How Can Uneven Cell Temperature Mimic String Mismatch

A hot PV string can look like a mismatched string even when the modules themselves are fine. The quickest check is to see whether the temperature difference is large enough to explain the measured power loss. With γPmax at -0.30%/°C, a 15°C temperature difference works out to about 4.5% lower maximum power. If the string is down 11%, there is still a large part of the loss that temperature cannot explain.

That is where current, MPPT layout, thermal images and the I-V curve become useful. Similar current and a smooth I-V shift fit a temperature-related loss much better than a sharp current drop, an I-V step, a recurring cell hotspot or a hot connector.

What 5°C, 10°C and 20°C Actually Mean

Start with the module datasheet. The number you need for a quick power check is γPmax, the maximum-power temperature coefficient. Tongwei module coefficients can be found in the module specification download section.

Using this example:

γPmax = -0.30%/°C

The calculation is straightforward:

Expected Pmax difference ≈ |γPmax| × ΔT

Sandia PV performance models also treat module power, current and voltage as separate temperature-dependent values rather than correcting every electrical parameter in the same way.^[1]

So a 20°C temperature difference can reasonably create a 6% maximum-power gap. It cannot, by itself, explain a 15% or 20% current loss under otherwise comparable conditions.

Current, Voltage and Power Do Not Move the Same Way

These coefficients are not interchangeable. βVoc is used when checking Voc. γPmax is used when estimating the change in maximum power. Using γPmax to calculate a voltage loss directly would give the wrong result.

In normal crystalline-silicon operation, temperature has a much stronger effect on voltage than on current. A hot string that still carries nearly the same current as its reference may therefore be behaving normally. A string that has lost 20% of its current is a different case and needs further checks.

First Check Which Strings Share an MPPT

Voltage data is easy to misread when several strings are connected to the same MPPT. Parallel strings normally share one MPPT operating voltage. The inverter may show a separate current for every string while showing only one voltage for the whole MPPT.

IEC 60904-1 defines how PV current-voltage characteristics are measured under natural or simulated sunlight.^[2]

There is another practical point here. A hotter string connected to a shared MPPT can show a different current at the common operating voltage because its I-V curve has shifted. So it is not accurate to say that temperature always shows up only as lower string voltage.

2% Current Loss and 23.5% Current Loss Are Not the Same Problem

These two examples show why current is worth checking before blaming temperature.

Here, the string is much hotter while current is still close to the reference. A temperature-related loss is a reasonable explanation.

Now look at the second case:

A +3°C temperature difference is nowhere near enough to explain a -23.5% current difference. At that point, the checks should move to partial shading, unequal irradiance, heavy or localized soiling, bypass-diode operation, wiring faults, or damaged cells and substrings.

This is also why real PV string mismatch should not be diagnosed from string power alone.

If Temperature Explains 4.5%, What Explains the Rest?

The gap left after the temperature estimate is often more useful than the total loss.

Use this example:

• γPmax = -0.30%/°C;
• reference module temperature = 45°C;
• suspect module temperature = 60°C;
• ΔT = 15°C.

The expected temperature effect is:

15 × 0.30% = 4.5%

A 6.0% loss with 4.5% already explained by temperature leaves only 1.5 percentage points to account for. A 12.0% loss under the same 15°C temperature difference leaves 7.5 percentage points unexplained. Those two cases should not be treated the same way.

This calculation is only a quick screening tool. IEC 60891 sets out the formal procedures used to translate measured I-V characteristics between different irradiance and temperature conditions.^[3]

For several strings sharing the same MPPT, γPmax × ΔT should not be treated as an exact operating-power correction for each individual string because they may not be running at their own separate maximum-power points.

Look at Where the Heat Is

A thermal image becomes much more useful once the hot area is tied to a physical part of the module. IEC TS 62446-3 covers outdoor infrared inspection of operating PV modules and plants.^[4]

The 8°C and 20°C values are examples, not universal pass/fail limits.

