xii cost of recompressing the natural gas to the original natural gas pipeline pressure can be avoided. The resulting estimated extraction cost for a 10% concentration and 80% recovery factor is $0.3-$1.3/kg, with the range resulting from economies of scale for a system size or recovery rate of 1,000-100 kg/day (see Figure 18). These costs per kilogram are reduced by approximately 10% if the hydrogen concentration is increased to 20%. PSA extraction could therefore become a relatively small cost component of the total delivered cost of hydrogen if the extraction is done at a pressure-reduction facility. With major pressure reduction stations often located near large urban areas, downstream extraction could prove to be an economical delivery option. It has been estimated that there are 11,200-14,800 metering and pressure regulating stations with inlet pressures greater than 300 psig in the United States (see section 3.1), and 34,600-56,700 stations with inlet pressures between 100 and 300 psig. Approximately 23%-25% of the stations with inlet pressures greater than 300 psig are contained within vaults, which is typical for stations located near urban or suburban areas. Therefore, it is likely that several thousand high-pressure city gate stations are located in close proximity to large U.S. urban areas where natural gas is transferred from transmission lines to distribution lines, and many of these may be candidates for hydrogen extraction.

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online ordering: http://www.ntis.gov/ordering.htm Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste iii Executive SummaryAs renewable electricity becomes a larger portion of the electricity generation mix, new strategies will be required to accommodate fluctuations in energy generation from these sources. One of the primary strategies proposed for integrating large amounts of renewable energy is using energy storage to absorb excess electricity-generating capacity during times of low demand and/or high rates of generation by renewable sources and then reconverting this stored energy into electricity during periods of high demand and/or low renewable generation.Various energy storage technologies have been developed or proposed. The goal of this analysis was to develop a cost survey of the most-promising and/or mature energy storage technologies and compare them with several configurations employing hydrogen as the energy carrier. A simple energy arbitrage scenario was developed for a mid-sized energy storage system consisting of a 300-MWh nominal storage capacity that is charged during off-peak hours (18 hours per day on weekdays and all day on weekends) and discharged at a rate of 50 MW for 6 peak hours on weekdays.For all the hydrogen cases, off-peak and/or excess renewable electricity is used to electrolyze water to produce hydrogen, which is stored in compressed gas tanks or underground geologic formations. The hydrogen is reconverted into electricity using a polymer electrolyte membrane (PEM) fuel cell or hydrogen expansion combustion turbine. The hydrogen storage scenarios are compared with the use of several battery systems (nickel cadmium, sodium sulfur, and vanadium redox), pumped hydro, and compressed air energy storage (CAES).All the energy storage systems are evaluated for the same energy arbitrage scenario using consistent financial and operational assumptions. Costs and performance parameters for the technologies were gathered from literature sources and, in the case of the hydrogen expansion combustion turbine, Aspen Plus modeling. Producing excess hydrogen for use in vehicles or backup power is also evaluated. Two production levels are analyzed: 1,400 kg/day (roughly equivalent to the U.S. Department of Energy's standard model for smallscale distributed hydrogen production) and 12,000 kg/day. As for the purely energy arbitrage scenarios, it is assumed that hydrogen would be produced with offpeak/renewable electricity. Cost results for the analysis are presented in terms of the annualized ("levelized" 1 Figure ES -1 ) cost for producing the energy output from the storage system: electricity fed back onto the grid during peak hours ($/kWh) and, in the case of producing excess hydrogen for vehicles, hydrogen ($/kg).summarizes the comparison of levelized cost of delivered electricity for hydrogen (green bars) and competing technologies (blue bars). For each technology, high-cost, mid-range, and low-cost cases were analyzed, and sensitivity analyses were 1 The leve...

In addition, key cost results presented in this report were provided by a select number of expert stakeholders who devoted significant time and attention to completing the HSCC. Sam Jaffe and Casey Talon of IDC Energy Insights administered implementation of the HSCC. This included compiling and aggregating results received from expert stakeholders, as well as serving as a communication interface between National Renewable Energy Laboratory staff and responding stakeholders to clarify the relevance of the data provided while maintaining the anonymity of respondents. Stakeholder input on opportunities to reduce hydrogen station costs collected during the Hydrogen Infrastructure Market Readiness workshop and a description of the process of administering the HSCC can be found in the workshop proceedings (Melaina, Steward et al. 2012).

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. U.S. Department of Energy (DOE) reports produced after 1991 and a growing number of pre-1991 documents are available free via www.OSTI.gov.Cover Photo by Dennis Schroeder: NREL 46494.NREL prints on paper that contains recycled content.

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Solar and wind energy are being rapidly integrated into electricity grids around the world. As renewables penetration increases beyond 80%, electricity grids will require long-duration energy storage or flexible, low-carbon electricity generation to meet demand and help keep electricity prices low. Here, we evaluate the costs of applicable technologies based on current technology status and future projections. We show which technologies have the lowest costs and identify opportunities for each to help decarbonize the electricity grid.