Residential PV
Units using capacity above represent kWDC.
2025 Annual Technology Baseline (ATB) data for residential solar photovoltaics (PV) are shown above, with a base year of 2023. The Base Year estimates rely on modeled capital expenditures (CAPEX) and operations and maintenance (O&M) cost estimates benchmarked with industry and historical data. Capacity factor is estimated based on hours of sunlight at latitude for 10 resource categories in the United States, binned by mean global horizontal irradiance (GHI). The 2025 ATB presents capacity factor estimates that encompass a range associated with advanced, moderate, and conservative technology innovation scenarios across the United States. The 2025 residential-scale solar PV ATB, for the first time, has analyses for a Research and Development (R&D) cost drivers case and a broader Expanded cost drivers case, with each having assumptions for the set of underlying drivers that affects costs:
- R&D cost drivers case: Estimates costs based on R&D-driven improvements only, as applied to technologies and conditions existing during the most recent year with historical data.
- Expanded cost drivers case: Estimates costs based on R&D-driven improvements plus other cost drivers, such as changing market and supply chain conditions.
These definitions are explained further on the Financial Cases & Methods page. Future year projections for each cost drivers case are derived from bottom-up benchmarking of PV CAPEX and bottom-up engineering analysis of O&M costs. The year 2024 reflects the most recent historical data, derived from benchmarks made in the first quarter of 2024. Specific projections are made for 2030, 2040, 2050, and 2060. Straight lines interpolate between the 2024 and 2030 values, between the 2030 and 2040 values, between the 2040 and 2050 values, and between the 2050 and 2060 values. Cost fluctuations that may occur between each set of years are not represented, such as the fluctuations because of policy and market conditions that occurred after the first quarter of 2024.
Each cost drivers case has three projection scenarios for technology advancement and evolution as follows:
- Conservative Scenario: lower levels of R&D investment with minimal technology advancement and market conditions that result in domestically produced PV components
- Moderate Scenario: R&D investment continuing at similar levels as today, with corresponding levels of technological advancement and market conditions allowing for component price reductions consistent with trends from the past several years
- Advanced Scenario: an increase in R&D spending generates substantial innovation that drives down costs; market conditions reflect improved access to global markets.
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 R&D and Expanded cases' CAPEX trajectories for residential PV in the context of historical ranges.
Historical Sources: (DOE, 2024); (Barbose et al., 2024); (Ramasamy et al., 2022); (Ramasamy et al., 2023).
Future Projections: 2025 ATB.
Resource Categorization
The 2025 ATB provides the average capacity factor for 10 resource categories in the United States, binned by mean GHI. The annual average capacity factor for the contiguous United States is calculated using the Renewable Energy Potential (reV) model using solar resource data for 2012 from the National Solar Radiation Database (NSRDB). The county-level capacity factors are calculated for specific locations with azimuth and tilt, which are based on representative agents selected in the Distributed Generation Market Demand Model (dGen) 2020 Standard Scenarios agent database (Sigrin et al., 2016). A lookup table for these locations and the NSRDB is generated based on nearest distance. The azimuth and tilt as well as the resource GHI are used to generate a System Advisor Model (SAM) configuration file and run reV, which outputs the annual average capacity factor at each evaluated location. The U.S. average capacity factor for each resource category is weighted by the population of each county within the GHI resource category. The county estimated populations are provided by geospatial and tabular data from the U.S. Census. The map below shows average annual GHI in the United States.
