In 2011, the US Department of Energy's Solar Energy Technologies Office (SETO) launched the SunShot initiative to make solar-generated electricity competitive with conventional sources in most of the country by 2020. This goal was reached three years earlier for large-scale PV systems. In 2020, large utility plants produced electricity at a levelized (life cycle) cost of less than 5¢/kWh in places with average solar radiation and up to 3.5¢/kWh in the sunniest parts of the country, which That makes it one of the most cost effective forms of new energy generation.1
This cost reduction combined with solar policy incentives has led to rapid growth in solar photovoltaic (PV) generating capacity, from less than 0.1% of US electricity supply in 2011 to more than 3% in 2020. This upward trend is expected to continue. To fully decarbonise power generation by 2035, solar power may need to supply more than 40% of the country's electricity.2
To accelerate the deployment of solar power, SETO has announced a goal of reducing the levelized cost of electricity (LCOE) generated by utility-scale photovoltaics (UPV) to 2¢/kWh by 2030.3In parallel, SETO is targeting a 2030 LCOE benchmark of 4¢/kWh for commercial PV.45¢/kWh for private photovoltaic,5and 5¢/kWh for Concentrated Solar Power (CSP).6Figure 1 compares the 2030 LCOE targets with their corresponding historical values.
Figure 1. 2030 solar baseline LCOE targets compared to historical values.
The PV benchmark LCOE targets shown in Figure 1 are for a site with moderate solar resources. Areas with more sun have a lower LCOE, while areas with less sun have a higher LCOE. Figure 2 illustrates the geographic variation in annual solar resources and the resulting range of LCOE for a large UPV system. Please note that the LCOE varies by less than ±30% in the lower 48 states. This geographic variability is less than any competing renewable energy technology.
Figure 2. Annual solar resource map for a latitude-tilted south-facing surface showing LCOE values for large UPV systems near three cities representing low, medium, and high solar resources.
The different LCOE targets for residential, commercial, and utility scale PV systems are primarily due to differences in size. This scale dependency arises because there are some project costs that are nearly independent of system size, including back office functions such as engineering, sales and marketing, accounting, supply chain management, and permitting. Larger systems spread these fixed costs over more power delivered. Large-scale PV systems are the largest, typically between 5 and 500 MW, with some exceeding 1,000 MW. Residential PV systems are the smallest, typically between 2 and 10 kW, although some homes have systems up to 20 kW.7Commercial PV systems bridge the gap between residential and utility systems.
Residential and commercial systems are called distributed photovoltaic (DPV) systems. In 2020, DPV systems accounted for 30% of the solar power generated in the US.8Although DPV systems have a higher levelized cost of electricity than UPV systems, they have the advantage of delivering electricity directly to the point of consumption, allowing DPV to be cost competitive in most parts of the country.
The baseline LCOE for CSP shown in Figure 1 is for a sunny location in the Southwest, such as Daggett, CA, as shown in Figure 2. CSP facilities are primarily concentrated in this region of the country because haze Weather and clouds affect CSP performance more than PV.
Why does solar power need new targets?
Solar energy has become cheap, but the solar resource is variable: it peaks around noon and hits zero at night. If solar power covers a significant part of the regional power demand, there is often more solar power available at noon than can be used immediately. This is already happening in some parts of the country.
Generating excess electricity around noon offers an opportunity. If there are ways to use this surplus electricity economically, it will unlock the potential of solar energy to further contribute to the decarbonisation of the country's energy supply. There are three main approaches. The main one is energy storage, usually in the form of battery packs. Excess electricity during the day recharges batteries that can be used later. Another is transmission, which allows excess power to be transferred to where it is needed. The third is to shift more power demand to lunchtime. One example is charging electric vehicles at work instead of at home. All three 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 must cost even less so that the supplied power remains competitive with competing power sources after adding these additional costs.
The three main approaches to using excess power apply to both UPV and DPV, but while UPV systems deliver excess power to a vast network of grid-connected loads, DPV systems primarily serve the place where which are installed. DPV systems often produce more electricity than is directly consumed on site, with excess electricity being fed into the grid. Most utility companies pay DPV owners for their excess electricity, but as DPV becomes more common, utility companies are reducing the amount they pay. Consequently, DPV systems must cost less. Reducing the cost of DPV systems will also expand the geographic area in which they are profitable.
