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One of the key challenges that still facing the adoption of renewable energy systems is having a powerful energy storage system (ESS) that can store energy at peak production periods and return it back when the demand exceeds the supply. In this paper, we discuss the costs associated with storing excess energy from power grids in the form of hydrogen using proton exchange membrane (PEM) reversible fuel cells (RFC). The PEM-RFC system is designed to have dual functions: (1) to use electricity from the wholesale electricity market when the wholesale price reaches low competitive values, use it to produce hydrogen and then convert it back to electricity when the prices are competitive, and (2) to produce hydrogen at low costs to be used in other applications such as a fuel for fuel cell electric vehicles. The main goal of the model is to minimize the levelized cost of energy storage (LCOS), thus the LCOS is used as the key measure for evaluating this economic point. LCOS in many regions in United States can reach competitive costs, for example lowest LCOS can reach 16.4¢/kWh in Illinois (MISO trading hub) when the threshold wholesale electricity price is set at $25/MWh, and 19.9¢/kWh in Texas (ERCOT trading hub) at threshold price of $20/MWh. Similarly, the levelized cost of hydrogen production shows that hydrogen can be produced at very competitive costs, for example the levelized cost of hydrogen production can reach $2.54/kg-H 2 when using electricity from MISO hub. This value is close to the target set by the U.S. Department of Energy. Levelized cost of energy storage (LCOS) curves for several regions in the United States. Image 1 • A model to calculate the levelized cost of energy storage for reversible fuel cells. • RFC system as energy storage system can increase the resiliency of the power grids. • RFC can be designed to store electricity and produce hydrogen for other uses. • Roundtrip efficiency and capital cost are key factors that shape the LCOS in RFC. [ABSTRACT FROM AUTHOR]

Long-distance road-freight transport emits a large share of Germany's greenhouse gas (GHG) emissions. A potential solution for reducing GHG emissions in this sector is to use green hydrogen in fuel cell electric vehicles (FC-HDV) and establish an accompanying hydrogen refueling station (HRS) network. In this paper, we apply an existing refueling network design model to a HDV-HRS network for Germany until 2050 based on German traffic data for heavy-duty trucks and estimate its costs. Comparing different fuel supply scenarios (pipeline vs. on-site), The on-site scenario results show a network consisting of 137 stations at a cost of 8.38 billion € per year in 2050 (0.40 € per vehicle km), while the centralized scenario with the same amount of stations shows a cheaper cost with 7.25 billion euros per year (0.35 € per vehicle km). The hydrogen cost (LCOH) varies from 5.59 €/kg (pipeline) to 6.47 €/kg (on-site) in 2050. • Assessment of new refueling network design model and its cost for Germany in 2050. • Results show a network consisting of 137 stations. • Cost of an HDV-HRS network for on-site production is 8.38 bn€/a (6.47 €/kgH 2). • Cost of an HDV-HRS network for centralized production is 7.25 bn€/a (5.59 €/kg H 2). • Centralized production needs H 2 pipeline of 5381 km with 0.23 m average diameter. [ABSTRACT FROM AUTHOR]

• Simulated hydrogen (H 2) demand from 2030 California fuel cell vehicle deployment. • Simulated electrolysis H 2 production using PLEXOS power system model of Western US. • Flexible electrolysis operation can reduce system costs, carbon dioxide emissions. Hydrogen fuel cell electric vehicles (FCEVs) have been proposed as an option for lowering carbon dioxide (CO 2) and pollutants emissions from the transportation sector, when implemented in combination with green hydrogen production methods such as water electrolysis powered by renewable electricity. FCEVs also have the added advantages of high specific energy density and rapid refueling, two important challenges that battery electric vehicles have not yet fully overcome. Moreover, flexible operation of electrolysis could support the grid and lower electricity costs. In this paper, we simulate time-varying FCEV hydrogen refueling demand for light, medium- and heavy-duty vehicles met using electrolysis systems distributed throughout the Western U.S. power system. We find that by oversizing electrolyzers the resulting load flexibility results in different hydrogen generation temporal profiles, average electricity costs, renewable curtailment levels, and CO 2 emissions. Our results indicate that increasing hydrogen production flexibility lowers hydrogen and electricity generation cost and CO 2 emissions, but there is a tradeoff between lowering operational cost and increasing electrolyzer capital cost, yielding a minimum total system cost at a size corresponding to between 80% and 90% annual capacity factor assuming a future electrolyzer cost of $300/kW. [ABSTRACT FROM AUTHOR]