Changes in 2022
The Electricity ATB provides a transparent set of technology cost and performance data for electric sector analysis. The update of the 2021 ATB to the 2022 ATB includes general updates to all technologies as well as technology-specific updates—both of which are described below. Use the following charts to explore the changes from 2021 to 2022.
Compare the 2021 ATB and the 2022 ATB. Click "more details" above the chart to select a parameter (LCOE, CAPEX, fixed operation and maintenance O&M [FOM], capacity factor, and fixed charge rate [FCR]) and other filters.
General Updates to All Technologies
- The assumptions in each of the two financial assumptions cases have not been modified since ATB 2021.
- The Base Year is updated from 2019 to 2020 using new market data or analysis where applicable.
- The dollar year is updated from 2019 to 2020 with a 1.2% inflation rate (BLS, 2021).
- Historical data are updated to include data reported through year end 2020.
Generation Updates Summary
- Land-Based Wind: No major changes.
- Offshore Wind: The same experiential learning methodology as 2021 is used to derive future cost reductions. Empirical market data are updated, leading to a lower CAPEX learning rate of 7.2%. Future global deployment projections increased for both fixed-bottom and floating offshore wind.
- Distributed Wind: This technology is presented for the first time in the 2022 ATB.
- Photovoltaics: Initial cost metrics are informed by new benchmark results from (Feldman et al., 2021) and projections are based on (Ramasamy et al., 2021).
- Concentrating Solar Power: Component and system cost estimates for Base Year now include data from recent heliostat bottom-up analysis (Kurup et al., 2022).
- Geothermal: Data are updated to reflect lower fixed O&M in all cases and 100-MW enhanced geothermal system (EGS) plants in the advanced case.
- Hydropower: No changes are made from 2021 data.
- Utility-Scale PV-Plus-Battery: See Photovoltaics and Battery Storage.
- Battery Storage: Base year CAPEX is updated consistent with new benchmark results in (Ramasamy et al., 2021). Projections are revised based on a new literature survey (Cole et al., 2021).
- Pumped Storage Hydropower: Capital costs and resource characteristics are presented for the first time in the 2022 ATB based on (Rosenlieb et al., 2022).
- Natural Gas and Coal: Learning rates have been updated to reflect (EIA, 2022). A mid-year update added 95% and max carbon capture and storage cases (Schmitt et al., 2022).
- Base Year: As in the 2021 ATB, Capital expenditures (CAPEX) associated with wind plants installed in the interior of the country are used to characterize CAPEX for hypothetical wind plants with average annual wind speeds that correspond with the median conditions for recently installed wind facilities based on the newly updated 2020 Cost of Wind Energy Review (Stehly and Duffy, 2022) The operation and maintenance (O&M) cost is also informed by the new report (Stehly and Duffy, 2022); no variation of FOM with wind speed class is assumed. Capacity factors align with performance in Wind Speed Classes 2–7, where most installations are located.
- Projections: As in 2021 ATB, specific technology innovations are associated with each scenario. In the Moderate Technology Innovation Scenario (Moderate Scenario), large, segmented blades are transported by truck, enabling larger rotors. Segmentation enables higher hubs and larger turbines, and advanced controls enable higher capacity factors and lower CAPEX. In the Advanced Technology Innovation Scenario (Advanced Scenario), even larger turbines and advanced rotor configurations increase turbine capacity, on-site manufacturing further increases hub heights, and high-fidelity modeling and advanced controls are fully implemented.
- Base Year: As in the 2021 ATB, CAPEX and O&M costs are calculated with a combination of bottom-up techno-economic cost modeling (Beiter et al., 2016) and experiential learning effects with economies of size and scale from higher turbine and plant ratings (Beiter et al., 2020). Capacity factors are determined using a representative power curve for a generic National Renewable Energy Laboratory (NREL)-modeled 6-MW offshore wind turbine and updated in the 2022 ATB based on innovation trajectories from (Beiter et al., 2016) to reflect the 8-MW turbine technology assumed to be available starting in 2020. These capacity factors include geospatial estimates of gross capacity factors for the entire national wind resource (Musial et al., 2016).
- Projections: For the 2022 ATB, the CAPEX cost reduction trajectories were updated by updating the market data and global offshore wind deployment assumptions used to derive the experiential learning curves. As the learning curves predict future costs as a function of future offshore wind deployment, future costs in each of the ATB technology innovation scenarios are driven by different levels of deployment based on updated literature estimates. ITC assumptions have been revised to include the 10 year safe harbor period.
