How to Read a Solar Module's Bill of Materials and Cost Structure: What Is in the Module, Which Inputs Carry the Cost, Which Stage Sets the Price, and What China's Manufacturing Norms Assess for Their Enterprise List

Short answer. A crystalline-silicon module is mostly glass, aluminium and polymer by weight, and the cost sits with the light inputs. The IEA puts raw materials at 35–50% of module cost at 2021 prices, with the wafer and silver paste making up nearly two-thirds of material cost while silver and polysilicon are under 5% of weight; NREL's bottom-up model shows that materials are more than 80% of the cost of module assembly itself. This guide reads the module in that order: what is in it, which inputs carry the cost, which stage sets the price, what moves it, and which indicators China's norms use to assess whether an enterprise meets them. It quotes no supplier price, product or ranking.

1. What is in the module

The IEA's 2022 supply-chain report describes a c-Si module as completed with front glass (plus back and side glass on some models), a junction box and an aluminium frame; glass, aluminium and polymers — EVA and polyolefin encapsulant, PVDF/PVF/PET backsheets, PET junction boxes — make up most of its weight. NREL's module-assembly cost model lists the principal input materials: stringing and tabbing ribbons, front glass, backsheet, two sheets of EVA encapsulant, aluminium frame and edge sealant, junction box with potting agent and tape, and a label.

The US Department of Energy's 2022 assessment fills in the specifications behind those names: front "coverglass" for c-Si is typically 3.2 mm low-iron rolled glass with a dimpled side for encapsulant adhesion, rear glass for bifacial or thin-film modules is typically 2.0 mm soda-lime glass, most PV coverglass is produced in China; encapsulant resins are predominantly EVA; backsheets are the final back layer of monofacial modules, with some clear backsheets now used on bifacial modules; and frames are extruded, anodised or coated aluminium, typically a 6000-series alloy. CNWattHub editorial method: ask the supplier for a BOM declaration in these terms — glass thickness and type (rolled or float, front and rear), encapsulant resin, backsheet or rear glass, frame alloy and coating, junction-box rating — and tie it to the datasheet and the warranty, because a BOM change is invisible on the nameplate.

2. Which inputs carry the cost

The IEA's estimate is that raw materials are 35–50% of total module cost at 2021 prices, and that although silver and polysilicon together are less than 5% of a module's weight, the monocrystalline wafer and the silver paste represent nearly two-thirds of material costs at those prices. The same report says that in the IEA's Roadmap to Net Zero Emissions by 2050, solar PV's silver demand in 2030 could exceed 30% of 2020 global silver production, up from about 10% at the time of writing.

NREL's 1H 2018 benchmark shows the stack from the other end. Its minimum sustainable price for a monocrystalline PERC module made in urban China was $0.37/W, built up from $15/kg polysilicon, a $0.12/W wafer MSP and a $0.21/W cell MSP, plus $0.14/W module-assembly cost and a $0.02/W (15%) module operating margin. Assembly alone, excluding cells, came to about $0.13/W for a facility above 1 GW a year in urban China, with materials more than 80% of that cost and equipment and utilities next (mainly inspection, electroluminescence and lamination); the model assumed 0.5–0.7 direct employees per MW on an automated line, 20–25 kWh of electricity per 60-cell module, maintenance at 4% of equipment investment, equipment CapEx of $0.03–0.05/W and building CapEx of $0.04/W. NREL's 2020 benchmark put MSPs at $0.25–0.27/W across the c-Si technologies it analysed, with CdTe slightly higher at $0.28/W, and assumed module equipment CapEx of $0.03–0.05/W and facility CapEx of $0.02–0.03/W. These are 2018 and 2020 US-laboratory reference points, not current prices.

3. Which stage sets the price, and which country

NREL found that benchmark module MSPs fell $1.18/W (76%) between 2010 and 1H 2018 — $0.90/W from 2010 to 2015 through polysilicon price reductions, reduced silver consumption, process engineering and scale, and $0.28/W from 2015 to 1H 2018 through PERC and diamond-wire wafering — and that factory-gate MSPs in China, Taiwan, Malaysia and the Philippines were $0.05–0.20/W (11–37%) below those in South Korea, the United States and Germany, with cell costs primarily responsible for the country differences. Its technology comparison, which assumed the same encapsulant, backsheet, interconnection and stringing across Al-BSF, PERC, PERT, SHJ and IBC (an oversimplification it flags, since bifacial modules may replace the backsheet with glass), found a maximum module price difference between cell technologies of only $0.04/W; the figures exclude shipping, minimum import prices and tariffs, and NREL noted that shipping could become a growing fraction of module cost if prices continue to fall.

