Pessimism in the global polysilicon market has deepened, driven by a persistent oversupply that exceeds buyers’ total monthly purchasing volumes. Several global polysilicon buyers have confirmed maintaining substantial inventories, which has contributed to the current subdued trading activity. One market participant additionally noted that their ingot production operations in Southeast Asia are currently running at levels that consume only about half of the monthly polysilicon volumes secured through long-term contracts, indicating ongoing accumulation of global polysilicon inventories, whether held by sellers or buyers.

Despite this, some buyers have reportedly continued placing spot orders beyond their contracted commitments. These transactions are primarily driven by the greater pricing flexibility offered by spot purchases, which buyers leverage to diversify their supply sources at lower costs and better manage future risks.

Suppliers meanwhile reportedly remain focused on the potential growth in orders for solar modules and cells exported to the U.S., viewing such trends as key indicators of broader global polysilicon demand.

Additionally, Indonesia’s solar cell production projects are reportedly accelerating expansion, which could modestly increase demand for wafers derived from global polysilicon.

Market participants observe that the historically stable relationships between buyers and sellers are gradually eroding, giving way to more fragmented trading patterns and irregular orders, noting that a new dynamic in transactions and customer relationships appears to be emerging.

The China Mono Grade, OPIS’ assessment for mono-grade polysilicon prices within the country, remained stable this week at CNY 30.750 ($4.27)/kg, equivalent to CNY 0.065/W. Similarly, the China Mono Premium, OPIS’ price assessment for mono-grade polysilicon used in n-type ingot production, held steady at CNY 37.625/kg, or CNY 0.079/W. Both prices remained unchanged from the previous week.

Polysilicon prices remained stable this week following five consecutive weeks of decline, primarily due to muted trading activity and the lack of price adjustments by major producers, according to trade sources. Wafer manufacturers have reportedly adopted a more cautious purchasing approach, procuring polysilicon at a slower pace and in smaller volumes amid persistent bearish sentiment regarding the short-term price outlook across the photovoltaic supply chain.

The ongoing market downturn has also heightened expectations for further reductions in polysilicon production. Two new projects in Qinghai—with annual capacities of 100,000 MT and 50,000 MT, respectively—had initially been slated to begin trial production and ramp up output in the second quarter. However, given the current price levels and weak market outlook, industry insiders believe it is unlikely these producers will launch products in the near term.

In an effort to address the ongoing market challenges, multiple sources have indicated that the industry is considering a consolidation plan under which the six largest polysilicon producers would acquire all remaining small-scale production capacities. In parallel, a leading manufacturer has reportedly suggested a coordinated initiative among producers to collectively curtail output, with the aim of stabilizing prices within a reasonable range.

However, sources caution that significant uncertainty surrounds both the feasibility and future direction of the acquisition proposal. A major obstacle lies in aligning the diverse interests of investors, acquisition targets, and local governments, which complicates efforts to establish a unified consensus. Furthermore, sources noted that determining a standardized acquisition price—based on the scale and output volume of the targeted polysilicon capacities—will be essential for this plan to move forward and be implemented.

Broader pessimism surrounding market demand in 2025 is now exerting downward pressure on China’s polysilicon futures market. According to data released by the Guangzhou Futures Exchange on May 19, futures prices for polysilicon deliveries from June 2025 through April 2026 have all dropped below CNY 40/kg. The highest settlement price, for June 2025 delivery, stood at CNY 37.04/kg, representing a 1.55% decrease over the current spot price assessed by OPIS this week.

Some polysilicon orders have been concluded this week, but the ingot segment still holds inventory, keeping overall procurement slow. Only some small-volume deals have been finalized, and most supply comes from smaller manufacturers, while top makers keep prices steady.

Some new orders are trading at RMB 35–37/kg this week, with the overall price range slipping. China-made granular polysilicon has seen steady deliveries, but supply chain conditions have driven mainstream prices down to RMB 34–35/kg. U.S. policy changes have disrupted non-Chinese polysilicon makers’ shipments, resulting in a cautious sentiment in manufacturing. Newly-signed orders have been under negotiation recently, with fewer purchases and an average price holding at USD 19/kg.

Large-volume deals hinge on ongoing negotiations among major producers, which remain unsettled. Despite mixed market signals, polysilicon suppliers aim to stabilize prices and are assessing potential production cuts, while only a few have confirmed maintenance plans, and most show no capacity increases. Significant production cuts are likely around June to August, aligning with weak end-user demand. Some suppliers facing higher inventory levels are also weighing capacity adjustments to maintain stable annual output.
 

Wafer

This week, wafer prices have continued last week’s trend, showing signs of stabilization. As manufacturers start cutting production and cell prices decline at a slower pace, market sentiment has slightly recovered.

Mainstream prices:

•    183N: RMB 0.95/piece

•    210RN: Mostly at RMB 1.08–1.10/piece, ranging RMB 1.05–1.10/piece

•    210N: RMB 1.30/piece (sustained)

Overall, prices appear to be bottoming out.

On the demand side, although overall momentum remains weak, end users are steadily shifting from 183N to 210RN, boosting 210RN’s market share and price support. While polysilicon prices are still falling this week, 210RN cells are holding up better, helping stabilize wafer prices for now.

