A multi-billion-dollar hydrogen industry currently exists in the United States, serving a myriad of hydrogen end-use applications; however, about 99 percent of that hydrogen currently is used in chemical and petrochemical applications. Of the end uses, the largest consumers are oil refineries, ammonia plants, chlor-akali plants, and methanol plants. Some specific examples of hydrogen end use include:

• Petroleum refining—to remove sulfur from crude oil as well as to convert heavy crude oil to lighter products

• Chemical processing—to manufacture ammonia, methanol, chlorine, caustic soda, and hydrogenated non-edible oils for soaps, insulation, plastics, ointments, and other chemicals

• Pharmaceuticals—to produce sorbitol, which is used in cosmetics, adhesives, surfactants, and vitamins

• Metal production and fabrication—to create a protective atmosphere in high-temperature operations, such as stainless steel manufacturing

• Food processing—to hydrogenate oils, such as soybean, fish, cottonseed, and corn oil

• Laboratory research—to conduct research and experimentation

• Electronics—to create a special atmosphere for the production of semiconductor circuits

• Glass manufacturing—to create a protective atmosphere for float glass production

• Power generation—to cool turbo-generators and to protect piping in nuclear reactors.

Stationary Power Systems

Stationary power applications are widely viewed as a critical sector where there may be an opportunity to expand greatly the future use of hydrogen.

A near-term area of demand for fuel cells includes stationary power applications, such as backup power units, power for remote locations, and distributed generation for hospitals, industrial buildings, and small towns. Stationary fuel cell power systems already are commercially viable in settings where the consumer is willing to pay a small price premium for reliable energy, and in remote areas where fossil fuel transportation costs are prohibitive. To date, approximately 600 stationary power systems, each with 10 kilowatts or more capacity, have been built worldwide; and more than 1,000 smaller stationary fuel cells, less than 10 kilowatts, have been installed in homes and as backup power systems.

Comprehensive data on U.S. stationary fuel cell installations are not available, but the following types of stationary fuel cell applications are under development:

• Large cogeneration (combined heat and power) systems are being manufactured for large commercial buildings or industrial sites that require significant amounts of electricity, water heating, space heating, and/or process heat. Fuel cells combined with a heat recovery system can meet some or all of these needs, as well as providing a source of purified water.

• Small, standalone cogeneration systems currently are viable in some areas where the large cost of transmitting power justifies the added cost of a fuel cell. Currently, U.S. companies (such as Plug Power) manufacture small fuel cell systems that are able to produce up to 5 kilowatts of electricity and 9 kilowatts of thermal energy. The excess heat can be used for water or space heating to further reduce the site’s electrical energy use.

• Uninterruptible power supply (UPS) systems, in which fuel cells are used as backup power supplies if the primary power system fails, are one of the fastest growth areas for stationary fuel cell technologies. UPS systems often are used in important services, such as telecommunications, banking, hospitals, and military applications. Battery systems have been used for many years to provide backup power to essential services; however, the battery output time is relatively short. In contrast, fuel cells with refillable fuel storage systems can provide power for as long as required during a blackout.

• Home energy stations are another variant of small, standalone cogeneration systems. They use either reformers or electrolyzers to produce hydrogen fuel for personal vehicles, and they also incorporate a hydrogen fuel cell that can provide heat and electricity for the home. One advantage of the stations is that they offer enhanced utilization of the hydrogen gas, i.e., higher capacity factors for the hydrogen production unit, and therefore help to defray some of the overall cost of the hydrogen refueling station. Appliance-sized home energy stations are undergoing development by several automobile manufacturers as a potential alternative to commercial refueling stations.

Source: U.S. Energy Information Administration

Because hydrogen gas has such a low density, and because the energy requirements for hydrogen liquefaction are high, efficient hydrogen storage generally is considered to be among the most challenging issues facing the hydrogen economy. For current chemical applications, storage issues are not so critical, because the large producers of hydrogen both generate and consume the gas simultaneously on site, thereby reducing storage and distribution requirements significantly.

Stationary Storage Systems

Very large quantities of hydrogen can be stored as a compressed gas in geological formations such as salt caverns or deep saline aquifers. There are two existing underground hydrogen storage sites in the United States. In addition, the co-storage of hydrogen with natural gas has been proposed. There are 417 locations in the United States where natural gas is currently stored in rock caverns, salt domes, aquifers, abandoned mines, and oil/gas fields, with a total storage capacity exceeding 3,600,000 million cubic feet. Hydrogen stored in salt caverns has the best injection and withdrawal properties.

