Polycrystalline Photovoltaic Panels vs. Bifacial Solar Modules | How to Choose

Polycrystalline efficiency 18%-20% (good cost-effectiveness), bifacial total efficiency 24%-27% (rear-side gain 10%-30%, first-year degradation ≤1.5%).

Choose bifacial for high-reflectance scenarios, use polycrystalline for tight budgets.

Efficiency

Mainstream polycrystalline module mass production average conversion efficiency 15%-18% (NREL 2023), monocrystalline bifacial module front-side efficiency 21%-24% (PERC/HJT technology, PV-Tech 2024), with rear-side generating additional 5%-30% power via reflected light (snowfield reflectance >80%).

Temperature coefficient: polycrystalline -0.40% to -0.50%/°C, monocrystalline bifacial -0.30% to -0.35%/°C. Under high temperatures, the latter loses 10%-15% less power.

Conversion Efficiency

How Exactly is Efficiency Measured?

The mainstream method is STC (Standard Test Conditions): irradiance 1,000W/m², cell temperature 25°C, air mass AM1.5.

Labs use a solar simulator to illuminate the module, measure output electrical power divided by incident light power to get the percentage.

For example, a 300W module with an effective illuminated area of 1.6m² receives 1600W of incident light. Efficiency = 300/1600 = 18.75%.

However, efficiency changes in actual installations because field conditions are not STC.

The Efficiency Ceiling of Different Cell Technologies

Looking at mass production and laboratory data (source: NREL 2024 module efficiency chart):

l Polycrystalline Modules: Use cast polycrystalline silicon wafers with many grain boundaries, where electrons are easily "stopped" when moving. Mass production efficiency is stuck at 15%-18%, lab maximum 19.3% (recorded 2015, no recent breakthroughs). Manufacturers like First Solar's polycrystalline panels have a nominal efficiency of 16.5%, often dropping to 14% outdoors.

l Monocrystalline PERC Bifacial: Monocrystalline wafers + rear-side passivation film, front-side efficiency 21%-23%, lab 26.1% (LONGi 2023 data). The rear side can also absorb light, total efficiency 5%-10% higher than monofacial.

l HJT Bifacial: Heterojunction technology, silicon wafer and thin-film layers. Front-side efficiency 23%-24%, lab 26.8% (Japan's Kaneka 2024), temperature coefficient -0.25%/°C, stable efficiency under high temperature.

l TOPCon Bifacial: Tunnel Oxide Passivated Contact, front-side efficiency 22%-24%, lab 26.0% (JinkoSolar 2024), 1-2 percentage points higher than PERC, with similar cost.

Mass Production Efficiency Comparison Table (2024 Q1, PV-Tech statistics)

How Temperature "Steals" Efficiency

Modules are sensitive to heat. For every 1°C temperature rise, efficiency drops a bit. This "drop rate" is the temperature coefficient. Polycrystalline coefficient is poor, monocrystalline bifacial is better (data source: IEA PVPS 2023 module test report):

l Polycrystalline: -0.40% to -0.50%/°C. Example: a nominal 300W polycrystalline panel operating at 55°C (common in summer) loses 0.45%×(55-25)=13.5% efficiency, actual power = 300×0.865=259.5W.

l Monocrystalline PERC Bifacial: -0.30% to -0.35%/°C. Same 55°C, loses 0.33%×30=9.9%, power = 300×0.901=270.3W, 10.8W more than polycrystalline.

l HJT Bifacial: -0.25%/°C. At 55°C, loses 7.5%, power = 277.5W, advantage more obvious in high temperatures.

Measured Case: Phoenix, Arizona, USA power plant (annual average temperature 28°C, summer module temperature 60°C). Polycrystalline module annual energy yield 12% lower than nominal, HJT bifacial only 7% lower (NREL 2022 monitoring data).

Wrong Light Angle Reduces Efficiency

Incident angle loss is calculated by the cosine law: efficiency = nominal efficiency × cosθ at angle θ.

For example, θ=60°, cos60°=0.5, efficiency is halved.

Bifacial modules have a slight advantage here: the rear side can receive obliquely incident reflected light, with 5%-8% less loss than monofacial.

In an agrivoltaic project in Bavaria, Germany (tilt angle 30°), monofacial polycrystalline annual efficiency was 82%, monocrystalline PERC bifacial reached 88%.

Why Does Old Module Efficiency Keep Dropping?

Module efficiency degrades over time, divided into first-year degradation and annual degradation:

l Polycrystalline: First-year drop 2% (grain boundary oxidation), then 0.7% annually, leaving 80% of initial efficiency after 25 years.

l Monocrystalline PERC Bifacial: First-year drop 1.5% (PID effect), then 0.5% annually, leaving 84% after 25 years.

l HJT Bifacial: First-year drop 1%, then 0.4% annually, leaving 86% after 25 years, slowest aging.

