Costs Rise, Buyers Resist: Can Solar Module Prices Recover in Ex-China Regions? [SMM Analysis]

The ex-China PV market failed to sustain a broad-based price recovery in the third quarter of 2026. Weak demand and inventory liquidation pushed prices lower in July. Rising upstream material and module production costs in China then prompted manufacturers to raise price guidance and pull back from some low-priced orders in August. By September, Europe's summer holidays had ended and buyers in some markets were preparing for year-end projects. Yet stronger enquiries had not translated into a broad increase in new orders, leaving price gains concentrated in particular markets, specifications and transactions.

According to SMM market findings, China FOB prices for standard TOPCon modules recovered from their August lows but remained below early-July levels at the end of September. Southeast Asian CIF prices also recovered modestly, with Indonesia relatively weak. European warehouse prices rebounded briefly before low-priced inventory and project economics reasserted pressure. India retained distinct DCR and non-DCR pricing segments, with non-DCR prices posting a modest increase over the quarter.

The main shift in Q3 was therefore not full cost pass-through, but a reduced willingness among manufacturers to cut prices broadly. Buyers' negotiating leverage remained intact. Costs shaped suppliers' asking prices; project returns, inventory composition and policy eligibility determined what buyers would actually pay.

China FOB: a tentative recovery leaves a gap between price guidance and transactions

China's module export prices remained under pressure in July. Europe's summer slowdown, limited incremental orders from emerging markets and geopolitical disruption to some Middle Eastern deliveries left manufacturers relying on discounts to maintain shipments. Standard products offered limited differentiation, while large utility-scale buyers retained considerable bargaining power. Attempts by Chinese manufacturers to hold prices did not materially accelerate overseas procurement.

Standard TOPCon FOB prices reached a near-term low in early August. SMM's average price for 210R modules fell from US$0.1090/W on 1 July to US$0.1055/W in early August, before recovering to US$0.1075/W on 30 September. The closing price was about 1.9% above the trough but still 1.4% below early July. Prices for 182 mm and 210 mm modules fell by approximately 0.9% and 2.3%, respectively, over the same period. The rebound therefore recovered only part of the earlier decline rather than establishing a sustained quarterly uptrend.

Averaging the published daily assessments gives 210R prices of approximately US$0.1083/W in July, US$0.1061/W in August and US$0.1068/W in September. September was about 0.6% above August but remained below July. Some manufacturers raised overseas offers and price guidance by approximately US$0.003–0.0045/W in mid-to-late August. The slower recovery in actual transactions highlighted the limits that end-user demand placed on cost pass-through.

Leading manufacturers became more willing to withdraw exceptionally low offers in September, but low-priced supply did not disappear. Some second-tier suppliers continued to discount selected orders, while distributors cleared 610–625 W modules and other less sought-after specifications. Higher costs for newly produced modules thus coexisted with discounted legacy inventory, preventing a uniform price increase across the market.

Product mix also influenced pricing. High-power TOPCon and back-contact (BC) modules retained premiums, but these did not consistently widen. Between 17 August and 30 September, the average high-power 210R price fell from US$0.114/W to US$0.113/W. BC 210R prices briefly reached US$0.119/W before returning to US$0.121/W at quarter-end, while the BC 54-cell-format price rose from US$0.136/W to US$0.137/W. Efficiency, format suitability and distributed-generation demand supported differentiated products. Even so, suppliers still had to adjust high-power premiums relative to standard modules to secure orders: technological progress did not automatically translate into greater pricing power.

Southeast Asia: stronger policy expectations meet small, price-sensitive orders

Southeast Asian module prices broadly declined, stabilised and then recovered partially during Q3, although differences between markets persisted. Low China FOB prices capped the upside for delivered offers, while freight and delivery costs provided some support to CIF prices. Suppliers sought to pass through higher costs in August, but transactions remained concentrated in immediate project requirements, small low-priced orders and distributor replenishment.