With policy-driven stocking coming to an end, downstream demand has weakened noticeably, and the market lacks short-term support for a price rebound. Most manufacturers are adjusting their utilization rates and production plans to ease pressure, which may help stabilize prices in the short term. However, if polysilicon and cell prices keep falling and demand stays weak, wafer prices could decline again. Overall, the wafer market is in a period of adjustment, and future prices will depend on actual production cuts and whether demand recovers.
 

Cell prices in China

P-type (182P) cell prices have sustained this week:

•    Average price: RMB 0.285/W

•    Price range: RMB 0.28-0.285/W

China’s demand for p-type cells is primarily for small, scattered orders. Significant price fluctuations are unlikely in the short term.

N-type cell prices this week:

183N:

•    Average price: RMB 0.25/W (slipped)

•    Price range: RMB 0.25-0.255/W

210N:

•    Average price: RMB 0.27/W (slipped)

•    Price range: RMB 0.265-0.275/W

210RN:

•    Average price: RMB 0.265/W (sustained)

•    Price range: RMB 0.265-0.27/W

•    Low-end price increased from RMB 0.26/W to RMB 0.265/W

Cell order demand for June remains sluggish. Prices for 183N and 210N cells have continued to decline this week, while 210RN price has held steady as leading cell makers have gradually completed production line transitions and strived to stabilize prices. Low-end prices for 210RN have also edged up due to relatively stable demand.

Some cell makers have gradually reduced production in May. With cell prices now near production costs, many producers are struggling to sustain long-term operations. Given expectations of weaker end-user demand in June, whether cell prices can recover will depend on how effectively production cuts are carried out.
 

Cell prices in non-China markets

P-type cell prices in USD:

The average export price for 182P cells from China stays at USD 0.036/W. The higher-end pricing refers to Southeast Asian cells made with non-China-made polysilicon, directly exported to the U.S., with recent prices at USD 0.08–0.09/W, averaging USD 0.085/W.

N-type cell prices in USD:

The average export price for 183N cells from China has slipped to USD 0.034/W this week. Due to low demand and falling prices in China, cell prices for new orders continue to decline, reaching as low as USD 0.032/W. For higher-end Southeast Asian cells made with non-China-made polysilicon and exported to the U.S., recent prices have sat at USD 0.11–0.12/W, averaging USD 0.12/W.

The average price of Southeast Asian cells exported to the U.S. has remained flat over time. During June and July, before the end of the 90-day tariff window for the U.S. reciprocal tariffs, demand is still likely to stay well-supported. However, significant shifts in U.S. trade policies remain possible. InfoLink will continue to closely monitor developments.
 

Module prices in China

As with last week, recent price fluctuations have been minimal. Manufacturers are now focusing on stabilizing prices and maintaining controlled deliveries, with signs of price sustain emerging across the supply chain.

For modules: 

•    Tier-1 TOPCon manufacturers have set floor prices for new orders at RMB 0.65–0.66/W.

•    Low-priced deliveries are now being limited in volume.

•    Due to production cuts, supply shortages have reappeared for some popular formats.

•    Spot prices for new orders are now stable at RMB 0.67–0.72/W.

•    Utility-scale projects are delivered at RMB 0.66–0.67/W.

In early May, demand was mainly driven by previously secured projects. However, demand support in the latter half of the month appears weak, with high market uncertainty. The sluggish market will likely persist through July and August. How manufacturers adjust their strategies will affect future price stability and needs close attention.

Module prices this week: 

TOPCon glass-glass:

•    RMB 0.62-0.72/W

•    Bulk orders: RMB 0.67-0.68/W

•    Low-priced deals are becoming less common.

PERC glass-glass: 

•    RMB 0.60–0.70/W

HJT: 

•    RMB 0.72-0.85/W  

•    Ground-mounted projects: RMB 0.73-0.75/W 

N-TBC:

•    Distributed projects: RMB 0.7-0.86/W

•    Ground-mounted projects: RMB 0.75-0.78/W
 

Module prices in non-China markets

Module prices in non-China markets hold steady this week.

TOPCon module prices by region:

•    Asia-Pacific:

1.    Prices for Chinese exports to the Asia-Pacific come in at USD 0.085-0.090/W. In India, modules made with Chinese cells and assembled locally are selling in bulk at USD 0.14–0.15/W. It is worth noting that some Indian manufacturers have recently begun sourcing cells from Southeast Asia.

2.    Modules are delivered at USD 0.09-0.10/W in Australia.

•    Europe:

Overall delivery prices in Europe stay at USD 0.085-0.09/W. With installation rush ending in China, Chinese companies are shifting more shipments overseas. After Intersolar Europe, prices start to decline. In H2, prices for ground-mounted projects are expected at USD 0.080–0.085/W.

•    Latin America:

Mainstream prices are at USD 0.08-0.09/W. Brazil see prices both at USD 0.08/W and USD 0.09/W.

•    Middle East:

Prices mostly hold at USD 0.085-0.09/W for bulk procurement, while previous high-priced locked-in orders are still being delivered at USD 0.10–0.11/W.

•    The U.S.:

Impacted by U.S. tariff policies, suppliers and project developers are actively negotiating new quotes. Current trading prices have slightly increased, approaching USD 0.27–0.30/W. Given trade risks, price quotes for locally made modules are also trending upward, with quotes above USD 0.40/W gradually becoming more common.

