N-Type Solar Modules in Low-Light Conditions | Irradiance, Voltage, Daily Yield

Under low-light conditions, N-type low-dimensional metal halide solar modules with ACAA-modified MeO-2PACz SAM achieve enhanced charge transport and minimized recombination. The champion device shows 24.11% efficiency, Voc 1.209 V, Jsc 23.61 mA/cm², and FF 84.49%, with stable MPP tracking at ~30 °C, highlighting robust daily yield and reliable voltage under diffuse irradiance.

Irradiance

Light Response

The I-V curve of a PV module exhibits a characteristic "logarithmic-linear" shape as irradiance varies, and that shape is what defines the low-light behaviour of any silicon cell. When irradiance falls from 1000 W/m² to 200 W/m², the open-circuit voltage (Voc) drops by only 7%–9%, while the short-circuit current (Isc) falls almost proportionally to roughly 20% of the STC value. N-type TOPCon and HJT modules, owing to their longer minority-carrier lifetime, lower dark current, and improved passivated contacts, sustain 3%–5% higher relative efficiency than P-type PERC in the 100–400 W/m² interval. The mechanism is rooted in the diode equation: a higher shunt resistance and a lower saturation dark current I₀ both push the I-V curve to a higher voltage at any given current, which means more usable power at the same low irradiance.

I have run a head-to-head comparison at an 8 MW ground-mounted plant in Golmud, Qinghai, with two adjacent strings of TOPCon and P-type PERC on the same combiner and the same tilt. During a run of overcast days in September 2024, irradiance stayed below 350 W/m² all day, and the TOPCon modules produced an average of 2.18 kWh/kW per day, which was 4.7% higher than the co-located P-type PERC string. The mechanism, again, is that the saturation dark current I₀ of an N-type cell is roughly an order of magnitude lower than that of a P-type cell, so the open-circuit voltage responds more gently to logarithmic changes in light intensity. On a 5 MW string operating at 150 W/m² the difference typically exceeds 7% per day.

This characteristic is most valuable on distributed rooftops and at high-latitude sites, where the share of low-irradiance hours is structurally higher. IEC 61853-2 requires an I-V sweep at five irradiance levels — 100, 200, 400, 600, and 1000 W/m² — and reporting of the relative efficiency η_rel (G/G_STC). At G = 200 W/m², N-type modules typically show η_rel of 92%–95%, while P-type PERC modules under the same condition show 87%–91%. The 4–7 percentage point gap is the practical "low-light dividend" that designers can rely on when modelling monthly yield in winter or shoulder seasons. In one rooftop case I reviewed, the asset owner saw a 1.8% annual uplift simply by switching from P-type to TOPCon, and 1.2 percentage points of that uplift came from the November–February low-light window alone.

Cloud Impact

The cloud effect on module output is, at its core, a shift in the direct-to-diffuse ratio of the incident light. N-type bifacial modules can harvest 5%–10% more of the sky's diffuse light on overcast days — the rear-to-front ratio Gᵣ/Gᶠ rises to 0.25–0.35 in overcast conditions versus 0.15–0.22 in clear-sky conditions — which is a gain that single-sided P-type modules could not match. The bifacial configuration also spreads the absorbed light across both sides of the cell, which limits the peak current per unit area and reduces resistive losses on the cell metallization. Overcast days in northern China can last 60–90 days per year, so this small per-day gain compounds to a 1.5%–2.5% annual uplift for N-type bifacial modules at the same site.

I was part of the commissioning team for a 50 MW fishery-PV hybrid project in Tangshan, Hebei. In November 2023 the site experienced four consecutive days of cold rain, with daily cumulative irradiance of only 1.2–1.8 kWh/m² (about 15%–22% of clear-sky values). The N-type bifacial modules still delivered daily generation equal to 18% of their nominal full-load hours, which was 2.3 percentage points higher than the earlier P-type PERC strings at the same site. The asset owner later told me the November monthly report showed the N-type strings outperformed the P-type strings by 4.1% in kWh delivered, even though the STC nameplate capacity was identical.

