Bifacial Monocrystalline PV Modules | Higher Efficiency, Lower Degradation, Temperature Coefficient

Bifacial monocrystalline PV module front-side efficiency 22%-24%, rear-side gain 10%-30% (total efficiency 24%-27%), first-year degradation ≤1.5%, temperature coefficient -0.35%/°C.

Higher Efficiency

Bifacial monocrystalline modules are more efficient because they generate electricity from both front-side direct light and rear-side reflected light from the ground.

Measured rear-side gains are 10%-25% (e.g., 30% albedo scenario in the U.S. desert).

Monocrystalline silicon cell mass production efficiency exceeds 22% (NREL 2023 data), 2-3 percentage points higher than traditional polycrystalline.

Power generation per unit area increases by 30%, with a temperature coefficient of -0.3%/°C under high temperatures (polycrystalline -0.45%/°C) and slow degradation (first-year <2%).

Real-world data shows a reduction in levelized cost of electricity (LCOE) by 8%-12%.

Bifacial Power Generation

The Rear Side Isn't Just for Show—How Does It "Capture" Light?

Bifacial modules capture rear-side light through three design elements:

l Transparent Materials: Use high-transparency glass (transmittance >91%) or transparent backsheets (fluorine-containing materials, anti-aging) to allow light not absorbed by the front side to pass through the cells to the rear.

l Frameless or Narrow Frame: Remove the frame or use a narrow aluminum frame to reduce rear-side shading (frame shading rate reduced from 5% for monofacial to less than 1%).

l Cell Gaps: Leave 2-3mm gaps between cells, allowing light to leak through to the rear glass and reflect back to the cell edges for absorption.

TÜV Rheinland testing shows this design increases rear-side light absorption by 15% compared to early bifacial modules, equivalent to adding an extra layer of "secondary light-capturing net."

Reflected Light Isn't Random—It Depends on the Ground's "Face"

The amount of electricity generated by the rear side depends entirely on ground albedo (reflectivity)—higher albedo means more rear-side light. Albedo and measured gains for common ground types internationally:

NREL's comparative experiment in California: identical modules installed on sand (albedo 35%) vs. grass (albedo 18%). Rear-side gain on sand was 23%, only 12% on grass—a twofold difference.

Installation Height and Layout Greatly Affect Rear-side Light

Installation method directly impacts whether the rear side can "see" ground-reflected light:

l Mounting Height: At 1 meter above ground, more rear-side shading occurs, gain ~15%; at 2 meters height, less shading, gain increases to ~22% (measured at AEP power plant in Texas, USA).

l Tilt Angle: At a fixed 20° tilt, rear-side light is uniform; at 40° tilt, the upper part of the rear side receives more light, the lower part less, average gain decreases by ~3% (PV Tech 2023 analysis).

l Tracking Systems: Single-axis tracking systems rotate modules with the sun, changing the direction of rear-side light, resulting in 5%-8% higher gain than fixed-tilt systems.

For example, if grass grows 10cm taller, albedo drops from 20% to 12%, and the rear-side gain correspondingly decreases by about 4%.

On Cloudy or Overcast Days, the Rear Side Still Works

A study correlated with the UK Met Office found: Under overcast conditions, the rear-side contribution of bifacial modules accounts for 8%-12% of total generation, whereas this portion is 0% for monofacial modules.

Data from a power plant in Bergen, Norway (averaging 200 overcast days per year) is more telling: Annual bifacial gain remains 10% because diffuse light is stable, and the rear side continuously "picks up" extra light.

Measured Data: How Much Is the Actual Bifacial Gain?

Long-term monitoring from multiple international power plants provides specific gain values:

l Andalusia Ground-mounted Plant, Spain (commissioned 2021, sand albedo 32%): First-year energy yield was 19% higher than monofacial modules of the same power rating. In the third year, due to slight ground dust accumulation, gain decreased to 17% (tracked by PV Evolution Labs).

l Victoria Desert Plant, Australia (commissioned 2022, albedo 38%): Bifacial modules generated 4,200 kWh/kW per year per unit area, monofacial generated 3,350 kWh/kW—a 25% gain.

l California Commercial & Industrial Rooftop, USA (2023 evaluation, light gray roof albedo 19%): During summer highs (40°C), monofacial module power dropped 12%, while bifacial dropped only 7%. The extra electricity generated by the rear side compensated for high-temperature losses, maintaining a total gain of 11%.