Case: A polycrystalline power plant in California, USA, installed 10 years ago had 16% efficiency then, now only 13%, annual energy yield 20% lower than new panels.

The Efficiency Addition of Bifacial Modules

Rear-side efficiency is typically 60%-90% of the front side, depending on ground albedo:

l Snowfield (Albedo 80%): Rear-side efficiency = front side × 90%, total efficiency = front + 0.9×front = 1.9× front side.

l White sandy soil (Albedo 50%): Rear-side efficiency = front side × 70%, total efficiency = 1.7× front side.

l Grassland (Albedo 15%): Rear-side efficiency = front side × 30%, total efficiency = 1.3× front side.

Measured Data (Pastoral power plant in New South Wales, Australia, grassland albedo 18%): Monofacial polycrystalline annual efficiency 82 kWh/m², monocrystalline PERC bifacial 105 kWh/m², 28% more (CSIRO 2024 report).

Whose Efficiency is More Stable Under Low Light?

On cloudy days or at dawn/dusk with weak light (400W/m²), polycrystalline efficiency drops faster, monocrystalline bifacial is stable.

This is because monocrystalline silicon has high purity, with less electron recombination under low light.

Test: At 200W/m² irradiance, polycrystalline efficiency drops from 18% to 14% (22% drop), monocrystalline PERC drops from 22% to 20% (9% drop) (PV Magazine 2023 low-light test).

In northern Germany with many overcast days, power plants using monocrystalline bifacial generate 15% more electricity than polycrystalline.

System Energy Yield Efficiency

System Efficiency is Not Simple Addition of Module Efficiency

For example, a nominal 300W module with 18% STC efficiency, in a desert high-temperature + dust environment, actual annual energy yield may be only 80% of nominal, dropping system efficiency to 14.4%.

Rear-side Gain is Not Fixed, Depends on Ground and Installation

Gain depends on two variables: ground albedo and rear-side light exposure ratio (affected by mounting height, spacing).

l Ground Albedo Determines the Upper Limit (Data source: NREL Albedo Database 2024)

l Fresh snow: Albedo 80%-90%, strongest rear-side exposure;

l White sand/reflective film roof: 50%-70%;

l Concrete/light-colored gravel: 25%-40%;

l Grassland/dark soil: 10%-20%;

l Black roof/forest floor: <10% (almost no gain).

l Mounting Height Affects Rear-side Light Exposure Ratio (PV Magazine 2023 test)

l Increasing the mounting height from 0.5m to 2m increases the ratio of reflected light received by the rear side from 30% to 65%. For example, on snow (albedo 85%), rear-side gain is 12% at 0.5m height, reaching 22% at 2m.

Measured Case (Snowfield power plant in Colorado, USA, monocrystalline PERC bifacial modules):

How High is High Enough?

Higher mounting allows better airflow under modules, lowering operating temperature by 2-3°C, increasing efficiency 1%-2% (IEA PVPS 2023 report).

l Low Height (0.3-0.8 meters): Suitable for grassland/farmland, low cost, but low rear-side gain (5%-10%), poor heat dissipation, low efficiency on hot days.

l Medium Height (1-1.5 meters): Balances cost and gain, grassland gain 8%-12%, concrete 5%-8%.

l High Height (2+ meters): Often used for snow/sand, rear-side gain 15%-25%, but racking cost 20%-30% higher (Wood Mackenzie 2024 price data).

Case: Agrivoltaic project in Bavaria, Germany (grassland albedo 18%). At 1.2m height, annual energy yield 9% higher than at 0.6m, enough to offset the 5% increased racking cost.

Avoid Crowded Arrays, Shading Loss is Scary

Insufficient spacing reduces system efficiency 5%-15% (NREL 2022 shading simulation).

l Simple Spacing Calculation: At latitude 30, with module tilt 30, spacing = module height × 1.5 (e.g., module height 1m, spacing 1.5m). At latitude 45, spacing = module height × 2.

l Measured Loss (Madrid, Spain, latitude 40, tilt 35°):

l Spacing 1m (module height 1m): Back row shaded 9-11 AM in winter, annual efficiency loss 12%.

l Spacing 2m: No shading loss, full efficiency.

Different Locations, Different Weather, Where's the System Efficiency Difference?

Climate directly affects system efficiency. Three typical scenarios:

l Desert (High temperature + Strong sunlight):
Yuma, Arizona, USA power plant (annual average temperature 25°C, module temperature often >60°C). Monocrystalline HJT bifacial, with temperature coefficient -0.25%/°C, has 10% higher annual efficiency than polycrystalline (NREL 2023 monitoring), 4% higher than monocrystalline PERC.

l High Latitude (Low light + Long shadows):
Stockholm, Sweden (latitude 59°N, winter sunlight <4 hours). Bifacial modules utilize snow reflection, annual efficiency 18% higher than monofacial (Fraunhofer ISE 2024 report), while polycrystalline efficiency drops 22% due to low light.

l Cloudy Region (Large irradiance fluctuations):
Sheffield, UK (annual sunlight hours 1400, overcast 60%). Monocrystalline TOPCon bifacial efficiency drops only 8% under low light (400W/m²), polycrystalline drops 22%. Annual total generation 15% higher for bifacial (PV-Tech 2023 case).

