Table 2.

Summary of energy loads met, losses, energy supplies, changes in storage, and costs during the base 6-y (52,548-h) simulation

Energy load, supply, or lossEnergy (TWh) or cost
Total load met over 6 y82,695
 Electricity load for H2 production/compression9,469
 Electricity load not for H267,170
 Heat load from solar collectors and UTES6,056
Total lossesa10,189
 Transmission, distribution, maintenance losses6,334
 Losses CSP storage52.7
 Losses non-CSP, non-UTES storage238.9
 Losses UTES storage2,365
 Losses from shedding heat1,198
Total load plus losses (energy required)92,884
Total WWS supply before T&D losses92,979
 Onshore + offshore wind electricityb43,509
 Rooftop + utility PV + CSP electricityc39,901
 Hydropower electricityd2,413
 Wave electricitye320.8
 Geothermal electricityf1003.8
 Tidal electricityg113.0
 Solar heath5,718
Net energy taken from (+) or added to (−) storage−95.4
 Net energy taken from (+) CSP storage0
 Net energy taken from (+) non-UTES storage0
 Net energy taken from (+) UTES storage205.8
 Net energy taken from (+) H2 storage−301.2
Total energy supplied plus taken from storage92,884
Capital cost ($ trillion) new generators + storagei14.6 (12.0–17.2)
 Capital cost ($ trillion) new generators13.9 (11.8–16.0)
2050 total LCOE (¢/kWh-to-load) in 2013 dollars11.37 (8.5–15.4)
 Electricity + heat + short-distance T&D (¢/kWh)j10.26 (8.12–13.1)
 Long-distance transmission (¢/kWh)k0.32 (0.081–0.86)
 All storage except H2 (¢/kWh)l0.33 (0.062–0.75)
 H2 prod/compress/stor. (excl. elec. cost) (¢/kWh)m0.46 (0.22–0.69)
  • All units are TWh over the CONUS, except costs, which are either $ trillion or ¢/kWh-delivered-to-load. Bold indicates a total amount. Bold italics indicates a sum of totals. T&D, transmission and distribution.

  • a Transmission/distribution/maintenance losses are 5–10% of electricity generation for all generators except rooftop PV (1–2%) and solar thermal (2–4%). Transmission losses are averaged over short and long-distance (with high-voltage direct current) lines. Maintenance downtime is discussed in SI Appendix, Section S1.L. Storage efficiencies are given in SI Appendix, Table S1. Excess electricity is either stored or used to produce H2, so is not shed. Only excess heat is shed if heat storage is saturated.

  • b Onshore and offshore wind turbines, installed in the climate model, are REpower 5-MW turbines with 126-m-diameter rotors, 100-m hub heights, a cut-in wind speed of 3.5 m/s, and a cut-out wind speed of 30 m/s.

  • c Each solar PV panel for rooftop and utility solar, installed in the climate model is a SunPower E20 435 W panel with panel area of 2.1621 m2, which gives a panel efficiency (Watts of power output per Watt of solar radiation incident on the panel) of 20.1%. The cell efficiency (power out per watt incident on each cell) is 22.5%. Each CSP plant before storage is assumed to have the characteristics of the Ivanpah solar plant, which has 646,457 m2 of mirrors and 2.17 km2 of land per 100 MW installed power and a CSP efficiency (fraction of incident solar radiation that is converted to electricity) of 15.796%, calculated as the product of the reflection efficiency of 55% and the steam plant efficiency of 28.72% (36).

  • d The capacity factor for hydropower from the simulation is 52.5%, which also equals that from ref. 22.

  • e The assumed capacity factor for wave power is 23.3% (22).

  • f The assumed capacity factor for geothermal is 92.1% (22).

  • g The assumed capacity factor for tidal power is 26.1% (22).

  • h The efficiency of the solar hot fluid collection (energy in fluid divided by incident radiation) is 34% (23).

  • i Capital costs for new generators are derived from SI Appendix, Table S2 and for storage are derived from SI Appendix, Table S1.

  • j The electricity plus heat plus local transmission costs here are derived from capital costs in SI Appendix, Table S2 assuming a discount rate of 3.0 (1.5–4.5)%, a facility lifetime/amortization time of 30 (35–25) y for all technologies except geothermal [35 (30–40) y] and hydropower [55 (50–60) y], an annual O&M cost that varies by technology as in ref. 22, a short-distance transmission cost of 1.15 (1.1–1.2) ¢/kWh (22), a distribution cost of 2.57 (2.5–2.64) ¢/kWh (22), decommissioning costs of 1.125 (0.75–1.5)% of capital costs (22), and the annualized load met in Table 2.

  • k Long-distance transmission costs are 1.2 (0.3–3.2) ¢/kWh for 1,200- to 2,000-km lines (37). The base case assumes that 30% of all wind and solar electric power generated are subject to long-distance transmission lines. This percent is varied in sensitivity tests in SI Appendix, Fig. S13.

  • l Storage costs are the product of the storage capacity and the capital cost per unit of storage capacity of each storage technology (SI Appendix, Table S1), summed over all technologies, annualized with the same discount rates and annual O&M percentages as for power generators, and divided by the annual-average load met in Table 2 (i.e., the total load met over 6 y divided by 6 y).

  • m H2 costs are 4.0 (1.96–6.05) ¢/kWh-to-H2 for the electrolyzer, compressor, storage equipment, and water. This cost equals 2.36 (1.16–3.57) $/kg-H2 divided by 59.01 kWh/kg-H2 required to electrolyze (53.37 kWh/kg-H2) and compress (5.64 kWh/kg-H2) H2 (38). These costs exclude electricity costs, which are included elsewhere in the table. The overall cost of H2 in ¢/all-kWh-delivered is equal to the cost in ¢/kWh-to-H2 multiplied by the fraction of delivered power used for hydrogen (11.46% = Table 1, column 6 divided by column 2).