Concentrating Solar Power

2025 Annual Technology Baseline (ATB) data for concentrating solar power (CSP) are shown above. The Base Year is 2023; thus, costs are shown in 2023 USD. CSP costs in the 2025 ATB are based on cost estimates for CSP components (Kurup et al., 2022a) that are available in Version 2024.12.12 of the System Advisor Model (SAM), which details the updates to the SAM cost components. Future year projections are informed by the literature, National Laboratory of the Rockies (NLR) expertise, and technology pathway assessments for reductions in capital expenditures (CAPEX) and operations and maintenance (O&M) costs.

Costs within any given year and for any given project can vary based on site-specific or larger market factors. The chart below shows the 2025 ATB research and development (R&D) CAPEX trajectories for concentrating solar power in the context of historical ranges.

The three scenarios for technology innovation are as follows:

Conservative Technology Innovation Scenario (Conservative Scenario): No change in O&M or capacity factor from Base Year estimates (2023 for CSP) to 2050; CAPEX is reduced at a rate of 0.5% per year from 2023 to 2050, under the assumption of continuous improvement in the CSP supply chain from the installation of international projects; no change in CAPEX is assumed from 2050 to 2060.
Moderate Technology Innovation Scenario (Moderate Scenario): Projection based on recently published projections and NLR judgment of potential innovations in the power block, receiver, thermal storage, and solar field ((Murphy et al., 2019); (Mehos et al., 2020)). It is anticipated that the ATB CSP 2023 CAPEX of $7,868/kilowatts-electric (kWe) could drop by approximately 31% to $5,359/kWe by 2030, which is attributable to learning rates from new deployments, conversion of plant format to power parks that include multiple solar fields, and a conversion of the power block to a supercritical CO2 (sCO2) cycle at nitrate salt temperatures (i.e., 550–560°C). From 2030 to 2050, CSP CAPEX is projected to fall to approximately $4,610/kWe. This is a 14% reduction that may be attributed to learning rates from further ongoing deployments. From 2050 to 2060, there is no further reduction in the Moderate Scenario.
Advanced Technology Innovation Scenario (Advanced Scenario): Projection based on 1) the increased deployment of CSP based on hitting U.S. Department of Energy (DOE) Solar Energy Technologies Office cost targets (Murphy et al., 2019), the lower bound of the literature sample, and 2) on the Power to Change report (IRENA, 2016), consistent with innovations in power block, receiver, and thermal storage to accommodate higher-temperature systems and modularity in the solar field. It is anticipated that for the Advanced Scenario, the ATB CSP 2023 USD CAPEX of $7,868/kWe could drop to $4,310/kWe by 2030, or a 45% reduction. CSP CAPEX could fall to approximately $3,260/kWe, or a 24% further reduction from 2030 to 2050, which is attributable to accelerated learning rates and increased deployment. From 2050 to 2060, with further learning and improvements, costs could decrease in the Advanced Scenario to $3,063/kWe, or approximately a 6% reduction.

CSP technologies are not among the limited set of technologies explored in the pilot Expanded Cost Drivers Case, and therefore 2025 ATB technology innovation scenarios do not capture supply chain constraints or other cost factor assumptions for these technologies.

Resource Categorization

The solar resource is prevalent throughout the United States, but the Southwest is particularly suited to CSP plants. The direct normal irradiance (DNI) resources across the Southwest, which are some of the best in the world, range from 6.0 kilowatt hours/square meters/day (kWh/m²/day) to more than 7.5 kWh/m²/day (Roberts, 2018). The raw resource technical potential of seven states (Arizona, California, Colorado, Nevada, New Mexico, Utah, and Texas) exceeds 11,000 gigawatts-electric (GWe), which is almost tenfold the current total U.S. electricity generation capacity; some regions in these states have an annual average resource greater than 6.0 kWh/m²/day (Mehos et al., 2009).

For illustration in the ATB, a range of capacity factors calculated in SAM Version 2023.12.17 is associated with three resource locations in the contiguous United States for three classes of insolation:

Class 8: Abilene Regional Airport, Texas: 6.16 kWh/m²/day based on the site typical metrological year (TMY); the TMY file is available from the National Solar Radiation Database (NSRDB) Data Viewer.
Class 3: Phoenix, Arizona: 7.34 kWh/m²/day based on the site physical solar model (PSM) TMY3; the TMY file used is available in SAM Version 2024.12.12 as phoenix_az_33.450495_-111.983688_psmv3_60_tmy.
Class 2: Daggett, California: 7.67 kWh/m²/day based on the site PSM TMY3 file; the TMY file used is available in SAM Version 2022.11.21 as daggett_ca_34.865371_-116.783023_psmv3_60_tmy.