- Base Year: CAPEX is based on the Distributed Wind Futures Study and uses 2020 CAPEX and O&M costs from the Cost of Wind Energy study (Stehly and Duffy, 2022).
- Projections: CAPEX projections for distributed wind projects use methods from (Lantz et al., 2016), 2020 costs from the Cost of Wind Energy study (Stehly and Duffy, 2022), (DOE and NREL, 2015), and updates from the Distributed Wind Futures Study (McCabe et al., 2022).
Photovoltaics (PV): Utility-Scale, Commercial, and Residential
- Base Year: CAPEX for plants with a commercial operation date (COD) of 2020 are based on bottom-up modeling and market data from (Feldman et al., 2021), the same source as the 2021 ATB. For 2021 COD CAPEX, the new data are from (Ramasamy et al., 2021). The O&M costs are based on modeled pricing for PV systems from those same references.
- Projections: The DC-to-AC ratio (or inverter loading ratio) for utility-scale PV is changed from 1.34 in the 2021 ATB to 1.28 in the 2022 ATB for the base year and future years. The straight-line improvements in cost metrics through 2030 are now calculated using the 2021 benchmarks from (Ramasamy et al., 2021) as the initial points.
Concentrating Solar Power (CSP)
- Base Year: Based on recent assessment of the industry in 2022 and CSP costs in the 2022 ATB are based on cost estimates for CSP components (Kurup et al., 2022) that are available in Version 2021.12.02 of the System Advisor Model (SAM). As in the 2021 ATB, future year projections are informed by the literature, NREL expertise, and technology pathway assessments for reductions in capital expenditures.
- Projections: As in the 2021 ATB, the Moderate Scenario assumes a transition to a supercritical CO2 cycle in the powerblock, advanced coatings on the receiver, improved tanks, pumps, and component configurations for the thermal storage unit, and improved heliostat installation and learning that are due to deployment in the solar field. The Advanced Scenario assumes higher temperature supercritical CO2 , higher temperature receiver, advanced storage compatible with higher temperatures, and low-cost, modular solar fields with increased efficiency.
- Base Year: The lower O&M costs reflect results from additional empirical data. The lower CAPEX costs reflect shorter construction timelines. As in the 2021 ATB, estimates are based on bottom-up cost modeling using the Geothermal Electricity Technology Evaluation Model (GETEM) and inputs from the GeoVision Business-as-Usual scenario (DOE, 2019). The Base Year is updated to the 2020$ dollar year based on the consumer price index and producer price indices.
- Projections: As in the 2021 ATB, the projection of future geothermal plant CAPEX for the Advanced Scenario is largely based on the Technology Improvement scenario from the GeoVision Study ((DOE, 2019) and (Augustine et al., 2019)). In addition, for the 2022 ATB EGS power plants are assumed to be 100 MW, fixed O&M costs have been reduced from the 2021 ATB, and permitting timelines have been shortened. The Moderate Scenario is based on the Intermediate 1 Drilling Curve detailed as part of the GeoVision report to 2030 and on a minimum learning rate to 2050, which is implemented in AEO2015 (EIA, 2015) as a 0.5% annual reduction in CAPEX. The Conservative Technology Innovation Scenario (Conservative Scenario) retains all cost and performance assumptions equivalent to the Base Year and assumes a minimum learning rate to 2050.
- Base Year: The 2022 ATB data are the same as those for the 2021 ATB. The non-powered dam (NPD) data are based on a bottom-up modeling of reference sites using site-specific data (Oladosu, G. et al., 2021). The analysis used for the NPD data involved identification of 20 reference sites for U.S. NPD hydropower and detailed bottom-up design and cost simulations under baseline and near-term innovation cases. New stream-reach development (NSD) data in the 2022 ATB retain data from previous years based on projections developed for the Hydropower Vision study (DOE, 2016) using technological learning assumptions and bottom-up analysis of process and/or technology improvements to provide a range of future cost outcomes (O'Connor et al., 2015).
- Projections: The 2022 ATB data are the same as those for the 2021 ATB. The near-term innovation case for NPD is judged to be applicable in the next 5–10 years and includes use of new materials for penstocks and use of matrix turbines to reduce the cost of civil works. (Oladosu, G. et al., 2021). The NSD projections use a mix of U.S. Energy Information Administration (EIA) technological learning assumptions, input from a technical team of Oak Ridge National Laboratory researchers, and the experience of expert hydropower consultants.
