In 2011, the U.S. Department of Energy's Solar Energy Technologies Office (SETO) launched the SunShot Initiative to make solar-generated electricity competitive with conventional sources across most of the country by 2020. That goal was met for utility-scale photovoltaic installations three years early. In 2020, large utility-scale systems produced electricity at a levelized (life-cycle) cost below 5¢/kWh in locations with average sunlight, and as low as 3.5¢/kWh in the sunniest parts of the country, making it one of the least expensive forms of new electricity generation.1

This reduction in cost in combination with solar policy incentives has led to rapid growth in solar photovoltaic (PV) generation capacity, from providing less than 0.1% of the U.S. electricity supply in 2011 to over 3% in 2020. This upward trajectory is expected to continue. To fully decarbonize power generation by 2035, solar power may need to supply more than 40% of the nation’s electricity.2

To accelerate the deployment of solar power, SETO has announced a goal to reduce the benchmark levelized cost of electricity (LCOE) generated by utility-scale photovoltaics (UPV) to 2¢/kWh by 2030.3 In parallel, SETO is targeting a 2030 benchmark LCOE of 4¢/kWh for commercial PV,4 5¢/kWh for residential PV,5 and 5¢/kWh for concentrating solar-thermal power (CSP).6 Figure 1 compares the 2030 LCOE targets to their corresponding historical values.

SETO Levelized Cost of Energy Bar Chart and 2030 Goals

Figure 1. Solar-power benchmark LCOE targets for 2030 compared to historical values.

The benchmark LCOE targets for PV shown in Figure 1 are for a location with medium solar resource. Areas with more sun have lower LCOE, while those with less sun have higher LCOE. Figure 2 illustrates the geographic variation in the annual solar resource and the resulting range in LCOE for a large UPV system. Note that there is less than ±30% variation in LCOE across the contiguous 48 states. This geographic variability is less than for any competing renewable-power technology.

This map is a "heat map" that shows the available solar resource in the country. The desert southwest has the most sunlight, whereas the Great Lakes region and parts of New England have the least.

Figure 2. Annual solar resource map for a latitude-tilt south-facing surface, showing LCOE values for large UPV systems located near three cities that represent low, medium, and high solar resource.

The different LCOE targets for residential, commercial, and utility-scale PV systems is due primarily to the differences in size. This scale dependence arises because there are some project costs that are nearly independent of the size of the system, including office functions like engineering, sales and marketing, accounting, supply-chain management, and obtaining permits. Larger systems spread these fixed costs across more energy delivered. Utility-scale PV systems are the largest, typically between 5 and 500 MW, with some exceeding 1000 MW. Residential PV systems are the smallest, typically between 2 and 10 kW, though some homes have systems as large as 20 kW.7 Commercial PV systems span the gap between residential and utility-scale systems.

Residential and commercial systems are called distributed PV (DPV) systems. In 2020, DPV systems accounted for 30% of the solar electricity generated in the U.S.8 Although DPV systems have higher LCOE than UPV systems, they have the advantage of delivering power directly at the point of consumption, which makes it possible for DPV to be cost-competitive across most of the country.

The benchmark LCOE for CSP shown in Figure 1 is for a sunny location in the Southwest such as Daggett, CA shown in Figure 2. CSP installations are primarily focused on this region of the country because atmospheric haze and clouds impact CSP performance more than for PV.

Why Does Solar Power Need New Targets?

Solar power has become inexpensive, but the solar resource is variable – it peaks around noon and goes to zero at night. When solar power grows to supply a substantial fraction of regional energy demand, there will often be more solar power available at midday than can be immediately consumed. This is already happening in some parts of the country.

The generation of excess power around midday presents an opportunity. If there are ways to use this excess power cost-effectively, it will unlock the potential of solar power to contribute even more to decarbonizing the nation’s energy supply. There are three principal approaches. The primary one is energy storage, typically in the form of battery packs. Excess power charges batteries during the day that can be used later. Another is transmission, which allows excess power to be conveyed to some place that needs it. The third is to shift more electricity demand to midday. An example is charging electric vehicles at workplaces rather than at home. All three of these approaches come at a cost, whether it’s the cost of batteries, transmission lines, or EV-charging infrastructure. For any of these approaches to be cost-effective, solar power itself needs to cost even less, so that after adding these extra costs, the power delivered remains competitive with competing sources of electricity.