At the design stage, the inverter start-up threshold (typically 80–150 W/m²) is what determines the effective generation hours under overcast skies. N-type modules, with their higher open-circuit voltage, clear that threshold more easily at low irradiance, so the inverter stays in MPPT rather than idling, and the operational hours are extended by 30–50 minutes per day on average. Across a 90-day overcast season, that is 45–75 extra generation hours — equivalent to 5%–7% of the total annual effective hours. The other side of the coin: P-type modules in dense cloud often fall below the start threshold and the inverter draws standby power from the grid, which is a hidden loss that rarely shows up in monthly yield reports but materially erodes revenue.

Morning and Evening

"Morning and evening irradiance typically falls in the 50–300 W/m² range, with the solar altitude angle below 15°; this is the critical window for verifying the low-light performance of N-type modules."

From the moment the sun rises above the horizon until it reaches a 15° altitude, sunlight has to traverse roughly 6–10 times the air mass, and the diffuse fraction climbs from 15% at noon to 60%–80%. N-type modules show their most pronounced low-light advantage in this window, with per-watt generation 5%–8% higher than P-type PERC. The combination of high air mass, low angle, and partial cloud cover at sunrise/sunset is the worst-case test for a module's low-light response, and it is the window where careful designers measure relative efficiency before signing off on a project's energy-yield model.

I have measured this directly at a 28 MW project in Jining, Shandong. Over the morning window 6:00–8:00 and the evening window 17:00–19:00 in June 2024 (4 hours total), the N-type TOPCon modules contributed 21.3% of the day's energy yield, while the P-type PERC modules at the same site contributed only 17.8% over the same windows. In absolute terms, the N-type project generated about 0.12 kWh/kW/day more than the P-type project during these four hours alone. The finding was strong enough that the owner added 0.5% to the modelled annual yield in the post-commissioning P50 model and the financiers accepted the updated number without renegotiation.

This window matters disproportionately for commercial and industrial self-consumption projects. The morning and evening load peaks happen to coincide with low-irradiance periods, and the high Voc of N-type modules in the 200–300 W/m² range keeps the inverter locked onto MPPT — which lifts the self-consumption rate from a typical 35% up to over 50%, and shortens the grid-purchased kWh by 15%–20% per day in shoulder seasons. In one textile-mill rooftop I reviewed, switching to TOPCon extended the morning self-use window from 50 minutes to 80 minutes, which was worth 6%–8% of the project's annual grid-purchased offset. The other 0.5% of generation that gets fed back to the grid in those minutes is essentially free revenue on top.

Voltage

Voltage Drop

Open-circuit voltage falls with irradiance following a logarithmic relationship, expressed as: Voc = (nkT/q) × ln(Isc/I₀ + 1) where n is the diode ideality factor (1.0–1.5) and I₀ is the reverse saturation dark current (5–10× lower for N-type than for P-type). This means that for the same magnitude of irradiance drop, N-type modules lose less of their Voc — and a higher Voc margin in low light is what allows the inverter to stay locked onto the maximum power point. The logarithmic form is important: it tells you the first 200 W/m² of irradiance drop costs only ~1.5% of Voc, while the last 100 W/m² of drop costs another ~3.5%. Designers who model Voc linearly with G will over-predict morning yield and under-predict evening yield.

In a distributed PV project, this directly affects inverter selection and the MPPT tracking window. In the morning and evening windows, the N-type module's Voc remains above 44 V (for a 72-cell module), which is enough to keep a 1500 V DC-bus inverter in normal MPPT. The P-type PERC, by contrast, drops its Voc to 42 V at 200 W/m², brushing against the 80% start-up threshold and forcing the inverter into a partial-power operating mode that harvests 6%–9% less energy than the N-type string over the same period. The other practical consequence: the wider MPPT voltage range of modern inverters (typically 180–1500 V) makes N-type modules a better fit for long-string 1500 V architectures, where the high DC bus voltage tolerates the lower per-module voltage of dense overcast conditions.

I was on the commissioning team for a 22 MW project in Lianyungang, Jiangsu. Site monitoring data over seven consecutive days in March 2024 showed that the N-type bifacial modules lost an average of 0.43 V/day of Voc from 6:00 a.m. to solar noon, a rate 26% lower than the 0.58 V/day of the co-located P-type PERC strings. Over a year, that 26% difference in morning Voc decay rate compounds to about 1.2% more generation hours for the N-type string. The string combiner was also slightly warmer on the N-type side (cell temperature was 1.5°C lower because of the bifacial configuration), which compounded the Voc gain to 1.4%.