The following table summarizes estimated 2019 capacity factors (in the first year of operation) for each resource category and each resource category's associated population.
| Resource Class | GHI Bin (kilowatt-hours/square meters/day [kWh/m2/day]) | Mean Direct Current (DC) Capacity Factor | Population |
| 1 | >5.75 | 19.6% | 12,554,678 |
| 2 | 5.5–5.75 | 19.3% | 21,403,290 |
| 3 | 5.25–5.5 | 18.0% | 13,476,871 |
| 4 | 5–5.25 | 17.0% | 30,603,630 |
| 5 | 4.75–5 | 16.1% | 45,176,116 |
| 6 | 4.5–4.75 | 15.9% | 39,880,837 |
| 7 | 4.25–4.5 | 15.2% | 31,742,606 |
| 8 | 4–4.25 | 14.5% | 80,155,804 |
| 9 | 3.75–4 | 13.9% | 40,755,023 |
| 10 | <3.75 | 12.7% | 10,255,830 |
| Mean | 15.7% |
Scenario Descriptions
| Year | Module Efficiency | Inverter Power Electronics | Installation Efficiencies |
| 2030 | Technology Description: R&D case: Module efficiency (24%) is based on the International Technology Roadmap for Photovoltaic (ITRPV) projected 2030 Tunnel Oxide Passivated Contact (TOPCon) and Passivated Emitter and Rear Cell (PERC) module efficiency. TOPCon is assumed to almost fully comprise the market, with some PERC presence. This scenario assumes similar proportions of U.S. manufacturing and imported products as existed in 2024, with no product improvements beyond efficiency increases. The 2024 module market price ($0.39/watts direct current [WDC]) and efficiency (21%) from (DOE, 2024) are adjusted for 2030 module efficiency, resulting in a module cost of $0.34/WDC. Expanded case: This scenario assumes module price increases because of significant trade barriers and U.S. manufacturers scaling up capacity, with PERC comprising the entire market with an efficiency of 22%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. National Laboratory of the Rockies (NLR) internal analysis projected the cost of a potential fully U.S. manufactured modules market, resulting in a module cost of $0.55/WDC. Justification: This scenario represents the low end of projected module efficiency and high end of cost projections. | Technology Description: R&D case: A modeled market price (MMP) is assumed, resulting in an inverter price of $0.36/WDC. Expanded case: A 20% increase in inverter costs is assumed because of trade barriers. An MMP basis results in an inverter price of $0.43/WDC. Justification: Increasing trade barriers and reliance on domestic manufacturing may result in higher costs, reflected in the Expanded case. The R&D case represents a conservative projection of inverter prices. | BOS and labor costs decrease proportionally to the increase in module efficiency.
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| 2040 | Technology Description: R&D case: Module efficiency (25%) uses ITRPV projected TOPCon module efficiency extrapolated to 2040. TOPCon is assumed to fully comprise the market. This scenario assumes similar proportions of U.S. manufacturing and imported products as existed in 2024, with no product improvements beyond efficiency increases. The 2024 module market price ($0.39/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2040 module efficiency, resulting in a module cost of $0.33/WDC. Expanded case: This scenario assumes module price increases because of significant trade barriers and U.S. manufacturers scaling up capacity, with an interpolated module efficiency of 23%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. NLR internal analysis projected the cost of a potential fully U.S. manufactured modules market, resulting in a module cost of $0.53/WDC. Justification: This scenario assumes limited improvements in technology efficiency. Market disruptions are not fully resolved in the Expanded case. Module manufacturing is fully scaled up and efficient in the R&D case. | No change vs. 2024.
| BOS and labor costs decrease proportionally to the increase in module efficiency.
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| 2050 | Technology Description: R&D case: This scenario assumes similar proportions of U.S. manufacturing and imported products as existed in 2024, with no product improvements beyond efficiency increases. Module efficiency (25%) is extrapolated from the 2040 projected efficiency. The 2024 module market price ($0.39/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2050 module efficiency, resulting in a module cost of $0.32/WDC. Expanded case: This scenario assumes module price increases because of significant trade barriers and U.S. manufacturers scaling up capacity, with an interpolated module efficiency of 23%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in 🗨(DOE, 2024) is applied to rooftop module costs. NLR internal analysis projected the cost of a potential fully U.S. manufactured modules market, resulting in a module cost of $0.52/WDC. Justification: This scenario assumes limited improvements in technology efficiency. Market disruptions are not fully resolved in the Expanded case. Module manufacturing is fully scaled up and efficient in the R&D case.
