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Changes in 2024

The 2024 Electricity ATB provides a transparent set of technology cost and performance data for electric sector analysis. The update of the 2023 ATB to the 2024 ATB includes general updates to all technologies as well as technology-specific updates—both of which are described on this page. Use the following charts to explore the changes from 2023 to 2024.

Parameter value projections by ATB projection year

Compare the 2022 ATB and the 2023 ATB. Click on the black arrow to the right of "click arrow to explore details" to select a parameter (LCOECAPEX, fixed operation and maintenance O&M [FOM], capacity factor, and fixed charge rate [FCR]) and other filters.

General Updates to All Technologies

Generation Updates Summary

  • Land-Based Wind: Wind turbine technology configurations are now developed separately from cost and performance assumptions, which allows for multiple technologies to be used within each scenario. The scenarios are defined by combining bottom-up engineering-based modeling to inform the Moderate Scenario with calculated learning rates used to inform the Conservative and Advanced scenarios. Wind turbine technology configuration is now wind speed class-specific and is selected by the technology configuration with the lowest LCOE within each wind speed class. 
  • Offshore Wind: The 2024 offshore wind ATB estimates incorporate significant updates to the methodology- to bottom-up estimates for the base year (2022) and to cost projections. The cost trajectories are now informed by both long-term industry learning and short-term projections to adjust for macroeconomic headwinds facing early U.S. offshore wind projects (such as rising interest rates, inflation, and supply chain shocks). The rapid evolution of offshore wind costs has led to a higher degree of uncertainty, which are reflected through the three scenarios presented. Note also that floating offshore wind energy cost projections have been adjusted to better capture the cost reduction effects as the technology matures from a nascent stage to the first wave of commercial projects rather than assuming mature floating supply chains are available in all years like previous ATB analyses. We only present floating offshore wind cost estimates from 2030 and beyond when the first gigawatt-scale projects could feasibly be constructed in the United States.
  • Distributed Wind: This technology was added 2022 ATB for the first time, and there are no major updates in the 2024 ATB.
  • Photovoltaics: Initial cost metrics are informed by benchmark results from (Ramasamy et al., 2022).
  • Concentrating Solar Power: Component and system cost estimates for the Base Year now include data from recent heliostat bottom-up analysis (Kurup et al., 2022). There have been updates to the defaults in the System Advisor Model (SAM) power tower molten salt physical model.
  • Geothermal: Near-field and deep enhanced geothermal system (EGS) representative plant sizes are aligned for the base case. The representative plant size for the EGS Binary Moderate scenario is updated to 40 MWe based on planned commercial developments. As in the 2023 ATB, a single-factor learning curve is used to develop future projections in the Moderate and Advanced scenarios.
  • Hydropower: No changes are made from 2023 data.
  • Utility-Scale PV-Plus-Battery: See Photovoltaics and Battery Storage.
  • Battery Storage: Base year CAPEX for utility-scale and commercial storage is updated consistent with new benchmark results in (Ramasamy et al., 2023). Residential is unchanged other than updating the dollar year.
  • Pumped Storage Hydropower: Added sites that utilize existing reservoirs. Capital costs and resource characteristics are updated to use a new cost model described in (Cohen et al., 2023), and changes relative to (Rosenlieb et al., 2022) are described in "Closed-Loop Pumped Storage Hydropower Supply Curves" (NREL).
  • Natural Gas and Coal: The 2024 ATB expands the set of natural gas combined cycle (NGCC) power plant options to include an H-class 1x1 configuration (a single combustion turbine with heat recovery providing steam for a Rankine bottoming cycle) to provide cost and performance for deploying H-class technology for smaller plants (i.e., less than nominal 1 Gigawatt for a new-build conventional new electricity generating unit.
  • Nuclear: Capital costs and resource characteristics are updated from AEO2022 Reference scenario (EIA, 2022) to costs and characteristics based on (Abou-Jaoude et al., 2024).

