These tables summarize the U.S. Department of Energy (DOE) cost and performance targets for major hydrogen delivery process technologies: pressurized containment (for stationary and transport operations), pressurization (compression and pumping), and liquefaction.
More information about targets can be found in the Hydrogen Delivery section of the Fuel Cell Technologies Office's Multi-Year Research, Development, and Demonstration Plan.
Cost Targets for Hydrogen Delivery a
|Category||FY 2011 Status bb||FY 2015 Status||FY 2020 Target||Ultimate Target cc|
|Delivery costs associated with distributed H2 production aa|
|Aggregate fueling station cost ($/gge)||2.50||2.19||2.15||<1.70|
|Delivery costs associated with centralized H2 production aa|
|Aggregate cost of transport, distribution, and fueling ($/gge)||3.60–4.40||3.35–4.35||2.00||<2.00|
Technical Targets for Hydrogen Delivery Components a
|Category||FY 2011 Status bb||FY 2015 Status||FY 2020 Target||Ultimate Target cc|
|Gaseous Hydrogen Delivery|
|Total capital investment ($/mile for an 8-in. diameter equivalent pipeline) [excluding right-of-way] b||765,000||765,000||695,000||520,000|
|Transmission pressure c (bar)||70||70||100||120|
|H2 leakage (% of hydrogen transported) d||–||<0.5%||<0.5%||<0.5%|
|Lifetime e (years)||–||–||50||50|
|Pipelines: Distribution: Trunk and Service Lines|
|Total capital investment ($/mile for a 1-in. pipeline) [excluding right-of-way] f||440,000||355,000||230,000||140,000|
|Distribution pressure g (bar)||40||100||100||120|
|H2 leakage (% of hydrogen transported) h||–||0.02%||0.02%||≤0.02%|
|Lifetime e (years)||–||–||50||50|
|Pipeline, Terminal, and Geologic Storage Compressors (~200,000 kg H2/day peak flow, 20-bar inlet)|
|Compressor specific energy (kWh/kg) i||Undefined||0.82||0.82||0.84|
|Discharge pressure (bar)||Undefined||100||100||120|
|Uninstalled capital cost ($) j (200,000 kg/day)||5.4 million||5.5 million||3.6 million||1.8 million|
|Losses (% of H2 throughput) k||0.5%||0.5%||0.5%||<0.5%|
|Annual maintenance cost (% of installed capital cost) m||4%||6%||4%||2%|
|Lifetime (years) dd||–||–||15||15|
|Tube Trailer Terminal Truck Refueling Compressors (~300 kg H2/h peak flow, 100-bar input) n|
|Compressor specific energy (kWh/kg)||–||1.1||1.1||N/A|
|Discharge pressure (bar)||–||550||550||N/A|
|Uninstalled capital cost ($)||–||250,000||450,000||N/A|
|Losses (% of H2 throughput)||–||0.5%||0.5%||N/A|
|Annual maintenance cost (% of installed capital cost)||–||10%||2%||N/A|
|Lifetime dd (years)||–||–||15||>15|
|Small Compressors: Fueling Sites (~100 kg H2/h peak flow)|
|Compressor specific energy (kWh/kg) p||2.8||100-bar pipeline delivery: 1.6|
250-bar tube trailer delivery: 1.5
|100-bar pipeline delivery: 1.6|
500-bar tube trailer delivery: 1.4
|120-bar pipeline delivery: 1.4|
|Losses (% of H2 throughput)k||0.5%||0.5%||0.5%||<0.5%|
|Uninstalled capital cost ($) (based on 750 kg/day station [~100 kg H2/h peak compressor flow])q||675,000|
(three compressors at $225,000 each;
two at 50% throughput each, and one backup)
|100-bar pipeline delivery: 275,000|
(three compressors, no backup)
250-bar tube trailer delivery: 250,000
(one compressor, one backup)
|100-bar pipeline delivery: 275,000|
500-bar tube trailer delivery: 90,000
(one compressor, no backup)
|120-bar pipeline delivery: 170,000|
(one compressor, no backup)
|Annual maintenance r (% of installed capital cost)||4%||8%||4%||2%|
|Outlet pressure capability (bar) s||860||950||950||950|
|Lifetime (years) ee||–||–||10||>10|
|Stationary Gaseous Hydrogen Storage Tanks t|
|Low Pressure (160 bar)|
|Purchased capital cost ($/kg of H2 stored)||1,000||850||500||450|
|Corresponding tank size (kg)||–||25||710||400|
|Moderate Pressure (430 bar)|
|Purchased capital cost ($/kg of H2 stored)||1,100||1,100||600||600|
|Corresponding tank size (kg)||–||22||65||65|
|High Pressure (925 bar)|
|Purchased capital cost ($/kg of H2 stored) ll||1,450||2,000||600||600|
|Corresponding tank size (kg)||–||16||65||65|
