Overcapacity Is Now the Defining Feature of the Module Market

The global solar manufacturing base has grown far faster than demand. According to the IEA, worldwide module assembly capacity passed 1.1 TW per year by the end of 2024 — roughly twice the 600 GW of installations BloombergNEF recorded for the same period. China controls more than 80% of module capacity and over 90% of wafer, cell and polysilicon capacity. Industry-wide utilization rates sit near 50–60%, meaning hundreds of gigawatts of lines are effectively idle.
This imbalance is structural rather than cyclical. Capacity announced during the 2021–2023 price boom — N-type cell lines, ingot and wafer plants, glass and frame expansions — is still being commissioned through 2025. For buyers, that translates into abundant supply, short lead times and aggressive pricing. For manufacturers, it means volume leadership has not produced profit. Sourcing teams evaluating solar panels today negotiate from unusually strong .
The overhang also reshapes competitive strategy. Rather than adding capacity, leading manufacturers are converting PERC lines to TOPCon, mothballing older fabs, and competing on efficiency, warranty terms and balance-sheet strength instead of price alone. Wood Mackenzie estimates that meaningful capacity rationalization will take until 2026–2027 to restore a supply-demand equilibrium.

Module Prices Have Fallen Through Historical Floors

Prices have collapsed across the value chain. Chinese TOPCon module spot prices fell from roughly $0.27/W in 2022 to below $0.10/W by late 2024, while polysilicon dropped from about $39/kg to under $5/kg, according to data tracked by BloombergNEF and Sinovoltaics. The consequences are visible in financial statements: LONGi reported a 2024 net loss of roughly RMB 8.6 billion, and Trina Solar posted a loss near RMB 3.4 billion.
In mid-2025, Beijing's "anti-involution" campaign and manufacturer self-discipline agreements helped module prices recover modestly to around RMB 0.68–0.72/W. Regional price tiers remain wide, however. US module prices sit near $0.27–0.31/W because of tariffs and domestic-content requirements, while European delivered prices hover around €0.10–0.13/W. The same 580 W bifacial module can therefore cost two to three times more in one market than another.
For project developers, low module prices have shifted cost structure. Modules now represent a smaller share of total installed cost, making balance-of-system, labor, land and interconnection the dominant levers. That changes procurement priorities: a 1–2% efficiency gain can matter less than financing terms, warranty enforcement and delivery reliability.

TOPCon Has Won the Near Term; Tandem Waits

TOPCon has decisively replaced PERC. According to InfoLink Consulting, TOPCon accounted for roughly 70% of global module shipments in 2024 and is heading toward 80% or more in 2025. Commercial TOPCon module efficiencies now sit between 22.5% and 23.2%, with degradation warranties typically guaranteeing no more than 0.4% annual output loss over 25–30 years.
Heterojunction (HJT) and back-contact architectures occupy premium niches. LONGi's HPBC 2.0-based Hi-MO 9 series claims module efficiency above 24%, and JinkoSolar and Huasun continue to push HJT toward 23.5–24% at module level. Design trends are converging across all three: rectangular 182R and 210R wafers, zero-busbar (0BB) interconnection, dual-glass encapsulation and silver-reduction metallurgy to cut material costs.
Beyond silicon, perovskite tandems are the next frontier. LONGi has certified a silicon-perovskite tandem cell at 34.6%, and Oxford PV shipped its first commercial tandem module at 24.5%. Commercial scale-up, however, still faces durability, encapsulation and bankability hurdles. As our overview of PV and power electronics technology notes, module efficiency gains only translate into lower LCOE when inverters, trackers and storage are sized to match.

Industrial Policy Is Redrawing the Manufacturing Map

The United States is building a domestic supply chain around IRA incentives. Section 45X manufacturing credits provide $0.07/W for modules, $0.04/W for cells, $0.12/W for wafers and $0.05/W for polysilicon, plus a 10% domestic-content adder on the ITC. First Solar, producing cadmium telluride thin-film modules, reported more than $1 billion in 45X benefits in 2024 and is targeting roughly 25 GW of nameplate capacity by 2026. Announced US module capacity now exceeds 50 GW.
India is pursuing a similar playbook through the ALMM approved-list mechanism, a 40% basic customs duty on modules and 25% on cells, and production-linked incentives. Domestic module capacity has reached roughly 60–70 GW, but cell capacity remains near 10 GW — a gap New Delhi intends to close with ALMM List-II for cells from June 2026. The EU's Net-Zero Industry Act sets a non-binding 30 GW annual manufacturing benchmark for 2030, against only 4–5 GW operating today.
The net effect is a fragmented global market with persistent regional price differentials. Manufacturers now make siting decisions based on policy durability and local content rules rather than pure production economics, and buyers must navigate differing certification, traceability and tariff regimes in every region.

A Shakeout Is Consolidating the Supplier Base

Financial distress has already removed major names. SunPower filed for Chapter 11 in August 2024. Meyer Burger closed its Freiberg module plant in Germany and shelved its Colorado expansion. Maxeon restructured under new ownership, and Hanwha Qcells shut its Qidong facility in China. Dozens of smaller Chinese cell and module makers have idled lines or exited entirely, and analysts expect further attrition through 2026.
Countering that trend, a handful of manufacturers are expanding in protected markets. Qcells is scaling its Dalton, Georgia complex, First Solar is adding US and Indian capacity, and both LONGi and Canadian Solar have commissioned large US module plants through joint ventures in Ohio and Texas respectively. Tier-1 rankings from BloombergNEF now weigh bankability and project-track record as heavily as capacity.
For buyers, counterparty risk has become a first-order concern. Evaluating a supplier's balance sheet, warranty reserve adequacy, insurance backing and historical claims performance is now as important as headline wattage and price. Reviewing completed reference installations, such as the deployments catalogued in our project portfolio, offers a practical way to validate whether a manufacturer's warranty promises are supported in the field.

What This Means for Procurement and System Design

Compliance and traceability now shape purchasing decisions. US importers must demonstrate supply chains free of forced labor under the UFLPA, while the EU's Forced Labour Regulation and Ecodesign requirements for PV modules will impose documentation, carbon-footprint disclosure and recyclability obligations. France's simplified carbon footprint scheme already awards bonus points to low-carbon modules, effectively favoring European and some US production.
System design is shifting accordingly. Because module costs are low relative to everything else, developers are optimizing for energy yield, degradation and grid interaction rather than watts per dollar. Pairing high-efficiency modules with storage is increasingly standard, and battery storage systems allow owners to shift generation into evening peak tariffs, improving project economics more than another 0.5% of module efficiency would.
Finally, procurement teams should diversify across at least two or three qualified suppliers, contract for performance guarantees rather than nameplate ratings, and model LCOE over the full asset life. In a market this oversupplied, the cheapest module is rarely the least expensive decision.