Technology-Specific Updates

Land-Based Wind

  • Base Year: Capital expenditures Capital expenditures (CAPEX) associated with the four representative technologies are estimated using bottom-up engineering models for hypothetical wind plants installed in 2021. The Base Year value for each wind speed class is dependent on the selected representative technology. The all-in operating expenditure cost for each representative technology is informed by recent literature (Liu and Garcia da Fonseca, 2021) and (Wiser et al., 2019) and varies by the representative wind turbine's rating. Capacity factors are calculated by generating a power curve for each representative wind turbine technology using the Weibull distribution and the average annual wind speed in the wind speed class in which the representative wind turbine is placed. 
  • Projections: The technology configurations are used to estimate the total system CAPEX of a theoretical commercial scale (e.g., 200-MW) project and changes for each of the scenarios (i.e., Conservative, Moderate, and Advanced) from bottom-up engineering models and assumed learning rates. Operating expenditure estimates vary by wind turbine rating (Liu and Garcia da Fonseca, 2021) and change for each scenario based on assumed learning rates. Net cash flow projection methods are similar to the base year but assume technology innovations that increase wind plant energy capture through advanced controls and reduce total system losses for each scenario. 

Offshore Wind

  • Base Year: In the 2024 ATB, base year costs are modeled with a combination of the National Renewable Energy Laboratory's (NREL's) bottom-up cost models for gigawatt-scale fixed-bottom projects, but we only present floating offshore wind energy costs in 2030 and beyond when the first gigawatt-scale projects could feasibly be built in the United states. Specifically, the Renewable Energy Potential (reV) Model and NREL Wind Analysis Library (NRWAL) are used to assess offshore wind plant costs across U.S. waters as a function of site-specific parameters including wind resource, water depth, and distances to critical infrastructure (Maclaurin et al., 2019)(Nunemaker et al., 2023). Those site-specific cost estimates are informed by the Offshore Renewables Balance of System and Installation Tool (ORBIT) for CAPEX, the Windfarm Operations and Maintenance cost-Benefit Analysis Tool (WOMBAT) for OpEx, and the FLOw Redirection and Induction in Steady State (FLORIS) tool for AEP (Nunemaker et al., 2020)(Hammond and Cooperman, 2022);(National Renewable Energy Laboratory (NREL), 2021). ATB cost estimates are spatial averages presented in terms of wind classes by binning the sites on cost and hub-height wind speed.
  • Projections: 2024 offshore wind ATB cost trajectories are derived for each scenario in two parts: a long-term cost projection based on global industry experience and a near-term CAPEX adjustment to account for macroeconomic conditions facing early U.S. offshore wind energy projects not captured in the learning curves (rising interest rates, inflation, and supply chain shocks). For the long-term CAPEX projections, we follow the approach outlined in (Shields et al., 2022) to derive learning curves for each scenario from historical offshore wind project CAPEX data and projected global offshore wind deployment. Floating CAPEX projections include effects from improving plant economies of scale as the floating offshore wind industry matures, whereas fixed-bottom CAPEX projections are reflective of gigawatt-scale projects in all years. A range of short-term CAPEX adjustments corresponding to the three ATB scenarios is derived from literature and industry publications to highlight near-term macroeconomic uncertainty. The long-term projections for OPEX and Capacity Factor improvements are derived from (Wiser et al., 2021).

Distributed Wind

Photovoltaics (PV): Utility-Scale, Commercial, and Residential

  • Base Year: CAPEX for plants with a commercial operation date of 2022 are based on bottom-up modeling and market data from (Ramasamy et al., 2022), the same source as the 2023 ATB. For 2023 commercial operation date CAPEX, the new data are from (Ramasamy et al., 2023). The O&M costs are based on modeled pricing for PV systems from those same references.
  • Projections: The straight-line improvements in cost metrics through 2035 are now calculated using the 2023 benchmarks from (Ramasamy et al., 2023) as the initial points.

Concentrating Solar Power (CSP)

  • Base Year:  Based on a recent assessment of the industry, bottom-up cost model, and initial supply chain analysis  (Turchi et al., 2019) (Kurup et al., 2022), CSP costs in the 2024 ATB are based on cost estimates for CSP components that are available in Version 2023.12.17 of the System Advisor Model (SAM). As in the 2023 ATB, future year projections are informed by the literature, NREL expertise, and technology pathway assessments for reductions in CAPEX. 
    • The SAM Version 2023.12.17 has had default updates, including an update in the power cycle calculations to fix an error. The solar radiation database (NSRDB) has been updated with new resource data. The heliostat field design point was changed from 99% to 95% based on findings from the HelioCon Roadmap  (Zhu et al., 2022). After these changes were implemented, the SAM optimization routines were run. The SAM CSP molten salt power tower heliostat field size and the power tower height have increased due to the re-optimization.
  • Projections: As in the 2023 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 ; a higher-temperature receiver; advanced storage compatible with higher temperatures; and low-cost, modular solar fields with increased efficiency.