|Lifetime of high pressure vessels ff (years)||–||30||30||>30|
|Gaseous Tube Trailers u|
|Payload (kg of H2)||560||720||1,100||N/A|
|Operating pressure capability (bar)||250||250||500||N/A|
|Purchased capital cost ($/kg of payload)||930||720||600||N/A|
|Lifetimeg g (years)||–||30||30||>30|
|Geologic Storage v|
|Installed capital cost w ($)||equal to natural gas caverns||16 million||8 million||5 million|
|Liquid Hydrogen Delivery|
|Small-Scale Liquefaction (30,000 kg H2/day) x|
|Installed capital cost ($) y||54 million||70 million||70 million||–|
|Energy required (kWh/kg of H2) z||10||15||12||–|
|Large-Scale Liquefaction (300,000 kg H2/day) x|
|Installed capital cost ($) y||186 million||560 million||560 million||142 million|
|Energy required (kWh/kg of H2) z||8||12||11||6.0|
|Liquid Hydrogen Storage Tank (3,500 m3 tank)|
|Uninstalled capital cost ($)||–||6.6 million||6.6 million||3.3 million|
|Liquid Hydrogen Tank Trailers hh|
|Payload (kg hydrogen)||–||4,554||4,554||5,250|
|Purchased capital cost ($/kg of payload)||–||190||190||70|
|Lifetime (years) ii||–||30||30||>30|
|Liquid H2 Pumps (Terminals and Fueling) jj|
|Uninstalled capital cost ($) (<5 bar, 1,720 kg/h)||–||80,000||70,000||57,000|
|Uninstalled capital cost ($) (430 bar, 100 kg/h)||100,000||75,000||75,000||65,000|
|Uninstalled capital cost ($) (900 bar, 100 kg/h)||–||650,000||650,000||200,000|
|Specific energy (kWh/kg) (900 bar, 100 kg/h)||–||0.6||0.5||0.5|
|Uninstalled cost/dispenser ($) (1 hose per dispenser)||50,000|
|Refrigeration Equipment (10–15 tons/day) kk|
|Uninstalled capital cost ($)||–||140,000||100,000||70,000|
a All costs in table are in 2007 dollars to be consistent with EERE planning, which uses the energy costs from the Annual Energy Outlook 2009. These costs also assume a high-volume market.
b Pipeline capital costs: The 2011 and 2015 costs are from HDSAM V2.3. (See more details on the HDSAM.) The model assumes that a hydrogen pipeline costs 10% more to construct than a natural gas pipeline of the same diameter and length. The costs of natural gas pipelines are determined from analyses of historical construction costs published by Brown et al. ("National Lab Uses OGJ Data to Develop Cost Equations," Oil & Gas Journal, D. Brown, J. Cabe, and T. Stout, Jan. 3, 2011). It is important to note that construction costs do vary widely throughout the entire country, and the Brown et al. publication does have region-specific cost analyses. HDSAM V2.3 and the pipeline capital cost target in the Multi-Year Research, Development, and Demonstration (MYRD&D) plan are based on the analyses that corresponded to the entire country (rather than any particular region), however, and were vetted with industry consultation. The assumption of a 10% premium for hydrogen lines was based on discussions with industrial gas companies that build and operate the current system of hydrogen pipelines in the United States. Right-of-way costs have been excluded from the target, because they vary widely and are not a technical characteristic of the technology. They are, however, included in the top-down analysis that drives targets for the pipeline pathway.
c The 2015 status of transmission pressure is based on the maximum operating pressure of hydrogen pipelines as of March 2015. Find more information. The 2020 target is set to lower compression requirements at the forecourt.
d Hydrogen leakage is hydrogen that permeates or leaks from fittings, etc., as a percent of the amount of hydrogen carried by the pipeline. The 2015 status and future targets are based on industry consultation, along with the assumption that leak rates from hydrogen pipelines will be no higher than those from current natural gas pipeline infrastructure. Leak rates for the natural gas pipeline infrastructure were taken from ANL's GREET model. The values in GREET are based primarily on the Environmental Protection Agency's 2013 Inventory of Greenhouse Gas Emissions and Sinks. View the publication details.
