The U.S. Department of Energy's (DOE's) Solar Energy Technologies Office (SETO) aims to accelerate the advancement and deployment of solar technology in support of an equitable transition to a decarbonized economy no later than 2050, starting with a decarbonized power sector by 2035. Its approach to achieving this goal includes driving innovations in technology, hardware, and soft cost reductions to make solar affordable and accessible for all. As part of this effort, SETO must track solar cost trends so it can focus its research and development (R&D) on the highest-impact activities. The benchmarks in this report are bottom-up cost estimates of all major inputs to PV and energy storage system installations. Bottom-up costs are based on national averages and do not necessarily represent typical costs in all local markets. Like last year's report, this year's report includes two distinct sets of benchmarks: minimum sustainable price (MSP) benchmarks and modeled market price (MMP) benchmarks. MSP benchmarks can be interpreted as the minimum price a company needs to charge to remain financially solvent in the long term based on the minimum sustainable prices of all inputs including minimum sustainable profit margins. MMP benchmarks can be interpreted as the actual cash sales price a company charges in the given benchmark period. These simplified estimates are useful for tracking technological progress, but they do not reflect all experiences. In fact, no individual estimate under any approach can reflect the diversity of the PV and storage manufacturing and installation industries. Our residential MMP benchmark ($2.90 per watt direct current [Wdc]) is 24% higher than the MSP benchmark ($2.34/Wdc) and 9% lower than our MMP benchmark ($3.18/Wdc) from Q1 2022 in 2022 U.S. dollars (USD). For community solar, our MMP benchmark ($1.75/Wdc) is 18% higher than our MSP benchmark ($1.49/Wdc). Our Q1 2022 benchmark report has no community solar system for comparison. For utility-scale systems with one-axis tracking, our MMP benchmark ($1.17/Wdc) is 22% higher than our MSP benchmark ($0.96/Wdc) and 10% higher than its counterpart ($1.07/Wdc) in Q1 2022 in 2022 USD.

This is one of a series of reports and deep dive assessments produced in response to Executive Order 14017 "America's Supply Chains," which directs the Secretary of Energy to submit a report on supply chains for the energy sector industrial base. The Executive Order is helping the federal government to build more secure and diverse U.S. supply chains, including energy supply chains. Over the past decade, solar power has gone from an emerging, niche technology to a mature energy industry. By 2035, solar power could supply 40% or more of U.S. electricity demand, dramatically accelerating the decarbonization of buildings, transportation, and industry; and, if current technology trends continue, it could do so without increasing the price of electricity. The rapid expansion of solar energy has the potential to yield broad benefits in the form of economic activity and workforce development. The solar industry already employs roughly 230,000 people in the United States, at an average wage that is higher than the national average for most comparable positions. By decarbonizing the electricity sector by 2035, the U.S. solar industry could employ 500,000–1,500,000 people by 2030. The components that are assembled to install a photovoltaic power system are produced by a global supply chain. Photovoltaic (PV) modules (also called panels) are made of cells that use a variety of technologies. There are two leading types of solar modules used in the United States, with crystalline silicon (c-Si) modules representing 84% of the market and cadmium telluride (CdTe) modules representing 16% of the market. Modules of either type require mounting structures to provide mechanical support (racking), which may be configured to follow the sun (tracking). The output of any PV module is direct current (dc), which is almost always converted to alternating current (ac) by an inverter.

This paper presents a fully-coupled 3D drift-diffusion simulation for the volume within the pyramids of a textured surface on a silicon wafer to compute the surface parameters needed for solar-cell modeling. First, the diffusion process is numerically simulated, resulting in a nonuniform surface dopant concentration that is higher at the pyramid's peak and ridges. Results are presented for quasi-Fermi potential, recombination, and hole current as a function of forward bias; lateral current flow in the diffused layer; and photogeneration profiles that account for double-bounce polarized reflection from the pyramid facets. Some surprising results include a bulbous protrusion of the space-charge region below the pyramid peak and majority-current crowding near the center of the pyramidal volume. The software used, PC3S, is open-source and freely available for personal computers running Microsoft Excel (Mac or Windows).

NREL's bottom-up cost models can be used to assess the minimum sustainable price (MSP) and modeled market price (MMP) of PV and storage systems having various configurations. MSP can be used to estimate future potential cost-reduction opportunities for PV and PV-plus-storage systems, thus helping guide research and development aimed at advancing cost-effective system configurations. MMP can be used to understand the cost of systems under recent market conditions. The MSP data in this annual benchmarking report will be used to inform the formulation of, and track progress toward, the Solar Energy Technologies Office's Government Performance and Reporting Act cost targets.