The three principal approaches for making effective use of excess power apply to both UPV and DPV, but whereas UPV systems supply excess power to a vast network of loads connected to the power grid, DPV systems primarily serve the site where they are installed. DPV systems frequently produce more power than is immediately consumed on-site, and the excess power is exported to the grid. Most electric power utilities pay DPV owners for their excess power, but as DPV becomes more prevalent, utilities are reducing the amount they pay. Consequently, DPV systems need to cost less. Reducing the cost of DPV systems will also expand the geographic range over which they are cost-effective.

While PV is the most prevalent technology for converting sunlight into electricity, it is not the only way. Concentrating solar-thermal power (CSP) uses the sun’s heat to drive a conventional turbine-generator, which works best in areas with sunny skies such as the desert Southwest. CSP systems can be efficiently integrated with thermal energy storage to collect solar heat during the day and use it to generate power when it is needed most, even after dark. This ability to ramp power up or down on demand (dispatchability) is an attractive attribute, but to compete economically, CSP costs must be reduced to compete with other energy sources.

Utility-Scale Photovoltaics (UPV)

Impact of module efficiency on the module cost needed to reach an LCOE for UPV of 2¢/kWh.  The plus signs indicate the module cost and efficiency used in the 2030 scenarios in Table I.

Figure 3. Impact of module efficiency on the module cost needed to reach an LCOE for UPV of 2¢/kWh. The plus signs indicate the module cost and efficiency used in the 2030 scenarios in Table I.

There are many paths to reduce the LCOE for UPV systems to the target set for 2030, but they all rely on improvement in seven key parameters: module conversion efficiency, module cost, balance-of-system (BOS) cost, initial operating cost, operating cost escalation, initial annual energy yield, and degradation rate.9 Table I lists representative values for these key parameters for a large UPV system using single-axis tracking10 of monofacial modules installed in 2020 near Kansas City, a location with medium solar resource. Two possible sets of these parameters are shown that would achieve the LCOE target in 2030,11 one representing a low-cost approach and the other a high-performance approach. The low-cost scenario assumes that the cost of PV modules continues its historical downward trend unabated, but module conversion efficiency increases only slightly. The high-performance scenario assumes that by 2030 very-high-efficiency modules are available, though at higher cost. Component reliability and lifetime are improved in both scenarios, but more so in the high-performance scenario.

Table I. Benchmark parameters for a 100-MW UPV system in a location with medium solar resource.

Parameter 2020 
Benchmark8
2030 
Low-Cost
2030 
High-Performance
Module efficiency 19.5% 20% 30%
Module cost $0.41/W $0.17/W12 $0.30/W13
Balance-of-system cost14 $0.46/Wdc $0.27/Wdc15 $0.30/Wdc16
Project overhead17 $0.21/Wdc $0.11/Wdc $0.15/Wdc
Initial operating cost18 $8.7/kWdc-yr $4.8/kWdc-yr $5.0/kWdc-yr
O&M cost escalation19 5.4%/yr 3.0%/yr 1.0%/yr
Initial annual energy yield 1717 kWh/kWdc 1916 kWh/kWdc20 2040 kWh/kWdc21
Performance degradation 0.7%/yr (30 yr) 0.5%/yr (40 yr) 0.4%/yr (50 yr)
LCOE (2019 US$) 4.6¢/kWh 2.0¢/kWh 2.0¢/kWh
illustrates how the target reduction in LCOE is distributed across the categories in Table I for both of the 2030 scenarios.

Figure 4. Components of LCOE improvement for UPV in the two scenarios of Table I.