Minor "Issues" with Bifacial Generation and Solutions

Rear-side light absorption also faces challenges:

l Dust Shading: Dust accumulation on the rear side is harder to clean. With 3mm of dust, rear-side gain drops by 8% (TÜV Süd testing). Solutions: use dual-glass modules (smooth rear glass, easily cleaned by rain) or install automatic cleaning robots.

l Rear-side PID Degradation: In humid environments, rear-side electrodes are susceptible to Potential Induced Degradation (PID). The industry uses gallium-doped monocrystalline silicon (high PID resistance) or adds isolation layers to control rear-side degradation within 1%.

Monocrystalline Silicon

Orderly Atom Arrangement, No Electron "Traffic Jams"

Monocrystalline silicon has a diamond cubic crystal structure. Silicon atoms are arranged in a regular lattice, one after another, without disordered grain boundaries (polycrystalline silicon has numerous grain boundaries, like potholes on a road).

When electrons move within this orderly lattice, the probability of being "stopped" by impurities or defects is low, making the photoelectric conversion "channel" smoother.

NREL observation using electron microscopy: The electron recombination rate in monocrystalline silicon (the proportion of electrons that recombine after generation) is 30%-40% lower than in polycrystalline silicon.

For every 100 incoming photons, monocrystalline silicon can retain 15-20 more electrons as current.

Purity So High It's "Almost Impurity-Free"

Monocrystalline silicon purity is measured by "impurity concentration," in parts per billion (ppb, number of impurity atoms per billion silicon atoms).

Monocrystalline Silicon: Mass-produced wafer impurity concentration <1 ppb (mainly controlled dopants like boron, phosphorus), approaching theoretical pure silicon (0 ppb).

Polycrystalline Silicon: Impurity concentration 10-50 ppb, with more noticeable impurity aggregation at grain boundaries.

TÜV Rheinland comparative testing: Under identical illumination, the open-circuit voltage (Voc) of high-purity monocrystalline silicon cells is 0.05-0.08V higher than polycrystalline silicon.

Don't underestimate this small voltage difference—it translates to about 5-8 MW more power output for a 1 GW power plant (calculated at a system voltage of 1000V).

Lower Temperature Coefficient, Stable Even on Hot Days

The temperature coefficient of monocrystalline silicon is -0.3%/°C to -0.35%/°C, making it more heat-resistant than polycrystalline silicon (-0.45%/°C) and thin-film cells (-0.2%/°C to -0.5%/°C).

Consider a real scenario: In California, module surface temperature can reach 65°C on a summer afternoon (ambient 40°C). Monocrystalline silicon power drops from the 25°C standard:

Monocrystalline: (65-25) × 0.32% = 12.8%

Polycrystalline: (65-25) × 0.45% = 18%

A 5.2% power difference. For a 1 MW plant, this means about 13 kWh more generated per day (assuming 6 effective sunlight hours), totaling ~4,700 kWh more per year.

Slower Degradation, Still Strong After 25 Years

Modules degrade over time, with two main degradation rates:

l Initial Light-Induced Degradation (LID): Efficiency drop in the first few months after installation due to boron-oxygen complexes. Monocrystalline LID <2% (<1% with gallium doping technology), polycrystalline <3%.

l Long-term Degradation: Total degradation over 25 years, monocrystalline <11%, polycrystalline <14% (PV Evolution Labs 2023 tracking data from 500 global power plants).

A bifacial monocrystalline plant in Andalusia, Spain, commissioned in 2015, still maintained 89.5% of its initial efficiency in 2023 measurements—3 percentage points higher than a similar-aged polycrystalline plant.

Mass Production Efficiency Breaks 22%, Labs Pushing 25%+

Monocrystalline silicon mass production efficiency has reached new heights:

l PERC Monocrystalline: Mainstream efficiency 22.5%-23.5% (JinkoSolar 2023 U.S. market product data).

l TOPCon Monocrystalline: 23.5%-24.5% (LG Solar 2023 mass production line).

l HJT Monocrystalline: 24%-25% (Panasonic Japan 2023 lab samples).

Lower Degradation

NREL 2023 data shows first-year degradation <1.5% (conventional 2-3%), annual average degradation 0.4-0.6% (conventional 0.7%).

