What is solar degradation?
Solar degradation is the gradual loss of output capacity that photovoltaic modules experience over their operating life. The phenomenon is well-characterised, predictable, and included in manufacturer warranties. The typical pattern: a larger drop in the first year (around 2 percent, attributable to initial cell settling and LID), then a more linear degradation of 0.5 to 0.7 percent per year for the next 24 years. By year 25, output typically sits at 80 to 85 percent of original rated power.
Multiple mechanisms contribute to degradation. UV radiation breaks down the EVA encapsulant over time. Thermal cycling stresses cell-to-cell connections and contributes to micro-cracking. Moisture ingress through encapsulant or backsheet failures accelerates corrosion. Cell-level effects like LID (Light-Induced Degradation) and PID (Potential-Induced Degradation) contribute. The cumulative effect is the gradual capacity loss measured in the output curve.
Different cell technologies show different degradation rates. Modern TOPCon and HJT cells degrade marginally slower than PERC. Quality manufacturing reduces first-year drop and constrains long-term degradation within published warranty bounds.
Why solar degradation matters
For solar project economics, degradation is one of the variables that affects 25-year IRR. A 0.3 percentage point higher annual degradation translates to 7 to 8 percent lower cumulative kWh over 25 years. Honest payback models include the degradation curve; aggressive models that ignore degradation overstate returns.
For module selection, degradation rate is a discriminator between modules. Tier-1 modules with lower degradation rates produce more lifetime kWh for the same upfront investment. The premium for low-degradation modules often pays back over 25 years.
For warranty management, output guarantees are tied to degradation curves. A module performing below the warranty curve triggers manufacturer warranty obligations.
For lenders and investors, the degradation assumption in financial models matters for credit risk assessment. Conservative degradation assumptions support credit; aggressive ones expose risk.
How degradation is characterised and modelled
- Initial degradation. First-year drop of about 2 percent typical for modern modules.
- Linear annual degradation. 0.5 to 0.7 percent per year after first year.
- Cumulative model. Year-N output = Year-1 × (1 - first-year drop) × (1 - annual rate)^(N-1).
- Warranty curve. Manufacturer guarantees minimum output at year 10 (typically 90 percent) and year 25 (80 to 85 percent).
- Field measurement. Performance measured against reference conditions over time.
- Warranty claim. Below-warranty performance triggers manufacturer obligation.
- Replacement. Defective modules replaced; rest of system unaffected.
Real example: 25-year degradation curve for a 5 kWp Indian rooftop
System. 5 kWp residential rooftop, 9 × 560 Wp PERC modules, ALMM-listed Tier-1 brand.
Warranty. 2 percent first-year drop; then 0.55 percent per year. Year 25 guaranteed at 84.8 percent of rated.
Year-1 generation. 5 × 1,540 × 0.79 = 6,083 kWh (assume Pune-area irradiance).
Year-10 generation. 6,083 × (1 - 0.02) × (1 - 0.0055)^9 = 6,083 × 0.98 × 0.9510 = 5,668 kWh.
Year-25 generation. 6,083 × 0.98 × (1 - 0.0055)^24 = 6,083 × 0.98 × 0.8754 = 5,217 kWh.
25-year cumulative. Approximately 142,000 kWh total. Compared to a hypothetical zero-degradation model: 152,000 kWh. Degradation reduces cumulative output by about 6.5 percent.
Benefits of understanding degradation
- Realistic payback modelling. Honest 25-year IRR.
- Warranty management. Track field vs guaranteed performance.
- Module selection. Lower-degradation modules deliver more lifetime kWh.
- Customer communication. Set expectations for long-term performance.
- O&M planning. Anticipate when warranty claims may arise.
- Lender modelling. Conservative assumptions support project finance.
Limitations and field variation
Lab vs field divergence. Indian conditions sometimes push field degradation higher than lab estimates.
Module-to-module variation. Within a batch, some modules degrade faster than others.
External stress factors. Hail, severe weather, structural issues can accelerate.
Connector and junction box failures. Often confused with cell degradation.
Long-term data limited for newer technologies. TOPCon and HJT have shorter field history.
Warranty enforcement variance. Different manufacturers have different claim processes.
Degradation in Indian solar context
| Technology | First-year drop | Annual degradation | Year-25 output |
|---|---|---|---|
| Mainstream PERC | 2 to 2.5 percent | 0.55 to 0.70 percent | 80 to 84 percent |
| TOPCon | 1.5 to 2 percent | 0.45 to 0.60 percent | 83 to 87 percent |
| HJT | 1.0 to 1.5 percent | 0.40 to 0.55 percent | 86 to 89 percent |
| Bifacial glass-glass | Marginally lower | Marginally lower | 1 to 2 percentage points higher |
| Indian summer effect | Adds 0.05 to 0.10 percent/year | Higher temperatures stress modules | Lower end of range |
Quick facts
| Term | Solar Degradation (Module Degradation) |
|---|---|
| First-year typical | 2 percent for modern PERC; lower for TOPCon, HJT |
| Annual typical | 0.5 to 0.7 percent |
| Year-25 output | 80 to 85 percent of original (PERC); higher for premium |
| Warranty guarantee | Typically 90 percent at year 10, 80 to 85 percent at year 25 |
| Causes | UV, thermal cycling, moisture, LID, PID, mechanical stress |
| Modelling tool | PVsyst, NREL SAM |
| Reversible vs irreversible | Irreversible (vs soiling, which is reversible) |
Common mistakes about solar degradation
- Quoting zero-degradation 25-year savings. Overstates return.