How Much Efficiency Drops Over Time?

Over a 25-year lifespan, polycrystalline drops 20%, monocrystalline bifacial 15%-16% (Wood Mackenzie module aging database 2024).

l First-year Degradation: Polycrystalline 2% (grain boundary oxidation), monocrystalline PERC 1.5% (PID effect), HJT 1% (more stable).

l Annual Degradation: Polycrystalline 0.7%/year, monocrystalline bifacial 0.5%/year, HJT 0.4%/year.

l Efficiency After 25 Years: Polycrystalline 80% remaining, monocrystalline PERC 84%, HJT 86%.

Inverters and Racking Shouldn't Drag Efficiency Down; Poor Matching Wastes Efficiency

Other system modules also affect efficiency:

l Inverter Efficiency: String inverter efficiency 97%-98%, central inverter 96%-97%. A 1% difference means 1% less annual energy yield (SMA 2024 technical documentation).

l Racking Tracking System: Single-axis tracking yields 25%-35% higher annual efficiency than fixed-tilt (desert scenario), but costs 30% more (IEA 2023 report).

l Cable Loss: DC cable too long (50m) causes 2%-3% resistive loss, requiring thicker cables (≥6mm²).

Temperature Coefficient

What Exactly Does Temperature Coefficient Mean?

Simply put, the temperature coefficient is the percentage of efficiency lost for every 1°C increase in module temperature, in %/°C.

For example, a coefficient of -0.4%/C means for every 1°C temperature rise, efficiency drops 0.4%.

The smaller this number (smaller absolute value of the negative), the more heat-resistant the module is.

Module nominal efficiency is measured at 25°C (STC), but in actual installation, summer module surface can reach 60°C, winter maybe 10°C. The temperature coefficient determines the efficiency difference under these conditions.

Where Do Different Modules' Temperature Coefficients Differ?

Polycrystalline uses polycrystalline wafers with many grain boundaries; electrons move more chaotically at high temperatures, leading to a poor coefficient.

Monocrystalline (PERC/HJT/TOPCon) has pure crystals, leading to a better coefficient. Mass production data (source: NREL 2024 module parameter database):

l Polycrystalline Modules: -0.40% to -0.50%/°C, NOCT (Nominal Operating Cell Temperature) 45-47°C (at 800W/m² irradiance, 20°C ambient).

l Monocrystalline PERC Bifacial: -0.30% to -0.35%/°C, NOCT 42-44°C.

l HJT Bifacial: -0.25% to -0.28%/C, NOCT 40-42°C (heterojunction structure dissipates heat well).

l TOPCon Bifacial: -0.29% to -0.32%/C, NOCT 41-43°C (slightly better than PERC).

Temperature Coefficient Comparison Table (2024 mainstream manufacturer averages)

How Much Efficiency is Lost on Hot Days? A Clear Calculation

Take a 250W module as an example, nominal efficiency 20% (at 25°C). Summer operating temperature 55°C (30°C above 25°C). Efficiency loss = temperature coefficient × temperature difference:

l Polycrystalline: -0.45%×30 = -13.5%, actual power = 250×(1-0.135) = 216W.

l Monocrystalline PERC Bifacial: -0.33%×30 = -9.9%, actual power = 250×0.901 = 225W.

l HJT Bifacial: -0.26%×30 = -7.8%, actual power = 250×0.922 = 230W.

Measured Case (Yuma, Arizona, USA power plant, summer module temperature 60°C):

l Polycrystalline module average daily power 220W, monocrystalline PERC 235W, HJT 242W.

l Over a month, HJT generated about 11 kWh/module more than polycrystalline (NREL 2023 monitoring).

How is the Temperature Coefficient Measured?

Per IEC 61,215 standard, using NOCT conditions: irradiance 800W/m² (not STC's 1,000W), ambient temperature 20°C, wind speed 1 m/s, module tilt 30°.

Place the module in a solar simulator, measure output power at different temperatures, plot a curve, calculate the slope—that's the temperature coefficient.

Test Error Control: Measure the same module 3 times, average. Ambient temperature sensor accuracy ±0.5°C, wind speed with hot-wire anemometer (error <0.1 m/s).

For example, an HJT module measured 3 times, coefficients -0.25%, -0.27%, -0.26%, final label -0.26%/°C.

How Much Does Temperature Coefficient Impact Vary by Location?