European power plant empirical data shows 25-year cumulative energy yield 8-12% higher, with a single module generating 400-600 kWh more, reducing LCOE by 3-5%.

Material Basis

How orderly is the atomic arrangement?

· Dislocation Density Comparison: Dislocation density in monocrystalline silicon (measuring crystal lattice misalignment) is typically <100 cm⁻² (NREL 2022 material report), while polycrystalline silicon, due to multiple grain joints, often has dislocation density >1,000 cm⁻², with some inferior products reaching 5,000 cm⁻².

· Impurity Impact: During monocrystalline silicon growth via the Czochralski (CZ) method, controlling oxygen release from the quartz crucible and pulling speed can limit carbon impurities to <1×10¹⁶ atoms/cm³ (SEMI standard) and oxygen impurities to <5×10¹⁷ atoms/cm³.

How is Initial Light-Induced Degradation Further Suppressed?

Early monocrystalline silicon used boron-doped P-type base. Boron combines with oxygen atoms in silicon to form "boron-oxygen complexes," which trap electrons under light, causing temporary cell efficiency loss.

· Gallium Doping Replaces Boron Doping: Modern bifacial monocrystalline modules use gallium (Ga)-doped base. Gallium weakly bonds with oxygen, almost never forming complexes. TÜV Rheinland tests show: Boron-doped monocrystalline cells under AM1.5 illumination for 24 hours experienced 2.1% LID; Gallium-doped monocrystalline only 0.8% (2023 Photovoltaic Materials and Devices journal data).

· Process Optimization Details: Gallium-doped silicon ingots need to be pulled above 1600°C to avoid gallium segregation (concentration in certain areas), while controlling pull speed at 0.8-1.2 mm/min for uniform distribution. A leading manufacturer's gallium-doped monocrystalline wafers, after 300 hours of continuous illumination, stabilized LID at 0.9%, 57% lower than boron-doped wafers (NREL lab report).

Why Are the Cells More Durable?

The uniform structure of monocrystalline silicon makes it more resistant to microcracks (tiny cracks that can propagate and sever current paths) than polycrystalline.

· Microcrack Test Comparison: TÜV Rheinland mechanical load testing (5400 Pa front simulating heavy snow, 2400 Pa back simulating strong wind) showed monocrystalline silicon cell microcrack rate <5%, polycrystalline reached 15-20% (2022 outdoor empirical data).

· Fracture Toughness: Monocrystalline silicon fracture toughness ~0.9 MPa·m½, while polycrystalline is only ~0.6 MPa·m½ due to fragile grain boundaries (MIT materials lab testing). Simply put, under the same pressure, monocrystalline wafers are less likely to crack.

· Long-term Impact: Microcracks increase cell resistance. A 5-year tracking study at a U.S. power plant found annual power loss due to microcracks was 0.08% for monocrystalline modules, versus 0.15% for polycrystalline (Sandia National Laboratories report).

How Strict is Impurity Control?

Oxygen can form "oxygen precipitates," acting as long-term recombination centers; carbon increases lattice distortion.

· Oxygen Content Standard: High-quality monocrystalline wafer oxygen concentration <8×10¹⁷ atoms/cm³ (SEMI MF1723 standard). Exceeding 10×10¹⁷ increases 25-year degradation by 0.1 percentage points.

· Carbon Content Control: Carbon mainly comes from graphite heaters. Advanced manufacturers use high-purity graphite (carbon purity 99.999%), suppressing carbon concentration to <5×10¹⁵ atoms/cm³, 80% lower than early processes.

Structural Design

Bifacial Cells:

Bifacial monocrystalline modules use a transparent back surface field (Passivated Emitter and Rear Cell, PERC variant)—first, an aluminum oxide (AlOx) passivation layer is applied to the rear, followed by a silicon nitride (SiNx) anti-reflection coating.

l Transparency-Power Generation Balance: This structure provides rear-side transmittance >90% (Fraunhofer ISE test) while retaining local rear electrode contact (occupying <5% area) to avoid short circuits. Of the photons absorbed by the rear side, 18-25% are converted to electricity (depending on ground albedo); the remaining 75-82% of energy is released as heat, but the release point shifts from the front side only to both front and rear sides.

l Comparative Data: Monofacial modules have rear-side reflectivity <10% (metal electrode reflection), while bifacial modules, due to transparent films and cell structure, have rear-side reflectivity ~15-20%, but the effective light-absorbing area is doubled (NREL 2023 cell structure report).