Malaysia had relatively firmer demand support. Progress on utility-scale projects and the Large Scale Solar 6 (LSS6) programme improved medium-term expectations, while approaching year-end installations generated some enquiries and purchases. The average CIF price for 210R modules fell from US$0.1150/W on 3 July to US$0.1115/W in early August, before recovering to US$0.1135/W in late September. It nevertheless remained below its early-quarter level. Project pipelines and tender progress attracted interest without yet generating procurement on a scale sufficient to sustain price increases.

Thailand and Vietnam also recovered from their August lows. Procurement in Thailand was influenced by progress towards Thai Industrial Standards Institute (TISI) certification and expectations around market access. As more suppliers obtain certification, temporary supply constraints should ease. However, stocking ahead of a certification transition is not equivalent to sustained growth in installation demand. Vietnam relied more heavily on commercial and industrial, and self-consumption projects, with procurement still shaped by approvals, grid connections and execution schedules. Prices across module sizes in both markets moved within narrow ranges, and low prices remained a key purchasing criterion.

Indonesia was weaker. The average CIF price for distributed-generation TOPCon modules fell from US$0.1150/W on 3 July to US$0.1110/W on 25 September, a decline of approximately 3.5%. The market was still awaiting government project quotas for the second half of the year, alongside details of procurement by state utility PLN and the proposed initial 30 GW solar tender. Uncertainty over quotas and implementation kept developers cautious, preventing policy expectations from translating into large import orders. TKDN local-content requirements further restricted the projects accessible to imported modules, limiting near-term demand growth.

In the second half of September, some Southeast Asian distributors stepped up clearance of modules rated at 620 W and below. Even where manufacturers raised guidance for standard and high-power products, lower-power stock offered an alternative for price-sensitive buyers. Further regional price recovery will depend not simply on the size of project pipelines, but on when orders are placed, how quickly legacy inventory clears and whether efficiency and delivery requirements justify higher prices.

Europe: the end of summer holidays does not resolve weak project economics

Europe experienced some of the clearest price pressure in Q3. Summer holidays slowed project activity and procurement from July, while readily available warehouse stock and distributor inventory pressure pushed standard module prices lower. Replenishment for distributed-generation projects and demand for some high-efficiency products proved more resilient, but were insufficient to offset ample standard TOPCon supply and aggressive discounting.

Between 3 July and 25 September, the average Rotterdam warehouse price for 450–475 W distributed-generation TOPCon modules fell from €0.1197/W to €0.1127/W, down approximately 5.8%. The 620–640 W distributed-generation price declined from €0.1097/W to €0.1067/W, or about 2.7%. Utility-scale 620–640 W and 710–730 W prices fell by approximately 3.4% and 4.5%, respectively. Despite intermittent recoveries, all four assessments ended below their early-quarter levels.

Cost pressure prompted manufacturers to test higher European offers in August, briefly lifting some distributed-generation prices. After the summer break, however, September activity initially consisted mainly of delayed deliveries, urgent replenishment and small distributor purchases. New projects and large utility-scale orders had yet to expand materially. Shipments for pre-Christmas delivery were also under way, but largely fulfilled existing contracts. Some hundred-megawatt-scale projects scheduled for delivery next year still secured supplier discounts, leaving limited price support from new demand.

Low power purchase agreement (PPA) tariffs were a major constraint. Some awarded projects had already locked in low electricity sale prices and thin returns. Higher module prices would raise upfront investment and reduce internal rates of return further. Developers therefore preferred to negotiate discounts, split procurement into stages or defer commitments rather than accept supplier price increases. Financing costs and grid-connection delays lengthened payback periods and further weakened the incentive to accelerate equipment purchases.

Negative electricity prices also weighed on investment expectations. Frequent low or negative prices during midday solar generation peaks in parts of Europe reduced realised solar capture prices and increased curtailment and revenue-volatility risks. Investors became more cautious about projects with significant merchant exposure or without secured long-term revenues, restraining equipment procurement.

Storage deployment is accelerating, but grid approvals, revenue models, financing and construction lead times continue to limit how quickly it can relieve peak solar integration constraints. Without timely storage and grid investment, project economics cannot improve quickly enough to accommodate rising module costs. Continued liquidation of lower-power inventory also gives buyers leverage and cheaper alternatives.