- Confusing degradation with soiling. Different phenomena.
- Ignoring first-year drop. Material to first-year revenue.
- Treating all module technologies equally. TOPCon and HJT degrade slightly slower than PERC.
- Skipping warranty review. Output guarantees vary by manufacturer.
- Comparing year-1 generation across systems of different ages. Need to normalise.
- Underestimating Indian climate impact. Heat and UV push degradation higher.
- Forgetting non-module degradation. Inverters, connectors also degrade.
Key takeaways
- Solar degradation is the gradual output loss modules experience over operating life.
- Typical: 2 percent year-1 drop, then 0.5 to 0.7 percent annually.
- Year-25 output typically 80 to 85 percent of original.
- Module warranties guarantee minimum performance against degradation.
- TOPCon and HJT degrade marginally slower than PERC.
- Indian conditions push degradation toward higher end of range.
- Honest 25-year payback models include the degradation curve.
Frequently Asked Questions
What is solar degradation?
Solar degradation is the gradual loss of output capacity that solar modules experience over their operating life. Most modules lose about 2 percent in the first year (initial degradation), then 0.5 to 0.7 percent per year thereafter. After 25 years, output typically sits at 80 to 85 percent of original rated power.
What causes solar degradation?
Multiple factors: UV exposure breaking down EVA encapsulant, thermal cycling stressing cell-to-cell connections, moisture ingress, cell-level effects like LID (Light-Induced Degradation) and PID (Potential-Induced Degradation), and cumulative micro-damage from environmental stress.
Is degradation included in module warranties?
Yes. Module manufacturers publish output warranties guaranteeing minimum performance: typically 90 percent at year 10 and 80 to 85 percent at year 25. Falling below the guarantee triggers warranty claims.
What is LID?
Light-Induced Degradation. A small reduction in cell efficiency that occurs in the first hours of exposure to sunlight. Modern PERC and TOPCon cells have significantly reduced LID through improved manufacturing processes.
What is PID?
Potential-Induced Degradation. A cell-level degradation effect caused by high voltage potential between the cell and the module frame. Quality modules use PID-resistant cells and grounding designs to minimise PID.
How is degradation modelled in solar payback calculations?
Typical 25-year cash flow models use 2 percent first-year degradation, then 0.5 to 0.7 percent per year. Cumulative output by year 25 lands at 80 to 85 percent of year-1 generation. Honest IRR calculations include the degradation curve.
Are TOPCon and HJT less degraded than PERC?
Yes, marginally. TOPCon typical annual degradation is 0.5 to 0.6 percent; HJT is 0.4 to 0.6 percent. PERC runs 0.5 to 0.7 percent. Over 25 years, lower-degradation modules produce more cumulative kWh.
Can degraded modules be repaired?
Generally no. Cell-level degradation cannot be repaired. Modules are replaced under warranty if performance falls below guaranteed thresholds. Connector or junction-box issues are sometimes repairable.
How is degradation measured?
Module performance is measured against reference test conditions over time. Field measurements at consistent irradiance and temperature, plus comparison against original rating, reveal degradation. PVsyst and field monitoring data provide ongoing visibility.
Does soiling count as degradation?
No. Soiling is a reversible loss recovered through cleaning. Degradation is a permanent loss of the module's underlying capacity. They are different phenomena.
What is annual degradation in lab vs field?
Lab degradation testing under accelerated conditions correlates with field performance, but field results sometimes diverge. Field degradation depends on local conditions: temperature, humidity, UV exposure, thermal cycling. Indian conditions tend to push degradation toward the higher end of lab estimates.
Why does first-year degradation differ from subsequent years?
First-year drop includes LID effects and initial settling. After first year, degradation is more linear from cumulative stress. Quality modules limit first-year drop to under 2 percent.
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- NREL. Module degradation studies and field data. nrel.gov
- IEC 61215. Module qualification testing including accelerated stress.
- Fraunhofer ISE. PERC, TOPCon, HJT degradation research.
- Module manufacturer warranties. Degradation curves published by Tier-1.
- PVsyst documentation. Degradation modelling in performance simulation.
- IRENA and IEA reports. Long-term solar module performance.
- Indian field data. Long-term operational performance of deployed modules.
Written by QuickEstimate Editorial, QuickEstimate Editorial (Surat).
Last updated: 4 June 2026.