  • Base Year: 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 2022$ dollar year based on producer price indices. The significantly lower CAPEX for EGS technologies, compared to the 2023 ATB, are due to revisions in the model assumptions for drilling and reservoir performance. A 7% decline in the baseline drilling cost (in addition to the 3% reduction applied in the 2021 ATB) is applied to account for an increase in drilling efficiency as reported in ongoing demonstration and commercial-scale projects (El-Sadi et al., 2024). The EGS production flow rate, productivity, and injectivity are updated to 60 kg/s, 1,365 lb/hr-psi, and 1650 lb/hr-psi, respectively to reflect economical levels reported in (Norbeck and Latimer, 2023). Other updates are made to assumptions on and stimulation success rates, and plant sizes (Moderate case only).
  • Projections: Future CAPEX projections between 2022 and 2035 for the Moderate and Advanced scenarios are based on a single-factor learning curve (Fukui et al., 2017). The learning rates applied are 13% for hydrothermal Moderate, 18% for EGS Moderate, 30% for hydrothermal Advanced, and 35% (updated for the 2024 ATB) for EGS Advanced Scenarios. (Fukui et al., 2017)(Latimer and Meier, 2017)(El-Sadi et al., 2024). The 2035 CAPEX for the Advanced Scenario is largely based on the Technology Improvement scenario assumptions from the GeoVision Study  (DOE, 2019)(Augustine et al., 2019)), but includes some updates to EGS drilling success  (Snyder et al., 2017). The 2035 Moderate Scenario CAPEX is based on the Intermediate 1 Drilling Curve detailed as part of the GeoVision with improvements in drilling and stimulation success and well injectivity/productivity. The Conservative Scenario assumes a 0.5% annual reduction in CAPEX from 2022 to 2050 as implemented in the AEO2015 (EIA, 2015). After 2035, a 0.5% annual reduction is applied to the CAPEX up to 2050, as in the Conservative Scenario. O&M costs remain constant from 2022 to 2050 in the Conservative Scenario. For each Moderate and Advanced Scenario, a linear drop in O&M cost is applied between 2023 and 2035, they remain constant afterwards to 2050.


  • Base Year: The non-powered dam (NPD) data in the 2024 ATB are estimates of costs from a reduced-form model estimated with bottom-up simulation results for nearly 20 reference sites (Oladosu et al., 2021). Data for New stream-reach development (NSD) in the 2023 ATB are retained 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). For NPD, interconnection costs (i.e., electrical infrastructure) were separated from the 2024 ATB capital expenditures. For NSD, $60/kW was subtracted from the 2024 ATB capital costs, and a separate grid connection cost variable with a value of $100/kW was created. The dollar base year was updated to 2022 using the US Consumer Price Index (CPI).
  • Projections: The near-term innovation case for NPD is judged to be applicable in the next 5–10 years and includes the use of new materials for penstocks and matrix turbines to reduce the cost of civil works (Oladosu et al., 2021). The NSD projections use a mix of the U.S. Energy Information Administration's technological learning assumptions, input from a technical team of Oak Ridge National Laboratory researchers, and the experience of expert hydropower consultants.

Utility-Scale PV-Plus-Battery

  • Base Year: CAPEX for plants with a commercial operation date of 2022 is based on new bottom-up modeling and 2023 Q1 market data from (Ramasamy et al., 2023). Cost savings for colocated systems have also been updated using that report. 
  • Projections: As in the 2023 ATB, PV-plus-battery projections in the 2024 ATB are driven primarily by CAPEX cost improvements but also by improvements in energy yield, operating cost, and cost of capital (for the Market + Policies case). Projected technology costs are based on a new report (Ramasamy et al., 2023).

Battery Storage

  • Base Year: Utility-scale storage CAPEX is based on bottom-up modeling and market data from a new report (Ramasamy et al., 2023). Residential and commercial storage have been updated to the 2022 dollar year.
  • Projections: Projections are still drawn from (Cole and Karmakar, 2023). This literature survey incorporates projections that show near-term increases in price, as well as those that project rapid price declines.