Three typical regions (data source: IEA PVPS 2023 regional report):

l Tropical Desert (Riyadh, Saudi Arabia, annual average 26°C, summer module 60°C):
HJT annual energy yield 12% higher than polycrystalline (temperature coefficient advantage + better heat dissipation), 5% higher than PERC.

l Temperate Continental (Chicago, USA, winter -5°C/summer 32°C, summer module 55°C):
Monocrystalline PERC annual efficiency 8% higher than polycrystalline, HJT 10% higher.

l Nordic Maritime (Oslo, Norway, summer 18°C/winter -3°C, summer module 35°C):
Temperature coefficient impact small, annual yield difference between polycrystalline and HJT <3% (coefficient difference reduced at low temperatures).

Why Are Bifacial Modules More Heat-Resistant Than Monofacial?

Bifacial modules generate power from the rear side, simultaneously dissipating some heat.

Operating temperature is 2-3°C lower than the same model's monofacial module (PV Magazine 2023 infrared temperature measurement).

For example, a monofacial PERC module at 55°C, its bifacial counterpart might be 52°C, preserving 0.33%×3=1% more efficiency, equivalent to 1-2W more power.

Heat Dissipation Test (Fraunhofer Institute, Germany):

Monofacial polycrystalline module (NOCT 46°C), ground-mounted temperature 48°C.

Same model bifacial polycrystalline, rear side facing up for ventilation, temperature 45°C, efficiency 2% higher than monofacial.

How Does High Temperature Affect Module Lifespan?

High temperature accelerates module aging. Modules with poor temperature coefficients have greater first-year degradation (source: Wood Mackenzie aging database 2024):

l Polycrystalline: High temperature accelerates grain boundary oxidation, first-year degradation 2% (1.8% at 25°C), annual degradation 0.7%/year.

l Monocrystalline PERC: PID effect (Potential Induced Degradation) is significant under high temperature and humidity, first-year degradation 1.5% (1.2% at 25°C).

l HJT: No PID effect, encapsulation material has good temperature resistance, first-year degradation 1%, annual degradation 0.4%/year.

How Does Installation Method Affect Temperature Coefficient Performance?

Mounting height and orientation change module heat dissipation, indirectly affecting the actual performance of the temperature coefficient:

l Roof Mount (Poor ventilation): Module temperature 3-5°C higher than ground. Polycrystalline efficiency drops an extra 1.2-2%, HJT drops an extra 0.8-1.3%.

l High Ground Mount (2m above ground): Good ventilation, temperature 2-3°C lower than roof. Monocrystalline PERC efficiency preserves 0.7-1% more.

l Tracking Rack (Single-axis): Modules rotate with the sun, even heating, temperature 1-2°C lower than fixed-tilt (Middle East project measurement).

Installation Requirements

Polycrystalline relies on monofacial light absorption, racking height ≤1m, weight 15-20kg/㎡, suitable for low-reflectance surfaces (grassland albedo <20%).

Bifacial requires a high-reflectance environment (snow albedo 80%+), racking height ≥1.5m, weight 18-22kg/㎡.

According to NREL 2023 data, bifacial ground-mount plant racking costs increase 20%, with power gain 10-30%.

Site Selection

Bifacial Modules Are Picky About Reflectance

Sandia National Laboratories 2022 tests show ground reflectance must exceed 30% for bifacial modules' rear side to contribute significant gain.

Below that, rear-side generation is less than 5% of total, making cheap polycrystalline a better choice.

Looking at different surfaces: Fresh snow reflectance can reach 80%, maximum rear-side gain.

Ground-mount plants in North America often use this in winter, e.g., a project in Alberta, Canada, where snow adds 25% rear-side generation.

White gravel reflectance 50%, favored by large ground-mount plants in Spain, rear-side gain 15-20%.

Light-colored concrete reflectance 45%, used in California, USA parking lot canopy projects with bifacial modules, rear-side adds 12% generation.

But grassland reflectance is only 15%, dark soil 10%. Installing bifacial here is wasteful; the rear side barely works.

Table: Common International Surface Reflectance and Bifacial Module Rear-side Gain (NREL 2023)

Shadows Affect the Two Module Types Differently

Polycrystalline panels only generate from the front; shading stops generation in the covered area and can cause hot spots (local overheating damaging the module).

A rooftop project in San Diego, California, had tree shadows occasionally covering 10% of modules, causing an immediate 8% generation drop. Trimming branches solved it.

Industry experience: if shading area exceeds 5%, modules must be moved or obstacles removed.

Bifacial modules are trickier; both front and rear sides can be shaded.

Front shading reduces efficiency like polycrystalline. If the rear is blocked by walls, other modules, or tall grass, reflected light can't enter, eliminating rear-side gain.

A ground-mount plant in Arizona, USA, had incorrect row spacing, causing 20% rear-side shading on back rows, reducing the expected 18% rear-side gain to only 5%.

Therefore, bifacial modules need not only front-side shade-free but also sufficient open space behind for reflected light.

Slope and Orientation: Bifacial Requires an Extra Calculation Step

When installing polycrystalline panels, the tilt angle is adjusted per local latitude, generally latitude ±10°.