- Base Year: CAPEX for plants with a commercial operation date of 2021 is based on new bottom-up modeling and 2021 Q1 market data from (Ramasamy et al., 2021). The chosen configuration continues to reflect recent and proposed utility-scale PV-plus-battery projects; while it is similar to the configuration presented in the 2021 ATB, the nameplate capacity of the battery has been increased (from 50 MW to 71.5 MW) to allow for 55-MWDC of usable stored energy after accounting for state-of-charge and roundtrip efficiency constraints. In addition, interconnection and transmission costs now scale with the AC rating of the capacity, to reflect the potential for shared transmission costs. Also new in the 2022 ATB is that battery replacements are reflected in the fixed O&M costs, based on assumed battery degradation rates: we assume the need for a 20% capacity augmentation after both 10 and 20 years, where the future investment costs reflect technology advancement, a 2% discount rate (based on the real weighted average cost of capital), and labor costs. Finally, a grid charging cost of $22/MWh has been added to the default LCOE for the 25% of energy that comes from grid charging.
- Projections: As in the 2021 ATB, PV-plus-battery projections in the 2022 ATB are driven primarily by CAPEX cost improvements but also by improvements in energy yield, operational cost, and cost of capital (for the Market+Policies Financial Assumptions Case). Projected technology costs are based on the new report (Feldman et al., 2021).
- Base Year: CAPEX is based on new bottom-up modeling and market data from the new report (Ramasamy et al., 2021). Also new in the 2022 ATB is that battery replacements are reflected in the fixed O&M costs, based on assumed battery degradation rates: we assume the need for a 20% capacity augmentation after both 10 and 20 years, where the future investment costs reflect technology advancement, a 2% discount rate (based on the real weighted average cost of capital), and labor costs, with an assumed project duration of 30 years.
- Projections: As in the 2021 ATB, battery projections in the 2022 ATB are represented for utility-scale, commercial-scale and residential-scale battery systems. Cost improvements are driven by a literature survey as described by (Cole et al., 2021). This literature survey incorporates more-rapid reductions in battery pack and cell costs while soft costs and costs related to other factors decline more slowly.
Pumped Storage Hydropower (PSH)
- Base Year: Resource characterizations including capital costs are presented for the first time in the 2022 ATB. These are based on a national resource assessment for closed-loop PSH described in (Rosenlieb et al., 2022).
- Projection: Projected cost reductions in the Advanced Scenario are based on innovations in modularity, materials, pumps and turbines, and closed-loop concepts as described in (DOE, 2016).
Natural Gas and Coal
- Base Year: For unmitigated technologies, base year cost and performance data are based on (James III et al., 2019). Carbon capture and storage performance data are based on (Schmitt et al., 2022).
- Projections: Projections in the 2022 ATB are based on the rate of cost improvement from AEO2022 (EIA, 2022).
Nuclear and Biopower
- Base Year and Projections: Cost and performance estimates are updated to match the AEO2022 Reference scenario (EIA, 2022).
The following references are specific to this page; for all references in this ATB, see References.
BLS. “CPI for All Urban Consumers (CPI-U).” U.S. Bureau of Labor Statistics, 2021. https://beta.bls.gov/dataViewer/view/timeseries/CUSR0000SA0.
Feldman, David, Vignesh Ramasamy, Ran Fu, Ashwin Ramdas, Jal Desai, and Robert Margolis. “U.S. Solar Photovoltaic System and Energy Storage Cost Benchmark: Q1 2020.” Golden, CO: National Renewable Energy Laboratory, January 27, 2021. https://doi.org/10.2172/1764908.
Ramasamy, Vignesh, David Feldman, Jal Desai, and Robert Margolis. “U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks: Q1 2021.” Golden, CO: National Renewable Energy Laboratory, 2021. https://www.nrel.gov/docs/fy22osti/80694.pdf.
Kurup, Parthiv, Sertac Akar, Stephen Glynn, Chad Augustine, and Patrick Davenport. “Cost Update: Commercial and Advanced Heliostat Collectors.” Golden, CO: National Renewable Energy Laboratory, 2022. https://doi.org/10.2172/1847876.
Cole, Wesley, Will A. Frazier, and Chad Augustine. “Cost Projections for Utility-Scale Battery Storage: 2021 Update.” Technical Report. Golden, CO: National Renewable Energy Laboratory, 2021. https://www.nrel.gov/docs/fy21osti/79236.pdf.
Rosenlieb, Evan, Donna Heimiller, and Stuart Cohen. “Closed-Loop Pumped Storage Hydropower Resource Assessment for the United States.” Golden, CO: National Renewable Energy Laboratory, 2022. https://www.nrel.gov/docs/fy22osti/81277.pdf.