| No change vs. 2024.
| BOS and labor costs decrease proportionally to the increase in module efficiency. |
| 2060 | Technology Description: R&D case: This case assumes module costs remains the same beyond 2050, at $0.32/WDC. Expanded case: This scenario assumes module price increases because of significant trade barriers and U.S. manufacturers scaling up capacity, and TOPCon constitutes the entire market with an efficiency of 24%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in 🗨(DOE, 2024) is applied to rooftop module costs. NLR internal analysis projected the cost of a potential fully U.S. manufactured modules market, resulting in a module cost of $0.50/WDC. Justification: 🗨🗨This scenario assumes limited improvements in technology efficiency. Market disruptions are not fully resolved in the Expanded case. Module manufacturing is fully scaled up and efficient in the R&D case. | No change vs. 2024.
| R&D case: This case assumes BOS and installation labor costs remain the same beyond 2050. Expanded case: BOS and labor costs decrease proportionally to the increase in module efficiency.
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| Year | Module Efficiency | Inverter Power Electronics | Installation Efficiencies |
| 2030 | Technology Description: Efficiency of 24% is calculated using the weighted average of ITRPV projected efficiency and market shares of module technology types, with TOPCon constituting more than half the market.
A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: This scenario assumes a 35% reduction from the 2024 MMP for modules, resulting in $0.25/WDC. Expanded case: 2024 module price is projected to 2030 🗨using 2/3 of the rate of decline observed during 2018–2024 (EIA, 2023), resulting in $0.29/WDC. Justification: 🗨This scenario represents business as usual with a moderate short-term module efficiency-improvement expectation and a module price reduction following historical rates. | No change vs. 2024 (DOE, 2024).
| Technology Description: This scenario assumes 10% labor and hardware BOS cost improvements from 2024 minimum sustainable pricing through automation and preassembly efficiencies (e.g., module mounting and wiring) and through higher labor productivity (e.g., through better workforce training) and access to advanced hardware technologies. Justification: This scenario represents lower levels of improvement compared to the long-term historical average (Ramasamy et al., 2025). |
| 2040 | Technology Description: ITRPV market shares and efficiencies are linearly extrapolated outward to 2040, and efficiency is calculated using a weighted average approach, resulting in 26%.
A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: This scenario assumes a 55% reduction from the 2024 MMP for modules, resulting in $0.18/WDC. Expanded case: Module price decreases from 2030 by 1/2 of the U.S. Energy Information Administration (EIA) 🗨(EIA, 2023) rate from 2018 to 2024, reaching $0.21/WDC. Justification: This scenario represents business as usual with a moderate short-term module efficiency-improvement expectation and a module price reduction following historical rates. | Technology Description: R&D case: This scenario assumes inverter design simplification and manufacturing automation result in an inverter price of $0.33/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.27/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size. | Technology Description: This scenario assumes 35% labor and hardware BOS cost improvements over the 2024 market price through automation and preassembly efficiencies (e.g., module mounting and wiring) and through higher labor productivity (e.g., through better workforce training) and access to advanced hardware technologies. Justification: This scenario represents lower levels of improvement compared to the long-term historical average (Ramasamy et al., 2025). With increased global deployment and a more efficient supply chain, preassembly of module mounting and wiring is possible. |
| 2050 | Technology Description: Efficiency is calculated using the average of 2040 and 2060 Moderate Scenario projected efficiencies, resulting in efficiency of 27%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: 🗨This scenario assumes a 65% reduction from the 2024 MMP for modules, resulting in $0.14/WDC. Expanded case: Module price reduces from 2040 by 1/4 of the EIA rate 🗨(EIA, 2023) from 2018 to 2024, resulting in $0.18/WDC. Justification: This scenario represents business as usual with a moderate short-term module efficiency-improvement expectation and a module price reduction following historical rates. | Technology Description: R&D case: This scenario assumes inverter design simplification and manufacturing automation result in an inverter price of $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.17/WDC. Justification: The power electronics industry already has roadmaps 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 🗨over the 2024 market price through automation and preassembly efficiencies (e.g., module mounting and wiring) and through higher labor productivity (e.g., through better workforce training) and access to advanced hardware technologies. Justification: This scenario represents lower levels of improvement compared to the long-term historical average (Ramasamy et al., 2025). 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. |