For example, Dallas, Texas, latitude 32, tilt angle 22-42, south-facing is best for maximum noon sun.

Sandia Labs found that a 5° difference between front and rear tilt angles changes the reflected light incidence angle, affecting rear-side gain by 3%.

For ground-mount plants with a 30° tilt, the actual rear-side light incidence angle might be 25°.

Software like PVsyst is needed for accurate calculation, otherwise gain estimates are off.

Fraunhofer Institute, Germany, recommends bifacial module tilt angle has 2-3° more redundancy than polycrystalline to ensure the rear side also absorbs more light.

Surface Material: More Than Just Reflectance

White gravel has high reflectance but gets dusty easily, reflectance gradually dropping to 40%, rear-side gain dropping 5%.

A power plant in Queensland, Australia, cleans gravel monthly; otherwise, gain drops 10% after six months.

Light-colored concrete is durable but can crack from thermal expansion, collecting mud in cracks, leading to uneven reflectance.

A desert plant in Nevada, USA, used it; after three years, concrete cracked, local reflectance dropped from 45% to 30%, requiring regrounding.

Grassland has low reflectance, but if shade-tolerant grass (like Bermuda) is planted under the plant, taller grass can act as a natural reflective layer, increasing reflectance to 20%, better than bare grassland, but this depends on agricultural needs.

Racking Cost

Higher Racking Height Increases Material Cost

Polycrystalline panel racking is typically ground-level or low (≤1m), with short posts, saving material.

Bifacial modules require racking height of at least 1.5m for rear-side light absorption, often 3m for ground-mount plants.

Every 0.5m increase in height adds 15% to post steel usage.

A 2022 ground-mount plant project in Arizona, USA: polycrystalline racking used 12 kg steel per kW for posts; bifacial racking with 3m posts used 18 kg/kW, increasing post material cost by 0.2/W (calculated at steel price 0.8/kg).

Crossbeams also need lengthening; bifacial racking crossbeam span is 20% longer than polycrystalline.

Using aluminum, crossbeam cost per kW rises from 0.1 to 0.13.

Bifacial Modules Are Heavier, Increasing Foundation Cost

Polycrystalline panels weigh 15-20kg/㎡, bifacial 18-22kg/㎡, 10%-15% heavier.

For rooftop bifacial, roof load capacity must be checked—many old US roofs are designed for 20 kg/㎡, exceeding that with bifacial requires reinforcement.

A warehouse roof project in Los Angeles, California, increased load requirement to 25 kg/㎡ with bifacial modules.

Reinforcement used carbon fiber cloth, costing 5 per square meter, totaling 30,000 for the entire roof (for 500kW capacity, about $0.06/W).

Ground-mount plants are more troublesome; concrete pier size must increase: polycrystalline piers diameter 30cm, depth 50cm; bifacial requires 40cm diameter, 60cm depth.

Concrete per pier increases from 0.035 m³ to 0.075 m³, foundation cost per kW rises from 0.08 to 0.15.

Wind Load Design, More Bolts and Reinforcements Cost More

A project in Florida, USA hurricane zone: polycrystalline racking used 4 anchor bolts (each M12), bifacial racking needed 6 (M14), 50% more bolts. Per bolt with installation 5, bolt cost per kW rises from 0.02 to $0.05.

Crossbeam joints also need triangular reinforcement, adding 2 kg steel per kW, cost $0.016/W.

Sandia Labs tests show 3m high bifacial racking must withstand 30% more wind pressure than 1m high, with these reinforcements accounting for 12% of total racking cost (only 8% for polycrystalline).

Different Ground Types, Varying Foundation Costs

A desert plant in Queensland, Australia, had rocky ground, requiring hydraulic hammer pile driving, each pile 80 (1.5m deep).

Polycrystalline racking used 2 piles/kW, bifacial used 3 (high racking for stability), pile cost rising from 0.16/W to $0.24/W.

In soft soil areas like the Netherlands, concrete piers suffice: polycrystalline pier 50kg, bifacial pier 80kg, pier cost per kW 0.1 vs 0.16.

A desert plant in Nevada, USA, with loose sand, used concrete piers with rebar cages; bifacial pier rebar usage 30% more than polycrystalline, costing 0.18/kW (polycrystalline 0.11).

Cost Details from International Cases, Clear Numbers

l 2022 Ground-mount Plant, Arizona, USA: Polycrystalline racking total cost 150/kW (8% of total investment), bifacial racking 180/kW (10% of total), extra $30/kW. Post material accounted for 40% of the increase, foundation 35%, wind reinforcement 25%.

l Rooftop Project, Bavaria, Germany: Polycrystalline racking 120/kW, bifacial required roof reinforcement +30/kW, total $150/kW, reinforcement accounted for 60% of increase.

l Large Plant, Andalusia, Spain: Bifacial racking 20% higher than polycrystalline (160/kW vs 133/kW), but power gain 15%. At local electricity price $0.1/kWh, incremental cost recovered in 3 years.

