs

significantly more than the CcH2 system but less than all of

the other systems studied. The combination of hydrogen

delivery and storage system requirements results in an

ownership cost higher than for the CcH2 system and in the

mid-range of the storage systems examined.

The rest of the data presented will be limited to one

delivery pathway for each vehicle hydrogen storage system.

For the 350 bar, 700 bar, and Cold Gas-500 bar technologies, the

pathwaywill be a pipeline to a city-gate terminal with transfer

to 340 bar tube trailers (i.e., P-T340), since this is an attractive

delivery pathway with characteristic costs, energy use, and

GHG emissions for all three storage systems. It is also one that

could be implemented early in the transition to the use of

hydrogen and FCVs. An all-pipeline pathway is a little lower in

cost for 350 and 700 bar technologies, but it may be difficult to

0

20

40

60

80

100

120

MO

F 17

7-

250

bar-

L

H2

Tru

ck

Ene

rgy

Con

sum

ptio

n (k

Wh/

kg)

/ Ene

rgy

Eff

icie

ncy

(%)

Sta tion ($/kg)

Transport ($/kg)

Liquefaction ($/kg)

Production ($/kg)

Station (kWh/kg)

Transport (kWh/kg)

Liquefaction (kWh/kg)

Production (kWh/kg)

Energy Efficiency (%)

0

20

40

60

80

100

120

140

160

180

200

MO

F 17

7-

250

bar-

L

H2

Tru

ck

GH

G E

mis

sion

s (g

m C

O 2 -

eq/k

m)

Vehicle Hydrogen Storage System Cost ($/km)

Fuel Cost($/km)

Station (GHG)

Transport (GHG)

Liquefaction (GHG)

Production (GHG)

2-275 bar, and MOF 177e250 bar vehicle hydrogen storage

ion, Sacramento, 15% market penetration, average U.S. grid

bar, CcH2-275 bar, and MOF 177e250 bar vehicle hydrogen

rogen production, Sacramento, 15% market penetration,

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14545

justify building an extensive hydrogen pipeline infrastructure

in urban areas. Prior to building pipelines from central plants

to city gates, a pure 340 bar tube-trailer delivery pathway

would also be cost-effective as long as the hydrogen plant was

within a reasonable distance of the city gate (less than

200 km), as shown in Figs. 7 and 8. For CcH2-275 bar and MOF

177e250 bar technologies, an all-liquid truck delivery pathway

will be used as the example. This delivery option also could be

utilized early in the transition to the use of hydrogen for LDVs

and is reasonably cost-effective (see Fig. 9).

7. Impacts of hydrogen productiontechnology and grid electricity mix

Figs. 10 and 11 show the impact of the hydrogen production

technology utilized and the electricity grid characteristics on

the 700 bar and CcH2-275 bar WTW cases. The trends are

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700

bar

G

SMR

P-T

340

700

bar

G

Bio

-Gas

P-T

340

700

bar

G

Ele

ct. P

-T34

0

700

bar

NG

-G

SMR

P-T

340

700

bar

NG

-G

Bio

-Gas

P-T

340

Hyd

roge

n C

ost (

$/kg

)

0

50

100

150

200

250

300

350

400

450

700

bar

G

SMR

P-T

340

700

bar

G

Bio

-Gas

P-T

340

700

bar

G

Ele

ct. P

-T34

0

700

bar

NG

-G

SMR

P-T

340

700

bar

NG

-G

Bio

-Gas

P-T

340

700

bar

NG

-G

Ele

ct. P

-T34

0

GH

G E

mis

sion

s (g

m C

O 2 -

eq/k

m)

A

B

Fig. 10 e A e Impact of hydrogen production technology and gr

hydrogen storage system. Sacramento, 15% market penetration

electricity mix on GHG emissions and energy use for the 700 bar

penetration.

identical for these two vehicle storage technologies andwould

also hold for all the other storage technologies studied.