| 2060 | Technology Description: Efficiency is calculated using the average of 2060 Conservative Scenario and Advanced Scenario projected efficiencies, resulting in an efficiency of 29%. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. 🗨 R&D case: This scenario assumes module costs remain the same beyond 2050, at $0.14/WDC. Expanded case: Assumes a lower end of module efficiency at 28%.🗨🗨 Module price decreases from 2050 by 1/6 of EIA rate (EIA, 2023) from 2018 to 2024, resulting in a module price of $0.17/WDC. Justification: This scenario represents business as usual with a moderate short-term module efficiency-improvement expectation and a module price reduction following historical rates. | Technology Description: R&D case: This case assumes inverter costs remain the same beyond 2050, at $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.09/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size and longer timelines. | Technology Description: R&D case: This scenario assumes labor and hardware BOS cost remain the same beyond 2050. Expanded case: This scenario assumes 45% labor and hardware BOS cost improvements over 2024 market pricing through automation and preassembly efficiencies (e.g., module mounting and wiring). Justification: This scenario represents lower levels of improvement than the historical average (Ramasamy et al., 2025). 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. |
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| Year | Module Efficiency | Inverter Power Electronics | Installation Efficiencies |
| 2030 | Technology Description: This scenario assumes rapid improvements in module efficiency, based on ITRPV projected 2030 module efficiency with removal of PERC and increased tandem PV presence, resulting in a weighted average efficiency of 25%.
A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: The MMP is adjusted for module efficiency improvements, combined with a 45% reduction in costs from manufacturing improvements, resulting in $0.18/WDC. Expanded case: The 2024 global module spot price ($0.10/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2030 module efficiency, resulting in a module cost of $0.10/WDC. Justification: This scenario represents a more aggressive technological scenario with rapid shifts to high-efficiency module technologies and, in the Expanded case, assumes access to global market pricing. | Technology Description: R&D case: This scenario assumes inverter design simplification and manufacturing automation result in an inverter price of $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.17/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size. | Technology Description: This scenario assumes a 30% reduction from 2024 prices in BOS equipment and installation labor costs. This is achieved through automation and preassembly efficiencies (e.g., module mounting and wiring) and through better availability of labor and access to advanced hardware technologies. The use of carbon fiber—which is assumed to have achieved low cost, replacing steel and aluminum—cuts mounting costs. R&D case: 2024 market price basis is used. Expanded case: 2024 minimum sustainable price basis is used. Justification: 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 as the U.S. PV industry grows and matures. In addition, streamlining of installation practices through improved workforce development and training and developing standardized PV hardware are assumed.
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| 2040 | Technology Description: This scenario assumes rapid improvements of module technology efficiency. Module efficiency uses ITRPV projected module efficiency extrapolated to 2040 and significant market growth of tandem PV technology because of advances in durability and manufacturing techniques. This results in a weighted average module efficiency of 28%. 🗨
A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: The MMP is adjusted for module efficiency improvements, combined with a 50% reduction in costs from manufacturing improvements, resulting in $0.15/WDC. Expanded case: The 2024 global module spot price ($0.10/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2040 module efficiency, resulting in a module cost of $0.09/WDC. Justification: This scenario represents a more aggressive technological scenario with rapid shifts to high-efficiency module technologies and, in the Expanded case, assumes access to global market pricing. | Technology Description: R&D case: This case assumes inverter costs remain the same beyond 2030, at $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.14/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size. | Technology Description: This scenario assumes a 40% reduction from 2024 prices in BOS equipment and installation labor costs. This is achieved through automation and preassembly efficiencies (e.g., module mounting and wiring) and through better availability of labor and access to advanced hardware technologies. The use of carbon fiber—which is assumed to have achieved low cost, replacing steel and aluminum—cuts mounting costs. R&D case: 2024 market price basis is used. Expanded case: 2024 minimum sustainable price basis is used. Justification: The types of technology improvements are similar to those for the 2030 scenario above, with similar justification but more aggressive.