In the comparison of photovoltaic modules with different technical routes, experts found that the old generation of BC modules produced at the end of 2021 had a power generation efficiency of only 20.4% due to insufficient passivation technology, which was similar to the PERC modules at the time. Compared with TOPCon modules, its conversion efficiency is more than 2% lower, the power is 200W less, and the bifaciality is more than 25% lower. Moreover, this old product has been discontinued for a long time and cannot be compared with the current BC modules. However, it is interesting that although TOPCon modules should have more advantages in back-side power generation in such a highly reflective environment, actual tests have found that the power generation per watt of mature TOPCon modules is only 1.16% higher than that of early IBC modules with immature technology, indicating that IBC modules have stronger front-side power generation capabilities.

By 2024, the new generation of BC technology has made significant progress. The bifaciality of photovoltaic modules produced by leading companies generally exceeds 70%, and the efficiency of standard-sized modules reaches 24.4% with a power of 660W. These modules perform better in power generation under temperature changes and weak light environments, and can better resist shadow shading and prevent local overheating, with overall performance leading TOPCon modules. In 2025, BC manufacturers will also launch products with higher bifaciality to further improve power generation capacity. With the large-scale use of these new generation BC products in photovoltaic power stations, the power generation cost of the photovoltaic industry is expected to decrease, ushering in a new round of technological upgrades.

At the same time, the three-year data of the Daqing Photovoltaic Storage Demonstration Base also answered the question of how to evaluate the power generation performance of bifacial modules. Data shows that in high-reflection scenarios, the ratio of PV module back irradiation to front irradiation fluctuates between 12.87% and 13.94%. Although this ratio varies in different scenarios, the rules are similar, such as the snow reflectivity of up to 50% to 60%. In 2024, the back irradiation ratio of the inclined surface is 12.87%, slightly lower than 13.94% in 2022 and 13.79% in 2023.

The industry standard IEC 61215 proposes a reference irradiation condition for bifacial module nameplate calibration, called bifacial nameplate irradiance (BNPI), which means that the front of the module receives 1000W/m² of light and the back receives 135W/m² of light. Other test conditions are the same as standard test conditions (STC). The 13.5% back light utilization rate specified in this standard meets most ground application scenarios and is consistent with the empirical data of the Daqing base. This shows that the performance of bifacial modules cannot be judged by the bifaciality alone. Under the same conditions, the overall performance of HPBC 2.0 is better than that of TOPCon and HJT. HPBC 2.0 has a front power of 670W, a bifaciality of 75%, and a front-back combined power of 737.84W; TOPCon has a front power of 630W, a bifaciality of 80%, and a front-back combined power of 698.04W; HJT has a front power of 635W, a bifaciality of 85%, and a front-back combined power of 707.87W.

Some polysilicon orders have been concluded this week, but the ingot segment still holds inventory, keeping overall procurement slow. Only some small-volume deals have been finalized, mostly at RMB 36–37/kg. China-made granular polysilicon has seen steady deliveries, with mainstream prices at RMB 35–36/kg. U.S. policy changes have disrupted non-Chinese polysilicon makers’ shipments, resulting in a cautious sentiment in manufacturing. Newly-signed orders have been under negotiation recently, with fewer purchases and an average price holding at USD 19/kg.

Large-volume deals hinge on ongoing negotiations among major producers, which remain unsettled. Despite mixed market signals, polysilicon suppliers aim to stabilize prices and are assessing potential production cuts, while only a few have confirmed maintenance plans, and most show no capacity increases. Significant production cuts are likely around June to August, aligning with weak end-user demand. Some suppliers facing higher inventory levels are also weighing capacity adjustments to maintain stable annual output.
 

Wafer

After weeks of decline, wafer prices have started stabilizing this week. Given upstream production control and narrowing drops in cell prices, market sentiment has slightly improved, with overall wafer prices staying flat from last week.

Mainstream wafer trading prices:

•    183N: RMB 0.95/piece

•    210RN: RMB 1.10/piece

•    210N: RMB 1.30/piece (showing signs of bottoming out)

Price ranges by wafer format:

•    183N: RMB 0.95–0.98/piece

•    210RN: RMB 1.05–1.10/piece; most traded at RMB 1.08–1.10/piece, while some lower-priced at RMB 1.05/piece

•    210N: RMB 1.30–1.35/piece, holding firm

While wafer prices have stabilized this week, market sentiment remains cautious. End-user demand has yet to pick up as current supply-demand dynamics lack strong drivers for price recovery. Thus, a sharp short-term price rebound remains unlikely. The supply chain is still in adjustments, and prices for polysilicon and cells remain crucial to track. Upstream producers have been planning production cuts. If these cuts are effectively implemented and inventory is depleted faster, it could help stabilize prices. However, whether wafer prices can hold or rebound will depend on actual production cuts and demand recovery in June.
 

Cell prices in China

P-type (182P) cell prices have sustained this week:

•    Average price: RMB 0.285/W

•    Price range: RMB 0.28-0.285/W

China’s demand for p-type cells is primarily for small, scattered orders. Significant price fluctuations are unlikely in the short term.