7.1. Impacts of different production technologies withthe Average U.S. grid electricity mix (termed “G” in Figs. 10and 11)

Biomass-gasification production of hydrogen (termed “Bio-

Gas” in Figs. 10 and 11) is only somewhat more costly than

SMR. Electrolytic production of hydrogen (termed “Elect” in

Figs. 10 and 11) is considerably more costly. This cost is driven

by the relatively large amount of electricity required. Biomass

gasification uses more energy than SMR, but biomass is

renewable with little net GHG emission. Electrolysis utilizes

considerably more energy than either SMR or biomass gasifi-

cation. The reason for this difference is the large amount of

electricity needed and the low energy efficiency of electricity

production itself. The current average U.S. grid electricity mix

700

bar

NG

-G

Ele

ct. P

-T34

0

700

bar

R

SMR

P-T

340

700

bar

R

Bio

-Gas

P-T

340

700

bar

R

Ele

ct. P

-T34

0

Station

Transport

Production

0

20

40

60

80

100

120

140

160

180

700

bar

R

SMR

P-T

340

700

bar

R

Bio

-Gas

P-T

340

700

bar

R

Ele

ct. P

-T34

0

Ene

rgy

Con

sum

ptio

n (k

Wh/

kg)

Station (GHG)

Transport (GHG)

Production (GHG)

Station (kWh/kg)

Transport (kWh/kg)

Production (kWh/kg)

id electricity mix on hydrogen cost for the 700 bar vehicle

. B e impact of hydrogen production technology and grid

vehicle hydrogen storage system. Sacramento, 15%market

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114546

energy efficiency is only about 35% [19]. Electrolyzers them-

selves are fairly efficient (about 64%) [20]. The GHG emissions

for this electricity mix are also quite high.

The trends for the 700 bar and CcH2-275 bar cases using the

average U.S. grid electricity mix are the same across the three

production technologies examined. They have very similar

total hydrogen costs, but the GHG emissions and energy use

are distinctly higher for the CcH2 cases because of the added

energy-intensive liquefaction step.

7.2. Impacts of other electricity grid mixes

Because of the low efficiency and high GHG emissions char-

acteristic of the current average U.S. grid electricity mix, there

$0.00

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CcH

2-27

5 ba

r G

SM

R L

H2

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ck

CcH

2-27

5 ba

r G

B

io-G

as L

H2

Tru

ck

CcH

2-27

5 ba

r G

E

lect

. LH

2 T

ruck

CcH

2-27

5 ba

r N

G-G

SM

R L

H2

Tru

ck

CcH

2-27

5 ba

r N

G-G

B

io-G

as L

H2

Tru

ck

Hyd

roge

n C

ost (

$/kg

)

0

100

200

300

400

500

CcH

2-27

5 ba

r G

SM

R L

H2

Truc

k

CcH

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5 ba

r G

B

io-G

as L

H2

Truc

k

CcH

2-27

5 ba

r G

El

ect.

LH2

Truc

k

CcH

2-27

5 ba

r N

G-

G

SMR

LH

2 Tr

uck

CcH

2-27

5 ba

r N

G-

G

Bio

-Gas

LH

2 Tr

uck

CcH

2-27

5 ba

r N

G-

G

GH

G E

miss

ions

(gm

CO

2 -eq

/km

)

A

B

Fig. 11 e A e Impact of hydrogen production technology and gr

vehicle hydrogen storage system. Sacramento, 15% market pene

grid electricity mix on GHG emissions and energy use for the C

15% market penetration.

could be significant improvements in the WTW energy use

and GHG emissions for these hydrogen technologies if the grid

became “greener.” This was investigated by looking at two

alternative electricity grids: one that uses only natural gas

(termed “NG-G” in Figs. 10 and 11) and one that is 100% based

on renewable electricity (termed “R” in Figs. 10 and 11). The

all-natural-gas grid is meant to represent a potential nearer-

term shift in the U.S. grid mix to one with an improved

average efficiency and lower GHG emissions. The 100%-

renewable-electricity cases are meant to represent a situation

where hydrogen production (and when applicable, liquefac-

tion) would be co-located with a renewable-electricity gener-

ation plant. Renewable-electricity (e.g. hydroelectric, wind

and solar energy) plants are likely to be some distance from

CcH

2-27

5 ba

r N

G-G

E

lect

. LH

2 T

ruck

CcH

2-27

5 ba

r R

SM

R L

H2

Tru

ck

CcH

2-27

5 ba

r R

B

io-G

as L

H2

Tru

ck

CcH

2-27

5 ba

r R

E

lect

. LH

2 T

ruck

Station

Transport

Liquefaction

Production

0

20

40

60

80

100

120

140

160

180

200

Elec

t. LH

2 Tr

uck

CcH

2-27

5 ba

r R

SM

R L

H2

Truc

k

CcH

2-27

5 ba

r R

B

io-G

as L

H2

Truc

k

CcH

2-27

5 ba

r R

El

ect.