The semiconductor drift-diffusion equations describe the flow of electrons and holes in solar cells. When fully coupled using Poisson's equation, these equations are strongly nonlinear. However, with the exception of the first micrometer near each surface, the uniformly doped bulk in a solar cell is quasi-neutral, meaning that there is a nearly equal density of excess electrons and holes at each location. The drift-diffusion equations can then be reduced to two differential equations, one approximately linear in the excess carrier density and the other approximately linear in the excess electrostatic potential. The small deviations from linearity can be accommodated by initially treating the nonlinear terms as constant, updating the constants based on the solution result, and then iterating this cycle until convergence is achieved. When these linear differential equations are subject to reflective edge boundary conditions as typically occur when modeling solar cells, they can be solved efficiently using Fourier-series techniques. A specific numerical approach is described in detail and validated for the 2- and 3-D simulations of silicon-wafer solar cells with varying back contact parameters.

Approximate analytic expressions are given for the absorption of light emanating from a nonuniformly illuminated Lambertian surface into an absorptive layer having a spatially uniform coefficient of absorption, α. This situation is particularly relevant for silicon solar cells, which have deliberately textured surfaces and grid fingers that create nonuniform illumination. The approach uses Fourier superposition to represent spatial variation in the plane of the surface, represented by a series of wavenumbers in each axis. It is observed that the absorption rate and flux density at any given distance, z, into the layer is given by an effective wavenumber, keff, that is the root-sum-square of the wavenumbers in the two axes. This allows for simple analytic expressions that, for each Fourier component, depend only on the dimensionless terms keffz and αz. This Fourier-superposition approach is computationally efficient compared with ray tracing, and is particularly effective when the nonuniform illumination is periodic and symmetric in each axis, in which case the Fourier superposition becomes a cosine series of spatial harmonics. An example illustrates the good fidelity that can be obtained using as few as ten harmonics in each axis.

We explore the plausible range of future deployment of photovoltaic generation capacity in the USA using a supply‐focused model based on supply‐chain growth constraints and a demand‐focused model based on minimizing the overall cost of the electricity system. Both approaches require assumptions based on previous experience and anticipated trends. For each of the models, we assign plausible ranges for the key assumptions and then compare the resulting PV deployment over time. Each model was applied to 2 different future scenarios: one in which PV market penetration is ultimately constrained by the uncontrolled variability of solar power and one in which low‐cost energy storage or some equivalent measure largely alleviates this constraint. The supply‐focused and demand‐focused models are in substantial agreement, not just in the long term, where deployment is largely determined by the assumed market penetration constraints, but also in the interim years. For the future scenario without low‐cost energy storage or equivalent measures, the 2 models give an average plausible range of PV generation capacity in the USA of 150 to 530 GWdc in 2030 and 260 to 810 GWdc in 2040. With low‐cost energy storage or equivalent measures, the corresponding ranges are 160 to 630 GWdc in 2030 and 280 to 1200 GWdc in 2040. The latter range is enough to supply 10% to 40% of US electricity demand in 2040, based on current demand growth.

Manufacturing cost analysis is becoming an increasingly important tool in the photovoltaics industry to identify research areas that need attention and enable progress towards cost reduction targets. We describe a method to estimate manufacturing cost that is suitable for use during an early stage of technology development, delivering both the manufacturing cost estimate as well as an uncertainty analysis that quickly highlights the opportunities for greatest cost improvement. We apply the technique to three process sequences for the large-scale production of organic-inorganic hybrid perovskite photovoltaic modules. A process sequence that combines two demonstrated perovskite module sequences is estimated to cost $107/m(2) (uncertainty range $87 to 140/m(2)), comparable with commercial crystalline silicon and cadmium telluride technologies (on a US $/m(2) basis). A levelized cost of electricity calculation shows that this perovskite technology would be competitive in 2015 with incumbent photovoltaic technologies if a module power conversion efficiency of 18% and lifetime of 20 years can be achieved. Further analysis shows that even if the cost of the active layers and rear electrode were reduced to zero, a module power conversion efficiency of 18% and lifetime of 20 years would be required to meet the 2020 SunShot levelized cost of electricity targets. Copyright (C) 2017 John Wiley & Sons, Ltd.