Full Categorization of DNI Resource Classes

CSP Resource Class	DNI (kWh/m²/day)	Available Resource (GW)
Class 1	>7.75	114
Class 2	7.50–7.75	677
Class 3	7.25–7.50	1,251
Class 4	7.00–7.25	1,381
Class 5	6.75–7.00	1,098
Class 6	6.50–6.75	1,252
Class 7	6.25–6.50	1,282
Class 8	6.00–6.25	1,850
Class 9	5.75–6.00	1,725
Class 10	5.50–5.75	1,495
Class 11	5.25–5.50	1,925
Class 12	5.00–5.25	2,641

Source: (Murphy et al., 2019). Starting with the 2021 ATB, Class 1 is the best resource.

In the United States, CSP plants are already found in Arizona, California, Florida, and Nevada. California can be considered the most representative location for new plants in the United States because of the excellent resources there. In addition to the states with existing plants, New Mexico and Texas exhibit potential for future CSP deployment because of relatively low O&M and construction costs.

Scenario Descriptions

CSP research for both current and future advanced technologies is primarily in four main areas: the power block, the receiver, thermal storage, and the solar field. The following table highlights key innovation and research trends for the three ATB technology innovation scenarios.

Summary of Technology Innovations by Scenario (2030)

Scenario	Power Block	Receiver	Thermal Storage	Solar Field
Conservative Scenario	Technology Description: No change is expected, with cost reductions sourced from continuous improvement from increasing deployment.	Technology Description: No change is expected, with cost reductions sourced from continuous improvement from increasing deployment.	Technology Description: No change is expected, with cost reductions sourced from continuous improvement from increasing deployment.	Technology Description: No change is expected, with cost reductions sourced from continuous improvement from increasing deployment.
Moderate Scenario	Technology Description: The power cycle uses sCO2 instead of steam and operates at temperatures using today's solar salts (~550–565°C). Justification: Plants are being built and operated in other markets such as China and South Africa.	Technology Description: Advanced coatings are applied to today's receiver technology. Towers are quicker and cheaper to produce compared to today's technology. Justification: Testing of the coatings has found increased selective absorption and enhanced durability. Ongoing research is assessing what can be learned from the deployment of offshore wind turbines to improve CSP tower development.	Technology Description: Storage tank designs, pumps, and component configurations are improved. Justification: Engineering studies to improve designs are ongoing.	Technology Description: Improvements in heliostat installations lead to decreases in costs as a result of increased deployment and learning. Justification: The global pipeline of projects is significant, and projects are currently being constructed.
Advanced Scenario	Technology Description: An elevated-temperature (>700°C) sCO2 power block is used. The Gen 3 Particle Pilot Plant (G3P3) in development at Sandia National Laboratories is using particle-based storage to integrate with an sCO2 power cycle.	Technology Description: A high-temperature receiver consistent with >700°C power cycle is used.	Technology Description: Advanced storage media (particles) compatible with >700°C delivery are used.	Technology Description: Very low-cost, modular solar fields with increased solar field efficiency are deployed. For example, the 3 Gorges project deploys multiple solar fields for a single power block to improve optical efficiency.
Impacts	Higher cycle efficiencies and potential reduction in power block CAPEX and OPEX (operating expenses).	Higher temperatures delivered to thermal storage and power block.	Lower-cost storage medium and therefore reduced CAPEX Increased storage temperature feeding into increased delivery temperature.	Significantly lower CAPEX and OPEX for future CSP plants Increased automation and reduced assembly times and therefore decreased construction times.
References	(SolarPACES, 2024) (Lei, 2024) (Ho et al., 2020)	(Kraemer, 2019) (SolarPACES, 2017) (ASTRI, 2019)	(Mehos et al., 2017) (Ho et al., 2020)	(DOE, 2015) (SolarPACES, 2024) (REN21, 2024) (Thonig et al., 2023)