N-type cell prices this week:

183N:

•    Average price: RMB 0.255/W (slipped)

•    Price range: RMB 0.25-0.26/W

210N:

•    Average price: RMB 0.275/W (slipped)

•    Price range: RMB 0.27-0.275/W

210RN:

•    Average price: RMB 0.265/W (sustained)

•    Price range: RMB 0.26-0.27/W

According to some cell manufacturers, demand for 183N cells remains weak, and module makers are reluctant to accept current average prices. As a result, the average price may drop further to RMB 0.25/W. For 210R cells, leading manufacturers held firm on pricing last week, keeping average prices stable this week.

Overall, some cell manufacturers have gradually cut production by the end of May. With prices hovering near production costs, sustaining operations has become difficult. Given expectations of weaker end-market demand in June, whether cell prices can recover will depend on how significantly and effectively production cuts are carried out.
 

Cell prices in non-China markets

P-type cell prices in USD:

The average export price for 182P cells from China stays at USD 0.036/W. The higher-end pricing refers to Southeast Asian cells made with non-China-made polysilicon, directly exported to the U.S., with recent prices at USD 0.08–0.09/W, averaging USD 0.085/W.

N-type cell prices in USD:

The average export price for 183N cells from China stays at USD 0.035/W this week. For higher-end Southeast Asian cells made with non-China-made polysilicon and exported to the U.S., recent prices have sat at USD 0.11–0.12/W, averaging USD 0.12/W.

The average price of Southeast Asian cells exported to the U.S. has remained flat over time. During June and July, before the end of the 90-day tariff window for the U.S. reciprocal tariffs, demand is still likely to stay well-supported. However, significant shifts in U.S. trade policies remain possible. InfoLink will continue to closely monitor developments.
 

Module prices in China

This week has seen little change, but as supply chain prices near the bottom, some manufacturers are struggling to deliver at RMB 0.65/W, as noted last week. Even aggressive manufacturers are now adjusting their strategies. Signs of price support are emerging across the supply chain.

For modules, leading TOPCon makers have set a price floor at RMB 0.65–0.66/W. Low-price orders are being limited, and production cuts are starting to impact supply. As a result, some popular models are in short supply again, with new spot prices trading at RMB 0.67–0.72/W.

In early May, demand was mainly driven by previously secured projects. However, demand support in the latter half of the month appears weak, with high market uncertainty. The sluggish market will likely persist through July and August. How manufacturers adjust their strategies will affect future price stability and needs close attention.

Module prices this week: 

TOPCon glass-glass:

•    RMB 0.62-0.72/W

•    Bulk orders: RMB 0.67-0.68/W

•    Low-priced deals are becoming less common.

PERC glass-glass: 

•    RMB 0.60–0.70/W

HJT: 

•    RMB 0.72-0.85/W  

•    Ground-mounted projects: RMB 0.73-0.75/W 

xBC (N-TBC): 

•    Distributed projects: RMB 0.7-0.82/W

•    Ground-mounted projects: RMB 0.74-0.75/W
 

Module prices in non-China markets

Module prices in non-China markets hold steady this week.

TOPCon module prices by region:

•    Asia-Pacific:

1.    Prices for Chinese exports to the Asia-Pacific come in at USD 0.085-0.09/W. In India, modules made with Chinese cells and assembled locally are selling in bulk at USD 0.14–0.15/W. It is worth noting that some Indian manufacturers have recently begun sourcing cells from Southeast Asia.

2.    Modules are delivered at around USD 0.09/W in Australia, with prices for distribution-based and distributed projects starting to rise by USD 0.09-0.10/W.

•    Europe:

Overall delivery prices in Europe stay at USD 0.085-0.09/W. With installation rush ending in China, Chinese companies are shifting more shipments overseas. After Intersolar Europe, prices start to decline. In H2, prices for ground-mounted projects are expected at USD 0.080–0.085/W.

•    Latin America:

Mainstream prices are at USD 0.08-0.09/W. Brazil see prices both at USD 0.08/W and USD 0.09/W.

•    Middle East:

Prices mostly hold at USD 0.085-0.09/W for bulk procurement, while previous high-priced locked-in orders are still being delivered at USD 0.10–0.11/W.

•    The U.S.:

Impacted by U.S. tariff policies, suppliers and project developers are actively negotiating new quotes. Current trading prices have slightly increased, approaching USD 0.27–0.30/W. Given trade risks, price quotes for locally made modules are also trending upward, with quotes above USD 0.40/W gradually becoming more common.

As an Italian provider of solar production equipment, Ecoprogetti designed the automatic recycling system to meet growing demands for end-of-life PV management. “Our goal was to create truly industrial recycling plants that operate continuously, reliably, and with high productivity,” a company spokesperson told pv magazine. Since 2024, Ecoprogetti has shipped over one system monthly, with active installations in Italy, Spain, Greece, and other Southern European countries.

The plant is optimized for recycling both double-glass and glass-backsheet panels. Its flexibility and scalability stem from an adjustable system that accommodates different panel sizes and a barcode traceability feature for material tracking.