e Pipeline lifetime refers to the minimum time period that the pipeline must remain in service to justify the capital cost of its installation. The 2020 and ultimate targets are intended to be at least equivalent to that of natural gas pipeline infrastructure. The actual life of a pipeline can exceed its design life.
f The 2011 status for distribution pipelines was based on the lines being built out of steel and their construction costs being 10% higher than those of natural gas pipelines. The costs of natural gas pipelines were taken from HDSAM V2.3 and are detailed further in Footnote b. The 2015 status and future targets are based on distribution pipelines being built out of fiber-reinforced composite material. Industry consultations were used to derive the cost of FRP pipelines in 2015.
g The 2015 distribution pressure is based on the current rating of fiber-reinforced composite pipe. The ultimate target has been set to enable the pipeline delivery pathway to meet its ultimate cost target.
h The leak rate refers to hydrogen losses through the pipeline material and/or fittings. The 2011 status was based on the use of steel for pipeline construction, while the current status and future targets are based on the use of fiber-reinforced composite piping (FRP). The values of permeation rates through FRP liners and joints were derived from experimentation conducted on FRP at SRNL in 2009. Some of these results can be seen in their 2009 Annual Merit Review presentation.
i Compressor specific energy: In the 2012 version of the MYRD&D plan, the energy consumption of compressors was characterized by their isentropic efficiency, which was about 88% for large reciprocating compressors used for hydrogen. In 2015, this metric was changed to represent energy consumption for every unit of hydrogen compressed (kWh/kg) at the specified inlet pressures, discharge pressures, and capacities. The current metric characterizes the isentropic efficiency, losses, motor efficiency, and motor size of a large compressor. The 2015 status is based on the expected performance of a centrifugal compression technology funded by DOE from 2008–2014.
j Large compressor capital cost: The 2011 cost status was based on HDSAM V2.3. HDSAM V2.3 contains algorithms that can estimate a compressor's cost as a function of its motor size. These algorithms were derived from cost data supplied by various vendors for two- and three-stage reciprocating compressors. The 2015 status is based on the projected capital cost of centrifugal compression technology funded by DOE from 2008–2014. The 2011 cost status is lower than the 2015 cost status because it was a projection for a hypothetical technology, and because it assumed reciprocating compression rather than centrifugal compression. HDSAM V2.3 had been used to estimate the motor power that a reciprocating compressor of the specified size (200,000 kg/day from 20 bar to 100 bar) would require, and to then estimate the compressor cost corresponding to that power; the 2011 cost status was not based on a commercially available compressor. The 2015 status is instead based on cost projections for an existing centrifugal design, which is likely to be preferable to reciprocating compression because of better reliability. The 2020 and ultimate targets are based on cost reductions that would be necessary to achieve overall delivery cost objectives.
k Losses: Hydrogen can leak through compressor seals. The 2015 status of leak rate was based on typical ratings of hydrogen compressor seals. Future targets are set to ensure leak rates do not exceed the current status.
l Large compressor reliability: The 2011 status was based on the use of redundant reciprocating compression, which faces reliability issues due to the large number of moving parts. It was assumed that three compressors, each rated at 50% of the system flow, would be necessary to ensure reliable pipeline operation. The 2015 status is based on a reliability analysis that was completed by Concepts NREC for a novel centrifugal compression technology they designed and tested with DOE funding between 2008 and 2014. The analysis estimated their compressor's availability based on typical failure rates of its components. The 2020 and Ultimate targets are based on reliability remaining high enough that each compressor requires only one redundancy.
m Annual maintenance: The 2015 maintenance cost status was derived from a reliability analysis completed by Concepts NREC for the 240,000 kg/day centrifugal compressor they designed with DOE funding from 2008–2014. The study indicated that the Concepts compressor has a maintenance cost of about $0.005/kWh (as indicated in their 2014 Annual Merit Review presentation). HDSAM V2.3 was used to determine the kWh the compressor would consume in a year. In the past, DOE also set targets for the contamination potential of compressors. It is now assumed that any compressor that meets DOE targets will not add contaminants to the hydrogen fuel. The 2011 maintenance status was based on a review of delivery technologies completed by Nexant, Inc., in conjunction with several national laboratories, industrial gas companies, and technology research companies and assumed reciprocating compression rather than centrifugal compression. While the 2015 maintenance cost status is greater than that for 2011, it is believed to be more accurate because it is based on a detailed review of a specific technology.