Growing interest in high-power TOPCon does not mean that all high-efficiency products can command higher prices. Buyers still compare system returns, module premiums and installation requirements. Suppliers must demonstrate that a higher module price delivers corresponding system value. Whether Europe moves beyond price competition in Q4 will therefore depend on new contracts and inventory clearance, not simply stronger enquiries after the summer holidays.

India: a tighter window for front-loading US shipments threatens non-DCR demand and raises return risks

India retained separate pricing dynamics for modules that meet domestic content requirements (DCR) and non-DCR modules in Q3. Local-content rules, the cost of Indian-made cells and procurement for policy-supported projects sustained the DCR premium. Non-DCR prices were more exposed to imported cell costs, demand from eligible projects and changes in export orders.

SMM's weekly assessments show that the average DCR price fell from US$0.2485/W on 3 July to US$0.2425/W in late July, recovered to US$0.2450/W by late August and then remained stable. It ended the period about 1.4% lower. Non-DCR prices started at US$0.1410/W, dipped to US$0.1405/W in late July, rose to US$0.1455/W by late August and then eased to US$0.1435/W in September, where they stabilised. The net increase was approximately 1.8%, leaving the DCR premium at about 70.7% at quarter-end.

Indian policy also influenced the two price series. Limited transitional provisions under List II of the Approved List of Models and Manufacturers (ALMM) preserved a temporary procurement window for eligible non-DCR products in certain net-metering and open-access projects, diverting some orders from DCR products. DCR local-content requirements and ALMM eligibility rules continued to apply separately.

On the export side, US stockbuilding ahead of Section 232 implementation was an important source of support for Indian non-DCR orders in Q3. SMM research indicates that some US importers brought forward procurement and deliveries to build inventory before the new tariffs and minimum import prices take effect on 4 December. This policy-driven stocking, combined with higher upstream costs, supported Indian non-DCR orders and prices in August. It did not imply a corresponding increase in US installation demand.

The US has since tightened that window for accelerated shipments. Anti-stockpiling controls effective from 22 September through 3 December limit new importers registered with US Customs on or after 6 August 2026 to 55 relevant modules and 2,000 cells per week, unless they obtain a waiver approved by the US Department of Commerce. Established importers face scrutiny of unusually high volumes and may have further imports suspended if shipments materially exceed historical levels. The weekly limits apply to specified new importers, not to a single nationwide quota shared by all US importers.

Non-DCR prices had already eased from their peak in the first half of September as the initial procurement rush cooled and buyers resisted higher offers. The late-September anti-stockpiling controls further curtailed the scope for concentrated shipments through new importers, exposing policy-driven US stockbuilding demand to a pronounced slowdown. If regular project demand and approved imports do not provide sufficient support, Indian manufacturers could face fewer subsequent orders, revised delivery schedules and pressure on non-DCR prices.

Cargoes already in transit also face potential disruption. If restrictions prevent an importer from clearing goods as planned and the necessary approval is not obtained, some modules could be held at port, diverted or returned to origin. This would increase storage and logistics costs and tie up working capital. Any returned cargoes re-entering India, or US-bound modules redirected to other markets, could add supply and intensify non-DCR price competition.

Meanwhile, final US antidumping and countervailing duty determinations on Indian crystalline-silicon cells and modules have added uncertainty to US-bound orders; subsequent duty orders remain dependent on the injury determination. Non-DCR products face both prospective tariff costs and limits on accelerated shipments, whereas DCR demand remains primarily tied to policy-supported projects and year-end deliveries within India. The two segments therefore retain distinct demand drivers.

Inventories: India's cell drawdown has not been matched by modules

Inventories reinforce the point that stable prices do not mean supply-demand pressure has cleared. SMM's daily data show Indian DCR module stocks rising from 13.16 GW on 20 August to 13.48 GW on 30 September. Despite intermittent reductions, inventories remained elevated. Cell stocks, by contrast, declined sharply in late September to 3.62 GW at month-end.