Table: Polycrystalline vs. Bifacial Racking Cost Composition Comparison (US 2023 industry average)

Racking Cost Isn't Fixed; Must See if Power Gain Can Compensate

NREL 2023 report notes bifacial racking cost is 60% higher than polycrystalline, but in high-reflectance sites (snow, white gravel) power gain can reach 25%-30%.

Over a 25-year lifespan, LCOE is actually 8% lower.

Low-reflectance sites (grassland) gain <5%; extra racking cost cannot be recovered in 20 years.

Electrical Design

Junction Box Placement: Bifacial Requires More Care

Polycrystalline panel junction boxes are mostly on the rear edge, hidden, not affecting front-side light absorption.

E.g., SunPower polycrystalline model, junction box 5cm from edge, cables run through racking gaps.

Bifacial modules can't do that; the rear side needs to absorb reflected light; junction box shading loses power.

Thus, some models move the junction box to the side (e.g., LG Bifacial 400W, junction box in the middle of the long side), some use dual junction boxes—one front, one rear, separately drawing current.

TÜV Germany tested: dual junction box design provides 3% more rear-side gain than single, but costs $0.01/W more (including extra cables).

Cable Protection: Rear Side Needs an Extra "Shell"

Polycrystalline cables only run between front-side racking, wrapped in ordinary PVC conduit, insulation rating 600V sufficient.

Bifacial modules have cables on the rear side (especially dual junction box models), requiring wear and UV protection.

UL standards (USA) require rear-side cables to use thick-wall conduit (wall thickness ≥2mm, e.g., PE material), maintaining ≥5cm insulation distance from racking (to prevent friction short circuits).

A bifacial plant in Queensland, Australia, without conduit, had sand wear through cable insulation, causing leakage after 3 months, generation dropped 4%, repair cost $0.3/W (including labor and materials).

List: Bifacial Module Cable Protection Requirements (NEC 2020)

l Rear-side cables must use thick-wall conduit (PE/PVC, wall thickness ≥2mm)

l Insulation distance from metal racking ≥5cm (fixed with plastic clips)

l Joints wrapped with waterproof tape, 3 layers (e.g., 3M 2228)

l One inspection well every 50 meters (for easy fault checking)

String Design: Bifacial Has Higher Current, Inverter Must Handle It

Polycrystalline module string current ~9-10A (400W model). Bifacial modules, due to rear-side generation, have 5-8% higher total current, e.g., same power bifacial module current can reach 9.5-10.8A.

Inverter MPPT input current must be high enough, otherwise current limiting reduces efficiency.

USA SMA Sunny Highpower 15000TL inverter, MPPT current limit 12A, can just connect 10 bifacial modules (10×10.8A=108A, divided into 9 MPPT channels, 12A each).

If using polycrystalline (10×9A=90A), there's 2A headroom.

Fronius Primo 8.2 inverter MPPT current limit 11A, connecting bifacial modules requires reducing by 1 module (9×10.8A=97.2A, divided into 9 channels ~10.8A each, near limit), otherwise high temperature may trigger over-current protection.

Table: Polycrystalline vs. Bifacial Module String Current Comparison (400W module, STC)

Inverter Matching: MPPT Tracking Must "Closely Follow" Bifacial Characteristics

Sandia Labs tests show bifacial modules at 200W/m² irradiance have 92% MPPT efficiency, polycrystalline only 88%.

Therefore, when selecting inverters, prioritize models with multiple MPPT channels and wide tracking range.

E.g., USA Enphase IQ8 microinverter supports bi-directional current tracking, recognizing bifacial module rear-side current, providing 2% higher generation gain than central inverters.

But microinverters are costly, 0.15/W vs. central 0.05/W, requiring economic calculation.

Grounding Design: Rear Side Also Needs "Grounding"

NEC (USA) standards require bifacial module grounding resistance ≤4Ω, and backsheet insulation resistance tested every 6 months (using megohmmeter, reading >100MΩ to pass).

Fraunhofer Institute, Germany case: a bifacial plant had loose rear racking grounding, causing leakage in the rainy season, generation dropped 5%, restored after re-grounding.

Electrical Pitfalls in International Cases, Clear Data

l 2023 Rooftop Project, California, USA: Used bifacial modules + ordinary PVC cables. After 1 year, rear cables worn, loss 500 (500kW capacity, ~0.001/W), solved by switching to thick-wall conduit.

l 2022 Ground-mount Plant, Australia: Bifacial string current exceeded inverter MPPT limit (11A for 10.8A modules), current limited on hot days, generation loss 3%, later added 1 inverter for shunt.

l 2021 Farm Project, Germany: Dual junction box bifacial modules with SMA inverter, high MPPT tracking efficiency, generated 2% more electricity than single junction box model, earning extra €2,000 annually (at €0.1/kWh).

Ideal Application

Polycrystalline modules ideal for tight budgets, small-area roofs, low-reflectance (20%) sites, and short-term (<5 years) projects, with 10%-15% lower cost and stable generation.

