2021 ATB data for utility-scale solar photovoltaics (PV) are shown above. The Base Year estimates rely on modeled capital expenditures (CAPEX) and operation and maintenance (O&M) cost estimates benchmarked with industry and historical data. Capacity factor is estimated for 10 resource classes, b Contact online >>
2021 ATB data for utility-scale solar photovoltaics (PV) are shown above. The Base Year estimates rely on modeled capital expenditures (CAPEX) and operation and maintenance (O&M) cost estimates benchmarked with industry and historical data. Capacity factor is estimated for 10 resource classes, binned by mean global horizontal irradiance (GHI) in the United States. The 2021 ATB presents capacity factor estimates that encompass a range associated with advanced, moderate, and conservative technology innovation scenarios across the United States. Future year projections are derived from bottom-up benchmarking of PV CAPEX and bottom-up engineering analysis of O&M costs.
A detailed description of the scenarios is below.
The map below shows average annual GHI in the United States.
Utility-Scale PV Resource Classes
DOE''s Solar Energy Technologies Office sets its PV cost targets for a location centered geographically within the continental U.S., in resource class 7, whereas the ATB benchmark is class 5, representing the national-average solar resource.
Summary of Technology Innovations by Scenario (2030)
Technology Description: Tariffs on PV modules expire, as scheduled, though some form of friction still remains, keeping U.S. panel pricing halfway between current U.S. and global pricing. Efficiency gains for panels are consistent with one standard deviation below that of the International Technology Roadmap for Photovoltaic (ITRPV—an annual report prepared by many leading international poly-Si producers, wafer suppliers, c-Si solar cell manufacturers, module manufacturers, PV equipment suppliers, and production material providers, as well as PV research institutes and consultants) to 2030, which is well below historical monofacial average gains and is below the leveling-off point to 21.5% by 2030, resulting in a price of $0.32/WDC
Justification: This scenario represents the low end of industry expectations of average module efficiency in 2030 and additional friction despite the scheduled removal of the tariff.
Technology Description: Tariffs expire, as scheduled, and efficiency gains are consistent with median the ITRPV road map to 2030, which are well below historical monofacial average gains and are below the leveling-off point to 22.5% by 2030, which results in a price of $0.19/WDC
Justification: This scenario represents manufacturers'' expectations for 2030.
Technology Description: This scenario assumes medium-voltage power transmission or centralized power conversion center for inverters of $0.04/WDC.
Justification: Industry is currently switching to this practice.
Technology Description:This scenario includes 30% labor and hardware balance-of-system (BOS) cost improvements through automation, preassembly efficiencies (e.g. module mounting, and wiring), and improvements in wind load design
Justification: This scenario represents lower levels of improvement than the historical average(Feldman et al., 2021). With increased global deployment and a more efficient supply chain, preassembly of module mounting and wiring is possible. Best practices for permitting interconnection and PV installation (e.g. subdivision regulations, new construction guidelines, and design requirements) are being developed.
Technology Description: This scenario assumes a 5% energy gain through lower system losses, increased use of bifacial modules, improvements in bifaciality, and a degradation rate reduction from 0.7%/yr to 0.5%/yr
Justification: Significant R&D is currently spent on better tracking, improved cell temperatures and lower degradation rates. Companies will likely continue to focus on improved uptime to maximize profitability, and bifacial modules are already becoming a significant part of the global and U.S. supply chain. ITRPV estimates bifacial modules'' world market share will grow from 10% in 2018 to over 60% by 2030. Industry participants have already demonstrated bifacial energy gains of 5%–33%, depending on the module mounting and other factors like albedo.
Technology Description: Modules maintain the historical average of 0.5% improvement per year to 25% by 2030, which results in a price of $0.17/WDC
Justification: Manufacturers reported mass produced cell efficiencies will increase from 20%–23% in 2018 to 21%–24% by 2021. Mass produced-monocrystalline and silicon heterojunction have already achieved cell efficiency records in a laboratory of 26.1% and 26.7% respectively.