A whole module running about 8°C hotter because it sits above a hotter roof section is one thing. One cell running about 20°C hotter than the cells around it is much more local and needs a different inspection.

With poor cooling, the chain is simple:

poor ventilation → higher cell temperature → lower voltage and Pmax

With a shaded or electrically weak cell, it runs the other way:

lower cell current → mismatch → reverse electrical stress → local heating

Only the first case is a straightforward example of temperature making a healthy module look weak. In the second, the heat is already a symptom of a real mismatch.

A Bypass Step Is a Different Signal

Temperature normally moves the I-V curve gradually. Bypass-diode operation can produce a clear step, a shoulder or another maximum-power peak.

There is no reliable rule that says one active bypass diode always removes exactly one-third of module voltage. The result depends on the module's internal circuit.

Different designs may use:

• full cells;
• half-cut cells;
• split layouts;
• different substring counts;
• different bypass-diode arrangements;
• shingled interconnections.

The actual cell layout and bypass-diode arrangement should be checked before a substring hotspot or voltage step is interpreted.

Smooth Shift or Clear Step?

Take an illustrative independent I-V measurement:

• stable-condition Voc: about 820 V;
• hotter-condition Voc: about 795 V;
• current remains close to 10 A;
• curve shape stays smooth.

The exact voltage movement depends on βVoc. Still, a smooth change like this fits temperature far better than a curve that suddenly develops a step while current falls 15% or 20%.

IEA PVPS uses Isc, Voc, curve slopes, fill-factor changes and I-V steps when assessing underperforming arrays instead of relying on Pmax alone.^[5]

If the same cell keeps appearing hot and neither the I-V curve nor visual inspection explains it, electroluminescence testing can help locate inactive areas, damaged current paths and significant cell cracks.

Bad Test Conditions Can Create Bad Conclusions

Small performance differences are hard to trust when irradiance or module temperature is moving quickly.

IEA PVPS field guidance recommends, where practical:

• irradiance above 800 W/m²;
• irradiance fluctuation below ±1% during the measurement;
• module-temperature change below ±1 K during the previous one-minute interval;
• checking temperature spread across the modules before choosing the temperature measurement point.

^[6]

Ambient air temperature is not a substitute for cell temperature. A weather station can show 30°C while operating modules are at 50°C, 60°C or above. Sandia's module-temperature model uses irradiance, ambient temperature, wind speed and mounting configuration for exactly this reason.^[7]

One temperature reading can also hide a large spread. If representative modules are at:

• 44°C;
• 47°C;
• 51°C;
• 59°C;
• 62°C

the string has an 18°C temperature spread. Reducing that to one “50°C string temperature” value throws away information that may explain the electrical difference.

A 2% Gap May Not Be a Fault at All

Field measurements are not exact enough to treat every small difference as a defective module.

IEA PVPS reports expanded uncertainty of roughly ±3.5% to ±5% for conservative on-site Pmax measurement cases, with a best-case value around ±2.5% under better controlled conditions.^[8]

The 8-12% range is not a failure threshold. It simply shows why a persistent 10% gap deserves more attention than one isolated 2% result.

Why a Bad Connection Gets Much Hotter at High Current

A connector hotspot should not be treated as normal module temperature loss.

Resistive heating follows:

P = I²R

For a hypothetical bad connection with resistance of 0.05 Ω:

Current only doubles from 5 A to 10 A, but heating rises from 1.25 W to 5.00 W. That is four times as much heat.

This is why a poor connector may look only slightly warm in the morning and become much hotter near peak production. If the heat is concentrated around a connector, crimp, terminal, ribbon or junction-box connection, the electrical path needs to be checked.

800 W/m² on the Front Can Still Hide a Bifacial Difference

Two bifacial strings can have the same front irradiance and still receive very different total light.

A front POA sensor makes the strings look identical, but one is receiving 50 W/m² more rear irradiance.

