Location not specified · Parcel — · 41.2335° N, 36.4481° E · Report date 9 Aug 2026 · solarsimpro RoofSim
1 · Report summary
Number of roofs3
Annual generation (P50)3,109.0 MWh
Specific yield1,110 kWh/kWp·year
Performance ratio (PR)81.9%
Installed capacity2,801.0 kWp
Horizontal irradiance (GHI)1,362 kWh/m²·year
Total annual shading loss1.53%
Plant 4,446 modules (2,801.0 kWp DC) and 2,188 kW AC inverter capacity was modelled; the DC/AC ratio is 1.28. Meteorological data: PVGIS-SARAH3, 2005–2023 · average of 19 weather years. Horizon profile included.
Layout — on satellite imagery (plan view)
The frame is taken from the actual layout at the moment the report was generated.
Layout — perspective
Roof pitch, parapet and obstacle heights are taken directly from the 3D model.
2 · Plausibility check
This section tests whether the calculated results are of the expected order of magnitude . The comparison is made against the nearest reference point ; for this project that is Kayseri (~289 km).
Where do the reference values come from?They are not the measured output of a built plant. The coordinates of 10 points spread across Türkiye were queried against the PVGIS v5.3 (SARAH3) database and the resulting model values were written into the report engine as constants. Each reference was computed with the following assumptions: optimum tilt, due south, free-standing array, 14% total system loss and no near shading. Your project's own irradiance values come from the same database gelir — ama at your coordinates and with your roof pitch and azimuth. Deviation is larger on rooftops than on ground-mounted plants: the pitch and orientation of a roof cannot be chosen — the building determines them. The deviation is not an error; it measures how far the roof geometry departs from the optimum.
Quantity
This project
Referans (Kayseri)
Deviation
Acceptance band
Assessment
What the deviation indicates
Horizontal irradiance (GHI)
1,362 kWh/m²
1,720 kWh/m²
−20.8%
±10%
✕ Outside the expected band
Climate and location difference. This is a horizontal-surface quantity and is independent of the roof — a large deviation points to a location or data-set error.
Plane-of-array irradiance (POA)
1,356 kWh/m²
1,945 kWh/m²
−30.3%
±12%
✕ Outside the expected band
Roof pitch and orientation. The reference is at optimum tilt; north-facing or low-pitch faces reduce POA — this is geometry, not loss.
Specific yield
1,110 kWh/kWp
1,516 kWh/kWp
−26.8%
±15%
! Borderline
The combined result of irradiance and loss assumptions. If it is worse than the POA difference, the loss and shading assumptions should be reviewed.
What does “reasonable” mean? If the absolute deviation is within the acceptance band it is marked ✔ Reasonable; up to twice that, ! Borderline; above that, ✕ Outside the expected band . The bands are chosen according to how sensitive each quantity is to geometry: GHI is independent of the roof and uses the narrowest band (±10%), while specific yield also carries the loss assumptions and uses the widest (±15%).
Reference network and selection
The reference point is chosen as the nearest in straight-line distance ; no other weighting is applied. The full network and its distances from your project are listed below.
Reference point
Distance
GHI (kWh/m²)
POA (kWh/m²)
Specific yield (kWh/kWp)
Kayseri ← selected
289 km
1,720
1,945
1,516
Ankara
333 km
1,654
1,885
1,476
Rize
341 km
1,161
1,330
1,055
Erzurum
429 km
1,587
1,815
1,451
Karapınar
459 km
1,830
2,088
1,611
Şanlıurfa
493 km
1,883
2,127
1,600
Konya
499 km
1,785
2,026
1,578
İstanbul
624 km
1,544
1,742
1,373
Antalya
680 km
1,897
2,170
1,649
İzmir
837 km
1,803
2,059
1,582
PR assessment: The performance ratio of this plant is 81.9%. The PR implied by the reference it is compared against is 77.9% (reference specific yield ÷ reference POA = 1,516 ÷ 1,945). The band commonly quoted in the industry for rooftop plants is 78–86% — a point below ground-mounted plants, because rear ventilation on a roof is weaker and temperature losses are larger. The value is within the band and above the reference.