Projections of CAPEX and O&M for future utility-scale CSP plants are based on the three technology innovation scenarios developed for scenario modeling as bounding levels. In general, differences among the scenarios reflect different levels of adoption of innovations. Reductions in technology costs reflect the following cost-reduction opportunities:

Power tower improvements:
- Better and longer-lasting selective surface coatings improve receiver efficiency and reduce O&M costs.
- Advanced heat transfer fluids allow higher operating temperatures and lower-cost thermal energy storage.
- Development of the power cycle running at approximately >700°C and 55% gross efficiency improves cycle efficiency, reduces power block cost by reducing complexity in the plant's auxiliary systems, and lowers O&M costs. The Moderate Scenario assumes an sCO2 power cycle operating at temperatures compatible with nitrate salets (~550–650°C).
Heliostat field improvements: Significantly lower-cost heliostats are developed as a result of design changes, field deployments, and automated high-volume manufacturing.
General and soft cost improvements:
- Expansion of the world market leads to greater and more efficient supply chains and reduced supply chain margins (e.g., profit and overhead charged by suppliers, manufacturers, distributors, and retailers) (Kurup et al., 2022b).
- Expansion of access to a range of innovative financing approaches and business models reduces costs.
- Automation of O&M will lead to reduced O&M costs.
- Developing standard designs and building multiplant power parks to scale up the capacity of the plant to capture economies of scale, learning, and volume discounts.
- A new focus on accelerating the deployment of CSP, leveraging international experience—other plants are deployed in less than 2 years (China Blue Book 2024).
- Greater deployment volume and learning are assumed for 2023 and onward based on the current state of the industry ((IRENA, 2016); (Lilliestam et al., 2017)).

These improvements are reflected in the following tables.

Performance Details by Scenario

Scenario Assumptions

The scenarios for CSP described above have the following deployment assumptions underlying the cost curves.

Deployment Assumptions for Cost Curves

Scenario	Base Year: 2023	2030	2050
Conservative Scenario	A molten-salt (sodium nitrate/potassium nitrate, i.e., solar salt) power tower with direct two-tank thermal energy storage (TES) combined with a steam-Rankine power cycle.	No changes in technology and costs, with similar levels of deployment.	No significant learning effects.
Moderate Scenario	A molten-salt (sodium nitrate/potassium nitrate, i.e., solar salt) power tower with direct two-tank TES combined with a steam-Rankine power cycle.	Increased deployment across the world, leading to learning, cost decreases, and supply chain improvements. Near-term cost reductions in the heliostat and TES.	Longer-term cost reductions (e.g., in the heliostats, TES, and power system). Increased deployment and learning.
Advanced Scenario	A molten-salt (sodium nitrate/potassium nitrate, i.e., solar salt) power tower with direct two-tank TES combined with a steam-Rankine power cycle.	Decreased costs based on particulate tower and TES combined with an sCO2 power cycle running at >700°C and 55% gross efficiency.	Very low-cost heliostats and TES, with significant cost reductions. Significant growth in advanced sCO2 cycle development.

The cost curves are derived using the learning rates in the following table.

Estimated Learning Rates for Different Scenarios

Scenario	Base Year–2030	2030–2050
Conservative Scenario	0.5% cost decrease in CAPEX per year	0.5% cost decrease in CAPEX per year
Moderate Scenario	10%–12% cost decrease of the CAPEX per doubling of historic cumulative capacity (Breyer et al., 2017)	10%–12% cost decrease of the CAPEX per doubling of historic cumulative capacity (Breyer et al., 2017)
Advanced Scenario	10%–15% cost decrease of the CAPEX per doubling of the capacity	20% cost decrease of the CAPEX per doubling of the capacity (Murphy et al., 2019)

Representative Technology

CSP technologies capture the heat of the sun to drive a thermoelectric power cycle. The most widely deployed CSP technology uses parabolic trough collectors. As of 2023, of the 6,700 megawatts (MW) of installed and operating CSP capacity in the world, more than 5,100 MW was from operational parabolic trough CSP (REN21, 2024). In the 2025 ATB, the representative CSP technology is assumed to be molten-salt power towers because indications are molten-salt power towers have the greatest cost reduction potential (Mehos et al., 2017).