That 50 W/m² should not be converted directly into the same amount of electrical-power gain. Bifaciality, rear non-uniformity, spectrum, shading and module temperature all affect the final output.

IEC TS 60904-1-2:2024+AMD1:2026 gives specific measurement requirements for bifacial PV devices.^[9]

Rails, cables, row spacing, junction boxes and other objects can also create uneven rear-side irradiance. These should be checked before a hotter or lower-current bifacial string is treated as defective.

Compare Like With Like

“Morning versus afternoon” is a weak comparison because irradiance, sun angle, tracker position and shading may all move at once.

A cleaner approach is to select data within a narrow irradiance band such as:

800-850 W/m²

Then compare the power gap at different temperature differences.

For a module near -0.30%/°C γPmax, that trend is broadly consistent with temperature.

But if ΔT moves from 2°C to 15°C and the suspect array stays about 8% below the reference every time, the fixed 8% loss needs another explanation.

Two Similar Symptoms, Two Different Diagnoses

Case A leaves only about 0.8 percentage points unexplained. At that size, field uncertainty and small operating differences matter.

Case B leaves about 9.5 percentage points unexplained. Lower current, a clear I-V step and a repeated substring hotspot all point away from ordinary temperature loss.

Record These Values Before Replacing a Module

1. MPPT assignment: identify whether the suspect and reference strings share one MPPT.
2. Irradiance: compare strings only when front and, for bifacial arrays, rear conditions are sufficiently similar.
3. String current: record the actual percentage difference, not just “low current.”
4. Valid voltage: distinguish independent string or MPPT voltage from a shared MPPT voltage.
5. Temperature spread: record several module temperatures, including the hottest and coolest areas.
6. γPmax: use the actual module datasheet value.
7. Thermal residual: subtract the approximate temperature contribution from the measured loss.
8. Heat pattern: record whether the anomaly covers a module, cell, substring, junction box or connector.
9. I-V shape: look for a smooth shift, current loss, step, shoulder or fill-factor change.

IEA PVPS field guidance recommends checking irradiance stability, module temperature, soiling, shading and array condition before field I-V results are used to judge PV performance.^[10]

Temperature Is No Longer the Best Explanation When These Signs Appear

• Current is 15-20% lower under genuinely comparable irradiance.
• The measured loss remains almost unchanged when ΔT changes substantially.
• γPmax × ΔT explains only a small part of the measured deficit.
• A cell-sized hotspot keeps appearing in the same position.
• The same substring repeatedly runs hotter.
• The I-V curve contains a clear step or shoulder.
• A connector, terminal or junction box has localized heating.
• Loss remains when suspect and reference modules reach similar temperatures.
• Visible damage or an electrically active cell crack is confirmed.

Persistent abnormalities can then be included in a broader module reliability inspection using electrical measurements, thermography, visual checks and, where needed, EL testing.

Safety

PV strings can stay energized whenever enough light reaches the modules. Turning off the inverter does not automatically remove DC voltage from an illuminated array.

I-V testing, connector work, junction-box inspection, string isolation and bypass-diode checks can expose technicians to high DC voltage and arc hazards. IEA PVPS recommends that this work be carried out by appropriately qualified personnel using suitable procedures, tools and protective equipment.^[11]

Thermal imaging can locate the suspicious area without disconnecting the string. A live PV connector should not be unplugged simply because it looks hot.

Finally

Use the measured gap, not the hotspot alone, to decide what to check next. At γPmax of -0.30%/°C, 5°C explains about 1.5% lower maximum power, 15°C about 4.5%, and 20°C about 6%. If the string is 11.0% behind while temperature explains only 1.5%, about 9.5 percentage points are still missing.

Similar current, a smooth I-V shift and a loss that shrinks as the modules cool fit a thermal cause. A 15-20% current deficit, a repeated cell or substring hotspot, a clear I-V step, a hot connector or a large unexplained gap should be treated as a real electrical or irradiance problem until testing shows otherwise.