LH2

Truc

k

Ener

gy C

onsu

mpt

ion

(kW

h/kg

)

Station (GHG)

Transport (GHG)

Liquefaction (GHG)

Production (GHG)

Station (kWh/kg)

Transport (kWh/kg)

Liquefaction (kWh/kg)

Production (kWh/kg)

id electricity mix on hydrogen cost for the CcH2-275 bar

tration. B e impact of hydrogen production technology and

cH2-275 bar vehicle hydrogen storage system. Sacramento,

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14547

major urban centers. For these cases, it was assumed that the

hydrogen plants were 484 km (300 mi) from the city gate. All

other cases were evaluated with the hydrogen production

plant located 100 km (62 mi) from the city gate. This

assumption does increase the transport cost portion for the

renewable-electricity-based WTW pathways (Note: It was

assumed that the cost of electricity is the same whether it

comes from the average U.S. grid mix, natural gas, or renew-

able resources. Actual electricity prices vary greatly depend-

ing on source and other factors. Hydroelectric power is

comparatively very low in cost but has limited availability.

Wind-based electricity, with the existing Federal subsidy, is

cost-competitive with fossil-based electricity. Solar-based

electricity is currently too costly for widespread use.

Natural-gas-based electricity varies with the price of natural

gas, which has fluctuated by more than a factor of three over

the past five years.).

Figs. 10 and 11 show the impact of these different grid

mixes on theWTWresults. For the 700 bar technology,moving

to natural-gas-based electricity reduces energy use, improves

energy efficiency and reduces GHG emissions. This is because

electricity production from natural gas is somewhat more

efficient than production from the average U.S. grid mix. The

impact is quite modest except for the GHG reduction for the

electrolysis production case, since this pathway uses much

more electricity than all others. For the CcH2-275 bar tech-

nology, the trends are the same but the shifts are larger for

each hydrogen production technology, since this pathway

involves significantly more electricity use owing to the

hydrogen liquefaction step.

Moving to 100% renewable electricity has dramatic effects,

as expected. Energy use is reduced significantly. This is

because with renewable-electricity based on solar or wind,

electricity production itself is calculated as 100% efficient in

GREET (energy accounting in GREET starts with the unit of

electricity generated, in the case of renewable sources). GHG

emissions become negligible for all cases except where SMR

hydrogen production is used.

8. WTW overall results

Table 4 and Figs. 12 and 13 provide an overall summary of the

WTW cost, energy use, GHG emissions, and storage system

performance for each of the vehicle hydrogen storage systems

examined. This data is for 15% market penetration in Sacra-

mento, SMR hydrogen production, and with the average U.S.

grid electricity mix. The delivery pathway chosen for each

storage technology is the one that is characteristic of what is

likely to be used, as discussed above. Information on gasoline

conventional and hybrid vehicles is also provided for refer-

ence. The fuel efficiency for these gasoline vehicles has been

projected to a 2020 mid-size vehicle to be comparable to the

FCV used in this study (see above). The gasoline price was

taken from the Energy Information Agency (EIA) 2009 Annual

Energy Outlook (AEO) 2009, projected for 2020 untaxed.

Although the 350 bar storage technology is relatively

attractive from a cost, energy use, and GHG emissions

perspective, it is far from the DOE volumetric-efficiency

targets and thus requires a quite large storage-system

volume on the vehicle, which is not practical for the long term.

The MOF 177e250 bar storage technology requires the

hydrogen to be liquefied and has a lower volumetric efficiency

than the CcH2 technology, resulting in high hydrogen cost,

energy use, and GHG emissions. Its need for a vacuum-

insulated pressure vessel and costly adsorbent material

results in a relatively high vehicle storage system cost. The net

result is a relatively high ownership cost. Its only advantage

over the CcH2 storage technology is a much greater allowable

dormancy time before venting hydrogen (Table 3). In order for

a sorption-material storage technology to be attractive, the

material needs to adsorb larger amounts of hydrogen per unit

volume and/or operate at higher temperatures comparedwith

MOF 177. The higher volumetric efficiency could reduce the

cost of the vehicle storage tank. If the material could operate

at a temperature such that cold hydrogen gas could be

charged, thus avoiding liquefaction, the result would be lower

hydrogen cost, lower energy use, and lower GHG emissions.