Cell destocking has not yet translated into a sustained, simultaneous reduction in module inventories. The cell drawdown may reflect a combination of shipments, procurement and production adjustments rather than stronger end-user demand alone. DCR prices would gain firmer demand support in Q4 only if project procurement grows consistently and module inventories also decline.

Q3 policy review: the US curbs stockbuilding while Asian projects and market-access rules shape procurement

Policy affected Q3 markets through three main channels: purchases brought forward, project execution and supplier eligibility. The US announced Section 232 import adjustments in August, encouraging some procurement ahead of implementation on 4 December. September's final antidumping and countervailing duty determinations covering India, Indonesia and Laos, followed by anti-stockpiling controls, imposed further constraints on advance purchases. The temporary order boost created by the policy window is now at risk of fading, leaving export plans more dependent on genuine project demand and compliant import arrangements.

Asian markets were more strongly influenced by local project pipelines and market-access requirements. India's July clarification of ALMM transitional arrangements preserved a temporary window for eligible non-DCR orders. Malaysia's LSS6 programme and associated storage projects expanded the medium-term pipeline. Indonesia's proposed initial 30 GW tender lifted expectations, but government quotas, specific tender packages and TKDN rules continued to shape import orders. In Thailand, product testing, factory audits and TISI certification affected supplier eligibility and delivery schedules, while mandatory implementation arrangements remained subject to the final regulations.

These developments did not produce synchronised restocking. Instead, demand became more differentiated between policy-window purchases, scheduled project deliveries and inventory built ahead of certification changes. In Q4, actual project execution and quota releases, compliant imports and the clearance of low-priced stock will have a more direct bearing on module procurement and transaction prices than headline policy targets alone.

SMM outlook: Q4 pricing depends on new orders and the pace of legacy inventory clearance

SMM views Q3 as a shift from persistent discounting towards firmer negotiations at low price levels, rather than a full reversal in the supply-demand balance. Higher costs reduced manufacturers' willingness to cut prices broadly. High-efficiency products and selected project demand provided support, but constrained project returns, legacy inventory and competition continued to cap transaction-price gains.

The first priority in Q4 is the quality of new orders, not simply the volume of enquiries. The durability of the recovery will depend on whether European replenishment develops into procurement for new projects, project progress in Southeast Asia and other markets generates sizeable orders, and India's year-end demand supports sustained module destocking. Higher shipments for pre-Christmas and year-end delivery must also be distinguished from a rise in new orders, as some volumes will fulfil existing contracts.

For Indian non-DCR modules, the pace at which US front-loading demand fades will be critical. Weekly limits and closer scrutiny of unusually large volumes could materially reduce concentrated stockbuilding. If eligible Indian projects and other export destinations fail to absorb the displaced supply, sales redirected into India, shipments diverted elsewhere and potential returned cargoes could intensify price pressure. DCR demand will remain more closely linked to Indian project procurement and inventory clearance, preserving the divergence between the two segments.

Inventory composition will also determine how quickly individual products recover. Continued discounted sales of legacy stock, including 610–625 W modules, would sustain competitive pressure on standard products. If low-priced supply diminishes and projects are willing to pay for efficiency, certification and reliability, high-power and differentiated products could regain pricing leverage first. Even high-power TOPCon saw modest discounting at quarter-end, however, showing that technical advantages still need to be reflected in buyers' willingness to pay.

For orders scheduled for delivery in 2027, expectations of changes to product-quality requirements and compliance costs may continue to encourage higher forward offers. Anticipated cost increases will not automatically lift spot transactions. Procurement schedules, legacy inventory clearance and project economics must align for price guidance to translate into realised sales. If demand disappoints, manufacturers and distributors may again intensify price competition for a limited pool of orders.

Overall, overseas module prices are likely to remain differentiated by region, technology and order type rather than simply follow the rise in China's upstream material prices. Q3's clearest lesson is that offers can move first; new orders and inventory clearance will determine whether prices hold in Q4.

Written by:

Ryan Tey Tze Yang | SMM PV Analyst

+60 127179370 | ryan.tey@metal.com