Pumped Storage Hydropower (PSH)

  • Base Year: Capital costs and resource characteristics are updated to use a new cost model described in (Cohen et al., 2023), and changes relative to (Rosenlieb et al., 2022) described in "Closed-Loop Pumped Storage Hydropower Supply Curves" (NREL). The PSH resource assessment now includes potential sites that utilize existing reservoirs, and these are included in the ATB as a subtype of PSH technology.
  • Projection: These have not changed for the 2024 ATB. 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: Base year cost and performance data now include new build 1x1 H-class technologies (Leptinsky et al., 2024).
  • Projections: Projections in the 2024 ATB are based on the rate of cost improvement from the AEO2023 (EIA, 2023), as in 2023.



  • Base Year and Projections: No changes beyond dollar year updates.


The following references are specific to this page; for all references in this ATB, see References.

Gagnon, Pieter, An Pham, Wesley Cole, Sarah Awara, Anne Barlas, Maxwell Brown, Patrick Brown, et al. “2023 Standard Scenarios Report: A U.S. Electricity Sector Outlook,” 2024.

BLS. “CPI for All Urban Consumers (CPI-U).” U.S. Bureau of Labor Statistics, 2024.

Ramasamy, Vignesh, Jarett Zuboy, Eric O’Shaughnessy, David Feldman, Jal Desai, Michael Woodhouse, Paul Basore, and Robert Margolis. “U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022.” Golden, CO: National Renewable Energy Laboratory, 2022.

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.

Ramasamy, Vignesh, Jarett Zuboy, Michael Woodhouse, Eric O’Shaughnessy, David Feldman, Jal Desai, Andy Walker, Robert Margolis, and Paul Basore. “U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2023.” Golden, CO: National Renewable Energy Laboratory, 2023.

Cohen, Stuart, Vignesh Ramasamy, and Danny Inman. “A Component-Level Bottom-Up Cost Model for Pumped Storage Hydropower.” National Renewable Energy Laboratory (NREL), Golden, CO (United States), September 19, 2023.

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.

EIA. “Annual Energy Outlook 2022.” Washington, D.C.: U.S. Energy Information Administration, March 2022.

Abou-Jaoude, Abdalla, Levi Larsen, Nahuel Guaita, Ishita Trivedi, Frederick Josek, Christopher Lohse, Edward Hoffman, Nicolas Stauff, Koroush Shirvan, and Adam Stein. “Meta-Analysis of Advanced Nuclear Reactor Cost Estimations.” Idaho National Laboratory, June 2024.

Liu, Daniel, and Leila Garcia da Fonseca. “2021 O&M Economics and Cost Data for Onshore Wind Power Markets.” Wood Mackenzie, May 2021.

Wiser, Ryan, Mark Bolinger, and Eric Lantz. “Assessing Wind Power Operating Costs in the United States: Results from a Survey of Wind Industry Experts.” Renewable Energy Focus 30, no. September 2019 (2019): 46–57.

Maclaurin, Galen, Nick Grue, Anthony Lopez, and Donna Heimiller. “The Renewable Energy Potential (ReV) Model: A Geospatial Platform for Technical Potential and Supply Curve Modeling.” Golden, CO: National Renewable Energy Laboratory, September 2019.

Nunemaker, Jacob, Grant Buster, Michael Rossol, Patrick Duffy, Matthew Shields, Philipp Beiter, and Aaron Smith. NREL Wind Analysis Library NRWAL. Golden, CO: National Renewable Energy Laboratory (NREL), 2023.

Nunemaker, Jake, Matt Shields, Hammond Robert, and Patrick Duffy. “ORBIT: Offshore Renewables Balance-of-System and Installation Tool.” Golden, CO: National Renewable Energy Laboratory, 2020.

Hammond, Rob, and Aubryn Cooperman. “Windfarm Operations and Maintenance Cost-Benefit Analysis Tool (WOMBAT).” Technical Report. Golden, CO: National Renewable Energy Laboratory (NREL), 2022.

National Renewable Energy Laboratory (NREL). “FLORIS. Version 3.4,” 2021.