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| 2050 | Technology Description: Module efficiency (30%) is the average between 2040 and 2060 projected efficiency values. A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. R&D case: The MMP is adjusted for module efficiency improvements, combined with a 55% reduction in costs from manufacturing improvements, resulting in $0.12/WDC. Expanded case: The 2024 global module spot price ($0.10/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2050 module efficiency, resulting in a module cost of $0.08/WDC. Justification: This scenario represents a more aggressive technological scenario with rapid shifts to high-efficiency module technologies and, in the Expanded case, assumes access to global market pricing. | Technology Description: R&D case: This case assumes inverter costs remain the same beyond 2030, at $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.11/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size. | Technology Description: This scenario assumes a 50% reduction from 2024 prices in BOS equipment and installation labor costs. This is achieved through automation and preassembly efficiencies (e.g., module mounting and wiring) and through better availability of labor and access to advanced hardware technologies. The use of carbon fiber—which is assumed to have achieved low cost, replacing steel and aluminum—cuts mounting costs. Justification: The types of technology improvements are similar to those for the 2040 scenario above, with similar justification but more aggressive. |
| 2060 | Technology Description: R&D case: This case assumes module costs remain the same beyond 2050, at $0.12/WDC. Expanded case: This scenario assumes rapid improvements of module technology efficiency as well as new technologies entering the market. NLR internal analysis projected the potential technology market share and module efficiency of a 2060 market (Kirstin Alberi et al., 2024)(Thomas G. Allen et al., 2024), resulting in a weighted average module efficiency of 32%.
A 17% supply chain premium based on the difference between utility module prices and rooftop module prices in (DOE, 2024) is applied to rooftop module costs. The 2024 global module spot price ($0.10/WDC) and efficiency (21%) from (DOE, 2024) are adjusted for 2060 module efficiency, resulting in a module cost of $0.08/WDC. Justification: This scenario represents a more aggressive technological scenario with rapid shifts to high-efficiency module technologies and, in the Expanded case, assumes access to global market pricing. | Technology Description: R&D case: This case assumes inverter costs remain the same beyond 2030, i.e., $0.30/WDC. Expanded case: This scenario assumes increased access in the market to advanced inverter technologies, resulting in an inverter price of $0.09/WDC. Justification: The power electronics industry already has roadmaps to simplify and automate current products, and there is more potential with increased industry size. | Technology Description: R&D case: This case assumes BOS and installation labor costs remain the same beyond 2050. Expanded case: This scenario assumes a 55% reduction from 2024 minimum sustainable price in BOS equipment and installation labor costs through better availability of labor and access to advanced hardware technologies. A significant step change in the use of emerging technologies impacts the reduction of system costs. Justification: Innovative technologies enter the market, increasing system efficiency and decreasing costs.
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Scenario Assumptions
The technology improvement scenarios are used to project CAPEX for utility-scale PV with linear interpolation between each target year, which results in CAPEX changes as described in the tables below.