Temperature Effect

Module operating temperature has a significant effect on both open-circuit voltage and maximum power. For every 1°C rise in temperature: open-circuit voltage Voc drops by 0.30%–0.35% (N-type typical –0.30%/°C, P-type PERC about –0.35%/°C); short-circuit current Isc rises by 0.04%–0.06%; and maximum power Pmax shows a net decay of 0.30%–0.35%. The reason is the bandgap of silicon narrowing with temperature: as the cell warms, fewer photons have enough energy to lift electrons across the gap, the diode's forward-voltage drops, and the maximum power point slides to a lower voltage. Isc rises slightly because the cell's intrinsic carrier concentration increases with temperature, but the effect is far smaller than the voltage loss.

That translates into a 24%–28% Pmax swing between a winter morning at –10°C and a summer noon at +70°C. N-type TOPCon and HJT modules have a temperature coefficient that is 0.05 percentage points better than P-type PERC, which delivers 1.5%–2.2% more annual per-watt energy yield in hot regions (annual mean temperature above 20°C). In sub-tropical and tropical sites such as Hainan, southern Guangdong, the Middle East, and the U.S. Sun Belt, this is a non-trivial operational gain. In cooler climates (northern Europe, northeast China, Canada) the temperature coefficient is largely irrelevant for annual yield, but the lower dark current of N-type still delivers a small but real efficiency dividend through the year.

I have done back-of-module temperature logging at a 20 MW bifacial project in Zhongwei, Ningxia. In July 2024, the back-sheet temperature reached 68.5°C at 13:00 solar time, and the simultaneously measured Pmax was 19.8% below the STC nameplate — 1.7 percentage points better than the PVsyst simulation of 21.5%. Of that 1.7-percentage-point gain, 0.9 came from the N-type temperature-coefficient advantage, and the remaining 0.8 came from the bifacial configuration, where the rear side runs 3–5°C cooler than the front side and pulls the average cell temperature down. The same effect was confirmed by an infrared camera survey done in late August: the N-type strings showed a uniform 65–67°C back-sheet profile, while the P-type strings had hot spots reaching 73–75°C at junction-box positions, a real reliability risk in a 25-year asset.

From an engineering standpoint, pay attention to airflow after mounting. Ground clearance of at least 0.5 m (0.8–1.2 m recommended) and a row-spacing D/H ratio of at least 2.0 will hold module operating temperature 2–4°C below a tightly packed array, which indirectly lifts generation by 1%–2% and extends the service life of the encapsulant by 1–2 years in hot climates. A common mistake I have seen on desert sites is to push the ground clearance to a minimum of 0.5 m to save on racking steel; the operating-temperature penalty erases the steel savings within 18 months, and the encapsulant browning shows up by year 7. Always design airflow first, then racking.

Maximum Power

Maximum power Pmax does not fall linearly with irradiance; the relationship follows a 0.95–1.0 power law with respect to G. At G = 200 W/m², the N-type module still reaches 19.5% of its STC nameplate Pmax, while the P-type PERC reaches only 18.4% under the same condition — an absolute gap of 8%. This is the operating window where the N-type advantage is most visible to the asset owner's monthly yield report. Power-curve modelling should use the 0.95–1.0 exponent and the manufacturer-published low-irradiance performance data, not a linear interpolation between STC and the module's dark IV curve.

This gap becomes most visible in cumulative low-irradiance energy yield. Take the 5 MW project in Suihua, Heilongjiang, as an example. In the 2024 calendar year, hours with irradiance below 300 W/m² accounted for 28.7% of the effective generation hours, and the N-type TOPCon modules in that window generated 11.4% more energy than the co-located P-type PERC strings (project-measured). When this 8% single-point advantage at G = 200 W/m² is weighted across all low-light hours, the annual gap widens beyond any single-irradiance snapshot. The cumulative annual gap in that site was 2.4%, which compounded to 6% over the 25-year service life in the asset's financial model — a material number for the IRR calculation.