The comparison between the 700 bar, Cold Gas-500 bar,

and CcH2-275 bar technologies represents a set of trade-offs.

The 700 bar system has a relatively high hydrogen cost

because of the energy needed for compression to this high

pressure. The vehicle hydrogen storage tank is also costly

because of its high-pressure requirements. The combination

results in the highest ownership cost. The 700 bar systemdoes

have the lowest energy use and GHG emissions of the

hydrogen storage systems studied, with the exception of the

350 bar system. The Cold Gas technology has the lowest

hydrogen cost but nearly the highest hydrogen storage system

cost, resulting in an intermediate ownership cost. Owing to

the energy needed to cool the hydrogen and compress it for

500 bar vehicle storage, the Cold Gas system uses a little more

energy and has slightly higher GHG emissions compared to

the 700 bar system. However, the energy needed for cooling

and compression is still considerably less than the energy

needed for hydrogen liquefaction. Thus, the Cold Gas system

has significantly less energy use and GHG emissions than the

CcH2 system. Its volumetric efficiency is slightly better than

the 700 bar system but not as good as the CcH2 system. The

CcH2 technology results in the highest hydrogen cost, energy

use, and GHG emissions. However, the CcH2 vehicle hydrogen

storage system has the lowest cost, because it operates at

a relatively lower pressure and the tank is smaller owing to

the CcH20s high volumetric efficiency. The net result is the

lowest ownership cost, but the differences are small on an

absolute basis. The CcH2 technology is the only one of the

hydrogen storage technologies examined that meets the DOE

2015 target for volumetric efficiency.

It is also important to compare these WTW results for

hydrogen and FCV technology with those for gasoline vehi-

cles. Although the cost of hydrogen is higher than the cost of

gasoline on an energy basis, the fuel cost/km driven is similar

because of the higher fuel efficiency of the FCV comparedwith

gasoline vehicles. Table 4 shows that the fuel cost/km for the

hydrogen FCV is less than for the conventional gasoline

vehicle and can approach the hybrid gasoline vehicle across

the different hydrogen storage technologies examined. The

hydrogen production cost used in this calculation is for SMR.

SMR generally has the lowest hydrogen production cost with

Table 4 e WTW Summary of Vehicle Hydrogen Storage Systems SMR Production, 15% Market Penetration, Average U.S. Grid Mix.

HydrogenCost ($/kg)

FuelCosta ($/km)

WTW EnergyUse(kWh/kg H2

to Fuel Cell

EnergyEfficiency (%)

WTWOwnershipCosts ($/km)

WTW EnergyUse (kWh/km)

WTW GHG(g CO2-eq/km)

VolumetricEfficiency(g H2/L)

Volume (L) Storage-SystemCost ($/vehicle)

350 bar P-T340 $4.26 $0.039 58.8 56.7% $0.081 0.54 123 17.2 326 $3096

700 bar P-T340 $4.71 $0.043 61.2 54.4% $0.090 0.56 129 25.6 219 $3506

Cold Gas-500

bar P-T340

$4.25 $0.039 63.8 52.2% $0.085 0.58 136 27.1 207 $3431

CcH2-275 bar

LH2 Truck

$4.80 $0.044 78.0 42.7% $0.074 0.71 174 41.8 134 $2219

MOF 177-250

bar LH2 Truck

$4.80 $0.044 78.0 42.7% $0.084 0.71 174 33.9 165 $2984

Gasoline

Conventional

Vehicle b

$3.32/galc $0.057 41.6/gald $0.057 0.76 204a,e N/A 62f $33

Gasoline Hybrid

Vehicle g

$3.32/galc $0.037 41.6/gald $0.037 0.46 124b,e N/A 62f $33

a Based on 110 km/kg projected for 2020 for the FCVs.

b Based on 55 km/gal projected for 2020.

c From EIA AEO 2009 for 2020, after deducting $0.40 for Federal and State taxes.

d Based on Argonne National Laboratory GREET Model.

e Based on Argonne National Laboratory GREET Model: 11,152 g CO2-eq./gal of gasoline.

f Based on 16 gal of gasoline.

g Based on 89 km/gal projected for 2020.