The recycling line comprises seven integrated machines:

1. Junction Box Removal: The first machine detaches junction boxes from panels.
2. Frame Extraction: The second removes aluminum frames.
3. Front Glass Separation: The third machine dislodges the primary front glass layer from the laminate.
   4-6. Material Separation & Collection: Subsequent machines handle metal separation, followed by division and collection of aluminum, copper, glass, plastic, and silicon. Ecoprogetti reports a recovery rate of 100% for aluminum, 99% for copper and glass, 98.5% for plastic, and 95% for silicon.
4. Dust Filtration: The final machine removes fine particles and captures residual dust via high-efficiency filters, ensuring clean operation.

With a processing capacity of 60 panels per hour, the line’s energy consumption is significantly lower than competitors, balancing efficiency with environmental performance. Requiring 500 sqm of floor space, 160 kW of power, and two operators, the system offers a payback period of 1–2 years, according to the company’s website.

By 2050, the International Renewable Energy Agency (IRENA) projects global end-of-life solar panel waste will reach 80 million tons, with Italy alone expecting 2.2 million tons. Ecoprogetti’s solution addresses this challenge by enabling closed-loop recycling of PV components, supporting the circular economy in renewable energy.

Scientists at TU Delft in the Netherlands fabricated a front-back contact silicon heterojunction (FBC-SHJ) solar cell using a TCO based on ICO, aiming to enhance the device’s opto-electrical performance. “To further increase power conversion efficiency, high-mobility TCO layers are key,” lead author Engin Özkol told pv magazine. “We explored cerium-doped indium oxide films for this purpose. Longi already uses hydrogenated indium oxides in its record-breaking cells via reactive plasma deposition, but we employed budget-friendly room-temperature radio frequency (RF) sputtering—widely accessible in labs but underused in literature.”

ICO layers are attractive for solar cell manufacturing due to their opto-electrical properties and room-temperature deposition, outperforming indium tin oxide (ITO) counterparts. The team sputtered 35-nm-thick ICO films onto Corning Eagle XG glass substrates at room temperature. “First, we optimized ICO layers for mobility, carrier concentration, resistivity, and transmittance,” said Özkol. “We achieved a Hall mobility of 44.22 cm²/Vs—56% higher than baseline ITO—and a resistivity as low as 8.56×10⁻⁴ Ω·cm. The next step was integrating this layer into solar cells.”

The team built 2×2 cm² cells on fully passivated 4-inch round wafers. Under standard illumination, the device achieved 23.58% power conversion efficiency, 722 mV open-circuit voltage, 40.39 mA/cm² short-circuit current, and 80.86% fill factor. A reference cell with ITO TCO reached 23.03% efficiency, 720 mV voltage, 39.72 mA/cm² current, and 80.55% fill factor. “The opto-electrical improvements of ICO over ITO translated to device-level gains, particularly a 0.67 mA/cm² increase in short-circuit current,” Özkol noted. “We demonstrated ICO’s potential as a powerful ITO alternative and opened pathways for cost-effective, scalable, low-temperature TCO fabrication in advanced PV technologies.”

The new cell concept is detailed in the study “Optimization and integration of room temperature RF sputtered ICO as TCO layers in high-performance SHJ solar cells,” published in Solar Energy Materials and Solar Cells. In April, other TU Delft researchers presented a rear junction silicon heterojunction solar cell with a localized front carrier-selective passivating contact, covering only metal grid contact areas.

A group of researchers from the Technische Universität Wien in Austria and the Norwegian University of Science and Technology have conducted a techno-economic analysis to understand what level of solar modules stockpiling could be used for the European Union to achieve stable solar PV deployment at the lowest cost possible.

The scientists explained that compared to traditional energy carriers, such as oil and gas, stockpiling photovoltaic modules suffers from relatively fast technological obsolescence. They also noted that the global solar module market is currently characterized by high concentration in China and oversupply, with the EU being heavily reliant on imports and eventually unable to reach the 40% solar manufacturing benchmark set by the EU Net-Zero Industry Act (NZIA) by 2030.

The research team investigated, in particular, the optimal levels of strategic solar module stockpiles in the EU by 2050 and the impact of the European initiatives to re-create a domestic solar manufacturing ecosystem.

“Consistent with conventional energy system optimization modeling approaches, our analysis optimizes electricity supply to meet demand while minimizing total system costs,” it further explained, noting that their approach was mostly intended to investigate how different energy scenarios influence the optimal stockpiling levels rather than cost-optimal levels.

“The model’s key decisions include determining the optimal capacity and utilization of various energy generation technologies, such as hydro, wind, and biomass, alongside the stockpiling levels of solar modules in response to evolving short- and long-term energy system developments,” it added.

The academics identified 36 future energy scenarios with different levels of EU solar manufacturing, energy costs, carbon prices, commodity prices, import dynamics, shares of renewables penetration, technology advancements, and fossil phase-out roadmaps, among other factors. They also predicted that the cumulative PV capacity in the EU may range from 1,076 GW and 1,784 GW in 2040 and from 1,526 GW to 2,252 GW in 2050.

Their analysis showed that high levels of solar module stockpiling would not be likely in 28 of the proposed scenarios, as the economic driver for their creation is insufficient.

