Shading on Commercial Solar Arrays: Losses and How to Reduce Them
Updated 10 November 2026 · SEO Dons Editorial
How does shade reduce the output of a commercial array?
Shade comes in two kinds. Far shading, from objects distant enough to hide or reveal the sun for the whole array at once, is described by a horizon line; PVsyst puts the threshold at roughly ten times the PV field size. Near shading, from objects that cast visible shadows on the array, needs a detailed 3D description of the system and its surroundings.
Either kind causes two losses. The irradiance loss is the sunlight removed from the shaded cells. The electrical loss is often larger than the shaded area suggests, because in a module string the total current is always determined by the current in the weakest cell. PVsyst's partition model rests on the observation that shading even a single cell may cause important mismatch losses, so the power of a whole string of modules can be lost. PVGIS warns that if only part of a module is in shadow the output may fall strongly, and says it has no way of modelling that effect.
Nearby objects matter most. MCS's shade guidance says near objects cast larger shadows, and for more hours of the day, than objects further away. Its worked example gives the same object a shade factor of 0.89 when it is more than 10 m from the array and 0.6 when it is nearer.
What do bypass diodes, module orientation and half-cut cells change?
A standard module is built from sub-modules, each protected by one bypass diode, and PVsyst notes there are usually three in series. Which sub-modules a shadow touches depends on how the module is turned.
On a flat roof the commonest shadow is the one a front row throws on the bottom edge of the row behind. PVsyst says mutual shading in regular rows will affect at least the bottom sub-modules. With standard modules in landscape that is one third of the sub-modules, whereas with modules in portrait all the sub-modules are shaded at the same time. With twin half-cut cell modules in portrait, only half the current is lost when the bottom part is shaded. Landscape rows of standard modules, or half-cut modules in portrait, therefore confine the damage from low-sun row shading, subject to the roof limits in the flat roof mounting guide.
How much does a distant obstruction cost? A worked PVGIS example
PVGIS accepts a user-defined horizon: a list of horizon heights at equal compass intervals, starting at north and moving clockwise. The runs below put a horizon of the stated height across the south-east, south and south-west points, with a clear horizon elsewhere, for a 1 kWp array in Birmingham with a 14% system loss. Because PVGIS treats the obstruction as a horizon line, the result suits wide, distant obstructions such as a neighbouring tower block. It does not describe a plant room on the same roof.
| Horizon height, south-east to south-west | South-facing, 10 degrees (kWh per kWp) | Loss | East-west, 10 degrees (kWh per kWp) | Loss |
|---|---|---|---|---|
| Clear horizon | 875 | - | 800 | - |
| 5 degrees | 875 | 0.1% | 800 | 0.0% |
| 10 degrees | 869 | 0.7% | 797 | 0.4% |
| 15 degrees | 848 | 3.1% | 787 | 1.6% |
| 20 degrees | 824 | 5.9% | 773 | 3.3% |
| 30 degrees | 778 | 11.1% | 742 | 7.3% |
Method: PVGIS 5.3 PVcalc, PVGIS-SARAH3 radiation, 1 kWp, 10 degree tilt, system losses 14%, userhorizon set to 0,0,0,H,H,H,0,0 for a horizon of H degrees (north, north-east, east, south-east, south, south-west, west, north-west). The east-west figure is the mean of an east-facing and a west-facing run, as in the yield guide. Run in October 2026.
Three readings follow. Low horizons are cheap: up to 10 degrees costs under 1% a year for the south-facing array. The loss then climbs quickly, to about 6% at 20 degrees and more than 11% at 30. And the same southern obstruction costs the east-west layout roughly half as much, probably because it draws more energy from the morning and evening sky, though it starts lower at about 800 kWh per kWp against 875. For scale, 20 degrees is the angle a building about 22 m above the array subtends from 60 m away (illustrative geometry).
What about shade from plant, parapets and the array's own rows?
These are near shadings, so a horizon line is the wrong tool. MCS's procedure treats objects within 10 m separately because they can have a very significant impact on performance, and it strongly recommends repositioning the array away from the shadow-casting object, or removing the object. Typical sources on a commercial roof are plant and flues, rooflights, parapets, access routes and the rows of the array itself.