n Tube trailer terminals large enough to serve a mature FCEV market (~70,000 kg/day) do not presently exist. Such terminals would likely be located near production plants and require storage capacity (at about 100 bar) to buffer differences between production rates and rates of trailer filling. Compressors in 2015 do not have sufficient capacity to meet the needs of a terminal in a mature market. The 2020 target is based on the capacity that would be necessary to satisfy the truck refueling needs of a terminal in a mature market with about 20 compressors in parallel and 5 redundant compressors.
o Fueling compressor reliability: The primary compressors being demonstrated for refueling station service are reciprocating, diaphragm, and ionic liquid technologies. The reliability of compression depends on the technology used. Diaphragm compressors typically have better availability than reciprocating compressors but lower capacity. Because three compressors have been assumed to be necessary in 2015 to meet the flow requirements of a 1,000 kg/day station supplied by pipeline, it is assumed that these compressors will also enable redundancy; a station would be able to operate at reduced capacity if one of its compressors failed. In the tube trailer pathway, only one compressor is necessary to satisfy flow requirements, and it is therefore assumed that a redundant compressor will be necessary. The future targets are based on reliability improving enough that redundant compression is not necessary.
p Compressor specific energy: In the 2012 version of the MYRD&D plan, the energy consumption of compressors was characterized by the isentropic efficiency, which was about 65% for hydrogen refueling station compressors. In 2015, this metric was changed to represent energy consumption for every unit of hydrogen compressed (kWh/kg). The current metric characterizes the isentropic efficiencies, losses, motor efficiencies, and motor sizes of the compressor(s) being employed to meet the specified throughput (100 kg/hour) at the specified suction and discharge pressures. The efficiencies differ depending on the delivery mode (pipeline or tube trailer) because the mode determines the compressor's suction pressure. It is assumed that a tube trailer's minimum delivery pressure (before it is returned to the tube trailer terminal) is 15 bar, and that the tube trailer consolidation strategy is implemented in the case of tube trailer delivery. Implementation of the consolidation strategy lowers the size of the compressor (in terms of throughput) necessary at the station.
q Fueling compressor capital cost: The 2011 and 2015 capital costs are modeled using correlations between motor size and compressor cost derived at ANL. The costs vary depending on the mode of delivery (pipeline or tube trailer) because the delivery mode determines the compressor's suction pressure, which determines the size of compressor necessary to meet the station's demand; the motor power requirement and throughput are both impacted by suction pressure. It is assumed that a tube trailer's minimum delivery pressure (before it is returned to the tube trailer terminal) is 15 bar, and that the tube trailer consolidation strategy is implemented in the case of tube trailer delivery. Implementation of the consolidation strategy lowers the size of the compressor (in terms of throughput) necessary at the station.
r Annual maintenance: This target refers to the cost of parts and labor associated with annual maintenance activities, including inspection and parts replacement. The 2011 maintenance status was based on a review of delivery technologies completed by Nexant, Inc., in conjunction with several national laboratories, industrial gas companies, and technology research companies. The 2015 maintenance status was based on more recent consultation with industrial experts on reciprocating hydrogen compression. The reason for the increase in estimated maintenance cost between 2011 and 2015 is an improved understanding of compression technologies. Additionally, the current version of the MYRD&D assumes that any compressor that meets DOE targets will not add contaminants to the hydrogen fuel; in the past, DOE also set targets for the contamination potential of compressors.
s Fueling hydrogen fill pressure: Light-duty FCEVs rolled out by original equipment manufacturers in the 2015 time frame will require 700-bar fills for full vehicle range, which in turn requires station compression capability of 950 bar. This is already being demonstrated at some fueling sites. The long-term goal of DOE is to develop solid or liquid carrier or other systems for vehicle storage tanks that allow for at least 300 miles of driving between refueling with more modest pressure storage (<500-bar psi). DOE has set targets that include 700-bar fills to allow for the introduction of hydrogen FCEVs with high-pressure vehicle gas storage technology prior to achieving commercialization of the ultimate goal of lower pressure vehicle storage technology.