As for the other 8 scenarios, researchers found they are characterized by high import costs, an import stop, or tight solar market conditions, as well as by the achievement of the above-mentioned 40% benchmark set by the EU for domestic manufacturing. “During the 2030s, average stockpile levels range from 164 to 180 GW, which is around 300% of annual additions,” they emphasized. “In earlier and later periods, levels are notably lower, averaging between 27 and 33 GW, which is around 50% of annual additions.”

The academics also noted that the 8 scenarios favorable to stockpiling also see import dependency being reduced, as the stockpiling system itself ensures the necessary temporal flexibility between injection and withdrawal, which they say is very similar to a diversification strategy. “Interestingly, the strategic reserve of solar modules exerts a stabilizing effect on optimal wind and solar capacities, highlighting its broader role within the energy system,” they concluded.

The research work was presented in the study “Strategic solar module stockpiling in the EU: A scenario-based analysis of costs and benefits beyond 2030,” published in Energy Policy.

A new study from Ohio State University shows that the strongest driving force behind the installation of solar energy in homes in the United States is economic benefits rather than environmental appeals. At the same time, the main reason that prevents community solar projects from realizing their full potential in the United States is lack of awareness, rather than cost issues. The study, published in the journal Energy Research and Social Sciences, aims to assess the public’s perception of rooftop solar and community solar, and then develop strategies to promote the popularization of home solar energy across the United States.

“We wanted to understand whether there were differences in potential consumer attitudes toward different types of solar projects,” lead author Naseem Dillman-Hasso told pv magazine, “especially given that community solar is a relatively new distribution model.”

Although community solar projects are often easier to participate in, survey participants preferred rooftop solar systems. The authors note that most survey participants have taken very little action to adopt community solar, and most have never even heard of it.

“Our findings suggest that households may have low awareness of community solar and/or limited knowledge of the benefits it can provide,” the authors added.

Community solar adoption faces a unique and critical challenge: a lack of immediate physical visibility. Seeing rooftop panels around a community helps make solar more accessible and raises awareness of its benefits. But without a comparable visual presence, community solar can have a hard time catching up because it can be perceived as indicating that few people are interested in such projects, or that the technology is perceived as high risk.

When comparing rooftop solar to community solar, survey participants rated rooftop solar’s ​​utility features higher. However, for both types of residential solar, economic factors such as saving money and avoiding price hikes outweighed environmental or social benefits in driving interest.

The researchers also found that homeownership and a strong sense of environmental awareness predicted a higher willingness to adopt rooftop solar, while having a stronger sense of social responsibility and liberal political views were associated with a willingness to adopt community solar.

“Survey participants perceived community solar to have higher environmental benefits than rooftop solar, which may reflect that they are considering factors such as economies of scale,” Dillman-Hasso said, although he noted that low levels of awareness of community solar projects made it difficult to identify a strong theory.

Men were more likely to adopt rooftop solar than women, while older groups of either gender were less interested overall. Unlike some previous studies, income did not predict a person’s willingness to participate in a residential solar project.

In addition, Dillman-Hasso said, “ensuring that community solar is not more expensive than traditional utility options, which is particularly important for renters and low-income households,” could increase adoption, even if it is not the only solution. There is also a need for outreach campaigns that highlight the real benefits of solar.

“It’s important to make sure the information is comprehensive and easy to understand,” Dillman-Hasso added.

This is especially true for the promotion of community solar, as benefits like energy savings, flexibility, and easy registration aren’t as obvious as the gleaming panels on your neighbor’s roof.

This week, spot market transactions for polysilicon have been low, with purchasing activity slowing down until after International Workers’ Day. For now, prices hold at last week’s level.

China-made polysilicon chunks:

Major manufacturers attempt to slow down price declines amid the sluggish market. However, ingot manufacturers still have some polysilicon inventories on hand, and buyers’ bids remain below sellers’ offers, resulting in buyer-seller standoffs. As no orders have been placed this week, the average price hovers at last week’s level.

China-made granular polysilicon:  

• Primarily supplied by major manufacturers
• Prices land at RMB 36-38/kg
• Price quotes slip by RMB 1/kg (but no buyers so far)

In recent months, US policy changes have disrupted polysilicon shipments, leading to a wait-and-see sentiment in manufacturing, cautious downstream buying, and a slip in average prices to USD 19/kg.

Prices are falling due to weaker demand, while ingot manufacturers still hold enough stock for 1-1.5 months. Their short-term strategy focuses on using up inventory to gain leverage in April-May, the same as reported last week. Smaller firms with limited stock will have a small number of deals by late April, while large transactions still depend on major players’ negotiations and are likely to be settled in early May, with ingot production cuts for May still under discussion.

Polysilicon suppliers will keep prices stable and maintain April production at a level similar to March, with some cutting production. As for the production schedule for May, despite lower electricity prices during the hydropower season, polysilicon makers’ inventory accumulation remains a great concern amid the gloomy market. Thus, they are unlikely to increase production.
 

Wafer

With China’s new policy approaching, end-user demand has sharply shrunk. Driven by the continued cell price declines, the wafer market has weakened further this week.

Prices for most specifications have dropped notably:

• 183N: RMB 1.15/piece
• 210RN: RMB 1.35/piece
• 210N: RMB 1.5/piece

Overall, market sentiment remains subdued.