Source: U.S. Energy Information Administration

Centrally produced hydrogen must be transported to markets. The development of a large hydrogen transmission and distribution infrastructure is a key challenge to be faced if the United States is to move toward a hydrogen economy. A variety of hydrogen transmission and distribution methods are likely to be used. Larger industrial users rely on pipelines and compressors to move the hydrogen gas.

Pipeline Systems

Currently, more than 99 percent of all the hydrogen gas transported in the United States is transported by pipeline as a compressed gas. Pipeline transmission of hydrogen dates back to the late 1930s. The pipelines that carry hydrogen generally have operated at pressures less than 1,000 pounds per square inch (psi), with a good safety record. As of 2006, the U.S. hydrogen pipeline network totaled over 1,200 miles in length, excluding on-site and in-plant hydrogen piping More than 93 percent of the U.S. hydrogen pipeline infrastructure is located in just two States, Texas and Louisiana, where large chemical users of hydrogen, such as refineries and ammonia and methanol plants, are concentrated.

The existing U.S. hydrogen pipeline network is only one-third of 1 percent of the natural gas network in length and has less than 200 delivery points. Also, because of concerns over potential leakage, the hydrogen pipes tend to be much smaller in diameter and have fewer interconnections. Special positive displacement compressors are also required to move hydrogen through the pipelines. The length of hydrogen gas piping tends to be short, because it is usually less expensive to transport the hydrogen feedstock, such as natural gas, through the existing pipeline network than to move the hydrogen itself through new piping systems. Historically, welded hydrogen pipelines have been relatively expensive to construct (approximately $1.2 million per transmission mile and $0.3 million per distribution mile). Consequently, the pipelines have required a high utilization rate to justify their initial capital costs. More recently, polyethylene sleeves and tubing systems have emerged as a possible low-cost alternative solution for new hydrogen distribution systems, with total capital investments for transmission piping potentially dropping to just under $0.5 million per mile (in 2005 dollars) by 2017 and with commensurately lower costs for distribution lines.

How a centralized hydrogen transmission and distribution system will evolve is unknown, and therefore the costs cannot be estimated with a high degree of confidence. The costs will depend on where the pipelines are sited, rights-of-way, pipeline diameter, quality and nature of the pipeline materials required to address the special properties of hydrogen, operating pressures, contractual arrangements with hydrogen distributors, financing and loan guarantees, the locations of dispensing stations relative to distributors, and how applicable environmental and safety issues in the production, transmission, distribution, and dispensing of hydrogen are addressed. Because all hydrogen gas has to be manufactured, hydrogen production facilities may be located in ways that minimize overall production and delivery costs.

Liquid Hydrogen (Cryogenic) Transport

Hydrogen can be cooled and liquefied in order to increase its storage density and lower its delivery cost. There are currently four liquid hydrogen suppliers and seven production plants in the United States with a total production capacity of about 76,495 metric tons per day. Those facilities support about 10,000 to 20,000 bulk shipments of liquid hydrogen per year to more than 300 locations. Most long-distance transfers of hydrogen use large cryogenic barges, tanker trucks, and railcars to transport the liquid hydrogen. NASA is the largest consumer of liquid hydrogen. The chief constraints to widespread use of this hydrogen transportation mode relate to the energy losses associated with liquefying hydrogen and the storage losses associated with boil-off.

Compressed Hydrogen Gas Cylinders

Hydrogen is also distributed in high-pressure compressed gas “tube trailer” trucks and cylinder bottles. This delivery method is relatively expensive, and typically it is limited to small quantities and distances of less than 200 miles.

Alternative Chemical Carriers

Hydrogen also can be transported using hydrogen-rich carrier compounds, such as ethanol, methanol, gasoline, and ammonia. Such carriers offer lower transportation costs, because they are liquids at room temperature and usually are easier to handle than cryogenic hydrogen; however, they also require an extra transformation step, with costs that must be weighed against the cost savings associated with transporting low-pressure liquids. Hydrogen carriers such as methanol and ammonia may also present some additional safety and handling challenges.

Hydrogen Fuel Distribution

The most economical methods for distributing hydrogen depend on the quantities and distances involved. For distribution of large volumes of hydrogen at high utilization rates, pipeline delivery is almost always cheaper than other methods—except in the case of long-distance transportation, e.g., over an ocean, in which case liquid hydrogen transport is cheaper.

Source: U.S. Energy Information Administration

Hydrogen production processes can be classified generally as those using fossil or renewable (biomass) feedstocks and electricity. The technology options for fossil fuels include reforming, primarily of natural gas in “on-purpose” hydrogen production plants, and production of hydrogen as a byproduct in the petroleum refining process. Electrolysis processes using grid or dedicated energy sources, including some advanced techniques that have not yet been proven, also can be used.

