LIVE PVGIS TMY · SOLAR GEOMETRY · TILT–AZIMUTH OPTIMIZATION
Choose any latitude and longitude, then calculate how much solar energy reaches a surface facing North, East, South, West or any azimuth at any tilt. The tool converts hourly GHI, DNI and DHI from PVGIS into plane-of-array irradiance and creates interactive monthly, hourly, 2D heatmap and 3D optimization charts.
Click the vector map for an approximate point, or type exact latitude and longitude.
Animate a representative day. The status shows whether direct sunlight reaches the active front face or falls behind the panel.
Move the time slider or press Play.
Same tilt, four azimuths: North, East, South, West.
Orientation sensitivity at the selected tilt.
Annual plane-of-array irradiation for 0–90° tilt and 0–355° azimuth.
The sky-diffuse term is calculated with either the isotropic or Hay–Davies model. Solar zenith and azimuth are calculated hour-by-hour from the PVGIS timestamp and coordinates.
PVGIS supplies an hourly Typical Meteorological Year for the selected coordinates. WattCostLab reads global horizontal irradiance (GHI), direct normal irradiance (DNI) and diffuse horizontal irradiance (DHI), calculates the solar position for every timestamp, and transposes the radiation onto the selected plane.
The surface convention used throughout the tool is North = 0°, East = 90°, South = 180° and West = 270°. Tilt is measured from the horizontal plane: 0° is horizontal and 90° is vertical.
The heatmap tests tilt from 0° to 90° and azimuth from 0° to 355° in 5° increments. Each point is the annual plane-of-array irradiation in kWh/m². The best tested combination is marked automatically, and the same dataset can be displayed as an interactive 3D surface.
Solar-resource data are requested from PVGIS, European Commission Joint Research Centre. A Typical Meteorological Year represents long-term typical conditions rather than a forecast for a specific future year. The model does not replace a detailed shading, horizon, structural or electrical site survey.
Use the exported hourly and monthly CSV files for reproducible research, sensitivity analysis or publication figures. The calculation is irradiance-based; PV module efficiency, temperature losses, inverter losses and electricity value are handled by WattCostLab's separate PV sizing and payback tools.
Solar irradiance on a panel is not determined by location alone. The same coordinates can produce different plane-of-array (POA) irradiation when the surface tilt or compass direction changes. A horizontal surface mainly follows the local global horizontal irradiance (GHI), while a tilted surface can capture more direct-beam energy when its normal points closer to the Sun. This calculator evaluates that geometry hour by hour instead of applying a single universal “best angle” rule.
GHI — Global Horizontal Irradiance: total solar irradiance received by a horizontal surface, including direct and diffuse components.
DNI — Direct Normal Irradiance: direct-beam irradiance measured on a surface kept perpendicular to the Sun's rays.
DHI — Diffuse Horizontal Irradiance: sky-diffuse solar irradiance received by a horizontal surface.
POA — Plane-of-Array Irradiance: solar irradiance received by the actual tilted surface after combining beam, sky-diffuse and ground-reflected components.
A common first-pass rule is to use a tilt near the site's latitude, but that is only an approximation. The annual optimum can shift with climate, diffuse-radiation fraction, seasonal goals, horizon conditions and panel orientation. A roof that cannot face the annual optimum may still deliver strong production, and an east- or west-facing array can be useful when the timing of electricity production matters. Use the optimization landscape above to calculate the best tested tilt and azimuth for the selected coordinates rather than assuming one angle works everywhere.
| Orientation | Typical solar-production pattern in the Northern Hemisphere | Why it may be selected |
|---|---|---|
| South | Usually strongest annual direct-solar exposure when the surface has a suitable tilt. | Annual-energy optimization. |
| Southeast | Shifts part of the production toward morning while retaining strong midday exposure. | Morning household or business loads. |
| Southwest | Shifts more production toward the afternoon. | Later daytime loads or time-of-use value. |
| East | Morning-biased production. | Morning demand, split east–west roofs. |
| West | Afternoon-biased production. | Afternoon/evening demand. |
| North | Usually lower direct-beam exposure on tilted surfaces. | Site constraints or special applications. |
In the Southern Hemisphere the preferred equator-facing direction is generally north rather than south. Near-horizontal surfaces are much less sensitive to azimuth because their orientation converges toward the horizontal plane.