The IEA says China is the most cost-competitive location for every component of the supply chain, with costs 10% lower than India, 20% lower than the United States and 35% lower than Europe, explained by energy, labour, investment and overhead costs; electricity is over 40% of polysilicon production cost and nearly 20% for ingots and wafers; and about 80% of the electricity used in polysilicon production is consumed in Chinese provinces at around USD 75/MWh, almost 30% below the global industrial average. The DOE adds that capital expenditure is 8% of c-Si production cost in China versus 10% in the United States, that virtually all US c-Si inputs from aluminium frame and glass to cells are imported and these import costs add 11% to US manufacturing costs, and that module assembly is less expensive and faster to scale than ingot and wafer production. The reading: the module price is set upstream (polysilicon, wafer, cell) and by electricity, while assembly is the thin, mobile layer on top.

4. What moves the price now

NREL/NLR's Summer 2025 update, citing BloombergNEF and PV Magazine, reports global module spot prices down about 2% in Q2 2025 to around $0.09/Wdc, average global polysilicon spot prices down 10% in Q2 2025 from $6.23/kg to $5.59/kg, then rising in July and early August 2025 as the Chinese government reportedly pressured manufacturers to ease price wars and planned to idle a significant portion of capacity; the average module price for US distributed systems in June 2025 was about $0.27/Wdc and the average imported cell price in Q2 2025 was $0.10/Wdc. The same update, citing PV Tech, Reuters and Wood Mackenzie, puts 2025 polysilicon capacity at 2.7 million metric tons in China against 200,000 metric tons outside China, with 270,000 tons planned in the Middle East and North Africa by 2028, and converts polysilicon tonnage to module output at 2 g/Wdc, a utilisation rate it attributes to the International Technology Roadmap for Photovoltaics. These are third-party figures reported by a national laboratory; CNWattHub has not verified them against the underlying data services.

5. What China's norms assess for their enterprise list

MIIT's 2024 PV manufacturing norms (光伏制造行业规范条件) are guidance conditions: the indicators below are what an enterprise is assessed against when it applies for MIIT's published list of enterprises meeting the norms (规范名单), and this guide reads them only in that sense — as conditions for the list, not as a mandatory threshold for every manufacturer or every module. Their electricity-use indicators by stage are: existing polysilicon projects under 46 kWh/kg reduction and 60 kWh/kg comprehensive electricity use (new and expanded projects under 40 and 53), existing mono-wafer projects under 100,000 kWh per million wafers (new under 80,000), P-type cell projects under 50,000 kWh/MWp and N-type under 70,000 kWh/MWp, and c-Si module projects under 25,000 kWh/MWp; their enterprise conditions also include annual R&D and process-improvement spending of at least 3% of sales and no less than 10 million yuan, and prior-year output of at least 50% of capacity when applying for the list. The same conditions include module degradation indicators (P-type c-Si no more than 2% in the first year, 0.55% a year thereafter and 15% over 25 years; N-type 1%, 0.4% and 11%; thin film 4%, 0.4% and 14%) and class B1 or better under GB 8624 for non-metallic module materials, and — in the clause that encourages ISO 9001 certification — a module power warranty of not less than 25 years, a workmanship-and-materials warranty of not less than 12 years and an inverter warranty of not less than 5 years. Read against the cost stack, the electricity indicators fall on the stages where electricity is the largest cost share, and the degradation and fire-class conditions fall on the materials that make up most of the weight. CNWattHub editorial method: use these figures to test whether a supplier that says it is on the list meets the norms' conditions, and confirm the listing itself on MIIT's published list; the figures do not by themselves settle whether a maker outside the list, or a particular module, meets a mandatory requirement.

Reading checklist

Scope limits

The cost structure is taken from US laboratory and agency work (NREL 2018 and 2020, DOE 2022) and the IEA (2022); the 2025 spot prices are third-party figures as reported by NLR. No Chinese government or industry-body module cost breakdown was found. ITRPV is cited only through NLR. The MIIT norms' indicators are read only as conditions for assessing an enterprise against the norms and its place on the published list, not as mandatory thresholds for every manufacturer or product. No supplier, product, price list or ranking is compared or recommended. Not procurement or investment advice.