3 · Performance ratio — definition and scope
The performance ratio of this plant is81.9%
Temperature-corrected PR86.8%
Specific yield1,110 kWh/kWp·year
PR is calculated as defined in IEC 61724-1:
PR = E_grid / (P_nom × GlobInc / 1000)
The irradiance in the denominator is POA (GlobInc), NOT horizontal irradiance (GHI). A "PR" computed with GHI comes out 10–15 points higher on a tilted system and is not comparable. In this report the denominator is the shade-free plane irradiance, weighted by module count across the orientation groups; shading, IAM and soiling reduce PR — so PR measures design quality.
Scope limits: (a) temperature-corrected PR is reported 86.8% (§11); (b) system age is 0 — degradation is not included; (c) bifacial modelling is off; (d) the calculation is based on the 2005–2023 average of 19 weather years.
The annual PR is notthe arithmetic mean of the monthly PR values; it is recomputed from the annual total yield and the annual total POA.
4 · Irradiance — monthly and annual
Annual horizontal irradiance 1,362 kWh/m², irradiance on the plane of array 1,356 kWh/m²; the choice of tilt and azimuth has %-0.5 the irradiance. The diffuse component makes up 46%of annual GHI.
Irradiance chain: GHI (horizontal) → transposition → GlobInc/POA (plane of array) → shading + IAM + soiling → GlobEff (effective irradiance) → PV conversion → EArray → inverter + AC → E_grid. The denominator of PR is GlobInc'tir.
5 · Monthly energy balance
Month
GHI kWh/m²
DHI kWh/m²
DNI kWh/m²
T_avg °C
POA kWh/m²
E_grid MWh
Y_f kWh/kWp
PR
January
49.0
26.7
60.7
4.3
48.8
111.62
39.8
81.7%
February
62.0
34.4
61.4
5.0
61.7
147.65
52.7
85.4%
March
95.1
51.1
77.9
7.2
94.7
227.02
81.0
85.6%
April
133.7
64.1
105.5
10.7
133.1
312.33
111.5
83.8%
May
165.1
73.2
128.7
15.3
164.3
378.67
135.2
82.3%
June
183.7
74.5
151.1
19.5
182.8
414.95
148.1
81.0%
July
190.1
77.4
159.1
21.8
189.2
427.18
152.5
80.6%
August
169.5
71.0
143.9
22.7
168.7
380.85
136.0
80.6%
September
122.4
55.7
110.5
19.2
121.8
279.48
99.8
81.9%
October
83.7
41.9
83.0
14.9
83.3
192.44
68.7
82.5%
November
60.1
28.4
80.2
10.4
59.8
132.50
47.3
79.1%
December
47.9
23.8
71.3
6.5
47.7
104.28
37.2
78.0%
ANNUAL
1,362
622
1,233
—
1,356
3,109.0
1,110
81.9%
A drop in PR over the summer months is expected behaviour: as module temperature rises, efficiency falls. The dashed line is the annual average PR.
6 · Loss diagram
Items sequentially (multiplicatively) — adding the percentages is wrong. The IAM item is computed hourly inside the model; the diagram shows its typical annual equivalent. Soiling, mismatch, cabling and transformer items are user assumptions.
7 · Shading
Total annual shading loss1.53%
Beam component1.53%
Worst module10.24%
Modules measured4,446
Linear (irradiance deficit)1.53%
Additional electrical loss0.47%
Electrical impact ratio100%
Linear and electrical shading losses are different things.Linear loss is the shaded AREA share. Electrical loss arises when any module in a string is shaded and the series-connected cells limit the current: the shaded string collapses almost entirely until the bypass diodes engage. The bypass diodes recover part of this loss; the share that cannot be recovered is given by the electrical impact ratio — in this run, 100%. For regular row layouts ~100% is appropriate; for scattered shadows (chimneys, distant buildings) 60–80%. The electrical effect is applied to the beam component only component only — diffuse irradiance is not restricted on a string basis.
This item matters more on roofs than on ground-mounted plants: point obstacles such as chimneys, lift overruns and HVAC units can shade a single module and bring down an entire string. The string configuration is built from the adjacency of modules in the layout order (string length: 10 modules); if your actual cabling differs, adjust the impact ratio accordingly.
The heat map is produced from a month × hour access matrix calibrated to the monthly loss of the canonical shading engine. Dark cells show the hours where shading concentrates — typically morning and evening in the winter months.