The trade-off between allowable module cost and efficiency is illustrated in Figure 3. Here, the curves represent the module cost per watt that is necessary to achieve an LCOE of 2¢/kWh at a location with medium solar resource, as a function of the module efficiency. For the top two curves, all parameters other than module cost and efficiency correspond to the two 2030 scenarios of Table I. These curves show that a module having less than 13% efficiency cannot achieve the target LCOE in a UPV system in either scenario. The red curve differs from the low-cost scenario only in that the degradation rate is increased to 1% per year with a corresponding 20-year lifetime. Achieving a module cost as low as the red curve is unlikely, but that curve shifts upward if BOS cost is further reduced, and it would approach the low-cost curve if all BOS costs are reduced from 2020 levels by 50% instead of 30%.15

Figure 4 illustrates how the target reduction in LCOE is distributed across the categories in Table I for both of the 2030 scenarios.22

Commercial and Industrial Photovoltaics (C&I PV)

Commercial and industrial photovoltaics represents a broad class of DPV systems that can be ground-mounted or mounted on the flat roof of a commercial building, typically 20 kW to 5 MW in size. The C&I PV market is evolving rapidly, including dual-use applications such as architectural solar, floating solar, and agricultural solar. Because of the wide range of system types within the C&I PV category, there is no single system configuration that can be considered typical of the category as a whole. The majority of systems, however, can be classified as either roof-mounted or ground-mounted systems.

Table II lists representative values of the key parameters for two C&I PV systems installed near Kansas City in 2020 and corresponding values that would achieve the LCOE target of 4¢/kWh in 2030. One system is 200 kW roof-mounted at a 10-degree tilt and the other is 500 kW ground-mounted at a fixed south-facing tilt of 33 degrees. The 2030 values for module efficiency, module cost, degradation rate, and O&M escalation match the low-cost scenario in Tables I and III for the ground-mounted and rooftop systems, respectively. The financial terms match those for utility-scale systems,9 except that a 1% higher annual return on investment is assumed to reflect the higher risk that investors typically perceive for C&I systems.

The ground-mounted system has higher energy yield than the rooftop system because of the higher tilt angle and its ability to generate additional power from the light that shines on the rear surface of bifacial modules. As a result, the ground-mounted system requires significantly less reduction in BOS cost than the rooftop system to achieve the same LCOE target.

Table II. Benchmark parameters for C&I PV systems in a location with medium solar resource.

Parameter 2020 Rooftop8 2020 Ground8 2030 Rooftop 2030 Ground
System size 200 kWdc 500 kWdc 200 kWdc 500 kWdc
Module efficiency 19.5% 19.5% 20% 20%
Module cost $0.41/W $0.41/W $0.17/W $0.17/W
Balance-of-system cost $0.78/Wdc $0.72/Wdc $0.43/Wdc23 $0.54/Wdc24
Project overhead25 $0.63/Wdc $0.68/Wdc $0.32/Wdc $0.42/Wdc
Initial O&M cost18 $9.3/kWdc-yr $9.4/kWdc-yr $4.6/kWdc-yr $5.8/kWdc-yr
O&M annual escalation19 5.6%/yr 5.6%/yr 3%/yr 3%/yr
Initial energy yield 1454 kWh/kWdc 1559 kWh/kWdc 1502 kWh/kWdc26 1740 kWh/kWdc27
Degradation rate28 0.7%/yr (30 yr) 0.7%/yr (30 yr) 0.5%/yr (30 yr) 0.5%/yr (40 yr)
LCOE (2019 US$) 8.7¢/kWh 8.1¢/kWh 4.0¢/kWh 4.0¢/kWh

 

Residential Photovoltaics (RPV)

Residential PV systems are small DPV systems installed on rooftops, most commonly on tilted roof surfaces that face roughly south (±90 degrees). Reducing LCOE for RPV systems requires improvements in the same parameters listed in Table I. In addition, the size of a residential system has a significant impact, with larger systems having a lower cost per watt and a lower LCOE. Residential systems are typically sized so that their annual energy production matches the energy consumed on-site. In 2020, this typically required 10 – 30 modules.29 By 2030, increasing use of electric vehicles and building electrification could more than double the number of modules needed per residence, so that the size of RPV systems will increasingly be limited only by the amount of suitable roof space.