Bifacial modules suitable for large ground-mount plants, high-reflectance (>30%) sites (sand/snow), tracking rack systems, with 5%-25% gain, optimal for project cycles >8 years.

Polycrystalline Modules

How Are Polycrystalline Modules Made?

First step: make ingot. Use casting method, pour molten polysilicon into square molds, cool, cut into bricks.

This saves 20% energy vs. monocrystalline's Czochralski method (1,200 kWh per furnace vs. monocrystalline 1,500 kWh).

Second step: Wafering. Diamond wire cutting, thickness controlled at 180μm, loss <3% (early slurry cutting loss 5%). One brick yields 60+ cells.

Third step: Make cells. Diffusion forms PN junction, screen print silver paste electrodes, efficiency stable at 17%-18% (monocrystalline 19%-21%, but polycrystalline cost lower).

Fourth step: Encapsulation. Use low-iron tempered glass + EVA film + TPT backsheet, frame aluminum alloy (5% lighter than monocrystalline). Overall, per-module yield >95%.

Where Exactly Are Costs Lower?

Polycrystalline module cost is 10%-15% lower than monocrystalline. Break it down:

Material cost 60%, with silicon using lower-grade material (purity 99.999% vs. monocrystalline 99.9999%), saving $0.05/W.

Wafer thickness: poly 180μm, mono 160μm, but poly silicon material utilization 15% higher (85% vs. 70%), net wafer cost saving $0.08/W.

Non-silicon materials: frame uses ordinary aluminum alloy (monocrystalline uses anodized aluminum), saving 0.03/W; encapsulant uses domestic EVA (monocrystalline uses imported POE), saving another 0.02/W.

Manufacturing energy consumption 0.8 kWh/W (monocrystalline 1.0 kWh/W), at industrial electricity 0.1/kWh, saving 0.02/W.

Labor: poly production line slightly less automated, but labor cost per unit capacity 15% lower (10 people/line vs. monocrystalline 12).

Overall, poly cost 0.25/W, monocrystalline 0.28/W, bifacial $0.30/W.

How Stable is Generation Performance?

Polycrystalline modules nominal power 270-330W, first-year degradation ≤2.5% (monocrystalline ≤2.0%), then ≤0.7% annually, 25-year total degradation ≤20% (monocrystalline ≤19%).

Temperature coefficient -0.45%/°C (monocrystalline -0.38%).

Summer high temperature (40°C) output 3% lower than monocrystalline, but winter low temperature (0°C) output 2% higher, annual average difference <1%.

Good low-light response, generation at dawn 6 AM and dusk 6 PM 2%-3% higher than monocrystalline, cloudy days 5% higher.

NREL test data: poly module outputs 300W at 1,000W/m², monocrystalline 320W, but poly outputs 55W at 200W/m² low light, monocrystalline 50W.

Where Are They Most Cost-effective?

l Small Rooftops (Residential/Commercial & Industrial): Area <200㎡, tilt 25-35° (common in US/EU), low rear-side exposure (gain <3%). Example: Texas, USA home installs 270W poly, roof 150㎡, annual generation 4,200 kWh (local sunshine 1,800 hours), electricity price 0.2/kWh, annual saving 840, cost $12,000, 6-year payback.

l Low-Reflectance Sites: Grassland (albedo 18%), dark asphalt roof (15%), bare soil (12%). Example: Berlin, Germany warehouse uses 300W poly, dark roof albedo 15%, annual generation 5,500 kWh, 110 kWh more than same-power bifacial module (rear-side gain only 2%).

l Short-term Projects (5 years): Temporary power (farm irrigation, construction sites), leased plants. Example: Victoria, Australia farm uses 280W poly, 4-year total generation 46,000 kWh, 3% above expectation, zero maintenance cost (only dust cleaning twice).

Compare with Other Modules?

How About Real International Cases?

l Residential Rooftop, California, USA: 270W poly, tilt 30, grassland albedo 18%, area 120㎡, annual generation 4,500 kWh, cost 11,000, 6.2-year payback (electricity 0.2/kWh).

l Warehouse, Bavaria, Germany: 300W poly, dark roof albedo 15%, area 500㎡, annual generation 28,000 kWh, 560 kWh more than bifacial module (2% gain), saving extra €11,000 over 10 years.

l Farm, New South Wales, Australia: 280W poly, temporary irrigation, 4-year total generation 46,000 kWh, 3% above expectation, residual value 30% (no scratches on appearance).

Bifacial Modules

What Do Bifacial Modules Look Like? How Are They Different from Ordinary Modules?

Front side same as ordinary: 3.2mm high-transmission low-iron tempered glass + EVA film + PERC/TOPCon cells (efficiency 19%-22%) + EVA film + backsheet (or directly glass).

Difference in rear side: Instead of traditional opaque backsheet, use transparent glass or transparent backsheet (transmittance >91%), allowing light to enter from rear.