Annual shading plan by module
Each module is coloured by ITS OWN annual shading loss. The dominant sources on a roof are parapets, chimneys, lift overruns, HVAC units and neighbouring buildings; the areas shading towards red gather on the north side of these obstacles. The numbers inside the modules are the module numbers — references such as "#48" in the text correspond to these numbers, and the 20 most shaded modules are also marked with a bold outline. The dashed blue line is the roof footprint.
Scope: Near shading (parapets, chimneys, obstacles, row spacing and neighbouring buildings) is computed by ray tracing. Distant horizon shading is accounted for on the irradiance side via the PVGIS horizon profile. Neighbouring structures not drawn in the project are NOT in the model — they must be verified by a site visit.
8 · Uncertainty and exceedance probabilities
Uncertainty component
σ
Satellite irradiance model (long term)
5.5%
Year-to-year variability
3.8%
Transposition model
2.5%
PV module model + STC rating
2.5%
Soiling / mismatch / availability
1.5%
Degradation
1.0%
Total (RSS)
7.79%
Scenario
Annual generation
Specific
P50
3,109.0 MWh
1,110
P75
2,945.5 MWh
1,052
P90
2,798.5 MWh
999
Method: Pxx = P50 × (1 − k·σ), k(P75) = 0.675 · k(P90) = 1.282. The components are combined by RSS (root sum of squares), not added linearly. Year-to-year variability is measured from the project's own 19-year series. These values are one-year exceedance probabilities; for an n-year average the σ_IAV component reduces by √n.
9 · System and equipment
Quantity
Value
Module
Generic module · 630 Wp
Module count / DC capacity
4,446 units · 2,801.0 kWp
Inverter
Generic string inverter · 2,188 kW AC total
DC/AC ratio
1.28
Array configuration
445 strings × 10 modules · 38 MPPT groups
Roof face pitch
7.0° (area-weighted)
Roof face azimuths
177° · 357° (0 = north, 180 = south)
Thermal model
Wind dependent · Uc 20 W/m²K, Uv 0.0
Meteorological data
PVGIS-SARAH3 · 2005–2023 · average of 19 weather years
10 · Roof and layout analysis
Number of roof faces6
Total roof area15,705 m²
Module count4,446
Area coverage76.5%
Obstacle / parapet3 units
Power density178.4 W/m²
The values in this section are PROJECT-WIDE — all 3 roofs are summed. The simulation likewise models the project as a whole.
Roof face
Area
Slope
Azimuth
Module
Share
1
2,617 m²
7.0°
357°
741
50.0%
2
2,617 m²
7.0°
177°
741
50.0%
Azimuth 0 = north, 180 = south. Each roof face receives its OWN PVGIS irradiance series for its tilt and azimuth; the hourly DC total then enters a single inverter model. Opposing faces (gable or hip roofs) therefore flatten each other's generation peak and reduce the risk of inverter clipping.
Obstacles and parapets
#
Type
Height
Geometry
1
area
50.00 m
12 corners
2
area
50.00 m
12 corners
3
area
50.00 m
12 corners
11 · Assumptions and limitations
This report is a design and feasibility output, not an independent energy yield assessment (EYA). Financing processes require cross-checking against site measurements and review by an independent engineer.
Topic
Status
Irradiance data
PVGIS-SARAH3 · satellite derived · 2005–2023 · average of 19 weather years
Roof level / pitch
User drawing — must be verified by site survey
Temperature-corrected PR
86.8% (IEC 61724-1 · corrected to a 25 °C cell temperature reference)
String / bypass diode electrical model
Yes — additional string-level loss of 0.47 points (impact ratio 100%, beam component only)
Inverter clipping loss
0.02% puan
Terrain peak / ridge shading
Yes — DEM horizon map (relief 2.11 m · 500 m reach · 36 azimuths)
Shading from undrawn neighbouring structures
Not modelled
Snow / spectral loss
Not modelled
Bifacial
Off
The loss assumptions are read from the interface values at the moment the report was generated. If they were changed after the simulation run, the table and the yield may be inconsistent.
solarsimpro Rooftop · shading engine (parapet and obstacle ray tracing + diffuse sky model) · PR as defined in IEC 61724-1 · reference values from PVGIS v5.3 SARAH3. This report is intended for pre-feasibility purposes.