Row-to-row shading follows simple geometry: the taller the rack and the lower the sun, the longer the shadow. As an illustration, a module 2.3 m long (an assumed size) tilted at 35 degrees stands about 1.32 m high, and a sun 10 degrees above the horizon throws its shadow about 7.5 m behind the row. At 10 degrees of tilt the same module stands 0.40 m high and the shadow is about 2.3 m. The flat roof mounting guide tabulates example row pitches. PVWatts counts this self-shading in its shading loss and offers a chart of loss against the ground coverage ratio, which it defines as the ratio of the array area to the roof area the array occupies.
Which fixes reduce the loss, and what do they trade off?
| Fix | What it does | Trade-off |
|---|---|---|
| Move or remove the source | Removes the shadow; MCS strongly recommends repositioning the array or removing the object | Costs roof area, and plant often cannot move |
| Separate strings by exposure | SMA's planning rules: group modules with similar irradiation and give strings with different irradiation their own MPP trackers | More inverter inputs, more complex stringing |
| Spread light shade evenly | SMA says a single shaded module, or under 10% of modules, can have its shade spread evenly over the strings | Only suits light shading |
| Choose module orientation | Landscape for standard modules, or portrait for half-cut modules (PVsyst) | Limited by roof size and wind design |
| Use inverter shade management | Features such as SMA ShadeFix, which SMA says minimises the negative impact of shading | Specific to each inverter range |
| Add module-level electronics | Optimisers or microinverters let each module work at its own best point | Extra roof electronics with losses of their own (PVsyst); see the inverter types guide |
No fix returns the sunlight a shadow removes. They limit the electrical damage around it, so the layout decision comes first. When shade, mixed orientations or a shutdown request justifies optimisers, and when string design is enough, is covered in solar optimisers on commercial roofs.
How should shading be modelled and checked in a proposal?
A proposal should show shading as its own line in the loss budget described in the PV system losses guide, and the PVsyst report guide shows where to find it. Five questions help:
- Which sources were included: horizon, plant, parapets, neighbouring buildings and the array's own rows?
- Was the shading modelled with a horizon line, a 3D scene or a simple shade factor? MCS says its simplified method is not intended to be as accurate as proprietary software, and estimates it will be within 10% of actual annual yield for most systems. PVsyst offers a detailed electrical calculation based on exact module positions.
- Is the electrical loss counted, or only the shaded area?
- What shade may appear later, such as new plant, trees or a neighbouring development?
- How will a new shadow show up? A repeating dip in one string at the same time each day is the usual sign, and the underperformance checklist lists it among the causes.
The commercial PV systems page covers where a shading study sits in a specification, and you can send an enquiry through the site's form to request quotes that include one.
Sources
- European Commission Joint Research Centre (PVGIS): PVGIS data sources and calculation methods; PVGIS non-interactive service (API) inputs; PVcalc runs for Birmingham with a user-defined horizon (PVGIS 5.3, SARAH3 radiation data), checked 22 October 2026.
- PVsyst SA, online documentation: Shadings; Electrical shadings: module strings and partitions; Array mismatch losses; Array losses, general considerations (for its own model only), checked 22 October 2026.
- MCS: MGD 005 Solar PV Shade Evaluation Procedure, issue 1.0 (16 September 2020), checked 22 October 2026.
- SMA Solar Technology AG: Shade Management with SMA ShadeFix (manufacturer page, own product only), checked 22 October 2026.
- PVWatts Calculator, National Laboratory of the Rockies: PVWatts system losses categories, checked 22 October 2026.
Common questions
Does a little shade really matter?
It can. PVGIS warns that if only part of a module is shaded the output may fall strongly, and PVsyst's partition model rests on the observation that shading even one cell can cost the power of a whole string. The loss depends on how modules are wired and turned, so the electrical loss should be shown separately from the shaded area.
Can PVGIS model the plant room on my roof?
No. PVGIS's built-in horizon has a resolution of about 90 m and cannot take into account shadows from nearby objects such as houses or trees. A user-defined horizon suits distant obstructions, and nearby plant needs a 3D shading model.
Do optimisers remove shading losses?
They reduce electrical mismatch by letting each module work at its own best point, but they cannot restore sunlight a shadow has taken. MCS notes that its shade procedure does not credit module-level electronics, and PVsyst models extra losses from optimisers themselves.
Is an east-west layout better for shade?
Not in general. In the Birmingham runs it lost less than a south-facing layout to a southern obstruction, 3.3% against 5.9% at 20 degrees, but it started from a lower yield. Plant and row shade depend on roof geometry, so each layout needs its own model.