t Stationary gaseous storage tank capital costs: Several different pressures are likely for stationary storage purposes in a hydrogen delivery infrastructure. Low-pressure storage will be necessary at terminals and fueling stations supplied by pipelines. Moderate pressure storage will be necessary at 350-bar refueling stations, and high-pressure storage will be necessary at 700-bar refueling stations. The 2015 and 2011 statuses represent the packaged cost of standard steel and composite tanks, including the costs of paint, cleaning, and mounting necessary to transport the tanks; this cost does not, however, include installation at the final destination. Because the cost of storage is highly dependent on the tank size, each of the costs in the Target Table corresponds to a specific tank size. The ultimate target for tank size is smaller in order to create a more aggressive target on a $/kg stored basis.
u Gaseous tube trailers: The 2015 status of gaseous tube trailer characteristics and costs are based on tube trailers that were developed with Office funding from 2008–2014. The key targets are hydrogen capacity and tube trailer capital cost; while higher pressure tube trailers are available on the market, it is unknown whether they have higher capacities or lower costs than those described. The 2020 cost targets are set to achieve the overall delivery cost objectives. There are several possible technology approaches to achieve these 2020 targets. It may be possible to develop more cost-effective composite structures to increase the working pressure of gaseous tube trailers. The pressures in the Target Table are based on the pressure required to achieve the targeted hydrogen capacity. The costs provided only characterize the storage vessels themselves, and not the chassis, truck, or any other ancillary equipment used to transport the vessels.
v Geologic storage: Transportation vehicle fuel demand is significantly higher in the summer than in the winter. To handle this demand surge in the summer without building prohibitively expensive excess production capacity, there will need to be significant hydrogen storage capacity within the hydrogen delivery system. Geologic storage is a very cost-effective storage method for these types of demand swings and is used very effectively for similar demand swings for natural gas. There are only a few currently operating geologic storage sites for hydrogen in the world (in Texas and one in Teeside, England). Greater knowledge needs to be developed on the availability of hydrogen geologic storage sites. Technology development may also be required to ensure suitability for hydrogen.
w Geologic cavern capital cost: The current cost corresponds to a salt cavern with about 1,110 tonnes of working gas, the capacity required to meet the long-term storage needs of a city with a population of about 1 million, and about 15% market penetration of FCEVs; HDSAM V2.3 was used to determine the capacity required. The current cost was extrapolated from a study of geologic storage of gaseous hydrogen published by SNL in 2014. While salt caverns are in use for both natural gas and hydrogen storage, their use is limited to regions of the country with salt deposits. Salt deposits in the United States are located primarily in the central region of the country. Lined hard rock caverns also have the potential to meet long-term storage requirements, and also allow for multiple cycles per year while minimizing the risk of leakage or contamination. They do, however, require a capital investment estimated to be about two to four times greater than that of salt caverns. Geologies along the U.S. East Coast would allow for the development of hard rock caverns, but their potential in California has not yet been assessed. The only commercial lined hard rock cavern in existence is in Sweden. For more details, see "Geologic Storage of Hydrogen: Scaling up to Meet City Transportation Demands," International Journal of Hydrogen Energy 39 (2014), A.S. Lord, P.H. Kobos, G.T. Klise, and D.J. Borns, pp. 15570–15582, and Commercial Potential of Natural Gas Storage in Lined Rock Caverns (LRC).
x The terms "small-scale" and "large-scale" characterize the capacities that would be necessary to serve small and large FCEV markets. A 30,000 kg/day liquefier would satisfy a market penetration of about 3%, while a 300,000 kg/day liquefier would satisfy a market penetration of about 30% in a city with a population of about 1 million.
y Liquefaction installed capital: The 2011 status cost is based on HDSAM V2.3, which uses a correlation as a function of capacity derived from information obtained from industrial gas companies and other sources. The 2015 and 2020 values are based on more recent consultations with industry. These costs only characterize liquefaction equipment (compressors, heat exchangers, expanders, etc.), and not any associated storage.
z Liquefaction energy use: The 2011 status energy requirements are based on HDSAM V2.3, which uses a correlation as a function of capacity derived from information obtained from industrial gas companies and other sources. The 2015 and 2020 values are based on more recent consultations with industry. The ultimate target is based on an innovative liquefaction design created as part of the European Union's IDEALHY project from 2011–2013. The design assumes a feed pressure of 80 bar. Find more details.
