available technology. Electrolysis, although more expensive than natural gas reformation, offers some unique features as an alternative method:
Since the infrastructure to deliver electricity exists in every corner of the United States, hydrogen can be produced close to or at the point of distribution, thereby minimizing initial capital investments in hydrogen infrastructure.
Unlike the reformation process where natural gas is the sole primary energy source, the energy sources for electricity production are diverse, including fossil fuel such as coal and natural gas; nuclear; and renewable energy, such as hydro, wind, solar and biomass.
The cost of electricity has been and is expected to remain much more stable than natural gas prices due to fuel diversification in the power generation sector. (In specific regions, factors such as regulated-deregulated market and marginal cost of power generation for electrolytic hydrogen production could impact such comparisons.)
Hydrogen produced by electrolysis emits no harmful substances at the point of production, which would be beneficial in environmentally sensitive urban areas. CO2 emissions from power plants would be easier to capture and sequester than those from small natural gas reforming plants.
Continuing progress to clean up power plant criteria and CO2 emissions will ensure that hydrogen produced from electricity in the future will benefit from the increased cleanliness fossil fuel power generation.
As a side benefit, the electrolysis process also produces oxygen that may have a market value.
As explained in Chapter 3, large electrolyzers using alkaline technology (producing more than 500 kg of hydrogen per day (kg/d) constitute a proven, commercially available technology. Smaller electrolyzers, using proton exchange membrane (PEM) technology, require more research, development, and demonstration (RD&D) to improve durability and efficiency and to reduce capital cost. For example, the capital cost per unit of production of a 10 to 100 kg/d PEM electrolyzer is four to seven times that of a 1,500 kg/d unit (EPRI, 2007). These smaller PEM units, if successfully developed, could provide an alternative or complementary approach to natural gas reformation for hydrogen production during the early commercialization stage.
From the power industry’s perspective, the installed generation capacity of any utility is built to meet peak power demand. Thus, a portion of this capacity sits idle during off-peak periods, such as during the night when demand is reduced. This results in cycling of the power plants to respond to time-varying demand. While some plants are explicitly designed for peaking operations (e.g., combustion turbines), others are designed for base load operation (e.g., coal, nuclear). To the extent that base load plants are not used for base load operation, they must be cycled on a daily basis, and this carries a significant “wear-and-tear” cost penalty from cycling them up and down. If that capacity could be used to produce hydrogen during the off-peak period, via electrolysis, power plants could minimize such cycling and hence increase overall capacity factor and asset utilization. If 10 percent of all light-duty vehicles were fueled with hydrogen produced solely from electrolysis off-peak, the U.S. grid could realize an average of 8 percent increase in load factor. However, the electrolyzer plant would operate only about 50 percent of the time, and the increased capital charge per kilogram of hydrogen produced would to some extent offset the reduced power cost.
Today the electrolysis process is only moderately efficient, which makes it applicable only in certain niche markets when high-purity hydrogen is required. However, it would be beneficial to develop more efficient and cost-effective electrolysis technology. Capital cost reduction and improvements in electrolysis efficiency would be very useful, potentially making the economics of electrolysis more competitive with natural gas reformation.
If HFCVs become widespread and hydrogen vehicle penetration increases in the longer term, large central hydrogen production facilities become more viable due to economies of scale. As described in Chapter 3, hydrogen production from coal with carbon capture and sequestration (CCS) could become one plausible way to meet the larger demand.
Integrated gasification-combined cycle (IGCC) power generation technology using coal is being developed, demonstrated, and commercialized. IGCC is more efficient in both power generation and emission control and, hence, could become the preferred alternative to pulverized coal power plants using a conventional combustion process. Furthermore, capturing and storing carbon dioxide (CO2) produced from the coal in geologic formations 5,000 to 10,000 feet under the ground would reduce its impact on climate change, if long-term burial with minimal leakage can be achieved. Essentially complete storage is guaranteed in depleted or partially depleted oil and gas reservoirs, which have demonstrated long-term storage capability by the nature of their past storage capacity. Storage in aquifers, deep coal beds, and other formations is likely but yet to be fully demonstrated. Capturing CO2 involves adding a water-gas-shift reactor to the IGCC process to convert the CO in the synthetic gas to CO2 and hydrogen. CO2 then would be separated from hydrogen, compressed, and sent underground via a pipeline for storage (sequestration), while the nearly pure hydrogen stream could enter a combustion turbine for power generation. The hydrogen produced in this process could be utilized for transportation fuel. This approach allows one to leverage a significantly higher upfront capital investment through the co-production of electricity and hydrogen, thereby making