CSP in general and power towers (e.g., based on the global deployment of less than 2 GWe) can be considered early in their deployment life. As such, the CSP sector and power towers still face challenges and difficulties from previous projects. For power towers relative to troughs, the main operating issue includes reliability concerns with such systems, with the key challenges being connected to the molten-salt-related systems (e.g., heat trace, valves, receiver, and storage tanks). The main concerns that R&D is looking to address for power towers include the attenuation and effects of aerosols on towers, transient behavior of the heliostat field and power block, and soiling effects of the heliostats in the difficult desert environments in which power towers operate (Mehos et al., 2020).

Thermal energy storage (TES) is accomplished by storing molten salt in a two-tank system that includes a hot-salt tank and a cold-salt tank. Stored hot salt can be dispatched to the power block as needed, regardless of solar conditions, to continue power generation and allow electricity generation after sunset. CSP technology in the 2025 ATB is represented as 102 net-megawatt-electric (MWe) molten-salt power tower plants, which use today's sodium and potassium nitrate salts, with 10 hours of TES using a two-tank molten-salt system. This configuration is similar to the Crescent Dunes CSP plant in Nevada, is representative of new global CSP development, and has the potential for further cost reductions relative to other configurations, such as parabolic trough projects.

As of 2023, CSP plants under construction had a combined capacity of approximately 1.8 GWe, with an additional 2 GWe under development, mostly located in China (Thonig et al., 2023). Power towers account for 70% of the projects, parabolic troughs for 25%, and linear Fresnel for the remaining 5%. All projects but one—the Redstone project in South Africa—are co-located with solar PV, indicating a trend toward hybrid systems. Outside of China, the second phase of Dubai Electricity and Water Authority's (DEWA’s) Noor Energy 1 parabolic trough project was the only CSP installed in 2023, increasing global capacity by 400 MW (REN21, 2024). Molten-salt power tower plants have been built in Chile (e.g., the Cerro Dominador molten-salt power tower plant was synchronized with the grid in 2021 (Roca, 2021)) and in Dubai, United Arab Emirates (NLR, Concentrating Solar Power Projects (Noor Energy 1, 2022)). However, a supply chain of CSP projects under development is growing, with more than 20 projects currently under construction or under development.

The largest CSP plant in the world is the 700-MW combined parabolic trough and power tower system in Dubai. Completed in 2023, this DEWA 700-MW complex (with an additional 250 MW of photovoltaics) comprises 600 MW of parabolic troughs (i.e., 3 × 200-MW trough plants) and a 100-MW power tower site, with each plant having 12–15 hours of TES ((Noor Energy 1, 2022); (SolarPACES, 2019); (Lilliestam and Pitz-Paal, 2018)). In 2021, Noor III—a 150-MWe molten-salt power tower with 7.5 hours of storage—was exceeding performance expectations (Yvonne Kamau, 2021).

Current indications are that molten-salt power towers have the greatest cost reduction potential in terms of both CAPEX and levelized cost of energy (LCOE; (Zhu et al., 2022); (Mehos et al., 2017), (REN21, 2024)). These towers are part of the DOE Generation 3 (Gen3) roadmap for the next generation of commercial CSP plants (Mehos et al., 2017).

Crescent Dunes (110 MWe with 10 hours of storage) was the first large molten-salt power tower plant in the United States. It was commissioned in 2015 with a reported installed CAPEX of $8.96/watts alternating current (W_AC;(Danko, 2015); (Taylor, 2016)). Despite the emergence of power tower systems, the CSP landscape is still dominated by parabolic trough systems. The United States is home to the following:

Three operational power tower plants totaling 392 MWe (e.g., the Ivanpah project; (SolarPACES, 2020); U.S. Energy Information Administration [EIA])
Eight operating parabolic trough projects totaling approximately 1,500 MWe (EIA; NLR, Concentrating Solar Power Projects in the United States).

The CSP technologies highlighted in the 2025 ATB are assumed to be power towers, but they have different power cycles and operating conditions as time passes, as shown in the following table. Technology changes in the power block, if any, are assumed to occur in 2030 and remain consistent from 2030 to 2050 by scenario.

Changes to Power Cycles and Operating Condition Assumptions Over Time

Scenario	Description
2023	A molten-salt (sodium nitrate/potassium nitrate, i.e., solar salt) power tower with direct two-tank TES combined with a steam-Rankine power cycle running at 574°C and 41.2% gross efficiency
2030: Conservative Scenario	No changes to existing technology
2030: Moderate Scenario	Longer-term cost reductions (e.g., in the heliostats, TES, and power block)
2030: Advanced Scenario	A low projection based on molten-salt power tower with direct two-tank TES combined with a power cycle running at 700°C and 55% gross efficiency

Although an advanced molten-salt projection is used for the Advanced Scenario, lower costs for baseload CSP are being investigated via different technology options (e.g., solid particle and gas phase towers) and as defined by the DOE Gen3 program ((Mehos et al., 2017); DOE, Goals of the Solar Energy Technologies Office).

