Energy load, supply, or loss | Energy (TWh) or cost |

Total load met over 6 y | 82,695 |

Electricity load for H_{2} production/compression | 9,469 |

Electricity load not for H_{2} | 67,170 |

Heat load from solar collectors and UTES | 6,056 |

Total losses^{a} | 10,189 |

Transmission, distribution, maintenance losses | 6,334 |

Losses CSP storage | 52.7 |

Losses non-CSP, non-UTES storage | 238.9 |

Losses UTES storage | 2,365 |

Losses from shedding heat | 1,198 |

Total load plus losses (energy required) | 92,884 |

Total WWS supply before T&D losses | 92,979 |

Onshore + offshore wind electricity^{b} | 43,509 |

Rooftop + utility PV + CSP electricity^{c} | 39,901 |

Hydropower electricity^{d} | 2,413 |

Wave electricity^{e} | 320.8 |

Geothermal electricity^{f} | 1003.8 |

Tidal electricity^{g} | 113.0 |

Solar heat^{h} | 5,718 |

Net energy taken from (+) or added to (−) storage | −95.4 |

Net energy taken from (+) CSP storage | 0 |

Net energy taken from (+) non-UTES storage | 0 |

Net energy taken from (+) UTES storage | 205.8 |

Net energy taken from (+) H_{2} storage | −301.2 |

Total energy supplied plus taken from storage | 92,884 |

Capital cost ($ trillion) new generators + storage^{i} | 14.6 (12.0–17.2) |

Capital cost ($ trillion) new generators | 13.9 (11.8–16.0) |

2050 total LCOE (¢/kWh-to-load) in 2013 dollars | 11.37 (8.5–15.4) |

Electricity + heat + short-distance T&D (¢/kWh)^{j} | 10.26 (8.12–13.1) |

Long-distance transmission (¢/kWh)^{k} | 0.32 (0.081–0.86) |

All storage except H_{2} (¢/kWh)^{l} | 0.33 (0.062–0.75) |

H_{2} prod/compress/stor. (excl. elec. cost) (¢/kWh)^{m} | 0.46 (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 H_{2}, 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 m^{2}, 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 m^{2}of mirrors and 2.17 km^{2}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}H_{2}costs are 4.0 (1.96–6.05) ¢/kWh-to-H_{2}for the electrolyzer, compressor, storage equipment, and water. This cost equals 2.36 (1.16–3.57) $/kg-H_{2}divided by 59.01 kWh/kg-H_{2}required to electrolyze (53.37 kWh/kg-H_{2}) and compress (5.64 kWh/kg-H_{2}) H_{2}(38). These costs exclude electricity costs, which are included elsewhere in the table. The overall cost of H_{2}in ¢/all-kWh-delivered is equal to the cost in ¢/kWh-to-H_{2}multiplied by the fraction of delivered power used for hydrogen (11.46% = Table 1, column 6 divided by column 2).