R&D Case CAPEX Changes
| Year | Conservative Scenario | Moderate Scenario | Advanced Scenario | |||
| Total | Per Year | Total | Per Year | Total | Per Year | |
| 2024–2030 | -9% | -1.6% | -21% | -3.8% | -39% | -7.9% |
| 2030–2040 | -2% | -0.2% | -24% | -2.7% | -17% | -1.9% |
| 2040–2050 | -2% | -0.2% | -14% | -1.5% | -14% | -1.5% |
| 2050–2060 | 0% | 0% | 0% | 0% | 0% | 0% |
Expanded Case CAPEX Changes
| Year | Conservative Scenario | Moderate Scenario | Advanced Scenario | |||
| Total | Per Year | Total | Per Year | Total | Per Year | |
| 2024–2030 | 11% | 1.7% | -19% | -3.4% | -50% | -10.8% |
| 2030–2040 | -6% | -0.6% | -28% | -3.2% | -22% | -2.5% |
| 2040–2050 | -2% | -0.2% | -20% | -2.2% | -21% | -2.3% |
| 2050–2060 | -2% | -0.2% | -21% | -2.3% | -18% | -1.9% |
Although we did not create our CAPEX projections based on rates of deployment, residential PV deployment is expected to increase substantially over our analysis period. For example, in the National Laboratory of the Rockies (NLR) Standard Scenarios Mid-case, U.S. distributed PV deployment (including residential and other distributed systems) grows by 222% between 2024 and 2035 (from 41 gigawatts [GW] to 131 GW) and by 32% between 2035 and 2050 (from 131 GW to 173 GW) (Gagnon et al., 2024).
Representative Technology
For the 2025 ATB, residential PV systems are modeled for an 8-kilowatts direct current (kWDC), fixed tilt, roof-mounted system with a 1.21 DC-to-AC (alternating current) ratio, or inverter loading ratio (ILR) (DOE, 2024). Flat-plate PV can use direct or indirect insolation, so PV modules need not directly face and track incident radiation. The county-level capacity factors are calculated for specific locations, which are based on representative agents selected in the dGen 2020 Standard Scenarios agent database (Barbose et al., 2024); (Sigrin et al., 2016). At each location, various tilt/azimuth combinations are evaluated and the optimal combination is chosen for modeling. The ability to use direct and indirect insolation gives rooftop PV systems a broad geographical application.
Methodology
This section describes the methodology to develop assumptions for CAPEX, O&M, and capacity factor. For standardized assumptions, see regional cost variation, materials cost index, scale of industry, policies and regulations, and inflation. The PV-specific and standardized assumptions for labor cost differ; the PV analysis assumes the use of nonunion labor only.
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Currently, CAPEX—not levelized cost of energy (LCOE)—is the most common metric for PV costs. Because of different assumptions in long-term incentives, system location and production characteristics, and cost of capital, LCOE can be confusing and often noncomparable for different estimates. Although CAPEX also has many assumptions and interpretations, managing it involves fewer variables. Therefore, PV projections in the 2025 ATB are driven entirely by upfront and operating cost improvements.
Three projections are developed for scenario modeling as bounding levels (see the scenario list above).
Capital Expenditures (CAPEX)
Definition: Capital expenditures (CAPEX) are expenditures required to achieve commercial operation in a given year. For residential PV, this is modeled only for a host-owned business model.
For the 2025 ATB—and based on the U.S. Department of Energy (DOE) PV System Cost Benchmark (DOE, 2024)—the residential PV envelope is defined to include items noted in the Components of CAPEX table below.
Base Year: Reported residential PV installation CAPEX (Joachim Seel et al., 2024) is shown (see chart above) in box-and-whiskers format through 2023 along with benchmarked CAPEX in 2023 (Ramasamy et al., 2023), 2024 (DOE, 2024), and projections from the 2025 ATB.
Reported and benchmark prices can differ for various reasons, as outlined by Barbose and Darghouth (Barbose et al., 2019); Bolinger, Seel, and Robson (Bolinger et al., 2019); and (Ramasamy et al., 2022), including the following:
- Timing-Related Issues: For example, the time between contract completion and project placement in service may vary.
- System Variations: The size, technology, installer margin, and design of systems installed in a given year vary over time.
- Cost Categories: There are variations in which cost categories are included in CAPEX (e.g., financing costs and initial O&M expenses).
Federal investment tax credits provide an incentive to include costs in the upfront CAPEX to receive a higher tax credit; these included costs may have otherwise been reported as operating costs. The bottom-up benchmarks are more reflective of overnight capital costs, which are in line with the ATB methodology of inputting overnight capital costs and calculating construction financing to derive CAPEX.