Methodology

This section describes the methodology to develop assumptions for CAPEX, O&M, and capacity factor. For standardized assumptions, see labor cost, regional cost variation, materials cost index, scale of industry, policies and regulations, and inflation.

For the 2025 ATB, various factors are used to demonstrate the range of LCOE and performance across the United States, including the following:

CAPEX is determined using manufacturing cost models and is benchmarked with industry data. CSP performance and costs are based on the molten-salt power tower technology with dry cooling to reduce water consumption.
O&M costs are benchmarked against industry data.
Capacity factor varies with the inclusion of TES and solar irradiance. The listed resource classes assume power towers with 10 hours of TES at three types of locations.

CSP costs in the 2025 ATB are based on cost estimates for CSP components available in Version 2024.12.12 of SAM. (Turchi et al., 2019); (Kurup et al., 2022a) detail the updates to the SAM cost components including the heliostats. DOE’s Solar Energy Technologies Office uses more conservative financial terms, which results in higher LCOE values than are obtained using the ATB methodology ((SolarPACES, 2021); (REN21, 2022); (Roca, 2021); (Noor Energy 1, 2022); (EIA, 2023)).

Future year projections are informed by the literature, NLR expertise, and technology pathway assessments for CAPEX and O&M cost reductions. Three projections are developed for scenario modeling as bounding levels:

Conservative Scenario: No change in O&M or capacity factor from Base Year estimates (2023 for CSP) to 2050; CAPEX is reduced at a rate of 0.5% per year from 2023 to 2050, under the assumption of continuous improvement in the CSP supply chain from the installation of international projects; no change in CAPEX is assumed from 2050 to 2060.
Moderate Scenario: Based on recently published projections and NLR judgment of U.S. costs for future CAPEX in 2025, 2030, 2040, and 2050 ((IRENA, 2016); (Breyer et al., 2017); (Feldman et al., 2016); (World Bank, 2014)). We assume no change in costs from 2050 to 2060.
Advanced Scenario: Based on the lower bound of the literature sample and on the Power to Change report (IRENA, 2016). We assume the learning rate is reduced by a factor of 2 from 2050 to 2060.

Capital Expenditures (CAPEX)

Definition: For plants whose construction duration exceeds 1 year, CAPEX costs represent technology costs that lag current-year estimates by at least 1 year. For CSP plants, the construction period is typically 3 years.

For the 2025 ATB—and based on key sources ((EIA, 2016); (Turchi, 2010); (Turchi and Heath, 2013))—the CSP generation plant envelope is defined to include items noted on the definitions page.

In the 2025 ATB, CAPEX does not vary with resource, though construction and O&M costs are likely to vary by location.

Base Year: The CAPEX estimate (with a base year of 2023) is approximately $7,868/kWe in 2023 USD. CSP technology in the 2022 ATB is represented as 102 net-MWe molten-salt power tower plants, which use today's sodium and potassium nitrate salts, with 10 hours of TES using a two-tank molten-salt system. This configuration is similar to the Crescent Dunes CSP plant in Nevada, is representative of new global CSP development, and has the potential for further cost reductions relative to other configurations, such as parabolic trough projects. Updated CSP system costs are reflected in SAM Version 2024.12.12 and are updated for inflation (Turchi et al., 2019); (Kurup et al., 2022a). The operating profile for this technology is primarily nighttime generation in the winter and approximates baseload production in the summer. The system design is consistent for all technology scenarios and years.

Note the CAPEX for the representative CSP plant in the ATB Data is estimated in the Base Year with three main portions:

Turbine capital costs include the power cycle, balance of plant, and indirect and direct contingencies.
Storage capital costs include the hot and cold tanks, molten-salt inventory, heat exchangers for the storage system, and indirect and direct contingencies.
Field capital costs include the heliostat installed cost, site improvements, tower, receiver, and indirect and direct contingencies.

