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TOPCon vs HJT vs PERC: Which Cell Technology for Commercial Roofs?

Updated 23 October 2026 · SEO Dons Editorial

Which cell technologies appear in 2026 commercial quotes?

TOPCon is the mainstream one. IEA PVPS says the dominant solar cell technology "shifted from p-type PERC to n-type TOPCon in 2024", that TOPCon "accounted for approximately 75% of the market in 2025", that heterojunction (HJT) represented around 5% and back-contact cells approximately 6%. Fraunhofer ISE describes the global market as "dominated by crystalline silicon and n-type TOPCon". Those are global production shares and not UK quotes, but they explain why most current datasheets name TOPCon. The PERC sheet used below is dated July 2024.

Is monocrystalline versus polycrystalline still a question?

Mostly for older arrays. IEA PVPS says monocrystalline "has progressively replaced multicrystalline silicon in mass production although they are present in a large volume of already operational PV systems". Crystalline silicon was approximately 98% of module production in 2025 and thin film the remaining 2%, so the three types of solar cell are monocrystalline, multicrystalline and thin film, and the sheets reviewed here that state a crystal type all say monocrystalline. PERC, TOPCon, HJT and back contact are different ways of building a monocrystalline cell.

How do PERC, TOPCon, HJT and back contact differ on datasheets?

Makers describe their own technology in their own terms. Jinko's sheet names "Tunnel Oxide Passivating Contacts (TOPCon) technology". Canadian Solar's HJT sheet claims "No B-O LID, excellent anti-LeTID & anti-PID performance". Aiko says of its back-contact cell "There is no metal grid on the front", and LONGi names its version HPBC 2.0. These are maker statements. Makers' own comparisons also use different PERC figures: Aiko's TOPCon cell page sets -0.30% against -0.45% for PERC cells, while Canadian Solar's PERC module sheet prints -0.34%, so module sheets are the like-for-like source. One row per technology, from one sheet each:

TechnologyExample sheetTop efficiency (%)Pmax temperature coefficient (% per °C)Bifaciality as printedFirst year, then annualProduct and power warranty (years)
PERCCanadian Solar BiHiKu7 CS7N-MB-AG, v2.821.6-0.3470%up to 2%, up to 0.45%12 and 30
TOPConJinko Tiger Neo 3.0 66QL6, © 202624.8-0.2685 ± 5%1%, 0.35%12 and 30
TOPConTrina Vertex N NEG19RC.20, TSM_EN_2025_D24.1-0.2980 ± 5%1%, 0.4%12 and 30
TOPConCanadian Solar CS6.3-66TB, v1.1124.8-0.2685% (headline: up to 90%)up to 1%, up to 0.35%12 and 30
HJTCanadian Solar HiHero+ CS6.2-66HB, v1.523.9-0.2490% (headline: up to 95%)up to 1%, up to 0.3%15 and 30
Back contactLONGi Hi-MO X10 LR8-66HVD24.8-0.26rear-gain table1%, 0.35%15 and 30
Back contactAiko Comet 3N72 (glass and backsheet), 202608 V1.125.5-0.26none printedup to 1%, up to 0.35%15 and 30

These are examples, not averages, and the formats differ: the PERC example is the larger 2,384 × 1,303 mm module and the others are 2,382 × 1,134 mm. Canadian Solar's TOPCon page also claims "2% higher energy generation than PERC", which is the maker comparing its own products.

What do the differences mean in kWh on a UK roof?

Efficiency. On the same module area, 24.8% against 21.6% is 14.8% more kWp, which matters only where roof area is the limit; the efficiency page works it through.

