TABLE 3.1 Dispensed Hydrogen Costs for Distributed Generationa

Process

Future Technology ($/kg)

Current Technology ($/kg)

Natural gas reforming

2.60

3.30

Electrolysis

5.60

7.20

NOTE: Production plant is 1,500 kg/d; natural gas costs $6.10/MBtu; electricity costs $0.08/kWh (see Chapter 6 for other assumptions).

aCosts are at the dispensing nozzle and are derived from the H2A model; they represent the final dispensed hydrogen cost using either technology demonstrated today or with anticipated future improvements and a minimum of 500 installed units.

costs for the main distributed options. Reforming a bioliquid such as ethanol also is possible, although that is in an earlier stage of development (Paster, 2007a). The alternative technologies to natural gas reforming could be useful because they could lead to lower CO2 emissions than natural gas reforming. Electricity for electrolysis could be generated by low-CO2 methods, such as wind power, solar technologies, or nuclear methods. Reforming ethanol or another bioliquid could yield much lower CO2 releases, depending on how the bioliquid is produced. This may become an important distinction depending on future carbon policy and regulations. For example, California currently requires that at least 33 percent of the energy used to produce hydrogen dispensed at state-funded stations be provided from renewable sources.

Late Transition to Self-sustaining Centralized Hydrogen Production

At some point in the hydrogen transition, the drive to increase production and to lower both the cost of hydrogen and the CO2 emissions associated with hydrogen production would shift the emphasis away from distributed production toward very large centralized production plants. This is likely to start between 2025 and 2030 in the MPR case. These central plants could use a variety of primary feedstocks including natural gas, coal, and biomass. In the longer term there could be additional technology options such as hydrogen from high-temperature nuclear and concentrated solar, photobiochemical, and photoelectrochemical methods and from centralized electrolysis using solar or wind energy.

The concept of centralized hydrogen production is very different from today’s centralized refining system for making gasoline, which is characterized by a few very large refining centers. They serve nearby population centers but also feed a large pipeline network for delivering to areas hundreds or thousands of miles away. Gasoline is cheaper to ship by pipeline than hydrogen (on an energy-equivalent basis). As a result, the optimal distribution system for hydrogen would lead to smaller-sized plants located closer to population centers, with few if any long-distance pipelines.

The cost of producing hydrogen at a central plant and delivering it to a station is highly dependent not only on the feedstock cost and conversion technology, but also on the size of a commercial plant and the method and distance of delivering the hydrogen. In a fully developed hydrogen economy, delivery and dispensing of hydrogen could cost as much as its production and consume significant energy.

The first central hydrogen production plants could be needed as early as 2025. With the long lead times needed to plan, permit, and construct large plants, the decisions on what type of feedstock to use would be made about 5 years prior to this. These plants will have to use commercially proven technology. Natural gas reforming and coal gasification technologies are available today. The cost of hydrogen from both feedstocks is similar when feedstock costs are $6 per million British thermal units (Btu) for natural gas and $27 per ton for coal. Twice as much CO2 is produced in a coal-fed plant as one using natural gas. Both types could include CO2 capture technology (at 80 to 90 percent efficiency), which produces a high-purity CO2 stream that can then be sequestered in underground geological formations. Although CO2 capture is a proven technology, CO2 sequestration (i.e., permanent disposal underground) has not yet been adequately demonstrated for commercial readiness.

Biomass gasification for hydrogen production is under development but not commercially ready yet. It is likely that with continued emphasis on development it could be ready for commercial decisions in about 2025. Hydrogen from biomass gasification is more expensive than from natural gas or coal, but the net CO2 releases are very low if land use issues can be kept small (see Chapter 4, “Alternative Technologies for Light-Duty Vehicles”). If CO2 sequestration is not commercially available when central plants are needed, biomass could be an important source of hydrogen that would not contribute to carbon emissions.

Table 3.2 reviews the estimated costs of central hydrogen production. The costs shown in this table are derived

TABLE 3.2 Centralized Plant Gate Hydrogen Production Costs

Process

Future Technology ($/kg)

Current Technology ($/kg)

Natural gas reforming (379 tons/d)

1.50

1.60

Coal gasification (306 tons/d)

1.50

1.90

Biomass gasification (155 tons/d)

1.80

2.50

NOTE: Costs are at the plant gate and represent a learned out cost derived from the H2A model for either technology understood today or with anticipated future improvements. CO2 capture costs are included for coal gasification but not the other technologies. CO2 sequestration costs are not included for any technology. Future delivery and dispensing costs of about $1 to $2/kg (pipeline) or $3.50/kg (liquid) must be added to the production cost for the final delivery cost (Paster, 2007b). Feedstock costs: natural gas $6.10/MBtu; coal $27/ton; biomass $38/ton.



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