Phoenix is a useful demonstration location because it lets you see how a high-solar-resource site responds to geometry changes without assuming that one fixed angle is universally optimal. Enter 33.4484° latitude and −112.0740° longitude, load the PVGIS TMY data, and keep the location unchanged while comparing the following scenarios.
| Test | Tilt | Azimuth / direction | What to compare |
|---|---|---|---|
| Horizontal reference | 0° | Azimuth has little practical effect | Annual POA versus GHI. |
| Low tilt | 15° | South (180°) | Annual POA and summer profile. |
| Moderate tilt | 30° | South (180°) | Annual POA versus the 15° case. |
| Steeper tilt | 45° | South (180°) | Seasonal redistribution of irradiation. |
| Morning-oriented | 30° | East (90°) | Hourly profile and annual penalty versus south. |
| Afternoon-oriented | 30° | West (270°) | Hourly profile and annual penalty versus south. |
Then run Tilt × azimuth optimization. The calculator reports the best geometry found on its 5° search grid and shows the annual irradiation surface as a heatmap or 3D landscape. Because the values come from the live PVGIS dataset selected by the application, the example does not hard-code a universal Phoenix production number.
A fixed array is normally designed around an annual or use-case-specific compromise. A seasonally adjustable surface can use a steeper winter setting and a shallower summer setting, but the practical value depends on mounting complexity and how often the adjustment is actually made. Vertical surfaces at 90° tilt are relevant to façades, fences and building-integrated photovoltaics; they generally produce a different seasonal and hourly profile from roof-mounted systems. The 0–90° optimization range lets you compare all of these geometries with the same solar dataset.
The answer depends on the starting geometry. Near 0° tilt, changing azimuth has little effect because the surface is almost horizontal. At larger tilts, orientation becomes increasingly important because the surface normal points more strongly toward one part of the sky. The heatmap is therefore more informative than changing tilt or azimuth in isolation: it shows their interaction across the full tested range.
Irradiance in kWh/m² is a solar-resource metric, not the same thing as photovoltaic electricity output in kWh. PV production also depends on module characteristics, array size, temperature, inverter behavior, wiring and system losses. After identifying a useful plane here, continue to the Solar PV Calculator by Location for location-specific PV yield and system sizing, then use the Solar Payback Calculator or Solar Installation Cost Calculator for project economics.
The orientation model is designed for solar-resource comparison. It does not replace a detailed site design and does not explicitly model nearby-tree or building shading, module-level mismatch, snow accumulation, soiling, module temperature, inverter clipping, wiring losses, roof structural limits or local electrical requirements. PVGIS horizon and radiation data improve the location context, but a final PV design should still use a site-specific survey and equipment model.
Azimuth describes compass direction. WattCostLab uses 0° for North, 90° for East, 180° for South and 270° for West.
There is no single best angle for every location. Latitude is a useful first approximation, but the annual optimum depends on local solar conditions, orientation and the objective of the system. Use the tilt–azimuth optimization chart for the selected coordinates.
Equator-facing arrays often maximize annual direct-solar exposure: generally south in the Northern Hemisphere and north in the Southern Hemisphere. East and west can be useful when morning or afternoon production is more valuable.
Irradiance is instantaneous solar power per unit area, normally expressed in W/m². Irradiation is solar energy accumulated over time and is commonly expressed in kWh/m² for daily, monthly or annual comparisons.
Global Horizontal Irradiance is the total direct and diffuse solar irradiance received by a horizontal surface.
Plane-of-array irradiance is the solar energy incident on the actual tilted surface after direct-beam, sky-diffuse and ground-reflected components are combined.
Not necessarily. Tilt near latitude is a rough starting rule, not a universal optimum. The best annual or seasonal angle can differ, so location-specific modeling is preferable.
East-facing surfaces shift more production toward morning hours, while West-facing surfaces shift more toward afternoon hours. The hourly profile chart makes this timing effect visible.
Yes. Vertical photovoltaic surfaces can be used on façades and other structures, but their annual and seasonal irradiation profile differs from a conventionally tilted roof array. Set tilt to 90° to evaluate the solar resource.
This page calculates solar irradiance received by the plane. For system kWh, installed cost and payback, continue to the Solar PV by Location and Solar Payback calculators.