Cells themselves are "double-sided light absorption" design, front grid lines occupy <5% area, rear also has metallized contacts (aluminum grid lines).

Bifaciality (rear efficiency/front efficiency) can reach 80%-95% (PERC bifaciality 80%-90%, TOPCon bifaciality 90%-95%).

Example: a 400W bifacial module generates 400W front, under suitable conditions, additional 40-100W rear (total 440-500W).

How Exactly Does Rear-side Generation Work? How is Data Calculated?

Rear-side generation relies on two types of light: sky diffuse light (cloudy, dawn/dusk) and ground reflected light (direct light bounced off ground). Gain isn't arbitrary, has formula:

Rear-side Gain (%) = (Ground Albedo × Rear Cell Efficiency × Rear Light Exposure Time) ÷ Front Generation Baseline × 100%

l Ground Albedo: Sandy soil 35%-40%, snow 50%-70%, light-colored concrete 30%-35%, grassland 15%-20%, dark roof 10%-15%.

l Rear Light Exposure Time: Related to racking tilt. At 30° tilt, rear exposure ~40% of day; at 50° tilt, ~60%.

l Measured Data: Almería, Spain test station (sand albedo 38%, tilt 30°), bifacial rear gain 22%; Tromsø, Norway (snow albedo 65%, tilt 45°), gain 28%; Arizona, USA (grassland albedo 18%, tilt 25°), gain only 6%.

Where is the Cost Higher? Breakdown

Bifacial module initial cost 10%-15% higher than monofacial polycrystalline ($0.2-0.3/W), spent on:

l Cells: Bifacial cell process complex, requires rear passivation and metallization control, yield 3%-5% lower than monofacial (monofacial 98%, bifacial 95%), cost +$0.08/W.

l Encapsulation Materials: Rear uses transparent glass (+0.05/W vs. monofacial backsheet), encapsulant uses high-transmission EVA (transmittance 92% vs. ordinary 88%), +0.03/W.

l Racking Adaptation: Bifacial modules need higher ground clearance (≥1m, for ground reflected light), racking cost +5%-8% (monofacial racking 0.1/W, bifacial 0.11/W).

l Transport & Installation: Bifacial modules 5%-8% heavier (thicker glass), transport +$0.02/W.

How Much Gain Difference at Different Sites? See Measured Data

High Reflectance Sites (Must Choose Bifacial)

l Sandy Soil/Gobi (Albedo 35%-40%): 100MW plant, Nevada, USA, single-axis tracking, bifacial annual generation 190 million kWh, 24% more than polycrystalline monofacial, extra $28 million revenue over 10 years.

l Snowfield (Albedo 50%-70%): Kiruna, Sweden plant (near Arctic Circle), bifacial annual gain 28%, winter (Dec-Feb) generation 35% higher than polycrystalline (strong snow reflection).

l Light-colored Concrete (Albedo 30%-35%): Agrivoltaic project, southern France, concrete albedo 32%, bifacial gain 19%, also shades crops, lowering ground temperature 5°C.

Tracking Rack Systems (Gain Amplifier)

l Single-axis Tracking (East-West rotation): California, USA plant, bifacial + single-axis, annual gain 25%-30% (vs. fixed-tilt polycrystalline), because tracking keeps rear side facing reflected light.

l Dual-axis Tracking (Full-angle rotation): Australian desert plant, bifacial + dual-axis, annual gain 32%, but high cost (racking 20% more), suitable for extremely high solar resource regions (2,800 annual sunshine hours).

High Latitude/High Altitude (More Diffuse Light)

Norway, Canada, etc., high latitude, many cloudy days, diffuse light >40% of total. Bifacial rear side absorbs more diffuse light.

Oslo, Norway plant generates 15% more annually than polycrystalline monofacial, despite ground albedo only 20% (grassland).

Parameter Comparison with Other International Modules

How About Real International Projects?

l 100MW Ground-mount Plant, Arizona, USA: Sand albedo 36%, single-axis tracking, 400W bifacial modules (TOPCon cells, bifaciality 93%), annual generation 185 million kWh, 26% more than polycrystalline monofacial, extra 32 million revenue over 8 years (electricity 0.12/kWh).

l 50MW Agrivoltaic, Andalusia, Spain: Light-colored concrete albedo 33%, bifacial modules tilt 30°, annual generation 85 million kWh, gain 20%, while growing shade-tolerant herbs underneath (increasing income 15%).

l 200MW Desert Plant, Queensland, Australia: Snow albedo (dry season sand 40%), dual-axis tracking, 450W bifacial modules, annual generation 420 million kWh, gain 32%, total revenue >A$500 million over 10 years.

l 10MW High Latitude Plant, Tromsø, Norway: Snow albedo 65%, bifacial modules tilt 45, annual generation 12 million kWh, gain 28%, winter generation 35% of annual total (monofacial only 25%).