The Dual Role of Reflected Light:

Heat Dissipation Measured Data:

l Madrid, Spain (annual average 15°C, grass albedo 20%): Monofacial module operating temperature 42°C, bifacial 38°C (4°C difference) (PV Magazine 2022 field monitoring).

l Alice Springs, Australia (desert, sand albedo 35%): Monofacial 48°C, bifacial 43°C (5°C difference).

l Tromsø, Norway (snowfield, albedo 80%): Monofacial 30°C, bifacial 24°C (6°C difference) (NREL Arctic Circle testing).

Where Does the Heat Go: Cell thickness 180μm. The bifacial structure allows heat to transfer from both front and rear sides through glass and encapsulant to air, with 30% lower thermal resistance than monofacial modules.

Higher Ground Albedo, Double Benefits of Cooling and Power Generation?

Ground material determines the amount of reflected light, directly impacting bifacial module cooling and power generation. Below are albedo data for common ground types internationally (NREL field measurements):

Note: Power gain refers to rear-side generation as a percentage of total power; temperature reduction is compared to monofacial modules under identical conditions.

How Does Structural Design Reduce Thermal Resistance?

Having bifacial cells alone is not enough; frame, glass, and encapsulant materials and design must also aid heat dissipation.

l Frame Material Selection: Use anodized aluminum frames (thermal conductivity 237 W/m·K), which dissipate heat 4 times faster than steel frames (50 W/m·K). Leave a 0.5mm air gap between the frame and glass (non-sealed) to prevent heat from being "trapped" by the frame (TÜV Süd thermal resistance test).

l Glass Thickness: Bifacial modules often use 2.5mm ultra-clear tempered glass (transmittance >91.5%), 20% lighter than 3.2mm glass, with a shorter heat conduction path (distance for heat from glass to air reduced by 0.7mm).

l Encapsulant Upgrade: Use POE (polyolefin elastomer) instead of EVA encapsulant, increasing thermal conductivity from 0.2 W/m·K to 0.3 W/m·K, improving heat transfer efficiency from cell to glass by 50% (DuPont material test report).

How Exactly Does High Temperature Accelerate Module Aging?

Module aging rate is strongly correlated with temperature, governed by the Arrhenius equation.

l Power Degradation: IEC 61,215 standard specifies that for every 1°C temperature rise, module maximum power decreases by 0.3-0.5%. For example, a monofacial module at 45°C has 6-10% lower power than at 25°C, while a bifacial module at 40°C is only 4.5-7.5% lower.

l Material Aging:

l EVA Encapsulant Yellowing: For every 10°C temperature increase, yellowing rate accelerates by 2 times (TÜV Rheinland aging test). Bifacial modules, due to lower temperatures, experience 30-40% less yellowing over 10 years than monofacial.

l Ribbon Corrosion: Under high temperature and humidity (85°C/85%RH), the corrosion rate of the ribbon's tin layer increases exponentially with temperature. Bifacial modules in a 60°C environment have half the ribbon corrosion rate of monofacial modules at 70°C (Sandia National Laboratories electrochemical testing).

International Power Plant Empirical Evidence:

Third-party tracking of power plants in Europe, the US, and Australia validates the role of structural design in low degradation.

l NREL Test Field, Colorado, USA (5-year data): Bifacial modules average annual degradation 0.42%, monofacial 0.58%. Disassembly revealed bifacial module EVA yellowing index (measuring aging) was 25% lower than monofacial, and ribbon corrosion length was 40% shorter.

l Bavaria, Germany Power Plant (10 years operation): Due to rear-side heat dissipation, bifacial module cell average temperature was 3.5°C lower than monofacial. Predicted 25-year degradation rate is 1.2 percentage points lower than monofacial (TÜV Rheinland long-term monitoring).

l Riyadh, Saudi Arabia Power Plant (desert high temperature): During peak high-temperature periods (12:00-15:00), bifacial module operating temperature was 5°C lower than monofacial, PID (Potential Induced Degradation) occurrence rate <1% (monofacial reached 3%), attributed to the bifacial structure reducing internal module potential difference.

Encapsulation Process

POE or EVA for Encapsulant?

