Concentrating Solar Power
2023 ATB data for concentrating solar power (CSP) are shown above. The base year is 2021; thus, costs are shown in 2021$. CSP costs in the 2023 ATB are based on cost estimates for CSP components (Kurup et al., 2022a) that are available in Version 2022.11.21 of the System Advisor Model (SAM), which details the updates to the SAM cost components. Future year projections are informed by the literature, National Renewable Energy Laboratory (NREL) expertise, and technology pathway assessments for reductions in capital expenditures (CAPEX) and operation and maintenance (O&M) costs.
The three scenarios for technology innovation are:
- Conservative Technology Innovation Scenario (Conservative Scenario): no change in CAPEX, O&M, or capacity factor from base year estimates (2021 for CSP) to 2050
- Moderate Technology Innovation Scenario (Moderate Scenario): projection based on recently published projections and NREL judgment of potential innovations in the powerblock, receiver, thermal storage, and solar field. It is anticipated that the ATB CSP 2021 CAPEX of $7,254/kWe could drop by approximately 30% to $5,078/kWe by 2030. From 2030 to 2050, CSP CAPEX is projected to fall to approximately $4,352/kWe.
- Advanced Technology Innovation Scenario (Advanced Scenario): projection based (1) on 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 powerblock, 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 2021 CAPEX of $7,254/kWe could drop to $4,062/kWe by 2030. From 2030 to 2050, CSP CAPEX could fall to approximately $3,047/kWe.(EIA, 2022)
Solar resource is prevalent throughout the United States, but the Southwest is particularly suited to CSP plants. The direct normal irradiance (DNI) resource across the Southwest, which is some of the best in the world, ranges from 6.0 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 GWe, which is almost tenfold the current total U.S. electricity generation capacity; and 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 2022.11.21 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's typical meteorological year (TMY) file; the 2017 TMY file for a site adjacent to the airport is used, and it was downloaded 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 2022.11.21 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.
|CSP Resource Class||DNI (kWh/m2/day)||Available Resource (GW)|
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 resource there.
CSP research for both current and future advanced technologies is primarily in four main areas: the powerblock, the receiver, the thermal storage, and the solar field. The following table highlights key innovation and research trends for the three ATB technology innovation scenarios.
|Scenario||Powerblock||Receiver||Thermal Storage||Solar Field|
|Conservative Scenario||Technology Description: No change is expected if costs stay similar to base year costs.||Technology Description: No change is expected if costs stay similar to base year costs.||Technology Description: No change is expected if costs stay similar to base year costs.||Technology Description: No change is expected if costs stay similar to base year costs.|
Technology Description: The supercritical cycle (supercritical carbon dioxide carbon dioxide [sCO2]) operates at 565°C with today's solar salts.
Justification: The DOE Supercritical Transformational Electric Power program and other countries (e.g., China) are researching the use of sCO2 with today's salts.
Technology Description: Advanced coatings are applied to today's receiver technology.
Justification: Testing of the coatings have found increased selective absorption and enhanced durability.
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 cost 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 powerblock is used.||Technology Description: A high-temperature receiver consistent with >700°C power cycle is used.||Technology Description: Advanced storage media compatible with >700°C delivery is used.||Technology Description: Very low-cost, modular solar fields with increased solar field efficiency are deployed.|
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 for 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 powerblock cost, and lowers O&M costs.
- Heliostat field improvements
- Significantly lower-cost heliostats are developed as a result of design changes and automated and high-volume manufacturing.
- General and soft costs improvements
- Expansion of 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.
- Greater deployment volume and learning is assumed for 2021 and onward based on current state of industry (IRENA, 2016); (Lilliestam et al., 2017).
These improvements are reflected in the following tables.
The scenarios for CSP described above have the following deployment assumptions underlying the cost curves:
|Scenario||Base Year: 2021||2030||2050|
|Conservative Scenario||A molten-salt (sodium nitrate/potassium nitrate; aka, 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; aka, 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 deployments and learning.|
|Advanced Scenario||A molten-salt (sodium nitrate/potassium nitrate; aka, solar salt) power tower with direct two-tank TES combined with a steam-Rankine power cycle.||Decreased costs based on molten-salt power tower with direct two-tank TES combined with a 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.
|Moderate Scenario||10-12% (Breyer et al., 2017)||10-12% (Breyer et al., 2017)|
|Advanced Scenario||10-15%||20% (Murphy et al., 2019)|
Concentrating solar power (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 2021, of the 6,246 MW of installed and operating CSP capacity in the world, more than 4,000 MW were operational parabolic trough CSP ((SolarPACES, 2021); (Turchi et al., 2017)). In the 2023 ATB, the representative CSP technology is assumed to be molten-salt power towers, as indications are molten-salt power towers have the greatest cost reduction potential.
CSP in general, and power towers e.g., based on the global deployment of less than 2-GWe, can be considered early in it's deployment life. As such, there are still challenges and difficulties the CSP sector and power towers have faced from previous projects. For power towers relative to troughs, the main operating issue includes reliability concerns of 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 current and future 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 that power towers operate in (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 for electricity generation after sunset. 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.
In 2021, approximately 1 GWe of CSP electricity plants were under construction. Of this, parabolic trough projects made up approximately 70% (0.7 GWe), and they were followed by power towers at 30% (0.3 GWe) of plants under construction (REN21, 2022). 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 are being completed in Dubai (NREL, "Concentrating Solar Power Projects"; (Noor Energy 1, 2022)).