Although photovoltaics is the most widely used technology to convert sunlight into electricity, it is not the only option. Concentrating Solar Power (CSP) uses heat from the sun to power a conventional turbine generator that works best in areas with sunny skies like the desert Southwest. CSP systems can be efficiently integrated with thermal energy storage to harvest heat from the sun during the day and use it to generate electricity when it is most needed, even after dark. This ability to turn on and off as needed (dispatchability) is an attractive feature, but to compete economically, CSP costs must be brought down to compete with other power sources.
Large-Scale Photovoltaics (UPV)
Figure 3. Impact of module efficiency on the module costs needed to achieve a LCOE for UPV of 2¢/kWh. The plus signs indicate the cost and efficiency of the module used in the 2030 scenarios in Table I.
There are many ways to reduce the LCOE for UPV systems to the 2030 target, but all are based on improving seven key parameters: module conversion efficiency, module cost, balance of system (BOS) cost, initial operating cost, scaling of operating costs, initial annual energy yield and rate of degradation.9Table I lists representative values of these key parameters for a large UPV system using single-axis tracking.10of single-facial modules installed in 2020 near Kansas City, a medium solar power location. Two possible sets of these parameters are shown that would achieve the LCOE target by 2030,11one represents 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, but the conversion efficiency of the modules increases only slightly. The high performance scenario assumes that very high efficiency modules will be available by 2030, but at a higher cost. Reliability and component life are improved in both scenarios, but even more so in the high performance scenario.
Table I. Reference parameters for a 100 MW UPV system in a site with average solar irradiance.
|module efficiency||19,5 %||20%||30%|
|Module costs||0,41 $/W||0,17 $/W12||0,30 $/W13|
|Balance of system costs14||$0.46/weekDC||$0.27/weekDC15||0,30 $/WDCsixteen|
|Project overhead17||0,21 $/WDC||0,11 $/WDC||0,15 $/WDC|
|Initial operating costs18||8,7 $/kWDC-Year||4,8 $/kWDC-Year||5,0 $/kWDC-Year|
|Escalation of operation and maintenance costs19||5.4%/year||3.0%/year||1.0%/year|
|Initial annual energy yield||1717 kWh/kWDC||1916 kWh/kWDC20||2040 kWh/kWDC21|
|drop in performance||0.7%/year (30 years)||0.5%/year (40 years)||0.4%/year (50 years)|
|LCOE (2019 US dollars)||4,6 ¢/kWh||2,0 ¢/kWh||2,0 ¢/kWh|
Figure 4. Components of the improvement of the LCOE for the UPV in the two scenarios of Table I.
The trade-off between allowable module costs and efficiency is shown in Figure 3. Here, the curves represent the module cost per watt required to achieve an LCOE of 2¢/kWh at an average solar irradiation location as a function of the module efficiency. For the top two curves, all parameters except module cost and efficiency correspond to the two 2030 scenarios in Table I. These curves show that a module with less than 13% efficiency does not meet the target LCOE in a system UPV in no scenario I can reach. The red curve differs from the low-cost scenario only in that the degradation rate increases to 1% per year with a corresponding useful life of 20 years. Module costs are unlikely to be as low as the red curve, but this curve shifts upward as BOS costs continue to decline, and would approach the lowest cost curve if all BOS costs compared to levels will be reduced by 50% instead of 30% by 2020. . .15
Figure 4 shows how the target LCOE reduction is distributed among the categories in Table I for both 2030 scenarios.22
Commercial and Industrial Photovoltaics (C&I PV)
Commercial and industrial PV represents a broad class of DPV systems that can be mounted on the ground or on the flat roof of a commercial building, typically ranging in size from 20 kW to 5 MW. The C&I PV market is rapidly evolving, including dual-use applications such as architectural solar, floating solar, and agricultural solar. Due to 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. However, most systems can be classified as either ceiling or floor mounted systems.
Table II lists representative key parameter values for two C&I PV systems installed near Kansas City in 2020 and the corresponding values that would meet the 4¢/kWh LCOE target by 2030. One system is 200kW roof-mounted with a 10 degree tilt and the other is a 500kW floor mounted with a fixed 33 degree tilt to the south. The 2030 values for module efficiency, module costs, degradation rate, and O&M scaling correspond to the low-cost scenario in Tables I and III for ground- and roof-mounted systems, respectively. The financial conditions are the same as for large-scale plants,9except that a 1% higher annual return on investment is assumed to reflect the higher risk investors typically perceive for C&I systems.