Future Years: Three cost projections are developed for CSP technologies:

Conservative Scenario: No change in CAPEX, O&M, or capacity factor from Base Year estimates (2022 for CSP) to 2050; consistent across all renewable energy technologies in the 2025 ATB.
Moderate Technology Innovation Scenario (Moderate Scenario): Projection based on recently published projections and NLR judgment of potential innovations in the power block, receiver, thermal storage, and solar field ((Murphy et al., 2019); (Mehos et al., 2020)). It is anticipated that the ATB CSP 2023 CAPEX of $7,868/kWe could drop by approximately 32% to $5,359/kWe by 2030, which is attributable to learning from standard designs, international deployments, the development of power parks that include multiple solar fields, and a global supply chain. From 2030 to 2050, CSP CAPEX is projected to fall to approximately $4,610/kWe. This is a 14% reduction attributable to learning from increased deployment. From 2050 to 2060, there is no further reduction in the Moderate Scenario.
Advanced Technology Innovation Scenario (Advanced Scenario): Projection based on 1) the increased deployment of CSP based on hitting DOE Solar Energy Technologies Office cost targets (Murphy et al., 2019), the lower bound of the literature sample, and 2) on the Power to Change report (IRENA, 2016), consistent with innovations in power block, receiver, and thermal storage to accommodate higher-temperature systems and modularity in the solar field. It is anticipated that for the Advanced Scenario, the ATB CSP 2023 USD CAPEX of $7,868/kWe could drop to $4,310/kWe by 2030, or a 45% reduction. From 2030 to 2050, CSP CAPEX could fall to approximately $3,260/kWe, or a 24% further reduction (EIA, 2022). From 2050 to 2060, with further learning and improvements, costs could decrease in the Advanced Scenario to $3,063/kWe, or approximately a 6% reduction.

Considering currently reported CAPEX for plants either announced or in construction, $7,868/kWe in 2023 and $5,359/kWe in 2030 are possible. For example, the Noor III CSP power station in Morocco—a 150-MWe molten-salt power tower with 7.5 hours of storage that became operational in 2018—has an estimated CAPEX of $6,500/kWe in 2018 USD (Kistner, 2016). DEWA has an estimated bundled CAPEX of $5,500/kWe in 2018 USD ((Shemer, 2018); (Turchi et al., 2019)).

A range of literature projections is shown in the chart below to illustrate the comparison with the 2025 ATB. When comparing the 2025 ATB projections with other projections, note there are major differences in technology assumptions, radiation conditions, field sizes and solar multiples, storage configurations, and other factors. As shown in the chart, the Moderate Scenario projection is consistent with other recently analyzed projections from other organizations. The Advanced Scenario ATB projection is based on the lower bound of the literature sample and on the Power to Change report (IRENA, 2016).

Use the following tables to view the components of CAPEX and how they change with the scenarios.

Components of CAPEX

Cost Details by Scenario

Operation and Maintenance (O&M) Costs

Definition: O&M costs represent the annual expenditures required to operate and maintain a CSP plant over its lifetime, including items noted on the definitions page.

Base Year: Fixed O&M (FOM) is assumed to be approximately $77.7/kWe-yr in 2023, in which the kWe are defined as the nameplate capacity of the power block (i.e., net AC generation of the turbine at designed conditions). Variable O&M is approximately $4.1/MWh in 2023 (Kurup and Turchi, 2015); both assumptions are consistent with prior years and updated for inflation.

Future Years: Future FOM costs are assumed to decline until 2030 to approximately $57/kW-yr in the Moderate Scenario (i.e., approximately a 27% drop) and approximately $47/kW-yr by 2030 in the Advanced Scenario (i.e., approximately a 39% drop) based on DOE investments likely to help lower costs (DOE, 2012).

Use the following table to view the components of OPEX.

Components of OPEX

Capacity Factor

Definition: Capacity factors are influenced by power block technology, storage technology and capacity, solar resources, expected downtime, and energy losses. The solar multiple is a design choice that influences the capacity factor.

Base Year: The 2025 ATB capacity factors are generated from plant simulations using SAM Version 2024.12.12 at the resource locations identified below, with 10 hours of storage, and corroborated by operating data:

Class 8: Abilene Regional Airport: leads to a 51.4% capacity factor
Class 3: Phoenix, Arizona: leads to a 64.7% capacity factor
Class 2: Daggett, California: leads to a 66.6% capacity factor.