On-Purpose Hydrogen Production Technologies

The on-purpose hydrogen production technologies are reforming, partial oxidation (including gasification), and electrolysis. Each process has its own advantages and disadvantages with respect to capital costs, efficiency, life-cycle emissions, and technological progress.

Electrolysis, or water splitting, uses energy to split water molecules into their basic constituents of hydrogen and oxygen. The energy for the electrolysis reaction can be supplied in the form of either heat or electricity. Large-scale electrolysis of brine (saltwater) has been commercialized for chemical applications. Some small-scale electrolysis systems also supply hydrogen for high-purity chemical applications, although for most medium- and small-scale applications of hydrogen fuels, electrolysis is cost-prohibitive.

One drawback with all hydrogen production processes is that there is a net energy loss associated with hydrogen production, with the losses from electrolysis technologies being among the largest. The laws of energy conservation dictate that the total amount of energy recovered from the recombination of hydrogen and oxygen must always be less than the amount of energy required to split the original water molecule. For electrolysis, the efficiency of converting electricity to hydrogen is 60 to 63 percent. To the extent that electricity production itself involves large transformation losses, however, the efficiency of hydrogen production through electrolysis relative to the primary energy content of the fuel input to generation would be significantly lower.

Economics of Hydrogen Production Technologies

The economics of hydrogen production depend on the underlying efficiency of the technology employed, the current state of its development (i.e., early stage, developmental, mature, etc.), the scale of the plant, its annual utilization, and the cost of its feedstock.

Electrolysis technologies suffer from a combination of higher capital costs, lower conversion efficiency, and a generally higher feedstock cost when the required electricity input is considered. A distributed electrolysis unit using grid-supplied electricity is estimated to have a production cost of $6.77 per kilogram of hydrogen when the assumed 70-percent capacity factor is considered. A central electrolysis unit operating at 90-percent capacity factor, with 30 percent of the power requirements coming from wind and 70 percent from the grid, is estimated to have a production cost roughly 15 percent higher than that of a distributed SMR plant.

Because electrolysis technologies generally have higher capital and operating and maintenance costs, the implied price for electricity would have to be lower to achieve cost parity with a fossil or biomass feedstock.

Source: U.S. Energy Information Administration

Hydrogen is the most abundant element in the universe. Yet, there is effectively no natural hydrogen gas resource on Earth. Hydrogen gas is the smallest and lightest of all molecules. When released, it quickly rises to the upper atmosphere and dissipates, leaving virtually no hydrogen gas on the Earth’s surface. Because hydrogen gas must be manufactured from feedstocks that contain hydrogen compounds, it is considered to be an energy carrier, like electricity, rather than a primary energy resource.

Currently, the main sources of hydrogen are hydrocarbon feedstocks such as natural gas, coal, and petroleum; however, some of those feedstocks also produce CO2. Thus, to provide overall emission savings, greenhouse gas (GHG) emissions must be mitigated during hydrogen production through CCS (carbon capture and storage) or similar technology, during end use through comparatively greater vehicle efficiency, or at other stages in the life cycle of the hydrogen fuel source. It is generally recognized that demand is not static and the accessibility of resources may be problematic. Also, the costs for addressing CO2 and other GHG emissions may increase, which could deter the full utilization of fossil fuels as a primary energy source for a hydrogen economy unless suitable mitigation measures are employed.

Another source for hydrogen production is electrolysis of water. For decades, the National Aeronautics and Space Administration (NASA) has used this process in hydrogen fuel cells to produce both power and water for its astronauts in space. However, hydrogen production from conventional grid-based electricity is an expensive process, as discussed below, and at present it is the least carbon-neutral method for hydrogen production, given that more than 49 percent of U.S. electricity generation in 2007 was from coal-fired power plants. Reducing costs and emission impacts may be achievable through the application of CO2 mitigation measures for existing electricity generation technologies or through breakthroughs in advanced electrolysis technologies.

The construction of new renewable generation capacity for the exclusive purpose of producing hydrogen from electrolysis is unlikely to be desirable from an investment perspective if, in order to make the resulting hydrogen competitive, the cost of the electricity is required to be less than the wholesale price at which that electricity could be sold to the grid.

Under a CO2-constrained scenario, large amounts of existing coal-fired capacity are likely to be retired, and new nuclear and renewable generators are likely to be added, to meet the CO2 emissions target. Because a CO2-constrained scenario is defined by policies that achieve a targeted level of CO2 emission reductions, any grid-based power production would already have those target CO2 emission levels factored into prices, with wind, biomass, and other power sources having been rewarded for their contributions, and higher CO2-emitting technologies having been penalized, as appropriate.

Source: U.S. Energy Information Administration