The ground-mounted system has higher energy harvest than the ceiling-mounted system due to the greater angle of inclination and its ability to generate additional energy from light shining on the back of the bifacial modules. As a result, the ground-mounted system requires significantly less BOS cost reduction than the ceiling-mounted system to achieve the same LCOE target.
Table II Reference parameters for C&I photovoltaic systems in a site with average solar irradiance.
|Parameter||2020 on the roof8||Bogota 20208||ceiling 2030||2030 Bogota|
|module efficiency||19,5 %||19,5 %||20%||20%|
|Module costs||0,41 $/W||0,41 $/W||0,17 $/W||0,17 $/W|
|Balance of system costs||$0.78/weekDC||$0.72/weekDC||$0.43/weekDC23||0,54 $/WDC24|
|Project overhead25||$0.63/weekDC||0,68 $/WDC||$0.32/weekDC||$0.42/sec.DC|
|Initial operation and maintenance costs18||9,3 $/kWDC-Year||9,4 $/kWDC-Year||4,6 $/kWDC-Year||5,8 $/kWDC-Year|
|Annual O&M escalation19||5.6%/year||5.6%/year||3 years||3 years|
|Initial energy yield||1454 kWh/kWDC||1559 kWh/kWDC||1502 kWh/kWDC26||1740 kWh/kWDC27|
|degradation rate28||0.7%/year (30 years)||0.7%/year (30 years)||0.5%/year (30 years)||0.5%/year (40 years)|
|LCOE (2019 US dollars)||8,7 ¢/kWh||8,1 ¢/kWh||4,0 ¢/kWh||4,0 ¢/kWh|
Residential Photovoltaics (RPV)
Residential PV systems are small rooftop DPV systems, most commonly on sloped roof surfaces that face approximately south (±90 degrees). Reducing the LCOE for RPV systems requires improvements to the same parameters listed in Table I. Additionally, the size of a home system has a significant impact, as larger systems have a lower cost per watt and lower LCOE. . Residential complexes are usually sized in such a way that their annual energy production corresponds to the energy consumed on site. In 2020, this typically required 10-30 modules.29By 2030, the increasing use of electric vehicles and building electrification could more than double the number of modules needed per home, so the size of RPV systems will be increasingly limited by the amount of adequate roof space. .
Figure 5. Effect of RPV system size on LCOE (1.63 m2 modules at 25% efficiency).
The financial arrangements for RPV systems differ significantly from UPV systems because condominiums are generally financed by the owner rather than investors. For homeowners who have equity in their homes, the cheapest financing available is a home equity loan. The discount rate, which describes how owners perceive the value of benefits that do not accrue until years later, is also different from that of investors who finance UPV schemes. Because homeowners don't sell the electricity they produce, there's no earnings to pay taxes on or depreciation of assets to deduct. Despite these large differences between RPV and UPV financing, the effective cost of capital, which represents the perceived value of money over time, is remarkably similar, between 5% and 7% per year.
Table III lists representative values of key parameters for a typical RPV system installed near Kansas City in 2020.8and two possible sets of these values that would achieve the LCOE target by 2030, one representing a low-cost approach and the other representing a high-performance approach.
Table III. Reference parameters for a private photovoltaic system in a location with average solar radiation.
|Parameter||benchmark 2020||2030 Low cost||2030 high performance|
|module efficiency||19,5 %||20%||30%|
|number of modules||22 (7kWDC)||36 (12kWDC)||36 (18 kWDC)|
|Module costs||0,41 $/W||0,17 $/W10||0,30 $/W|
|Balance of system costs30||$1.68/weekDC||0,92 $/WDC13||0,80 $/WDC31|
|Initial operating costssixteen||14,4 $/kWDC-Year||8,7 $/kWDC-Year||10,7 $/kWDC-Year|
|Escalation of operation and maintenance costs17||5,4 %||3,0 %||1,0 %|
|Initial annual energy yield||1542 kWh/kWDC||1593 kWh/kWDC33||1593 kWh/kWDC|
|drop in performance26||0.7%/year (30 years)||0.5%/year (30 years)||0.4%/year (30 years)|
|Loan rate and term||5%/year for 18 years||4%/year for 30 years||4%/year for 30 years|
|LCOE (2019 US dollars)34||12,8 ¢/kWh||5,0 ¢/kWh||5,0 ¢/kWh|
Figure 6. LCOE improvement components for RPV in the two scenarios of Table III. The part labeled "Other" represents improvements in energy performance, mining rate, and O&M scaling rate.