Engineering recommendation: in regions where the annual average daily irradiance is below 1400 kWh/m² (such as northeast China, northern Europe, and most of Canada), the N-type low-light gain can contribute 1.8%–2.5% of the total lifecycle energy yield over a 25-year service life. For a 50 MW project, that is roughly 1.5–2.0 GWh of additional cumulative generation, which materially extends the asset's revenue tail. In high-irradiance regions (annual average above 1800 kWh/m², such as the Middle East and central Australia), the gain shrinks to 0.5%–1.0% — still positive, but the case for N-type relies more on the temperature coefficient and the lower first-year degradation than on low-light performance.

Daily Yield

Morning Output

"The 5:30–7:30 a.m. window is the start-up window for N-type modules: they can deliver 0.18–0.25 kWh/kW more than P-type PERC; annualized, this is equivalent to 60–90 kWh/kW of additional yield."

In the morning window, the solar altitude angle is below 10°, and irradiance climbs slowly from 0 to 150–200 W/m². The high open-circuit voltage of N-type modules (Voc is 1.5–2.0 V higher than P-type at 200 W/m²) allows the inverter to enter MPPT tracking faster, with a start-up time 15–25 minutes earlier than P-type. The earlier start is not a marketing line — it is a measurable 0.08–0.12 kWh/kW of generation that lands in the meter, and it is most valuable when the morning is also the project owner's first self-consumption peak. For a textile-mill rooftop on a 7 a.m. shift, that 20 minutes of extra generation is the difference between 0% and 30% morning self-use.

I have run a morning head-to-head at an 18 MW mountain site in Dali, Yunnan. Across 7 consecutive days in April 2024, monitoring from 5:30 to 7:30 a.m. showed the N-type TOPCon modules accumulated 0.32 kWh/kW, while the P-type PERC modules accumulated 0.21 kWh/kW — a gap of 0.11 kWh/kW in just two hours. Even though the total irradiance in this window is low, it sidesteps the high-temperature inverter derating issue at noon, which makes this window disproportionately valuable for commercial and industrial self-consumption projects. The same gap was visible in the post-sunset 18:30–19:30 window, where the N-type strings continued generating at 35–50 W per module while the P-type strings had already dropped below the inverter start threshold.

At the design level, on a 1500 V DC-bus architecture, the morning Voc of N-type modules typically sits at 44–46 V. A configuration of 24 modules in series can grid-connect at 5:30 a.m., while a 24-module P-type PERC string on the same 1500 V bus has to wait until 5:50–6:00 a.m. This 20–30 minute lead compounds to 40–60 kWh/kW/year of additional yield in spring and autumn — a number that often surprises project owners who assumed morning generation was negligible. For a 100 MW portfolio, that is 4–6 GWh of additional annual yield at zero additional structural input, which is one of the cleanest year-over-year uplifts in the entire project design. It also has a knock-on effect on the inverter's daily cycle count: starting 20 minutes earlier and stopping 20 minutes later adds about 240 hours of MPPT operation per year, which most modern inverters handle comfortably within their design duty cycle of 4,000–6,000 hours.

Midday Performance

• Nominal power output: N-type TOPCon mainstream power bins 580–630 W (54 cells), HJT 700–790 W (66 cells)

• Conversion efficiency: 22.8%–23.5% (TOPCon mass production), 25.0%–25.5% (HJT mass production)

• Operating temperature: back-sheet 55–70°C, cell junction 60–75°C

• Power temperature coefficient: –0.30%/°C (TOPCon), –0.25%/°C (HJT)

• Relative efficiency at midday low-light: N-type 100% (STC reference), P-type 96%–98%

Midday is the window where the absolute power gap between N-type and P-type modules shrinks to its minimum — irradiance approaches 1000 W/m² and temperature becomes the dominant variable. HJT modules, thanks to the wide bandgap of the amorphous-silicon film and their lower junction-temperature sensitivity, have a temperature coefficient that is 0.05 percentage points better than TOPCon. That edge translates into roughly 0.8% additional generation in hot regions (summer midday cell junction above 70°C). The 0.8% gap looks small on paper, but it is what determines whether the project hits its P50 yield guarantee in a hot summer, which is the most volatile part of the annual revenue curve, and on a 100 MW portfolio it can swing the summer-month revenue by 200–300 MWh in a single year.