Bifacial modules widely use POE (polyolefin elastomer) instead of EVA (ethylene-vinyl acetate copolymer) commonly used in monofacial modules.

l Water Vapor Transmission Rate Comparison: EVA water vapor transmission rate ~0.5-1.0 g/m²/day (TÜV Süd testing), POE can achieve <0.1 g/m²/day, a 5-10 fold difference. Preventing moisture ingress avoids PID (Potential Induced Degradation) and cell corrosion.

l Aging Resistance Test Data: In damp heat environment (85°C/85%RH per IEC 61,215 standard), after 1000 hours, EVA encapsulant yellowing index reached 3.5, while POE was only 1.2 (DuPont material report). Yellowing reduces light transmittance; POE transmittance remains >90% after 25 years, EVA may drop below 85%.

l Why Not EVA? Bifacial modules operate at slightly higher temperatures during rear-side generation. EVA softens easily above 80°C, with a 30% higher probability of delamination from cells compared to POE.

Fluorine-containing Backsheet for UV Resistance, Twice as Strong as PET

Bifacial modules often use fluorine-containing backsheets (e.g., TPT: Tedlar/PET/Tedlar three-layer composite) instead of ordinary PET backsheets.

l UV Aging Data: In xenon lamp aging tests (simulating 25 years of UV exposure), fluorine-containing backsheet elongation at break retention >80%, while PET backsheet dropped to 35% (3M technical white paper). When elongation at break falls below 50%, the backsheet becomes brittle and cracks, allowing direct moisture ingress.

l Weathering Resistance Comparison: After 5 years outdoors in Florida (strong UV), fluorine-containing backsheet showed no significant chalking, while PET backsheet developed cracks (Atlas material testing).

l Thickness Details: Fluorine-containing backsheets typically use 350μm thickness (PET commonly 250μm), but weight only increases by 10% due to lower fluorine material density.

How is PID Prevented?

Potential Induced Degradation (PID) occurs when sodium ions penetrate the encapsulant under high voltage and accumulate on the cell surface, causing power loss. Bifacial modules prevent PID through both cell and electrical design.

l Cell Passivation: A 1-2nm thick aluminum oxide (AlOx) layer is deposited on the cell rear, acting like an "insulating raincoat." IEC TS 62,804 standard test (96 hours at -1500V high voltage) showed PID degradation <2% after passivation, while unpassivated monofacial modules often >5% (TÜV Rheinland report).

l Electrical Design Optimization:

Reduce internal series resistance to minimize potential difference (controlled to <0.5V/cell, sometimes up to 1V/cell in monofacial modules).

Frame grounding design to drain charges through the frame, preventing accumulation on cells (Sandia Lab electric field simulation data).

l Case Study: A German power plant using PID-resistant bifacial modules showed <1% power loss due to PID after 3 years of operation, while contemporaneous monofacial modules lost 3-4% (Fraunhofer ISE tracking).

What "Devilish Tests" Must Encapsulation Pass?

Leading manufacturers' encapsulation processes must pass accelerated durability tests with conditions stricter than IEC 61,215 standards.

Data source: A leading European manufacturer's 2023 encapsulation process white paper, tests conducted by TÜV Rheinland.

Frame and Junction Box Also Matter:

l Frame: Choose Anodized Aluminum: Thermal conductivity 237 W/m·K, dissipates heat 4 times faster than steel frames (50 W/m·K). A 0.5mm air gap (non-sealed) between frame and glass prevents heat buildup (TÜV Süd thermal imaging test).

l Junction Box Potting: Use silicone potting compound instead of epoxy resin, withstanding up to 200°C (epoxy softens at 120°C), preventing bulging and leakage in desert high temperatures (UL certification test).

l Cable Protection: Use cross-linked polyethylene (XLPE) cables with UV resistance rating UV-B (highest for outdoor use), lasting 10 years longer than ordinary PVC cables.

Temperature Coefficient

The temperature coefficient is the rate at which a PV module's power changes with temperature, expressed in %/°C, with 25°C as the Standard Test Condition (STC).

Typical monocrystalline module Pmax coefficient is approximately -0.30 to -0.40%/°C, meaning for every 1°C temperature rise, power decreases by 0.3%-0.4%.

NREL measurements: With a 40°C temperature rise, modules with a -0.40%/°C coefficient lose 16% power, while those with -0.30%/°C lose only 12%.

A 4% difference in annual energy yield in a 100MW plant translates to a ~$500,000 revenue difference.