Impact of RPV system size on LCOE

Figure 5. Impact of RPV system size on LCOE(1.63 m2 modules @ 25% efficiency).

The financial arrangements for RPV systems are quite different from UPV systems, because residential systems are typically financed by the homeowner rather than by investors. For homeowners who have equity in their homes, the lowest-cost financing available is a mortgage-backed home-equity loan. The discount rate that describes how homeowners perceive the value of benefits that won’t be received until years later is also different from that of investors who fund UPV systems. Also, since homeowners are not in the business of selling the electricity they produce, there is no profit on which to pay taxes and no asset depreciation to deduct. Despite these extensive differences between the financing of RPV versus UPV, the effective cost of capital taking into account the perceived time value of money is remarkably similar, at 5 - 7% per year.

Table III lists representative values for the key parameters for a typical RPV system installed near Kansas City in 2020,8 and two possible sets of these values that would achieve the LCOE target in 2030, one representing a low-cost approach and the other a high-performance approach.

Table III. Benchmark parameters for a residential PV system in a location with medium solar resource.

Parameter 2020 Benchmark 2030 Low Cost 2030 High Performance
Module efficiency 19.5% 20% 30%
Number of modules 22 (7 kWdc) 36 (12 kWdc) 36 (18 kWdc)
Module cost $0.41/W $0.17/W10 $0.30/W
Balance-of-system cost30 $1.68/Wdc $0.92/Wdc13 $0.80/Wdc31
Project overhead32 $0.62/Wdc $0.32/Wdc $0.33/Wdc
Initial operating cost16 $14.4/kWdc-yr $8.7/kWdc-yr $10.7/kWdc-yr
O&M cost escalation17 5.4% 3.0% 1.0%
Initial annual energy yield 1542 kWh/kWdc 1593 kWh/kWdc33 1593 kWh/kWdc
Performance degradation26 0.7%/yr (30 yr) 0.5%/yr (30 yr) 0.4%/yr (30 yr)
Loan interest and duration 5%/yr for 18 yr 4%/yr for 30 yr 4%/yr for 30 yr
LCOE (2019 US$)34 12.8¢/kWh 5.0¢/kWh 5.0¢/kWh
Components of LCOE improvement for RPV in the two scenarios

Figure 6. Components of LCOE improvement for RPV in the two scenarios of Table III. The portion labeled Other represents improvements in energy yield, degradation rate, and O&M escalation rate.

The influence of system size is illustrated in Figure 5. Achieving the 5¢/kWh target for a system smaller than 36 modules would require a greater reduction in component costs. For example, a system of 22 modules would require intrinsic BOS costs be reduced below the values in Table III by an additional 10%. That could be realized for systems installed as an integral part of new home construction.35

Reducing LCOE for RPV systems requires improvement in the same factors illustrated for UPV in Figure 4. Two additional factors that are important for RPV are reducing the cost of the loan for financing and increasing the system size. The contribution of each improvement to reducing LCOE is shown in Figure 6.

Concentrating Solar-Thermal Power (CSP)

CSP systems use a field of mirrors that track the sun and focus its rays onto a receiver, where a heat-transfer medium is heated to a high temperature that can be used to drive a conventional turbine-generator. CSP can directly address the grid-integration challenge posed by the variability of sunlight by efficiently incorporating thermal energy storage. The ability of the grid to draw power from a CSP plant whenever it is needed is called dispatchability. Dispatchability adds value to the grid, so the LCOE that makes CSP economically competitive is higher than for UPV. The benchmark 2030 LCOE target for CSP is 5¢/kWh for a system in the Southwest with at least 12 hours of thermal energy storage.

Impact of power-cycle efficiency on the power-block cost needed for an LCOE of 5¢/kWh. The plus signs indicate the power-block cost and efficiency target used in each 2030 scenario in Table IV.