The largest CSP plant being currently constructed in the world is the 700-MW combined parabolic trough and power tower system in Dubai, United Arab Emirates. This Dubai Electricity and Water Authority 700-MW complex (with an additional 250 MW of photovoltaics), which is under construction, is composed of 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) ( (IRENA, 2016), (Mehos et al., 2017)). These towers are part of the DOE Generation 3 (Gen3) road map 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/WAC ((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:
- Three operational power tower plants totaling 392 MWe (e.g., the Ivanpah project) (SolarPACES, 2020); (EIA, 2022).
- Eight operating parabolic trough projects totaling approximately 1,500 MWe ( (EIA, 2021); NREL, "Concentrating Solar Power Projects in the United States").
The CSP technologies highlighted in the 2023 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.
|2021||A molten-salt (sodium nitrate/potassium nitrate; aka, 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: Moderate Scenario||Longer-term cost reductions (e.g., in the heliostats, TES, and power system)|
|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|
Though 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").
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 2023 ATB, various factors are used to demonstrate the range of LCOE and performance across the United States, including that:
- CAPEX is determined using manufacturing cost models and is benchmarked with industry data. CSP performance and cost are based on the molten-salt power tower technology with dry-cooling to reduce water consumption.
- O&M cost is benchmarked against industry data.
- Capacity factor varies with 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 2023 ATB are based on cost estimates for CSP components that are available in Version 2022.11.21 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, 2022).
Future year projections are informed by the literature, NREL 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 CAPEX, O&M, or capacity factor from base year estimates (2021 for CSP) to 2050
- Moderate Scenario: based on recently published projections and NREL 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)). From analysis of these sources, it is anticipated that the 2021 CAPEX of $7,254/kWe, could drop by approximately 30% to $5,078/kWe by 2030. From 2030 to 2050, CAPEX is projected to fall to approximately $4,352/kWe.
- Advanced Scenario: based on the lower bound of the literature sample and on the Power to Change report (IRENA, 2016).
Capital Expenditures (CAPEX)
Definition: For plants whose construction duration exceeds one year, CAPEX costs represent technology costs that lag current-year estimates by at least one year. For CSP plants, the construction period is typically 3 years.
In the 2023 ATB, CAPEX does not vary with resource.
Base Year: The CAPEX estimate (with a base year of 2021) is approximately $7,254/kWe in 2021$. It is for a representative power tower with 10 hours of storage and a solar multiple of 2.4. Based on recent assessment of the industry in 2022 and updated CSP systems costs reflected in SAM 2022.11.21 (Turchi et al., 2019); (Kurup et al., 2022a).
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 the indirect and direct contingencies.
- Field capital cost include the heliostat installed cost, site improvements, tower, receiver, and the 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 (2021 for CSP) to 2050; consistent across all renewable energy technologies in the 2023 ATB
- Moderate Scenario: based on recently published projections and NREL judgment of U.S. costs for future CAPEX in 2025, 2030, 2040, and 2050 ((IRENA, 2016); (Breyer et al., 2017); (Murphy et al., 2019); (Feldman et al., 2016); (World Bank, 2014)). From analysis of these sources, it is anticipated that the 2021 CAPEX of $7,254/kWe could drop by approximately 30% to $5,078/kWe by 2030. From 2030 to 2050, CAPEX is projected to fall to approximately $4,352/kWe.
- Advanced Scenario: based on the lower bound of the literature sample, and on the Power to Change report (IRENA, 2016).
Considering currently reported CAPEX for plants either announced or in construction, $7,254/kWe in 2021 and $5,078/kWe in 2030 is 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 $6,500/kWe in 2018$ (Kistner, 2016). The Dubai Electricity and Water Authority has an estimated bundled CAPEX of $5,500/kWe in 2018$ ((Shemer, 2018), (Turchi et al., 2019)).
A range of literature projections is shown in the chart below to illustrate the comparison with the 2023 ATB. When comparing the 2023 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 in-line 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.
Operation and Maintenance (O&M) Costs
Definition: Operation and maintenance (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 $69/kW-yr in 2021. Variable O&M is approximately $3.66/MWh in 2021 and $3.59/MWh after 2022 (Kurup and Turchi, 2015).
Future Years: Future FOM is assumed to decline until 2030 to approximately $52/kW-yr in the Moderate Scenario (i.e., approximately a 25% drop) and approximately $45/kW-yr by 2030 in the Advanced Scenario based on DOE investments that are likely to help lower costs (DOE, 2012).
Use the following table to view the components of OPEX.
Definition: Capacity factors are influenced by power block technology, storage technology and capacity, the solar resource, expected downtime, and energy losses. The solar multiple is a design choice that influences the capacity factor.
Base Year: The 2023 ATB capacity factors are generated from plant simulations using SAM Version 2022.11.21 at the resource locations identified below, with 10 hours of storage, and corroborated by operating data:
- Class 8: Abilene, Texas: 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.
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 gigawatts electrical (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 that is due to degradation of mirrors and other components is not accounted for in the 2023 ATB estimates of capacity factor or LCOE.
Estimates of capacity factors for CSP in the 2023 ATB represent typical operation 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.
The following references are specific to this page; for all references in this ATB, see References.