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Annual Energy Outlook 2022

Release Date: March 3, 2022 Next Release Date: February 2023 AEO Narrative PDF
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As coal and nuclear generating capacity retire, new capacity additions come largely from wind and solar technologies

Renewable technologies account for the majority of the projected capacity additions

Figure 18.

Figure 18

Renewable electric generating technologies account for over 57% of the approximately 1,000 gigawatts (GW) of cumulative capacity additions that we project in the Reference case from 2021 to 2050. This large share is a result of not only declining capital costs, but also continuing legislative incentives, such as state renewable portfolio standard (RPS) targets and the extension of federal and state tax credits. Although wind capacity is added steadily throughout the projection period, much less wind capacity is added than solar. Solar capacity accounts for 47% of electric generating capacity additions, and wind accounts for about 10%. Generating technologies fueled by natural gas make up most of the remaining share of new capacity additions (39%), some of which is used to generate electricity when intermittent wind and solar resources are not available.

Solar accounts for the majority of U.S. capacity additions in most regions. The majority of coal and nuclear retirements come from the Mid-Continent, PJM, and Southeast regions

Figure 19.

Figure 19

Solar generating capacity grows steadily across all regions of the United States in the Reference case. Some regions build diurnal storage capacity to support larger daily price fluctuations from the solar capacity additions. We project that California will add nearly 13 GW of diurnal storage power capacity through 2050 in the Reference case, compared with 8.4 GW of natural gas-fired generation capacity. PJM and the West are the only regions that add more natural gas capacity than solar capacity, but these regions also show high growth in solar. Cheaper solar and wind energy, accompanied by natural gas-fired plants, replaces coal and nuclear in the Mid-Continent, PJM, and Southeast regions. Solar’s share of total U.S. capacity increases from 7% in 2020 to 29% in 2050. About 70% of solar additions are utility-scale PV power plants, and 30% come from end-use PV such as residential and commercial rooftop solar installations.

Figure 20.

Figure 20

Wind additions are largely tied to policy

The Reference case assumes the production tax credit (PTC) for wind will be available through 2024, following a one-year extension in 2020. Although capital costs for wind continue to decline throughout the projection period, most projected wind additions take advantage of available federal tax credits. Nearly half of cumulative wind capacity additions from 2021 to 2050 occur before the PTC expires for projects coming online after 2025. The steadier pace of solar additions reflects, in part, the continued availability of a 10% investment tax credit (ITC), which has no fixed expiration date after 2026, when the current 30% phases out.

Natural gas continues to have the largest share of fossil fuel capacity additions in all regions

Although renewable electric-generating technologies account for about 60% of cumulative capacity additions throughout the projection period in the Reference case, natural gas-fired capacity accounts for almost the entire remaining balance of additions—about 40% through 2050. These natural gas-fired generator additions are almost evenly split between combined-cycle technologies and combustion turbines, which both provide energy and help balance the intermittent output from wind and solar generators.

Coal-fired generating unit retirements largely take place by 2030

EPA’s Affordable Clean Energy (ACE) rule (84 FR 32520) was vacated by the U.S. Court of Appeals for the District of Columbia Circuit on January 19, 2021. This has been incorporated into the Reference case, leading some plants that retired in the AEO2021 Reference case to continue operating past 2025. Despite that development, the Reference case still shows substantial coal plant retirements, most of which take place by 2030. Those retirements are a result of both regulatory measures and market factors. In particular, low natural gas prices in the early years of the projection period contribute to the retirements of coal-fired plants and nuclear plants. Natural gas-fired generation sets power prices in wholesale electricity markets most of the time, and the lower natural gas prices affect the profitability of coal and nuclear units, which have high fixed costs. In addition, owners of many coal-fired plants have announced closings as part of meeting goals to decarbonize their systems.

The civil nuclear credit program, passed as part of the Infrastructure Investment and Jobs Act, supports continued use of existing nuclear power facilities. This act, along with several state support programs, provides out-of-market payments that will likely keep reactors in affected regions profitable over the next 5–10 years. We project nuclear capacity retirements to occur after 2030, partially because we assume that these plants will no longer receive those credit payments when the current legislation expires.

Renewable electric generating technologies account for over 57% of the approximately 1,000 gigawatts (GW) of cumulative capacity additions that we project in the Reference case from 2021 to 2050.