The influence of system size is shown in Figure 5. Reaching the 5¢/kWh target for a system with fewer than 36 modules would require further component cost reduction. For example, a 22 module system would require reducing the intrinsic cost of the BOS an additional 10% below the values in Table III. This could be done for systems installed as an integral part of new residential construction.35
Reducing the LCOE for RPV systems requires improving the same factors shown for UPV in Figure 4. Two additional important factors for RPV are reducing borrowing costs for financing and increasing the size of the system. The contribution of each improvement to the LCOE reduction is shown in Figure 6.
Concentrating Solar Thermal (CSP)
CSP systems use an array 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 power a conventional turbine generator. CSP can directly address the grid integration challenge arising from sunlight variability by efficiently integrating thermal energy storage. The ability of the grid to draw power from a CSP plant when needed is called dispatch capacity. Dispatch capacity increases the value of the network, so the LCOEs that make CSP economically competitive are higher than those of the UPV. The 2030 baseline LCOE target for CSP is 5¢/kWh for a Southwest system with at least 12 hours of thermal energy storage.
Figure 7. Impact of power cycle efficiency on the cost of the power block required for an LCOE of 5¢/kWh. The plus signs indicate the cost and efficiency targets for the power blocks used in each 2030 scenario in Table IV.
The main cost components of CSP are the power plant block housing the turbine generator, the array of tracking mirrors, site preparation, the receiver at the focal point, thermal energy storage, and costs. of operation and maintenance. The primary way to improve performance is through the efficiency of converting heat energy to electrical energy. Table IV presents three scenarios that would achieve the LCOE target for the CSP. The low cost scenario focuses on reduced costs with only a small improvement in efficiency. The high throughput scenario focuses on increasing the efficiency of the power block, allowing for higher system component costs to achieve the same target LCOE. An intermediate scenario is also shown, which is consistent with the high performance scenario, except for the field cost, which is consistent with the low cost scenario, reducing the required net power cycle efficiency to 50%.
Table IV Reference parameters for a 100 MW CSP system with 14 hours of thermal storage.36
|Net Power Cycle Efficiency||37%||40%||50%||55%|
|rated heat output||730 megawattsThermal-||675 megawattsThermal-||540 megawattsThermal-||491 megawattsThermal-|
|Power Block Cost||$1330/kWac-ugly||$700/kWac-ugly||$900/kWac-ugly||$900/kWac-ugly|
|Solar Field Costs||$140/mes2||$50/mes2||$50/mes2||$70/mes2|
|Site preparation costs||$16/mes2||$10/mes2||$10/mes2||$10/mes2|
|Tower and Receiver Costs||137 $/kWThermal-||100 $/kWThermal-||$120/kWThermal-||$120/kWThermal-|
|thermal storage costs||$22/kWhThermal-||10 $/kWhThermal-||15 $/kWhThermal-||15 $/kWhThermal-|
|Staggered operation and maintenance costs39||$9/kWThermal--Year||$6/kWThermal--Year||$7/kWThermal--Year||$7/kWThermal--Year|
|Leveled Capacity Factor||68,9 %||69,2 %||70,7 %||71,0 %|
|LCOE (2019 US dollars)40||9,8 ¢/kWh||5,0 ¢/kWh||5,0 ¢/kWh||5,0 ¢/kWh|
Figure 8. Components of the LCOE improvement for CSP under the three scenarios in Table IV The portion labeled "Other" represents improvements in tower, receiver, and O&M costs.
The capital cost used to finance the CSP systems in Table IV is higher than for the UPV systems in Table I because CSP technology has not been extensively tested in practice. If CSP systems can obtain financing through 2030 on the same terms currently available for UPV systems, this would reduce the LCOE to less than 4¢/kWh for each of the 2030 scenarios in Table IV.
Figure 7 shows how thermal-to-electric conversion efficiency affects the power block cost required to achieve the target LCOE of 5¢/kWh for the three 2030 scenarios in Table IV. Thermal components (solar panel, tower, receiver, and energy storage) lock in as efficiency changes, so the electrical rating of the system changes proportionally to duty cycle efficiency.
Figure 8 shows how improving each key parameter achieves the LCOE target for each 2030 scenario in Table IV. Most of the improvements are related to the field (cost of the solar field and site preparation) and the power block (reduced cost and increased efficiency).