Figure 7. Impact of power-cycle efficiency on the power-block cost needed for an LCOE of 5¢/kWh. The plus signs indicate the power-block cost and efficiency target used in each 2030 scenario in Table IV.

The primary cost components for CSP are the power block that houses the turbine-generator, the field of tracking mirrors, site preparation, the receiver at the focal point, thermal energy storage, and the cost of operations and maintenance. The primary opportunity for improving performance is the efficiency of converting thermal energy to electric power. Three scenarios that would achieve the LCOE target for CSP are shown in Table IV. The low-cost scenario focuses on reduced cost with only a marginal improvement in efficiency. The high-performance scenario focuses on increasing the power block’s efficiency, which allows higher costs for the system components to achieve the same target LCOE. An intermediate scenario is also shown that matches the high-performance scenario except for the field cost, which matches the low-cost scenario, thereby reducing the required net power-cycle efficiency to 50%.

Table IV. Benchmark parameters for a 100 MW CSP system with 14 hours thermal storage.36

Parameter 2018 
Benchmark
37,38
2030 
Low-Cost
2030
Balanced
2030 
High-Performance
Net power-cycle efficiency 37% 40% 50% 55%
Rated thermal power 730 MWthermal 675 MWthermal 540 MWthermal 491 MWthermal
Power block cost $1330/kWac-gross $700/kWac-gross $900/kWac-gross $900/kWac-gross
Solar field cost $140/m2 $50/m2 $50/m2 $70/m2
Site preparation cost $16/m2 $10/m2 $10/m2 $10/m2
Tower and receiver cost $137/kWthermal $100/kWthermal $120/kWthermal $120/kWthermal
Thermal storage cost $22/kWhthermal $10/kWhthermal $15/kWhthermal $15/kWhthermal
Levelized O&M cost39 $9/kWthermal-yr $6/kWthermal-yr $7/kWthermal-yr $7/kWthermal-yr
Levelized capacity factor 68.9% 69.2% 70.7% 71.0%
LCOE (2019 US$)40 9.8¢/kWh 5.0¢/kWh 5.0¢/kWh 5.0¢/kWh
Components of LCOE improvement for CSP in the three scenarios of Table IV.

Figure 8. Components of LCOE improvement for CSP in the three scenarios of Table IV. The portion labeled Other represents improvements in cost for the tower, receiver, and O&M.

The cost of capital used for financing the CSP systems in Table IV is higher than for the UPV systems in Table I because CSP technology has not been as extensively proven in the field. If, by 2030, CSP systems can attract financing on the same terms currently available for UPV systems, it would reduce LCOE for each of the 2030 scenarios in Table IV to less than 4¢/kWh. 

Figure 7 illustrates how the efficiency of thermal-to-electric conversion affects the power-block cost that is needed to achieve the target LCOE of 5¢/kWh for the three 2030 scenarios in Table IV. The thermal components (solar field, tower, receiver, and energy storage) are held fixed as efficiency is changed, so the rated electrical power output of the plant changes in proportion to the power-cycle efficiency.

Figure 8 illustrates how the individual improvements in the key parameters achieve the LCOE target for each 2030 scenario in Table IV. Most of the improvement is related to the field (cost of the solar field and site preparation) and the power block (reduced cost and increased efficiency).

 