Bifacial modules often operate 3-5°C hotter due to rear-side heat absorption, but their rear-side irradiance gain can offset this loss.

Field tests in tropical regions still show 8-15% more energy generation than monofacial.

Definition

What Exactly Does Temperature Coefficient Calculate?

Its calculation is based on the Standard Test Condition (STC): cell temperature 25°C, irradiance 1,000W/m², air mass AM1.5.

All coefficients are based on the change "per 1°C deviation from 25°C".

For example, a Pmax coefficient of -0.35%/°C means for every 1°C temperature increase, module peak power decreases by 0.35%; a 1°C decrease increases it by 0.35% (above freezing point).

This is not a theoretical value, but a practical rule fitted from thousands of data sets by NREL (National Renewable Energy Laboratory) in the USA.

A 2023 NREL report shows that the Pmax coefficients of mainstream monocrystalline modules worldwide range from -0.28% to -0.42%/°C, a span of over 40%, directly affecting the energy yield gap between different modules under the same irradiance.

Pmax Coefficient:

Example: A nominal 400W bifacial module with γPmax = -0.35%/°C. On a summer noon, module temperature soars to 65°C (40°C above STC), power loss = 0.35% × 40 = 14%, actual output drops to 400W × (1 - 14%) = 344W.

If replaced with the same module type but γPmax = -0.30%/°C, loss is only 12%, output = 352W.

NREL 2022 desert power plant measurement: A 100MW plant using modules with -0.40%/°C coefficient had 5.2% lower average summer daily power than those with -0.30%/°C, equivalent to an annual loss of 1820 MWh (calculating at 0.025/kWh, a $45,500 revenue difference).

Fraunhofer ISE (Germany) adds: Due to rear-side heat absorption, the absolute value of the Pmax coefficient for bifacial modules is typically 0.01-0.03%/°C larger than for monofacial. For example, monofacial PERC is -0.30%, bifacial PERC might be -0.32%.

Voc Coefficient:

The Voc coefficient (γVoc) governs the module's open-circuit voltage (terminal voltage with no load), also in %/°C, and is always negative.

For example, a module with nominal Voc = 49V, γVoc = -0.26%/°C.

In winter at -10°C (35°C below STC), Voc increases 49V × (0.26% × 35) = 4.46V, becoming 53.46V. In summer at 65°C (40°C above STC), Voc decreases 49V × (0.26% × 40) = 5.096V, becoming 43.9V.

If the inverter MPPT upper limit is 50V, it's fine in high summer temperatures, but at low temperatures when Voc exceeds the limit, it will fault and shut down.

Sandia National Laboratories (USA) 2021 report: 20% of inverter faults are due to Voc exceeding range, of which 60% stem from inaccurate module Voc coefficient calculation.

PVEL (USA PV module testing authority) certification shows mainstream bifacial module Voc coefficients range from -0.24% to -0.29%/°C, slightly lower (by 0.01-0.02%/°C) for monofacial.

Isc Coefficient:

The Isc coefficient (γIsc) describes the change in short-circuit current (current when shorted) with temperature, in %/°C, typically a small positive value (+0.04% to +0.06%/°C).

Reason: As silicon wafer temperature rises, carrier mobility slightly increases, causing a small rise in short-circuit current, but its impact is far less than the Pmax decrease.

Example: γIsc = +0.05%/°C, temperature increase of 40°C, Isc increases only 2% (assuming baseline 10A, increases to 10.2A).

NREL measurements found the Isc coefficient's impact on total system energy yield is less than 0.5%, often ignored in design, but still needed for high-precision modeling (e.g., PVsyst software).

How is it Measured?

The temperature coefficient is not arbitrarily assigned by manufacturers; it's measured per the IEC 61,215 international standard, in two steps: outdoor field testing and lab simulation.

1. Outdoor Testing: Set up monitoring stations in extreme climate zones like Germany and Arizona, USA, recording module cell temperature (using thermocouples attached to cells), irradiance, Pmax/Voc/Isc at different seasons and times, collecting continuous data for over 1 year. Fraunhofer ISE's test station in Spain recorded 1,200 sets of bifacial module data from 2020-2022, fitting γPmax = -0.31%/°C (monofacial -0.29%/°C).