internatio

naljo

urnalofhydrogen

energy

36

(2011)14534e14551

14548

0.00

0.20

0.40

0.60

0.80

0

1

2

3

4

5

6

350

bar

P-T

340

700

bar

P-T

340

Col

d G

as-

500

bar

P-T

340

CcH

2-27

5 ba

r L

H2

Tru

ck

MO

F 17

7-25

0 ba

r L

H2

Tru

ck

Gas

olin

e-C

onve

ntio

nal

Veh

icle

Gas

olin

e-H

ybrid

Veh

icle

Ene

rgy

Con

sum

ptio

n (k

Wh/

km)

Fue

l Cos

t ($

/kg)

Station ($/kg)

Transport ($/kg)

Liquefaction ($/kg)

Production ($/kg)

Station (kWh/km)

Transport (kWh/km)

Liquefaction (kWh/km)Production (kWh/km)

Reference Vehicles: Gasoline Conventional/Hybrid

(kW

h/km

)

(kW

h/km

)

($/g

al)

($/g

al)

Fuel Cost ($/gal)

EnergyConsumption (kWh/km)

Fig. 12 e Fuel cost and WTW energy use of vehicle hydrogen storage systems. SMR production, 15% market penetration,

average U.S. grid mix.

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14549

currently available technology, though it depends on the cost

of the natural gas used. As discussed earlier, biomass gasifi-

cation, which results in near-zero net GHG emission, can also

have a low cost for hydrogen production, depending on the

cost of the biomass feedstock used. However, other hydrogen

production options (e.g., electrolysis, as shown earlier) can

have significantly higher costs. On the other hand, both the

production and delivery technologies incorporated into the

H2A and HDSAM models used in this study represent 2005

technologies. Research efforts are continuing to reduce these

costs.

The overall cost/km driven is what is important to the

consumer. All of these vehicle hydrogen storage technologies

at their current state of development add considerable cost to

the vehicle. Fuel storage systems for conventional gasoline

vehicles only cost about $33. This factor results in a significant

difference in the ownership costs between gasoline vehicles

and hydrogen FCVs, as shown in Table 4 and Fig. 13. Research

is being done to reduce the cost of these hydrogen storage

technologies.

Table 4 and Fig. 12 show that the FCV hydrogen-storage

technologies studied use about the same or less energy per

kilometer on a WTW basis than the conventional gasoline

vehicle. All of them usemoreWTW energy per kilometer than

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

35

0 b

ar

P-T

34

0

70

0 b

ar

P-T

34

0

Col

d G

as-

50

0 b

ar

P-T

34

0

CcH

2-

27

5 b

ar

LH

2 T

ruck

MO

F 17

7-

250

ba

r L

H2

Tru

ck

Ow

ners

hip

Cos

t ($

/km

)

Volume: 326 L 219L 207L 134L 165L

SystemCost: $3,096 $3,506 $3,431 $2,219 $2,984

Fig. 13 e Ownership cost, WTW GHG emissions, volume, and c

production, 15% market penetration, average U.S. grid mix.

the hybrid gasoline vehicle. A very important factor, however,

is the type and source of the energy used. The fact that the U.S.

imports about 63% of the petroleum it needs [21] is a signifi-

cant energy-security concern. The type of energy used also

directly impacts the WTW GHG emissions. As discussed

above, there are a variety of domestically sourced energy

resources available for hydrogen FCV technology.

It is important to note that well over half of the GHG

emissions for these FCV cases stem from the SMR production

of the hydrogen (100 g CO2-eq/km, see Fig. 13). The total WTW

GHG emissions could be reduced substantially by using

renewable or other low-carbon-emitting technology to

produce the hydrogen. This was shown above with the

examples of biomass gasification and electrolysis, where the

electricity needed was produced from renewable sources.

Other potential low-carbon-emitting hydrogen production

technologies include coal gasification with carbon sequestra-

tion, solar thermochemical cycles, and nuclear energy. If

these near-zero-carbon-emitting technologies were used to

produce the hydrogen, the GHG emissions of all the WTW

storage technology pathways considered here would be

substantially lower. All but the CcH2 and MOF 177 storage

technologies would produce GHG emissions far below that of

the gasoline hybrid vehicle. The CcH2 and MOF 177 systems

0

50

100

150

200

250

Gas

olin

e-C

onv

enti

ona

l V

ehic

le

Ga

solin

e-H

yb

rid

Veh

icle

GH

G E

mis

sion

s (g

m C

O2-e

q/km

) Vehicle Storage System Cost ($/km)

Fuel Cost($/km)

Station (GHG)

Transport (GHG)

Liquefaction (GHG)

Production (GHG)

Reference Vehicles: Gasoline Conventional/Hybrid

(GH

G)

(GH

G)

62L 62L

$33 $33

($/k

m)

($/k

m)

Ownership Cost ($/km)

GHG Emissions (gm CO2-eq/km)

apital cost of vehicle hydrogen storage systems. SMR

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 114550

would emit about 35% less GHG than the gasoline hybrid

vehicle.

