Potential-induced degradation has been understood for more than a decade, and it still turns up in independent testing every year. Kiwa PVEL’s 2026 PV Module Reliability Scorecard reported lower average power loss from PID than in earlier editions. In the lab’s 2025 edition, 9% of the module designs tested still failed PID testing, most of them through a polarisation-type degradation that is drawing closer attention as newer cell technologies take over. For EPCs and developers, PID is best treated as a risk shared across the whole installation. The module, the string design and the inverter all contribute to it, and each can be used to prevent it.
What Actually Causes PID
A solar string operates at high voltage, while the module frames around it are grounded. That creates a large voltage difference between the cells inside a module and the frame holding it. NREL describes PID as electrical charge moving under that voltage over time, a process that speeds up with moisture and heat. The result is lost power and, in some cases, delamination of the module’s layers.
Not every module in a string faces the same stress. The voltage difference builds along the string, so modules at one end carry far more of it than those at the other. Higher system voltages, which help reduce cabling and inverter costs on large plants, increase that stress further. This makes PID resistance a design consideration as well as a module specification.
Not All PID Behaves the Same Way
Kiwa PVEL groups PID into three main forms.
Shunting-type PID (PID-s) creates leakage paths through the cell, so current that should reach the string is lost inside the module. It is the form most associated with the early, widely reported PID failures.
Polarisation-type PID (PID-p) is the form now appearing most often in testing. In an NREL-led study, researchers describe it as charge moving into or out of the cell’s thin surface layers, which reduces the cell’s ability to collect current. Kiwa PVEL notes that PID-p can often be reversed with UV exposure, but the lab still counts it as a failure because it has been reported in operating plants.
Corrosion-type PID (PID-c) involves physical deterioration inside the module. NREL notes that PID can lead to delamination of the module package, which is damage that no recovery process restores.
Newer cell designs do not remove the risk. In its 2025 results, Kiwa PVEL found no statistically significant difference in PID susceptibility under negative voltage between TOPCon, PERC and HJT modules, or between glass-glass and glass-backsheet construction, although TOPCon results showed a wider spread.
Bifacial modules add a second surface to the problem. In the NREL-led field study of bifacial glass-glass PERC modules, connected at the negative end of a 1,500V system, average power loss reached 4.5% to 6% in about two and a half weeks. That held both on racks around 30 cm above the ground and on structures raised to 2 m. The loss could be recovered. Modules given a reverse (positive) voltage overnight recovered in four to eight nights, while modules simply left in sunlight took 10 to 20 days.
Where Risk Concentrates and How to Spot It
SMA’s technical guidance on PID notes that it occurs most often in the module closest to the string’s negative pole, where the voltage relative to ground is most negative. How voltage is spread across a string depends on the inverter, and common transformerless designs each distribute it differently. Two plants using identical modules can therefore carry different PID risk because of their inverters.
Moisture and heat, the two conditions NREL identifies as accelerating PID, are present for long stretches across much of India. On a commercial solar installation in Gujarat, a rooftop string feeding a transformerless inverter through a humid monsoon season brings voltage, heat and moisture together for months at a time.
Catching PID early comes down to three checks. The first is a baseline. Electroluminescence imaging and I-V curve measurements at commissioning give a reference for each module’s condition at handover. The second is position-based monitoring. Because PID concentrates at the negative end of a string, modules there underperforming their neighbours is a far stronger signal than a uniform drop across the array, which usually points to soiling or irradiance. The third is follow-up imaging. Where monitoring shows that pattern, repeat EL imaging confirms whether the cells are showing the darkening typical of PID.
Prevention at the Module and System Level
At module level, materials matter as much as the cell. In one case from Kiwa PVEL’s 2024 testing, a manufacturer submitted three TOPCon glass-glass designs using the same cell, changing only the encapsulant supplier. PID losses came out at 1.1%, 2.69% and 3.3%. The encapsulant is a component few buyers ask about, and it can make the difference.
At system level, grounding is the most direct control. SMA’s guidance states that grounding the array’s negative pole prevents the negative cell voltage behind shunting-type PID. Where the inverter design doesn’t allow that, an offset device can apply a reverse voltage to the array overnight, undoing the day’s charge build-up while the plant isn’t generating. The right approach depends on the cell technology. NREL work on PID-p has also recorded front-side degradation in modules held at positive voltage, so a grounding scheme that protects one cell type may not suit another.
What the Certificate Covers and What to Ask For
The IEC 62804 test, as NREL documented during its development, holds a module at 60°C and 85% relative humidity under its rated system voltage for 96 hours, with a pass limit of 5% relative power loss. Kiwa PVEL’s extended testing runs considerably longer, and its Top Performer threshold requires under 2% degradation under both positive and negative voltage. A passed certificate shows a module cleared a defined, short test. It cannot show how that module will behave over years in a particular string.
That gap is where procurement questions do the most work. EPCs specifying industrial solar solutions in Gujarat, often near humid coastal belts or process plants, can ask for the full PID test report rather than the certificate alone. That report should show the test duration, whether both voltage polarities were tested, and the measured loss. It is also worth confirming that the encapsulant used in testing is locked into the bill of materials for the supplied batch, and getting the module manufacturer’s written guidance on grounding and recovery for that cell technology before the inverter is specified.
GREW Solar’s G12R DCR, an N-type bifacial TOPCon module, lists its encapsulation as PID-free on its datasheet and is rated for a maximum system voltage of 1,500 VDC. Both are manufacturer-stated specifications.
As cell technologies keep changing, the PID behaviour of any given module will be harder to assume from its technology label. The projects that avoid it will be the ones that treat the grounding scheme as a module specification, settled on paper before the first string is energised.