We analyze the potential cost competitiveness of two frameless, glass-glass thin-film tandem photovoltaic module structures, cadmium telluride (CdTe)/CuInSe2 (CIS) and CuIn0.3Ga0.7Se2 (CIGS)/CIS, based on the demonstrated cost of manufacturing the respective component cell technologies in high volume. To consider multiple economic scenarios, we base the CdTe/CIS module efficiency on the current industrial production of CdTe modules, while for CIGS/CIS, we use an aspirational estimate for CIGS efficiency. We focus on four-terminal mechanically stacked structures, thus avoiding the need to achieve current matching between the two cells. The top cell in such a tandem must have a transparent back contact, which has not been successfully implemented to date. However, for the purpose of understanding the economic viability of both tandems, we assume that this can be implemented at a cost similar to that of sputtered indium tin oxide. The cost of both tandem module structures was found to be nearly identical on an equal-area basis and approximately $30/m(2) higher than the single-junction alternatives. Both tandem modules are about 4% (absolute) more efficient than a module by using the top-cell material alone. We find that these tandem modules might reduce total system cost by as much as 11% in applications having a high area-related balance-of-system cost, such as area-constrained residential systems; however, the relative advantage of tandems decreases in the cases where balance-of-system costs are lower, such as in commercial and utility scale systems. Copyright (c) 2017 John Wiley & Sons, Ltd.

An economic analysis with a defined uncertainty range is presented that considers whether the future deployment of utility-scale PV (UPV) systems in the USA will be limited by the supply of PV modules or by market demand for these systems. An analysis of global PV module manufacturing growth and the fraction of modules produced that will be available for installation in the USA gives a plausible range of cumulative capacity for the UPV segment of 50 - 170 GW in 2030 and 60 - 500 GW in 2040. A parallel analysis of the future demand for UPV systems in the USA indicates a plausible range for cumulative capacity of 80 - 230 GW in 2030 and 150 - 530 GW in 2040. The plausible ranges for supply and demand substantially overlap in both 2030 and 2040, suggesting that neither supply nor demand is more likely to limit PV deployment in the USA. Consequently, mechanisms for enabling growth in both supply and demand can benefit efforts intended to increase the deployment of PV in the USA.

The past decade's record of growth in the photovoltaics manufacturing industry indicates that global investment in manufacturing capacity for photovoltaic modules tends to increase in proportion to the size of the industry. The slope of this proportionality determines how fast the industry will grow in the future. Two key parameters determine this slope. One is the annual global investment in manufacturing capacity normalized to the manufacturing capacity for the previous year (capacity-normalized capital investment rate, CapIR, units $/W). The other is how much capital investment is required for each watt of annual manufacturing capacity, normalized to the service life of the assets (capacity-normalized capital demand rate, CapDR, units $/W). If these two parameters remain unchanged from the values they have held for the past few years, global manufacturing capacity will peak in the next few years and then decline. However, it only takes a small improvement in CapIR to ensure future growth in photovoltaics. Any accompanying improvement in CapDR will accelerate that growth.

Tandem modules combining a III–V top cell with a Si bottom cell offer the potential to increase the solar energy conversion efficiency of one‐sun photovoltaic modules beyond 25%, while fully utilizing the global investment that has been made in Si photovoltaics manufacturing. At present, the cost of III–V cells is far too high for this approach to be competitive for one‐sun terrestrial power applications. We investigated the system‐level economic benefits of both GaAs/Si and InGaP/Si tandem modules in favorable future scenarios where the cost of III–V cells is substantially reduced, perhaps to less than the cost of Si cells. We found, somewhat unexpectedly, that these tandems can reduce installed system cost only when the area‐related balance‐of‐system cost is high, such as for area‐constrained residential rooftop systems in the USA. When area‐related balance‐of‐system cost is lower, such as for utility‐scale systems, the tandem module offers no benefit. This is because a system using tandem modules is more expensive than one using single‐junction Si modules when III–V cells are expensive, and a system using tandem modules is more expensive than one using single‐junction III–V modules when III–V cells are inexpensive. Copyright © 2016 John Wiley & Sons, Ltd.