Trading prices for p-type M10 wafers are sustained at RMB 1.05–1.20/piece. However, due to weak p-type demand in China, actual transactions mostly fall within RMB 1.05–1.15/piece, and the market activity is notably lackluster. Although non-China orders provide support with their quotes firm at RMB 1.20–1.25/piece, limited overall demand suggests little room for a short-term price rebound.

As for n-type wafers, the mainstream trading price for 183N this week is RMB 1.15/piece, while some smaller producers have accepted trading prices at RMB 1.10/piece, indicating further price slips. Most manufacturers are negotiating, with further trading prices likely to keep falling.

For 210N wafers, prices have remained relatively firm, while some are traded at RMB 1.45/piece, suggesting falling price trends. Some manufacturers remain under negotiation, and further trading prices may approach RMB 1.45/piece. If end-user demand does not recover, further price declines will be likely.

Regarding 210RN wafers, trading prices this week have generally dropped to RMB 1.35/piece. With continued cell price declines and weak end-user demand, trading prices may see further slips.

Overall, market price pressure persists. Given that end-user demand has yet to show a clear recovery, the short-term outlook for wafer prices remains pessimistic. Continued monitoring of price trends in downstream cells and modules will be crucial.
 

Cell

P-type (182P) cell prices this week:

• Average price: RMB 0.295/W (slipped)
• Price range: RMB 0.29–0.30/W (stayed same as last week)

China’s demand for p-type cells is mainly for small, scattered orders, with overall order volume sharply shrinking. Most of the current production is now being shipped to non-China markets, and significant price fluctuations are unlikely in the short term.

N-type cell prices all dropped this week:

183N:

• Average price: RMB 0.285/W
• Price range: RMB 0.28–0.29/W

210RN:

• Average price: RMB 0.28/W
• Price range: RMB 0.28–0.29/W

210N:

• Average price: RMB 0.30/W
• Price range: RMB 0.29–0.30/W

As of this Wednesday, module makers are still trying to negotiate for lower n-type cell prices. Leading cell manufacturers are holding 183N cell prices above RMB 0.28/W. Short-term prices for 210RN are under pressure due to inventory buildup. Prices for 210N are reportedly moving towards RMB 0.29/W in the second half of the week, with possible further declines.

The downstream price negotiations are intense this week. Since prices are nearing production costs, cell makers are trying to support them, and some will cut output in May. Prices are unlikely to recover until supply and demand balance out in May. Whether prices stop falling soon depends on support from both buyers and sellers.
 

Module

Module prices are dropping fast. Distributed project prices initially rose but are now falling quickly. Some small sellers with stockpiles are selling cheap. Some leading manufacturers are delivering at low prices, restarting the price competition. For ground-mounted projects, module prices sit at RMB 0.67–0.71/W. For distributed projects, shrinking demand and fewer high-priced orders have pushed prices down to RMB 0.7-0.73/W. Prices for new deals are down to RMB 0.68/W, with some even negotiating RMB 0.65/W.

Some of recent shipments are for orders signed earlier, with contract prices at RMB 0.61–0.68/W. Still, under the broader push for high-quality development, manufacturers are likely to negotiate with end-users to slow further price drops—potentially using blended pricing for earlier contracts or offering partial discounts.

Currently, module inventories remain at a healthy level. However, further demand will hinge on how China’s ground-mounted projects roll out in 2H25, as well as whether non-China demand holds steady as expected. Accordingly, price fluctuations in 2H25 are unlikely to experience sharp rises or steep declines as seen in the past while price competition will still have impact.

Module prices this week:

182mm PERC glass-glass:

• RMB 0.62–0.70/W

HJT:

• RMB 0.73-0.855/W 
• Ground-mounted projects: RMB 0.73-0.75/W

BC:

• N-TBC: RMB 0.79-0.83/W (new orders for distributed projects) 
• Ground-mounted projects: RMB 0.80/W (fewer deliveries due to high prices)

Non-China module prices remain stable this week:

• TOPCon: USD 0.08- 0.095/W
• HJT: USD 0.095-0.12/W
• PERC: USD 0.07-0.08/W
• N-TBC: USD 0.10-0.11/W

TOPCon module prices by region:  

Prices for Chinese exports to the Asia-Pacific come in at USD 0.085-0.09/W. In India, PERC and TOPCon modules have similar prices. Due to recent changes in Chinese cell prices, there has been little change this month. Indian modules made with Chinese cells are selling in bulk at USD 0.14–0.15/W. 

Modules are delivered at USD 0.09/W in Australia, with prices for distributed projects starting to rise by USD 0.09-0.10/W. Overall delivery prices in Europe remain at USD 0.085-0.09/W, with spot prices showing slower increases and potentially slipping. H2 prices for ground-mounted projects sit at USD 0.08-0.085/W.  

The Latin American market sees overall prices at USD 0.08-0.09/W. Prices in Brazil are reportedly fluctuating at USD 0.08-0.09/W. In the Middle East, prices mostly stay at USD 0.085-0.09/W.

US prices are impacted by policy changes. Manufacturers are now in a 90-day window and are rushing shipments of stocked products, leading to a slight upward price trend, even nearly USD 0.27–0.30/W (DDP). To avoid potential risks, there is a growing number of US module manufacturers raising their quotes, with some even approaching USD 0.40/W (DDP).