In all three cases above, the solar field design is consistent. A key finding of (Murphy et al., 2019) is that if future costs of CSP decrease sufficiently, CSP could be deployed across a greater range of the United States and DNI resources, such as in Texas as highlighted in the lower DNI example. For example, with aggressive cost decreases and given regional market constraints, southeastern states with lower DNI resources (e.g., Florida and South Carolina) could see CSP capacity deployments of up to 5 GWe (Murphy et al., 2019).

Future Years: The future capacity factor projections for the Conservative, Moderate, and Advanced Scenarios are unchanged from the Base Year. Technology improvements are focused on CAPEX and O&M cost elements.

Over time, CSP plant output may decline. Capacity factor degradation because of the degradation of mirrors and other components is not accounted for in the 2025 ATB estimates of capacity factor or LCOE.

Estimates of capacity factors for CSP in the 2025 ATB represent typical operations and are based on the location's DNI. The dispatch characteristics of these systems are valuable to the electric system in managing changes in net electricity demand. Actual capacity factors will likely be influenced by the degree to which system operators call on CSP plants to manage grid services.

References

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

ASTRI. “Public Dissemination Report.” Australian Solar Thermal Research Institute, June 2019. https://arena.gov.au/assets/2013/01/astri-public-dissemination-report.pdf.

Breyer, Christian, Svetlana Afanasyeva, Dietmar Brakemeier, Manfred Engelhard, Stefano Giuliano, Michael Puppe, Heiko Schenk, Tobias Hirsch, and Massimo Moser. “Assessment of Mid-Term Growth Assumptions and Learning Rates for Comparative Studies of CSP and Hybrid PV-Battery Power Plants.” In AIP Conference Proceedings, 1850:160001-1-160001–9. AIP Publishing, 2017. https://doi.org/10.1063/1.4984535.

Danko, Pete. “SolarReserve: Crescent Dunes Solar Tower Will Power Up in March, Without Ivanpah’s Woes.” Breaking Energy, February 10, 2015. https://breakingenergy.com/2015/02/10/solarreserve-crescent-dunes-solar-tower-will-power-up-in-march-without-ivanpahs-woes/.

DOE. “SunShot Vision Study.” Washington, D.C.: U.S. Department of Energy, February 2012. https://doi.org/10.2172/1039075.

DOE. “DE-FOA-0001268: Concentrating Solar Power: Concentrating Optics for Lower Levelized Energy Costs (COLLECTS),” 2015. https://eere-exchange.energy.gov/Default.aspx?Search=DE-FOA-0001268.

EIA. “Capital Cost Estimates for Utility Scale Electricity Generating Plants.” Washington, D.C.: U.S. Energy Information Administration, 2016. https://www.eia.gov/analysis/studies/powerplants/capitalcost/pdf/capcost_assumption.pdf.

EIA. “Solar Explained - Solar Thermal Power Plants,” April 15, 2022. https://www.eia.gov/energyexplained/solar/solar-thermal-power-plants.php.

EIA. “Annual Energy Outlook 2023.” Washington, D.C.: U.S. Energy Information Administration, March 2023. https://www.eia.gov/outlooks/aeo/.

Feldman, David, Robert Margolis, Paul Denholm, and Joseph Stekli. “Exploring the Potential Competitiveness of Utility-Scale Photovoltaics plus Batteries with Concentrating Solar Power, 2015-2030.” Golden, CO: National Renewable Energy Laboratory, 2016. https://doi.org/10.2172/1321487.

Ho, Clifford K., Kevin J. Albrecht, Lindsey Yue, Brantley Mills, Jeremy Sment, Joshua Christian, and Matthew Carlson. “Overview and Design Basis for the Gen 3 Particle Pilot Plant (G3P3).” In AIP Conference Proceedings, 2303:030020. Daegu. South Korea: AIP Publishing, 2020. https://doi.org/10.1063/5.0029216.

IRENA. “The Power to Change: Solar and Wind Cost Reduction Potential to 2025.” Abu Dhabi, United Arab Emirates: International Renewable Energy Agency, 2016. https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2016/IRENA_Power_to_Change_2016.pdf.

Kistner, Rainer. “Update on Recent Developments in the CSP Technology.” Berlin, Germany: Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH, 2016. https://www.giz.de/de/downloads/giz2016_en_CSP%20Update_Abu%20Dhabi.pdf.

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