As shown in Table 4, gasoline storage systems consume far

less volume on vehicles than any of the hydrogen storage

systems studied. The DOE ultimate hydrogen-storage volu-

metric-efficiency target is designed to achieve vehicle volume

utilization for the hydrogen storage system that is similar to

today’s gasoline storage systemwith a vehicle range of at least

480 km (300 mi).The best of the hydrogen storage systems

studied would require a mid-size vehicle designed with

135e220 L available for the hydrogen storage system. The

vehicle would have a range of 610 km (380 mi) with the

designed 5.6 kg of usable hydrogen capacity and the FCV fuel

efficiency used in this study.

9. Conclusions

The results of this study show the importance of under-

standing the WTW costs, energy use and GHG emissions as

well as the vehicle storage system performance to more fully

understand vehicle hydrogen storage technologies and to help

direct research efforts in this area.

The 700 bar, Cold Gas, and CcH2 hydrogen technologies

studied represent a set of trade-offs relative to their attrac-

tiveness for FCVs. Only the CcH2 system meets the critical

DOE 2015 volumetric-efficiency target, and none meets the

DOE ultimate volumetric-efficiency target.

For these systems to achieve a 480-km (300-mi) range with

the projected 110 km (68 miles)/kg H2 they would require

a storage system that holds 4.4 kg of hydrogen. Based on the

results of this study done at 5.6 kg of usable hydrogen, they

would require a volume of at least 105e175 L in amid-size FCV

(The volumetric efficiency will decrease somewhat as the

storage tank size decreases.).

The cost of the hydrogen fuel for FCVs has the potential to

be competitive on a cost/km basis with gasoline conventional

and hybrid vehicles despite the relatively high cost of delivery

of hydrogen. The cost of the hydrogen storage system on the

vehicle needs to be reduced. All the systems studied require

costly carbon-fiber-wrapped, pressurized vehicle storage

tanks. A breakthrough in carbon-fiber cost would be very

valuable.

For any of these vehicle hydrogen storage technologies,

energy use and GHG emissions are strongly affected by the

hydrogen production technology. The potential use of

domestic resources and low-carbon-emitting energy

resources for hydrogen production make hydrogen FCVs very

attractive from an energy-security and global-warming

perspective. However, vehicle hydrogen storage technologies

that require hydrogen liquefaction utilize significantly more

energy and produce significantly more GHG emis-

sionsdassuming the current liquefaction technology and the

average U.S. grid mixdthan the other hydrogen storage

technologies studied. Either a breakthrough in liquefaction

technology or the use of low-carbon-emitting electricity could

remedy this disadvantage.

The MOF 177 material-based storage system studied here

requires liquid hydrogen andhas a lower volumetric efficiency

than the CcH2 technology, making it less attractive than the

CcH2 system. These results point to the need for material-

based systems that have better volumetric efficiency and/or

operate at high enough temperatures but with low enough

heats of adsorption to avoid the need for liquid hydrogen.

Acknowledgement

This work was funded by the U.S. Department of Energy’s

Energy Efficiency and Renewable Energy, Fuel Cell Technolo-

gies Program.

r e f e r e n c e s

[1] Davis SC, Diegel SW, Boundy RG. Transportation energy databook: Edition 28, ORNL-6984. Oak Ridge: Oak Ridge NationalLaboratory, http://www.ornl.gov/sci/ees/etsd/cta_new/publications.shtml#2009; 2009.

[2] DOE-EERE hydrogen and fuel cells program: http://www.eere.energy.gov/topics/hydrogen_fuel_cells.html.

[3] DOE Hydrogen Analysis Resource Center. Inventory ofcurrent fuel cell and other hydrogen-powered vehicles:http://hydrogen.pnl.gov/cocoon/morf/hydrogen/article/709.

[4] Ahluwalia RK. System level analysis of hydrogen storageoptions. In: DOE Hydrogen Program 2009 annual progress:http://www.hydrogen.energy.gov/pdfs/progress09/iv_e_2_ahluwalia.pdf.