aa Costs associated with distributed production refer to an apportionment of the costs required to capitalize, build, and operate a fueling station that are directly attributable to non-production operations, namely gas compression, on-site gas storage (to account for daily and weekly variations in demand), and gas dispensing. Costs associated with centralized production account for the above station costs as well as those required in transmitting the hydrogen from the production facility to the fueling station. Note that station costs associated with distributed production are somewhat higher than those for centralized production. This is because the former requires a higher level of on-site storage to account for seasonal variations in fueling demand. Seasonal variations for the latter are accounted for via geologic and/or terminal storage. The apportionment between the fueling station cost and the transport and delivery cost is presented in Program record 12001. H2A was used to determine the cost of distributed production in 2015, assuming the fueling station is designed for dispensing of 1,000 kg/day and is fully utilized.
bb "2011 Status" numbers were retained in the 2015 update to this MYRD&D section to show the differences between 2011 and 2015.
cc Ultimate targets are based on a well-established hydrogen market demand for transportation (15% market penetration). The specific scenario examined assumes central production of hydrogen that serves a city of moderately large size (population: ~1M) and that the fueling station average dispensing rate is 1,000 kg/day.
dd The compressor lifetime assumes that routine maintenance is performed, such as replacement of seals and valves. The lifetime for pipeline compressors also assumes relatively continuous operation, with few starts and stops during a year. The 2015 statuses are unknown because few compressors are currently in operation in high-volume pipeline or tube trailer filling applications. The 2020 and ultimate targets have been set based on the lifetimes that are expected to be achievable given the technology currently available as well as the replacement frequencies that would enable hydrogen delivery and dispensing by pipeline to meet DOE's ultimate cost target.
ee The compressor lifetime assumes that routine maintenance is performed on the compressor, such as replacement of seals and valves, at the service intervals specified by the manufacturer. The 2015 status is unknown because fueling station compressors have not yet been in operation for a substantial amount of time, and operators are still learning how to properly maintain this equipment; achievement of the compressor's design life is highly dependent on proper operation and maintenance. The 2020 and ultimate targets are based on the lifetimes that are expected to be achievable given compressors currently used at natural gas stations as well as the replacement frequencies that would enable hydrogen delivery and dispensing to meet DOE's ultimate cost targets.
ff The lifetime status and targets are based on Type II vessels used for high-pressure (925-bar) storage, assuming routine maintenance is conducted. Storage at lower pressures (160 bar and 430 bar) can utilize Type I vessels, which are expected to last at least as long as Type II vessels. However, the impact of fatigue cycles seen at hydrogen stations on the lifetimes of storage vessels is still being assessed.
gg The lifetime corresponds to the maximum life that Type IV transportation vessels are currently permitted for by the DOT in CNG service. This service life corresponds to the number of deep cycles these vessels can withstand prior to leaking and/or bursting. Additional research is currently underway regarding the impact of deep fatigue cycles on Type IV vessels in hydrogen storage.
hh Liquid hydrogen tank trailers: The cost targets for this category refer only to the cost of the liquid hydrogen storage aboard a tank trailer, not the associated chassis or truck. The design of these tanks is similar to that of stationary storage but must additionally comply with DOT regulations. The 2015 status is based on consultation with industrial gas manufacturers.
ii The trailer lifetime assumes that they undergo inspections approximately every 5 years and refurbishing every 10 years.
jj Liquid hydrogen pumps: The 2011 and 2015 statuses are based on delivery of liquid hydrogen to refueling stations where it is stored in a cryogenic tank, pumped to an evaporator, and then charged to vehicles with the aid of a cascade charging vessel system. The pump costs are based on information from developers that currently manufacture this technology.
kk The refrigeration equipment constitutes a chiller and a heat exchanger that bring the temperature of hydrogen to -40ºC before it reaches the dispenser. It is assumed that one chiller and one heat exchanger will be necessary for each dispenser. The capacity of the refrigeration equipment (10–15 tons/day) describes the amount of heat the unit can remove in a day, not the tons of hydrogen it can cool in one day. The heat-removal capabilities of refrigeration units are commonly described in "tonnes," where the tonnage refers to the mass of ice the unit can freeze in a day.
ll Cost increased from 2011 to 2015 due to an improved understanding of the pressure vessel market. The 2011 cost status was based on analysis of the pressure vessel manufacturing process and components. Cost estimates were made through consultation with suppliers of pressure vessel manufacturers. The 2015 cost status is instead based on quotations from manufacturers themselves.