Technology Description: This scenario assumes inverter design simplification and manufacturing automation results in an inverter price of $0.03/WDC.
Justification: The power electronics industry already has road maps to simplify and automate current products and there is more potential with increased industry size.
Technology Description: This scenario assumes 40% labor and hardware BOS cost improvements through automation and preassembly efficiencies (e.g. module mounting, and wiring); the use of carbon fiber, which is assumed to have achieved low-cost, replacing steel and aluminum, cuts mounting costs.
Justification: This scenario represents lower levels of improvement than the historical average(Feldman et al., 2021). With increased global deployment and a more efficient supply chain, preassembly of PV module mounting and wiring is possible. Reduction of supply chain margins (e.g., profit and overhead charged by suppliers, manufacturers, distributors, and retailers), will likely occur naturally as the U.S. PV industry grows and matures. Additionally, streamlining of installation practices through improved workforce development and training and developing standardized PV hardware is assumed.
Technology Description: This scenario assumes a 20% energy gain through lower system losses, increased use of bifacial modules, improvements in bifaciality, and improved siting to increase average albedo from 0.2 to 0.3 without a significant increase to site prep costs (which is similar to dirt, gravel, and concrete), and a degradation rate reduction from 0.7%/yr to 0.2%/yr
Justification: In addition to the justifications listed above, industry participants have already demonstrated bifacial energy gains of 5%–33%, depending on the module mounting, location, and albedo.
1 Module efficiency improvements represent an increase in energy production over the same area of space, in this case, the dimensions of a PV module. Energy yield gain represents an improvement in capacity factor, relative to the rated capacity of a PV systems. In the case of bifacial modules, the increase in energy production between two modules with the same dimensions does not currently change the capacity rating of the module under standard test conditions, as the rating is based on light from one direction. Additionally, the rated capacity of a system does not increase with fewer system losses (e.g., panel cleanings).
Utility-scale PV systems in the 2021 ATB are representative of one-axis tracking systems with performance and pricing characteristics in-line with a 1.34 DC-to-AC ratio-or inverter loading ratio (ILR) for current and future years(Feldman et al., 2021). We recognize that ILR is likely to change in the future, particularly with the adoption of bifacial modules, and to also be highly dependent on location. However, allowing for this change would require the optimization of ILR and CAPEX by resource bin and year, causing a range of prices, independent of other regional factors. We believe this would create less transparency and more confusion to the impact of technology changes to these individual LCOE categories.
This section describes the methodology to develop assumptions for CAPEX, O&M, and capacity factor. For standardized assumptions,seelabor cost,regional cost variation,materials cost index,scale of industry,policies and regulations, andinflation.
PV projections in the 2021 ATB are driven primarily by CAPEX cost improvements, along with improvements in energy yield, operational cost, and cost of capital (for theMarket + PoliciesFinancial Assumptions Case).
Though CAPEX is one of the drivers of lower costs, R&D efforts continue to focus on other areas to lower the cost of energy from utility-scale PV, such as longer system lifetime and improved performance. We developed three scenarios for system cost and performance characteristics in 2030, modeling as bounding levels:
Definitions: For a PV system, the rated capacity in the denominator is reported in terms of the aggregated capacity of either all its modules or all its inverters. PV modules are rated using standard test conditions and produce direct current (DC) energy; inverters convert DC energy/power to alternating current (AC) energy/power. Therefore, the capacity of a PV system is rated either in MWDC via the aggregation of all modules'' rated capacities or in MWAC via the aggregation of all inverters'' rated capacities. The ratio of these two capacities is referred to as the inverter loading ratio (ILR). The 2021 ATB assumes current estimates, and future projections use an inverter loading ratio of 1.34.
The PV industry typically refers to PV CAPEX in units of $/MWDC based on the aggregated module capacity. The electric utility industry typically refers to PV CAPEX in units of $/MWAC based on the aggregated inverter capacity; starting with the 2020 ATB, we use $/MWAC for utility-scale PV.
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