  1. All costs quoted here exclude benefits from federal or state tax incentives, such as the Investment Tax Credit.
  2. Solar Energy Technologies Office, Solar Futures Study (2021).
  3. Utility-scale PV benchmark LCOE targets are for a 100-MW project on level ground with single-axis tracking.
  4. Commercial PV benchmark LCOE targets are for a 200-kW flat-roof system with 10 degrees tilt.
  5. Residential PV benchmark LCOE targets are for a rooftop system at 25 degrees tilt facing south.
  6. CSP benchmark LCOE targets are for a 100-MW project with at least 12 hours of thermal energy storage.
  7. https://emp.lbl.gov/sites/default/files/distributed_solar_2020_data_update.pdf (2020).
  8. https://www.eia.gov/energyexplained/electricity/electricity-in-the-us-generation-capacity-and-sales.php (2021).
  9. D. Feldman, et al., “U.S. Solar PV System and Energy Storage Cost Benchmark,” NREL/TP-6A20-77324 (2021).
  10. Each tracker has a horizontal axis of rotation with a north-south orientation, providing east-to-west tracking of modules mounted to occupy a single geometric plane. Trackers are spaced to avoid excessive inter-row shading.
  11. LCOE for UPV depends on the following financial terms typical for systems installed in the absence of tax incentives: Annual return on investment 7.75%, 71.8% debt at 5% annual interest for 18 yr, 21% federal and 6% state tax, 2.5% annual inflation, 5-yr MACRS depreciation.
  12. This value is achieved if module cost per watt in 2030 is 30% less than in 2020 and import tariffs expire.
  13. This value assumes that higher module efficiency will necessarily entail a higher cost per watt.
  14. Includes inverter, structural BOS, electrical BOS, installation, EPC overhead, and interconnection costs. 
  15. This value is achieved if each intrinsic (e.g., per-project, per-area, per-watt) BOS cost is reduced by 30%.
  16. This value is achieved if each intrinsic (e.g., per-project, per-area, per-watt) BOS cost is reduced by 20%.
  17. 25% overhead for profit, administration, taxes, working capital, financing fees, reserve fund, and contingency. 
  18. Each intrinsic component of the initial O&M cost reduces at the same rate as the installed system cost.
  19. Increase in annual O&M cost beyond inflation, due to increasing frequency of repairs as the system ages.
  20. This value is achieved if bifacial modules add 8% yield and system losses are reduced by 3% absolute.
  21. This value is achieved if bifacial modules add 15% yield and system losses are reduced by 3% absolute.
  22. Components are shown as last-in contributions, adjusted proportionally to account for interactions.
  23. This value is achieved if each intrinsic (e.g., per-project, per-area, per-watt) BOS cost is reduced by 44%.
  24. This value is achieved if each intrinsic (e.g., per-project, per-area, per-watt) BOS cost is reduced by 24%.
  25. 53% overhead for rooftop and 60% overhead for ground-mounted includes profit, project administration, sales tax, working capital, financing fees, reserve fund, and contingency.
  26. This value is achieved if system losses are reduced by 3% absolute.
  27. This value is achieved if bifacial modules add 8% yield and system losses are reduced by 3% absolute.
  28. System lifetime for rooftops is limited to the 30-year life of the roof. Otherwise, lifetime extends until the system’s annual energy production drops below 80% of its initial value.
  29. Residential PV modules are 1.6 – 1.8 m2 so a single person can carry them, with 1.63 m2 used here as typical.
  30. Includes inverter, structural BOS, electrical BOS, supply chain, installation, permitting, and customer acquisition.
  31. This value is achieved if each intrinsic (e.g., per-project, per-area, per-watt) BOS cost is reduced by 16%.
  32. 30% overhead for profit, project management, and sales tax.
  33. This value is achieved if system operational losses are reduced by 3% absolute.
  34. Annual discount rate 10%, 100% debt-financed, no tax, no depreciation benefit, 2.5% annual inflation.
  35. K. Ardani, et. al., “Cost-Reduction Roadmap for Residential Solar PV 2017-2030,” NREL/TP-6A20-70748 (2018).
  36. Molten-salt tower with 1000 suns peak receiver intensity near Daggett, CA. Other configurations may differ.
  37. C. S. Turchi, et al., “CSP Systems Analysis - Final Project Report,” NREL/TP-5500-72856, May 2019.
  38. System Advisor Model, v2020.11.29, National Renewable Energy Laboratory. Default CSP system configuration except: 14 hours storage, 2.7 solar multiple, 30-yr life, 100 MW, 8% higher receiver cost, 7%/yr cost of capital.
  39. Includes insurance. There is an additional $3.50/MWhac-net variable cost for maintaining the power block.
  40. Includes 37% overhead for administration, taxes, working capital, financing fees, reserve fund, and contingency.