Residential PV pricing and capacities are quoted in kWDC (i.e., module rated capacity) unlike other generation technologies (including utility-scale PV), which are quoted in kWAC. This is because kWDC is the unit most of the residential PV industry uses. Although costs are reported in kWDC, the total CAPEX includes the cost of the inverter, which has a capacity measured in kWAC.
CAPEX estimates for 2024 reflect analysis of recent system cost and pricing for projects that became operational in 2024 (DOE, 2024). Although the PV technologies vary, typical installation costs are represented with a single estimate per innovation scenario because residential PV CAPEX does not correlate well with solar resources. Although the technology market share may shift over time with new developments, the typical installation cost is represented with the projections above.
System prices of $2.79/WDC in 2023 and $3.15/WDC in 2024 are based on bottom-up benchmark analysis reported by (Ramasamy et al., 2023) and (DOE, 2024).
The Base Year CAPEX estimates should tend toward the low end of observed cost because no regional impacts are included. These effects are represented in the historical market data.
Future Years: Projections of residential PV system CAPEX for future years 2030, 2040, 2050, and 2060 are based on bottom-up cost modeling, with 2024 values from (DOE, 2024) and a straight-line change in price in the intermediate years between each pivot year. The assumptions for the R&D cost drivers and Expanded cost drivers cases vary, which results in different sets of results from the bottom-up cost model. The system design and price changes made in the models are summarized and described in the Summary of Technology Innovations by Scenario table. See Cost Details by Scenario below for the details of changes to components of system price in the various ATB scenarios.
We assume a straight-line change in price in the years between 2024 and 2030, between 2030 and 2040, between 2040 and 2050, and between 2050 and 2060.
We compare the CAPEX scenarios over time to three analyst projections—one from the U.S. Energy Information Administration (EIA) and two from private analysts—adjusted for inflation. The median of the private projections is displayed in the figure below through 2030, along with the EIA projection through 2050. The 2025 ATB Moderate and Conservative Scenario CAPEX projections are similar to the median of the private projections through 2030, whereas EIA projections become lower than the ATB Conservative projections by 2040.
Sources: 2025 ATB; (BNEF, 2024); (Wood Mackenzie, 2024); (EIA, 2023); (Ramasamy et al., 2023); (Ramasamy et al., 2025).
Use the following table to view the components of CAPEX.
Operation and Maintenance (O&M) Costs
Definition: O&M costs represent the annual expenditures required to operate and maintain a PV system over its lifetime, including items noted in the table below.
Base Year: A fixed O&M (FOM) cost of $32/kWDC-yr in 2023 is based on modeled pricing for a residential PV system quoted in Q1 2023 as reported by (Ramasamy et al., 2023). Lawrence Berkeley National Laboratory collected feedback from U.S. solar industry professionals (Wiser et al., 2020). The wide range in reported prices is in part because of maintenance practices that exist for a particular system. These cost categories include asset management (including compliance and reporting for incentive payments), insurance products, cleaning, vegetation removal, and component failure. Not all these practices are performed for each system; in addition, some factors depend on the quality of the parts and construction.
Future Years: FOM of $29.83/kWDC-yr for 2024 is based on pricing reported by (DOE, 2024), which can be divided into system-related expenses ($26.65/kWDC-yr) and administration-related expenses ($3.19/kWDC-yr). From 2024 to 2060, FOM is based on the ratio of O&M costs ($/kW-yr) to CAPEX costs ($/kW), which was 0.84:100 in 2024 as reported by (DOE, 2024). Historical data suggest O&M and CAPEX cost reductions are correlated; from 2010 to 2020, benchmark residential PV O&M fell 49% and PV CAPEX fell 65%, as reported by (Ramasamy et al., 2025). Administrative expenses are kept constant.
Use the following table to view the components of O&M.
Capacity Factor
Definition: The capacity factor represents the expected annual average energy production divided by the annual energy production, assuming the system operates at rated capacity for every hour of the year. It is intended to represent a long-term average over the lifetime of the system; it does not represent interannual variation in energy production. Future year estimates represent the estimated annual average capacity factor over the technical lifetime of a new system installed in a given year.