[5] Lasher S. Analysis of hydrogen storagematerials on-boardsystems. In: DOE hydrogen and fuel cell program, http://www.hydrogen.energy.gov/pdfs/progress09/iv_e_1_lasher.pdf; 2009.

[6] Hydrogen Delivery Scenario Analysis Model (HDSAM) V2.2:http://www.hydrogen.energy.gov/docs/hdsam_2_final.xls.

[7] H2A Hydrogen Delivery Infrastructure Analysis Models andConventional Pathway Options Analysis Results: http://www.eere.energy.gov/hydrogenandfuelcells/hydrogen_publications.html#2_general.

[8] University of California, Davis, Institute of TransportationStudies, Hydrogen Pathways Program, Project 3: HydrogenStation Siting Analysis: http//hydrogen.its.ucdavis.edu/research/track2/tr2pr3/view.

[9] Fuel Cell and Hydrogen Energy Association: http://www.fchea.org/index.php?id¼49

[10] Wang, M. GREET 1.5d Transportation Fuel-Cycle Model. ANL/ESD-39. Center for TransportationResearch, ArgonneNationalLaboratory (http://greet.es.anl.gov/publication-20z8ihl0).

[11] DOE H2A Production Analysis: http://www.hydrogen.energy.gov/h2a_production.html.

[12] A Kilogram of hydrogen contains the same amount of energyas a gallon of gasoline (within 2%, depending on the gasolineblend). Thus. a kilogram of hydrogen can be considereda gallon-of-gasoline equivalent (gge).

[13] Nrel Hssim, NREL publication number NREL/PO-540-48120(http://www.nrel.gov/docs/fy10osti/48120.pdf).

[14] U.S. Department of Energy, Office of Energy Efficiency &Renewable Energy, Vehicle Technologies Program,FreedomCAR & Fuel Partnership http://www1.eere.energy.gov/vehiclesandfuels/about/partnerships/freedomcar

[15] U.S. Energy Information Administration. Table 57: TotalUnited States. Online; December 2009: http://www.eia.doe.gov/oiaf/aeo/supplement/stimulus/suparra.htm.

[16] Hua TQ, Ahluwalia RK, Peng J-K, Kromer M, Lasher S,McKenney K, et al. Technical assessment of compressedhydrogen storage tank systems for automotive applications.International Journal of Hydrogen Energy 2011;36:3037e49.

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 6 ( 2 0 1 1 ) 1 4 5 3 4e1 4 5 5 1 14551

[17] DOE hydrogen and fuel cells program plan draft, http://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/program_plan2010.pdf; 2010.

[18] Ahluwalia RK, Hua TQ, Peng J-K, Lasher S, McKenney K,Sinha J, et al. Technical assessment of cryo-compressedhydrogen storage tank systems for automotive applications.International Journal of Hydrogen Energy 2010;35:4171e84.

[19] Calculated from EIA Data: http://www.eia.doe.gov/cneaf/electricity/epm/table1_1.html and http://www.eia.doe.gov/emeu/aer/pecss_diagram.html.

[20] Current. state-of-the-art hydrogen production cost estimateusing water electrolysis, independent review for the DOE,http://www.hydrogen.energy.gov/pdfs/46676.pdf; 2009.

[21] EIA data: http://www.eia.gov/dnav/pet/pet_sum_snd_d_nus_mbbl_a_cur.htm.

Notation,Acronyms, initialisms, andabbreviations

AEO: annual energy outlookAX-21: a specialized carbon material

CcH2: cryo-compressed hydrogenDOE: United States Department of EnergyEIA: United States Energy Information AdministrationEPA: United States Environmental Protection AgencyFCV: fuel cell vehicleGH2: gaseous hydrogenGHG: greenhouse gasGREET: greenhouse gases, regulated emissions, and energy use in

transportation modelH2A: hydrogen analysisHDSAM: hydrogen delivery scenario analysis modelHSSIM: hydrogen storage system simulatorLH2: liquid hydrogenLDV: light-duty passenger vehicleMOF: metal-organic frameworkSMR: steam methane reformingW: watt: unit of power equal to 1 J/sW-d: watt-day: unit of energy equal to 86.4 kJ(If a vehicle storage

system is designed with a heat leakage rate of 4 W, a 12W-d ofdormancy equals 3 days of dormancy.)

WTW: well-to-wheel