- All costs listed here exclude the benefits of federal or state tax incentives such as: B. the investment tax credit.
- Office of Solar Energy Technologies,solar future study(2021).
- The utility-scale PV benchmark LCOE targets are for a 100 MW flat-site project with single-axis tracking.
- Commercial PV Benchmark LCOE targets are for a 200 kW flat roof system with a 10 degree pitch.
- Benchmark LCOE targets for residential PV systems apply to a south-facing roof system with a 25-degree slope.
- CSP benchmark LCOE targets apply to a 100 MW project with at least 12 hours of thermal energy storage.
- D. Feldman,et al., “US Cost Benchmark for Solar Photovoltaic Systems and Energy Storage,” NREL/TP-6A20-77324 (2021).
- Each tracker has a north-south oriented horizontal axis of rotation, allowing east-west tracking of modules mounted to occupy a single geometric plane. The followers are spaced to avoid excessive shadows between rows.
- LCOEs for UPV are subject to the following financial conditions, which are typical for systems installed without tax incentives: 7.75% annual return on investment, 71.8% debt at 5% APR for 18 years, 21% federal tax and 6% state, 2.5% annual inflation, MACRS depreciation 5 years.
- This value will be reached when module costs per watt are 30% lower in 2030 than in 2020 and import tariffs expire.
- This value assumes that higher module efficiency inevitably means higher costs per watt.
- Includes inverter, structural BOS, electrical BOS, installation, EPC overhead and interconnection cost.
- This value is achieved when all intrinsic BOS costs (eg, per project, per area, per watt) are reduced by 30%.
- This value is achieved when all BOS intrinsic costs (eg, per project, per area, per watt) are reduced by 20%.
- 25% of general expenses for profit, administration, taxes, working capital, financial charges, reserve fund and contingent liabilities.
- Each intrinsic component of initial O&M costs is reduced at the same rate as the cost of the installed system.
- Increase in annual operating and maintenance costs beyond inflation due to increased frequency of repairs as the system ages.
- This value is achieved when bifacial modules provide 8% more performance and system losses are reduced by 3% in absolute terms.
- This value is achieved when bifacial modules provide 15% more performance and system losses are reduced by 3% in absolute terms.
- Components are shown as latest contributions, adjusted proportionally to account for interactions.
- This value is reached when each intrinsic (z.B., per project, per area, per watt) reduces BOS costs by 44%.
- This value is reached when each intrinsic (z.B., per project, per area, per watt) reduces BOS costs by 24%.
- 53% of rooftop overhead and 60% of floor overhead include utilities, project management, sales tax, working capital, financing fees, reserve funds, and contingent liabilities.
- This value is reached when the system losses are reduced by 3% in absolute terms.
- This value is achieved when bifacial modules provide 8% more performance and system losses are reduced by 3% in absolute terms.
- The life of the roof system is limited to the 30 year life of the roof. Otherwise, the useful life will be extended until the annual energy production of the plant is less than 80% of its initial value.
- Residential PV modules are 1.6-1.8m long2so that it can be carried by a single person, at 1.63 m2used here as typical.
- Includes inverter, structural BOS, electrical BOS, supply chain, installation, permitting, and customer acquisition.
- This value is reached when each intrinsic (z.B., per project, per area, per watt) BOS costs are reduced by 16%.
- 30% overhead for profit, project management, and sales tax.
- This value is reached when the operating losses of the system are reduced by 3% in absolute terms.
- Annual discount rate 10%, 100% leveraged, without taxes, without depreciation benefit, 2.5% annual inflation.
- K. Ardani,you in the, “Cost Reduction Roadmap for Residential Solar PV 2017-2030,” NREL/TP-6A20-70748 (2018).
- Molten salt tower showing the peak intensity of the 1000 sol receptor near Daggett, CA. Other configurations may vary.
- CS Turks,et al., "CSP Systems Analysis: Final Project Report," NREL/TP-5500-72856, May 2019.
- System Advisor-Modell, v2020.11.29, National Renewable Energy Laboratory. Standard CSP System Configuration Except: 14 Hour Storage, 2.7X Solar, 30 Year Life, 100 MW, 8% Plus Receiver Cost, 7%/Year Capital Cost.
- Insurance included. Add to that $3.50/MWhac-redVariable costs for maintenance of the power block.
- Includes 37% of general administration expenses, taxes, working capital, financial charges, reserve fund and contingent liabilities.