Residential PV system capacity factor is not directly comparable to other technologies' capacity factors. Other technologies' capacity factors (including utility-scale PV) are represented exclusively in AC units (see Solar PV AC-DC Translation). However, because residential PV pricing in the 2025 ATB is represented in $/WDC, residential PV system capacity is a DC rating. Because each technology uses consistent capacity ratings, the LCOEs are comparable.
The capacity factor is influenced by the hourly solar profile, technology (e.g., thin-film or crystalline silicon), expected downtime, and inverter losses to transform from DC power to AC power. The DC-to-AC ratio is a design choice that influences the capacity factor.
The baseline PV system capacity factor incorporates an assumed degradation rate of 0.7%/yr in the annual average calculation.
R&D could lower degradation rates of PV system capacity factor; future projections for the Moderate Scenario and the Advanced Scenario reduce degradation rates by 2035, using a straight-line basis, to 0.5%/yr and 0.2%/yr, respectively. The Conservative Scenario assumes no improvement in degradation rates through 2035.
Base Year: In the interactive data chart at the top of this page, select Technology Detail = All to add filters to the initial figure showing a range of capacity factors based on variation in solar resources in the contiguous United States. The ATB provides the average capacity factor for 10 resource categories in the United States, binned by mean GHI. The annual average capacity factor for the contiguous United States is calculated using the reV model using solar resource data for 2012 from the NSRDB. The county-level capacity factors are calculated for specific locations with azimuth and tilt, which are based on representative agents selected in the dGen 2020 Standard Scenarios agent database (Barbose et al., 2020). A lookup table for these locations and the NSRDB is generated based on nearest distance. The azimuth and tilt as well as the resource GHI are used to generate a SAM configuration file and run reV, which outputs the annual average capacity factor at each evaluated location. U.S. average capacity factor for each resource category is weighted by the population of each county within the GHI resource category. The county estimated populations are provided by geospatial and tabular data from the U.S. Census.
First-year operation capacity factors as modeled range from 12.7% for Class 10 (for locations with an average annual GHI less than 3.75) to 19.6% for Class 1 (for locations with an average annual GHI greater than 5.75). Actual systems will vary significantly, depending on location and system configuration (e.g., south-facing or west-facing).
Over time, PV installation output is reduced because of degradation in module quality, which is accounted for in ATB estimates of capacity factor over the 30-year lifetime of the system. The adjusted average capacity factor values in the 2025 ATB Base Year range from 11.7% for Class 10 (for locations with an average annual GHI less than 3.75) to 18.3% for Class 1 (for locations with an average annual GHI greater than 5.75).
Future Years: Projections of capacity factors for systems installed in future years increase over time because of reduced system losses and a straight-line reduction in PV system degradation rates from 0.7%/yr that reduces to 0.5%/yr and 0.2%/yr by 2035 for the Moderate Scenario and the Advanced Scenario, respectively. The Conservative Scenario assumes no improvement in degradation rates through 2035. The following table summarizes the difference in average capacity factor in 2035 caused by these changes in the technology innovation scenarios. We assume each scenario's 2050 capacity factor is the equivalent of the 2035 capacity factor of the scenario but one degree more aggressive, with a straight-line change in the intermediate years between 2035 and 2050. In the Advanced Scenario, there is a 4.4% improvement between 2023 and 2050, and capacity factors remain constant after 2050.
| Scenario | Degradation Rate (%/yr) | Average Capacity Factor in 2035 (Class 10–Class 1) | Percentage Improvement From Base Year (2023) |
|---|---|---|---|
| Advanced Scenario | 0.2 | 12.4%–19.1% | 4.44% |
| Moderate Scenario | 0.5 | 12.0%–18.5% | 1.75% |
| Conservative Scenario | 0.7 | 11.7%–18.1% | 0.0% |
References
The following references are specific to this page; for all references in this ATB, see References.