EIA. “Annual Energy Outlook 2022.” Washington, D.C.: U.S. Energy Information Administration, March 2022. https://www.eia.gov/outlooks/aeo/.
Schmitt, Tommy, Sarah Leptinsky, Marc Turner, Alex Zoelle, Chuck White, Sydney Hughes, Sally Homsy, et al. “Cost And Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity.” National Energy Technology Laboratory (NETL), Pittsburgh, PA, Morgantown, WV, and Albany, OR (United States), October 14, 2022. https://doi.org/10.2172/1893822.
Stehly, Tyler, and Patrick Duffy. “2020 Cost of Wind Energy Review.” Technical Report. Golden, CO: National Renewable Energy Laboratory (NREL), January 2022. https://www.nrel.gov/docs/fy22osti/81209.pdf.
Beiter, Philipp, Walter Musial, Aaron Smith, Levi Kilcher, Rick Damiani, Michael Maness, Senu Sirnivas, et al. “A Spatial-Economic Cost-Reduction Pathway Analysis for U.S. Offshore Wind Energy Development from 2015-2030.” Technical Report. Golden, CO: National Renewable Energy Laboratory, 2016. https://doi.org/10.2172/1324526.
Beiter, Philipp, Walt Musial, Patrick Duffy, Aubryn Cooperman, Matt Shields, Donna Heimiller, and Mike Optis. “The Cost of Floating Offshore Wind Energy in California between 2019 and 2032.” NREL Technical Report. Golden, CO: National Renewable Energy Laboratory, November 2020. https://www.nrel.gov/docs/fy21osti/77384.pdf.
Musial, Walt, Donna Heimiller, Philipp Beiter, George Scott, and Caroline Draxl. “2016 Offshore Wind Energy Resource Assessment for the United States.” Technical Report. Golden, CO: National Renewable Energy Laboratory, September 2016. https://doi.org/10.2172/1324533.
Lantz, Eric, Benjamin Sigrin, Michael Gleason, Robert Preus, and Ian Baring-Gould. “Assessing the Future of Distributed Wind: Opportunities for Behind-the-Meter Projects.” Golden, CO: National Renewable Energy Laboratory, November 1, 2016. https://doi.org/10.2172/1333625.
DOE, and NREL. “Wind Vision: A New Era for Wind Power in the United States.” Technical Report. Washington, D.C.: U.S. Department of Energy, 2015. https://doi.org/10.2172/1220428.
McCabe, Kevin, Ashreeta Prasanna, Jane Lockshin, Parangat Bhaskar, Thomas Bowen, Ruth Baranowski, Ben Sigrin, and Eric Lantz. “Distributed Wind Energy Futures Study.” Golden, CO, May 2022. https://www.nrel.gov/docs/fy22osti/82519.pdf.
DOE. “GeoVision: Harnessing the Heat Beneath Our Feet.” Washington, D.C.: U.S. Department of Energy, May 2019. https://doi.org/10.15121/1572361.
Augustine, Chad, Jonathan Ho, and Nate Blair. “GeoVision Analysis Supporting Task Force Report: Electric Sector Potential to Penetration.” Technical Report. Golden, CO: National Renewable Energy Laboratory, 2019. https://doi.org/10.2172/1524768.
EIA. “Annual Energy Outlook 2015 with Projections to 2040.” Annual Energy Outlook. Washington, D.C.: U.S. Energy Information Administration, 2015. https://www.eia.gov/outlooks/archive/aeo15/.
Oladosu, G., George, L., and Wells, J. “2020 Cost Analysis of Hydropower Options at Non-Powered Dams.” Oak Ridge, TN: Oak Ridge National Laboratory, 2021.
DOE. “Hydropower Vision: A New Chapter for America’s Renewable Electricity Source.” Washington, D.C.: U.S. Department of Energy, 2016. https://doi.org/10.2172/1502612.
O’Connor, Patrick W., Scott T. DeNeale, Dol Raj Chalise, Emma Centurion, and Abigail Maloof. “Hydropower Baseline Cost Modeling, Version 2.” Oak Ridge, TN: Oak Ridge National Laboratory, 2015. https://doi.org/10.2172/1244193.
James III, Robert E., Dale Kearins, Marc Turner, Mark Woods, Norma Kuehn, and Alexander Zoelle. “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity.” National Energy Technology Laboratory, September 24, 2019. https://doi.org/10.2172/1569246.