The high cost of wafers suitable for epitaxial deposition of III‐V solar cells has been a primary barrier to widespread use of these cells in low‐concentration and one‐sun terrestrial solar applications. A possible solution is to reuse the substrate many times, thus spreading its cost across many cells. We performed a bottom‐up techno‐economic analysis of three different strategies for substrate reuse in high‐volume manufacturing: epitaxial lift‐off, spalling, and the use of a porous germanium release layer. The analysis shows that the potential cost reduction resulting from substrate reuse is limited in all three strategies––not by the number of reuse cycles achievable, but by the costs that are incurred in each cycle to prepare the substrate for another epitaxial deposition. The dominant substrate‐preparation cost component is different for each of the three strategies, and the cost‐ranking of these strategies is subject to change if future developments substantially reduce the cost of epitaxial deposition. Copyright © 2016 John Wiley & Sons, Ltd.

Tandem modules, formed by stacking two PV cells, either monolithically or mechanically, can offer higher solar conversion efficiency than modules that use only one type of PV cell. Such modules necessarily cost more per unit area than either single-junction alternative, but the increased efficiency leverages area-related costs to potentially reduce system cost per watt. High-efficiency, low-cost tandems could arise if the cost of III-V cells is reduced to approach the cost of silicon cells, or if stable large-area perovskite cells are demonstrated with efficiency approaching that of today's best laboratory devices. Within the scope given by these optimistic assumptions, future costs and performance still have a substantial range of uncertainty. A probabilistic Monte Carlo model is presented that generates a large number of cost and performance scenarios based on a range of values for each input parameter. The results can be used to assign a probability, within the scope of the assumptions, that the tandem will be more cost-effective than either single-junction alternative. Four types of tandem modules are analyzed: (1) III-V on silicon, (2) III-V on thin film, (3) perovskite on silicon, and (4) perovskite on thin film. All of these tandems have a reasonable chance (> 10%) of providing slightly lower cost per watt for residential systems, and the two thin-film options might also slightly benefit utility-scale systems. Achieving a substantial cost benefit is less likely. Only the perovskite on thin film tandem has a reasonable chance of reducing system cost per watt by more than 10% for residential systems, or of reducing system cost per watt by more than 5% for utility-scale systems.

Using a bottom-up cost model, we assess the impact of initial factory capital expenditure (capex) on photovoltaic (PV) module minimum sustainable price (MSP) and industry-wide trends. We find capex to have two important impacts on PV manufacturing. First, capex strongly influences the per-unit MSP of a c-Si module: we calculate that the capex-related elements sum to 22% of MSP for an integrated wafer, cell, and module manufacturer. This fraction provides a significant opportunity to reduce MSP toward the U.S. DOE SunShot module price target through capex innovation. Second, a combination of high capex and low margins leads to a poor financial rate of return, which limits the growth rate of PV module manufacturing capacity. We quantify the capex of Czochralski-based crystalline silicon (c-Si) PV manufacturing, summing to 0.68 $/WaCap ($ per annual production capacity in watts, $year/W) from wafer to module and 1.01 $/WaCap from polysilicon to module. At a sustainable operating margin determined by the MSP methodology for our bottom-up scenario, we calculate the sustainable growth rate of PV manufacturing capacity to be ∼19% annually – below the historical trend of ∼50% annually. We conclude with a discussion of innovation opportunities to reduce the capex of PV manufacturing through both incremental and disruptive process innovation with c-Si, platform innovations, and financial approaches.

The past decade’s record of growth in the photovoltaic manufacturing industry indicates that global investment in manufacturing capacity for photovoltaic modules tends to increase in proportion to the size of the industry. The slope of this proportionality determines how fast the industry will grow in the future. Two key parameters determine this slope. One is the annual global investment in manufacturing capacity normalized to the manufacturing capacity for the previous year (capacity-normalized capital investment rate, CapIR, units $/W). The other is how much capital investment is required for each watt of annual manufacturing capacity, normalized to the service life of the assets (capacity-normalized capital demand rate, CapDR, units $/W). If these two parameters remain unchanged from the values they have held for the past few years, global manufacturing capacity will peak in the next few years and then decline. However, it only takes a small improvement in CapIR to ensure future growth in photovoltaics. Any accompanying improvement in CapDR will accelerate that growth.

The value of any new photovoltaics (PV) technology depends on its anticipated performance and manufacturing cost. Computer models can be used to predict module and system performance, but there are few tools available for predicting the future manufacturing cost of PV technologies while they are still under development. This paper presents a useful approach for comparing the cost of competing silicon cell and module concepts that minimizes the extrinsic influences of location, timing, and scale. As such, it is targeted at PV specialists tasked with choosing a technology platform to develop for future production.