Shields, Matthew, Philipp Beiter, and Jacob Nunemaker. “A Systematic Framework for Projecting the Future Cost of Offshore Wind Energy.” Technical Report. Golden, CO: National Renewable Energy Laboratory (NREL), December 1, 2022.

Wiser, Ryan, Joseph Rand, Joachim Seel, Philipp Beiter, Erin Baker, Eric Lantz, and Patrick Gilman. “Expert Elicitation Survey Predicts 37% to 49% Declines in Wind Energy Costs by 2050.” Nature Energy 6, no. May 2021 (April 15, 2021): 555–65.

McCabe, Kevin, Ashreeta Prasanna, Jane Lockshin, Parangat Bhaskar, Thomas Bowen, Ruth Baranowski, Ben Sigrin, and Eric Lantz. “Distributed Wind Energy Futures Study.” Golden, CO: National Renewable Energy Laboratory, May 2022.

Stehly, Tyler, Patrick Duffy, and Daniel Mulas Hernando. “2022 Cost of Wind Energy Review.” December 2023.

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.

DOE. “Wind Vision: A New Era for Wind Power in the United States.” Washington, D.C.: U.S. Department of Energy, 2015.

Turchi, Craig, Matthew Boyd, Devon Kesseli, Parthiv Kurup, Mark Mehos, Ty Neises, Prashant Sharan, Michael Wagner, and Timothy Wendelin. “CSP Systems Analysis: Final Project Report.” Golden, CO: National Renewable Energy Laboratory, May 2019.

Zhu, Guangdong, Chad Augustine, Rebecca Mitchell, Matthew Muller, Parthiv Kurup, Alexander Zolan, Shashank Yellapantula, et al. “Roadmap to Advance Heliostat Technologies for Concentrating Solar-Thermal Power.” Golden, CO: National Renewable Energy Laboratory, 2022.

DOE. “GeoVision: Harnessing the Heat Beneath Our Feet.” Washington, D.C.: U.S. Department of Energy, May 2019.

El-Sadi, Kareem, Brittany Gierke, Elliot Howard, and Christian Gradl. “Review Of Drilling Performance In A Horizontal EGS Development.” In Proceedings, 49th Workshop on Geothermal Reservoir Engineering. Stanford University, Stanford, CA, 2024.

Norbeck, Jack Hunter, and Timothy Latimer. “Commercial-Scale Demonstration of a First-of-a-Kind Enhanced Geothermal System,” July 18, 2023.

Fukui, Rokuhei, Carl Greenfield, Katie Pogue, and Bob van der Zwaan. “Experience Curve for Natural Gas Production by Hydraulic Fracturing.” Energy Policy 105, no. June 2017 (June 1, 2017): 263–68.

Latimer, Tim, and Peter Meier. “Use of the Experience Curve to Understand Economics for At-Scale EGS Projects.” Stanford, CA: Stanford University, February 15, 2017.

Augustine, Chad, Jonathan Ho, and Nate Blair. “GeoVision Analysis Supporting Task Force Report: Electric Sector Potential to Penetration.” Golden, CO: National Renewable Energy Laboratory, 2019.

Snyder, Diana M., Koenraad J. Beckers, Katherine R. Young, and Henry Johnston. “Analysis of Geothermal Reservoir and Well Operational Conditions Using Monthly Production Reports from Nevada and California.” Davis, CA: Geothermal Resources Council, October 4, 2017.

EIA. “Annual Energy Outlook 2015 with Projections to 2040.” Annual Energy Outlook. Washington, D.C.: U.S. Energy Information Administration, 2015.

Oladosu, Gbadebo, Lindsay George, and Jeremy Wells. “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.

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.

Cole, Wesley, and Akash Karmakar. “Cost Projections for Utility-Scale Battery Storage: 2023 Update.” Golden, CO: National Renewable Energy Laboratory, 2023.

Leptinsky, Sarah, Marc Turner, Mark Woods, Jeffery Hoffmann, and Logan Hackett. “Cost and Performance Estimates for State-of-the-Art and Advanced 1x1 H-Class Natural Gas-Fired Power Plants.” National Energy Technology Laboratory, June 2024.

EIA. “Annual Energy Outlook 2023.” Washington, D.C.: U.S. Energy Information Administration, March 2023.

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