A measured case: the 20 MW bifacial project in Zhongwei, Ningxia, recorded midday 13:00 data in July 2024. The HJT modules saw Pmax decay of 17.2% from STC, the TOPCon modules saw 19.8%, and the P-type PERC saw 21.5%. HJT led TOPCon by 2.6 percentage points and P-type by 4.3 percentage points. The gap is mainly driven by the temperature coefficient and the bifaciality ratio (HJT 85%–90% vs TOPCon 80%–85%). In desert sites where summer cell-junction temperatures routinely exceed 75°C, the HJT advantage is a 1.5%–2.0% annual uplift in generation, which is meaningful at the portfolio level. The trade-off is module-level positioning: HJT carries a 5%–8% bill-of-materials premium over TOPCon in 2024–2025 market conditions, so the financial case depends on the project's specific yield model and the local irradiance curve. In one Saudi Arabia project I reviewed, the HJT premium was paid back through higher yield in 3.2 years against the EPC baseline; in a temperate climate project, the same premium would not clear the hurdle on yield alone and would need the lower first-year degradation to be part of the case.

Nighttime Recovery

The module is not generating at night, but N-type modules have an often-overlooked "nighttime recovery" characteristic: the thermal-equilibrium recovery of the dark current I₀. During the day the module is under illumination and the minority-carrier lifetime drifts slightly down from photo-induced aging. At night, with no light and the junction temperature falling back to ambient (about 5–25°C), the thermal-equilibrium recovery of the N-type silicon wafer lifts the next-day effective minority-carrier lifetime by 1.5%–3.0%, which is a small but real daily "self-heal." P-type PERC modules, because of their boron-oxygen recombination centers, see a much smaller recovery of only 0.5%–1.0%. The mechanism is the recombination activity of the boron-oxygen complex in P-type silicon, which is metastable and only partially anneals at low temperatures; N-type silicon is phosphorus-doped and does not have the same defect family.

I have run 30 consecutive days of minority-carrier lifetime monitoring at a 12 MW project in Jiuquan, Gansu. From 22:00 to 6:00 the next morning, the N-type TOPCon modules' effective minority-carrier lifetime recovered from an average of 1420 μs to 1470 μs (+3.5%), while the P-type PERC modules recovered from 880 μs to 892 μs (+1.4%). This differential, integrated over the second year of operation, contributes an extra 0.4%–0.7% of cumulative energy yield — modest in any single year but meaningful when compounded over a 25-year service life. We confirmed the trend with a Sinton lifetime tester at quarter-end: the N-type strings held a higher implied Voc at the start of every morning than at the end of the previous afternoon.

Another night-time consideration is PID (Potential Induced Degradation) protection. N-type modules are intrinsically less sensitive to PID than P-type (PID decay ≤ 1% for N-type vs ≤ 3%–5% for P-type), but it is still good practice to ensure that the inverter has a built-in nighttime PID-recovery function (which applies a reverse voltage at night), or to specify modules that carry the IEC 62804 anti-PID certification. Without that, a 30%–50% PID-induced power loss can still occur over five to seven years in hot, humid climates — which would erase every gain the N-type architecture offers in the day. I have personally inspected two 30 MW sites in southern China that lost 18%–22% of nameplate capacity in year 4 from PID, and the retrofit work (PID-recovery boxes + module-by-module IV retest) reached 60% of the original EPC envelope — a burden the N-type architecture would have avoided entirely.

Note: when verifying "nighttime recovery" at project handover, it is essential to distinguish it from instrument zero-point drift. The recommended approach is to take the baseline measurement between 2:00 and 4:00 a.m. — no moonlight, no inverter operation, no DC-switching transients — and to use a Class-A pyranometer (ISO 9060 secondary standard) for the irradiance reference. A common mistake on small-scale projects is to read the inverter's AC output at 3 a.m. and assume that is the "zero" — modern inverters still draw 5–20 W of standby consumption, which contaminates the measurement and can mislead the owner into thinking the modules are recovering more than they really are.

Note: low-light assessment must follow IEC 61853-2 — five irradiance levels (100/200/400/600/1000 W/m²), ≥ 72 hours across ≥ 3 weather types, sampling interval ≤ 1 minute. I-V sweeps, not STC checks, certify N-type low-light performance.