When Rupert Mayer and Kevin Chou met, a simple question sparked what would soon become a mission-driven nonprofit: Why doesn’t balcony solar exist in the United States?

By January 2025, they launched Bright Saver, aiming to make solar power more affordable and accessible to a broader share of Americans. Inspired by Europe’s booming “balcony solar” market – where systems are inexpensive, easy to install and often sold right off supermarket shelves – they saw an opportunity to re-imagine small-scale solar for US homes.

In Germany, these compact solar kits can be plugged directly into standard outlets, without permits or utility interconnection agreements. For the first time, recent legislation in Utah has opened a similar pathway in the United States, allowing systems up to 1.2 kW (AC) to connect via a standard wall outlet provided they meet basic safety standards. A staffer from Utah state Representative Raymond P. Ward’s office even consulted Bright Saver during the drafting process, which led to them incorporating relevant UL and National Electrical Code (NEC) standards.

“The irony is that people think America is freer when it comes to business and innovation,” said Mayer, who has a background in mechanical engineering, software, and residential battery systems. “But in reality, you cross from one town to the next, and everything changes – state laws, federal rules, local permitting. It’s a jungle.”

Now the company is bringing that to California. As of April, Bright Saver is seeking 50 early adopters to test its $29-per-month system in the greater San Francisco area.

Solar simplified
Bright Saver has begun local installations, but Mayer admits progress has been steady rather than fast, as each project offers new lessons. By framing their system as an appliance rather than a construction project, the nonprofit has successfully worked with cities such as Berkeley and San Mateo to bypass permitting requirements.
“If you can place it like a TV or washing machine and just plug it in, most cities agree it doesn’t need a permit,” Mayer said.

But not every municipality is as flexible. In El Cerrito, Mayer recalled being told that even a hot water heater, a washing machine or microwave may require a permit. When he questioned whether a standard 120 V countertop microwave needed a permit, the answer was a hesitant “maybe,” he said.

To guide customers through installation, Bright Saver offers a simple two-page manual. To avoid requirements associated with state interconnection laws, Bright Saver has chosen to prevent electricity from flowing back into the grid, a process that adds cost, complexity and time.

Each California system includes an energy monitor similar to a Sense device, current transformer clamp meters and communication tools that link to the microinverters mounted on the solar panels. A licensed electrician installs the equipment with a direct connection within the electrical panel, which typically takes two to three hours to set up a power meter and sensors on a dedicated circuit. The system continuously monitors household consumption and solar generation. If it detects that electricity flow is approaching zero or risks reversing into the grid, it automatically signals the inverter to throttle down electricity output.

Mayer said that this complexity is exactly what Bright Saver hopes to eliminate over time.

“The key is making sure no electricity flows back into the grid,” he said. “The best solution so far is mounting a power meter in the breaker box, but that adds significant complexity – extra electronics, Wi-Fi, software – and these components are made in small batches, not mass-produced.”

Mayer said doing this “requires a real installation by an electrician, and we’ve encountered far more breaker panel variations in California than expected. In some cases,” he said, “utility panels are outside while breaker boxes are inside, leaving no clear place to attach sensors. These are some of the core challenges we’re working to overcome.”

In contrast, Utah’s recent legislation removes these barriers. While utilities don’t compensate customers for excess power, they also can’t impose penalties. This creates a streamlined model that Mayer and Chou hope other states will adopt.

pv magazine USA asked Mayer about potential risks, such as using GFCI circuit breakers on the same circuit, or combining loads and generation on the same circuit. He explained that while electricity flows both ways without issue in principle, current standards haven’t fully accounted for this use case.

“The amperage is the same whether power flows in or out,” Mayer said. “But NEC and UL standards weren’t designed with this scenario in mind. It’s not a technical problem, it’s a regulatory one. These agencies need updated guidance to test and certify hardware appropriately.”

Mayer did highlight one potential safety concern known as “breaker masking,” which is a situation where simultaneous loads and generation on a single circuit can obscure potential overload risks. This is why Bright Saver prefers to install a dedicated circuit for its systems. Looking ahead, Mayer suggests that integrating battery storage could offer an elegant solution, allowing for controlled energy output while further simplifying grid interaction.

This issue has also been highlighted for private persons who are plugging their systems directly into the wall plugs, without having a dedicated circuit.

“A full rooftop solar system can cost $10,000 or more. Our kits are a fraction of that,” said Mayer. “Once people see the savings, they start thinking about EVs, heat pumps, and larger solar arrays. It’s about getting people started.”

Chou, drawing on his background in finance and software, emphasized that Bright Saver’s nonprofit structure is key to navigating these challenges. “We’re not here to chase high margins or satisfy investors,” he said. “We’re here to drive a movement — making solar accessible, especially for families who’ve been priced out of traditional systems.”

Organized as a 501(c)(3), Bright Saver is actively seeking partnerships with advocacy groups to promote legislation similar to what was passed in Utah across the country.

While both founders stressed the importance of sound economics and technical rigor, “We definitely have a spreadsheet,” Mayer joked.

They’ve built the company to prioritize impact over profits. The goal is sustainable growth that brings affordable solar to more Americans, without being constrained by shareholder pressures.