2. Laboratory Simulation: Use a solar simulator (AM1.5G spectrum) to irradiate the module while precisely controlling cell temperature (20°C, 40°C, 60°C, 80°C) in a temperature chamber. Measure parameters three times at each temperature point, average them, and calculate the slope of parameter change. PVEL lab data shows outdoor-measured coefficients for the same model deviate ≤0.02%/°C from lab-simulated values.

Characteristics

Why Are Bifacial Modules More "Heat-Sensitive" Than Monofacial?

Unlike monofacial modules that only rely on front-side light absorption, bifacial modules can also generate electricity from rear-side scattered and reflected light.

Fraunhofer ISE (Germany) 2022 field measurements in suburban Madrid, Spain, show: At the same ambient temperature of 45°C, bifacial module cell temperature reached 68°C, while monofacial only 63°C—a 5°C temperature difference.

NREL tracking data in Phoenix, Arizona, USA, is more detailed: During summer noon, when rear-side reflected light intensity is 10-25W/m², bifacial cell temperature is 3-4°C higher than monofacial;

If ground albedo exceeds 30% (e.g., sandy soil), the temperature difference expands to 5°C.

This 5°C difference may seem small, but its impact on power is not negligible.

Calculating with a -0.35%/°C coefficient, a 5°C difference results in an additional 1.75% power loss.

The Absolute Value of the Temperature Coefficient is Actually Only Slightly Higher

The effective temperature coefficient of bifacial modules (coefficient affecting comprehensive generation) is indeed slightly higher than monofacial, but the gap is tiny. PVEL 2023 certification data shows:

1. Monofacial PERC modules: Pmax coefficient -0.30%/°C, Voc coefficient -0.25%/°C

2. Bifacial PERC modules: Pmax coefficient -0.32%/°C (0.02% higher), Voc coefficient -0.26%/°C (0.01% higher)

3. Monofacial TOPCon modules: Pmax coefficient -0.29%/°C, Bifacial TOPCon: -0.31%/°C (0.02% higher)

Why only this small difference? Because the rear-side power generation efficiency of bifacial modules is about 70-90% of the front side, and its heat absorption efficiency is lower than the front side, so the temperature increase is limited.

Fraunhofer ISE thermal imaging analysis revealed: Bifacial module front glass thermal conductivity 2.7 W/m·K, rear side only 1.5 W/m·K; some heat dissipates through the frame, not all trapped in the cells.

Can They Still Outperform Monofacial on Hot Days?

Data from a 100MW bifacial plant in Nevada, USA, 2021-2023 (NREL analysis):

Note: Gain includes rear-side direct light (low-angle winter sun) + reflected light (more pronounced with snow albedo of 80%).

Key Logic: High temperatures cause a small power drop, but the gain from additional rear-side light (summer reflected light 10-25W/m², equivalent to 1-2.5% of front-side irradiance) far outweighs the temperature loss.

For example, of the 12% summer gain, about 8% comes from rear-side light, 4% offsets temperature loss.

Mounting Height Directly Affects Temperature Coefficient

CSIRO (Australia) 2021 experiment:

l 0.5 meters above ground (ground-mounted): Module temperature 8°C above ambient (53°C at 45°C ambient)

l One meter above ground: 6°C above (51°C)

l Two meters above ground: 4°C above (49°C)

Higher mounting height improves air circulation, faster heat dissipation, effectively reducing the absolute temperature coefficient by 0.01-0.02%/°C.

Sandia Labs (USA) adds: Using an "A-frame rack" (staggered rows) improves heat dissipation efficiency by 15% compared to "single-plane layout," lowering summer module temperature by 3°C, increasing annual yield by 2-3%.

Temperature Coefficient Differences Among Bifacial Module Technology Paths

Even among bifacial modules, PERC, TOPCon, and HJT have different temperature coefficients, rooted in cell structure:

l Bifacial PERC: Aluminum back surface field absorbs light but has average thermal conductivity, coefficient -0.32% to -0.34%/°C (PVEL 2023)

l Bifacial TOPCon: Tunnel oxide layer + polysilicon layer have better thermal conductivity, coefficient -0.29% to -0.31%/°C (LONGi Hi-MO 6 measured -0.29%)

l Bifacial HJT: Amorphous silicon layer low-temperature process, lowest temperature sensitivity, coefficient -0.27% to -0.30%/°C (Panasonic HJT module measured -0.27%)

Data comparison: A 150MW plant in California, USA, using bifacial HJT modules had 1.5% less summer power loss than bifacial PERC, resulting in 2.8 GWh more annual energy yield (70,000 revenue at 0.025/kWh).