Temperature. PVGIS says module temperature "depends on both air temperature and the irradiance". To size the effect, hourly PVGIS data was used (irradiance on a 10 degree south-facing plane and 2 m air temperature, 2015 to 2023). Cell temperature was estimated as air temperature plus (NMOT - 20) ÷ 800 times irradiance, and the loss is the coefficient times the cell's excess over 25 °C, weighted by irradiance. This is the editor's calculation, with NMOT set at 43 °C. The annual loss from cell temperature, in percent of output:

Pmax temperature coefficient (% per °C)SouthamptonBirminghamGlasgow
-0.34 (PERC sheet)1.600.850.0
-0.29 (TOPCon sheets)1.360.720.0
-0.26 (TOPCon and back contact)1.220.650.0
-0.24 (HJT sheet)1.130.600.0

At Birmingham the PERC-to-HJT gap is 0.25 of a point, and at Southampton 0.47, so for example on an array that would produce 120,000 kWh a year it is about 300 kWh and 560 kWh. At Glasgow the generation-weighted cell temperature is about 25 °C, so the annual loss rounds to zero. NMOT matters as much as the coefficient: the sheets here print 41 °C (Canadian Solar), 42 °C (DMEGC) and 45 °C (LONGi), and at Birmingham moving a -0.29 module from 41 to 45 °C changes the loss from 0.39% to 1.06%. Roofs with poor airflow behind the modules can run hotter than the NMOT test conditions.

Degradation terms. Over 25 years the PERC warranty line (up to 2%, then 0.45% a year) averages 92.6% of nameplate and the 1% and 0.35% line 94.8%. On the 120,000 kWh example that is about 2,600 kWh a year. Warranty lines are ceilings and not forecasts; the lifespan page sets them beside field data.

Bifaciality. The sheets print 70% for PERC, 80% to 85% for TOPCon and 90% for HJT, but rear-side gain depends on mounting height and the surface below, so it is a site question; see bifacial panels on commercial roofs.

What do independent bodies say about reliability?

IEA PVPS Task 13 (February 2025) says UV-induced degradation "occurs in some PV modules but is manageable by using UV-stable designs and encapsulation materials", and that degradation in polymer encapsulation "remains a major issue". A US fleet study published by the Department of Energy in 2023 found loss rates "did not differ much on account of different module technologies", though the summary reports no separate n-type result. Lower-degradation claims for new technologies are therefore claims to test, and a quote can be asked for test evidence for the exact module. Next-generation cells are covered on the perovskite and tandem page.

How should a commercial roof choose between them?

  1. If roof area is the limit, efficiency decides capacity; if demand or the grid connection is the limit, it does not.
  2. Compare warranty length and degradation terms on the exact model sheets.
  3. Treat the temperature coefficient as a tie-breaker on UK sites.
  4. Check weight and build against the roof; the glass-glass page covers that.

The commercial PV panels page lists the datasheet lines to check. An enquiry about a specific quote or roof can be sent through this site's form.

Sources

Common questions

Is PERC obsolete?

It is no longer the mainstream, though sheets still exist: the Canadian Solar PERC sheet used here is dated July 2024. IEA PVPS says the dominant cell technology shifted from p-type PERC to n-type TOPCon in 2024. For a new commercial quote offering PERC, the sheets here show lower efficiency, a less favourable temperature coefficient and a larger first-year degradation allowance than the n-type sheets.

Is monocrystalline better than polycrystalline for a business roof?

The question mostly concerns older arrays. IEA PVPS says monocrystalline has progressively replaced multicrystalline silicon in mass production, and the datasheets reviewed here that state a crystal type all say monocrystalline. Multicrystalline modules remain in a large volume of operational systems.

Does TOPCon last longer than PERC?

Warranty terms differ: Canadian Solar's PERC sheet allows up to 2% loss in the first year and 0.45% a year, against up to 1% and 0.35% on its TOPCon sheet. A warranty is a ceiling, not a measured lifetime. IEA PVPS Task 13 says UV-induced degradation in newer designs is manageable with suitable materials, so test evidence for the exact module matters.

Do HJT panels suit commercial roofs?

HJT modules are made in the same 2,382 × 1,134 mm format as TOPCon, and the Canadian Solar HJT sheet prints a -0.24% coefficient and a 15-year product warranty. HJT held around 5% of the 2025 market, so quotes name it less often. Compare it on efficiency, warranty and the roof, not on the label.

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