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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.
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 illustratesthe 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.
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.
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 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.
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.
Table I. Benchmark parameters for a 100-MW UPV system in a location with medium solar resource.
Figure 4. Components of LCOE improvement for UPV in the two scenarios of Table I.
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 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.
Figure 5. Impact of RPV system size on LCOE(1.63 m2modules @ 25% efficiency).
Table III lists representative values for the 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 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.
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.
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.
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.
Table IV. Benchmark parameters for a 100 MW CSP system with 14 hours thermal storage.36
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