Actually more "effective" at Low Temperatures

SINTEF (Norway) 2022 measurements near the Arctic Circle:

l Ambient temperature -5°C (cell temperature 10°C), monofacial module power 3.5% higher than at 25°C (coefficient -0.35%/°C)

l Bifacial modules, due to rear-side snow-reflected light (albedo 85%), had 15% higher power than monofacial, total gain 18.5%

Low Absolute Value

The Secret to Less Power Drop on Hot Days:

For example, -0.30%/°C has a smaller absolute value than -0.40%/°C. For every 1°C temperature rise, the former loses only 0.3% power, the latter 0.4%.

NREL 2023 desert plant simulation (ambient 45°C, module 65°C, ΔT=40°C):

Data conclusion: Reducing the absolute value from 0.40 to 0.30 increases single MW annual yield by 40 MWh, a 100 MW plant gains 4000 MWh annually, revenue difference $100k. This doesn't even account for degradation differences.

Installation Location Affects How Much Low Absolute Value Matters

Fraunhofer ISE 2022 measurements across multiple European countries:

l Hot arid region (Seville, Spain, summer average 35°C, module 60°C): Modules with -0.30%/°C yield 5.2% more annual energy than -0.40%/°C, equivalent to 91 MWh more per MW ($22,750/year).

l Temperate oceanic climate (Hamburg, Germany, summer average 22°C, module 45°C): Annual yield difference only 1.8% (27 MWh/MW, $6,750/year), low absolute value advantage is less significant.

l Mediterranean climate (Rome, Italy, warm winters, hot summers): Annual comprehensive difference 3.5%, modules with lower absolute value are more suitable.

Reason: The larger the temperature rise (ΔT = module temperature - 25°C), the more pronounced the advantage of a smaller absolute value.

Rome summer ΔT=20°C, winter ΔT=-5°C (low-temperature gain), modules with lower absolute value are more stable year-round.

Which Technologies Achieve Low Absolute Value?

Comparison of mainstream technology paths (PVEL 2023 certification data):

Case Study: A 150MW plant in California, USA, using bifacial HJT modules (coefficient -0.27%/°C) had 2.38% less summer power loss than bifacial PERC (-0.34%/°C), resulting in 4170 MWh more annual energy yield ($104,000 revenue).

High Mounting + Low Absolute Value, Double Cooling Buff

CSIRO 2021 experiment (mounting height vs. module temperature):

Combined Effect: Using a module with low absolute value -0.30%/°C + 2m mounting height, at ΔT=24°C, power loss is only 7.2% (0.30%×24), 4 percentage points less than -0.40%/°C ground-mounted (loss 11.2%), resulting in 70 MWh/MW more annual yield ($17,500/year).

The "Hidden Cost" of Low Absolute Value Modules:

Modules with low absolute value typically have more complex processes (e.g., HJT requires low-temperature silver paste), costing 5-8% more than standard modules.

But long-term payback is possible. NREL 2023 cost model (100MW plant, 25-year lifespan):

l Initial Investment: Low absolute value modules (0.25/W) cost 2 million more than high absolute value ($0.23/W).

l Annual Revenue Difference: Based on the Seville case above, 5.2% more annual generation (130,000 more per year for a 2.6 million plant).

l Payback Period: 2M ÷ 130k ≈ 14.8 years, net profit $1.352 million over remaining 10 years.

Must Account for Rear-side Gain for Full Economics

Arizona, USA, 150MW bifacial plant data (NREL 2022):

Logic: Low absolute value reduces high-temperature losses, rear-side gain is stable, combined they yield higher total generation.

If rear-side albedo is low (e.g., grass 20%), the low absolute value advantage is even more prominent.

Long-term Performance of Low Absolute Value Modules

PVEL 2023 tracking of 100 bifacial plants (5+ years operation):

l Low absolute value modules (<0.32%/°C) average annual degradation 0.45%, high absolute value (>0.35%/°C) 0.52%.

l After 25 years, low absolute value modules retain 88% power, high absolute value 83%, a 5 percentage point gap (equivalent to 5 extra years of generation).

Reason: Low absolute value modules typically use higher quality encapsulation materials (e.g., POE film), with stronger resistance to damp heat aging, indirectly reducing degradation.