Konferensartikel

A 110-MW parabolic trough power plant operating in California was modeled to observe the effect of molten salt thermal energy storage capacity on plant performance; cost; and profitability. A plant with no storage (PT-NG) was modeled to match the hourly and annual electricity output of a comparable plant with storage (PT-TES). The solar field area for the PT-TES plant was selected to minimize the unsubsidized levelized cost of electricity (LCOE). For each storage capacity modeled here (1-12 hours); PT-NG resulted in a larger solar field area and higher O&M costs than the respective PT-TES option. PT-TES generally had higher capital costs than PT-NG; and the PT-NG levelized cost of electricity (LCOE) varied from 6% higher compared with smaller TES capacities to 6% less compared with larger TES capacities. The profitability of PT-NG compared to PT-TES followed a similar trend to the LCOE with larger margins of difference in select scenarios. These results were achieved with 3-22% of the net electric output from natural gas in the PT-NG plant. The 30% investment tax credit (ITC); currently in place for solar energy in the United States; lowered the capital costs and LCOE for each configuration. Electricity pricing through a power purchase agreement (PPA) of $200/MWh was more profitable than hourly real-time electricity pricing; which resulted in a net annual loss for all configurations. Both the PPA and ITC were required to achieve a positive annual profit; and the maximum annual profit achieved was $US 11 million per year with 0 hours of storage.

Concentrated solar power; thermal storage