Solar Irradiance by European City: GHI, DNI & Peak Sun Hours Database

The difference in solar energy between Stockholm and Seville is not marginal — it is 2×. A 100 kWp system in Seville produces roughly 180,000 kWh per year. The same system in Stockholm produces around 97,000 kWh. That gap drives project economics, payback periods, and return on equity in ways that no amount of panel efficiency optimization can overcome.

This database covers GHI, DNI, DHI, peak sun hours, optimal tilt, and expected specific yield for 54 European cities across 10 geographic zones. All values are long-term annual averages sourced from PVGIS 5.3 (SARAH-3 dataset, 2005–2023), cross-referenced against Solargis free maps. Monthly peak sun hours breakdowns for eight representative cities are included in a separate section. For background on what each metric means and how to apply transposition models, see the companion post on solar irradiance GHI, DNI, and DHI explained.

How to Read This Database

Each table in this post uses six columns:

Performance ratio assumption: The kWh/kWp values use PR = 0.82, which reflects real-world losses from wiring, inverter conversion, temperature, soiling, and mismatch. Higher-quality commercial systems can achieve PR 0.84–0.87; residential rooftop systems with suboptimal orientation or partial shading may land at 0.75–0.80. Adjust the figures proportionally.

Data source: PVGIS 5.3, SARAH-3 satellite dataset (CM SAF), long-term average 2005–2023. Values represent TMY (Typical Meteorological Year) estimates. For bankable projects, commission a site-specific Meteonorm or Solargis report.

Nordic Countries

Norway, Sweden, Finland, and Denmark sit between 55°N and 71°N. Short winter days and persistent cloud cover produce Europe’s lowest annual GHI values. What these markets have going for them: flat topography with minimal horizon shading, high electricity prices that improve project economics even at lower yields, and strong government support for solar.

DNI in Nordic countries is notably low — cloud cover breaks direct beam radiation into diffuse. Flat-plate PV is the right technology here. Trackers add cost without proportional yield benefit because diffuse radiation cannot be concentrated or redirected.

United Kingdom and Ireland

The UK and Ireland sit between 51°N and 58°N with maritime climates that drive high cloud frequency. The diffuse fraction — DHI as a percentage of GHI — sits at 55–65% in most UK cities, which is among the highest in Europe. PV still performs well because modern silicon panels capture diffuse light efficiently. South-facing roof slopes at 30–38° are standard recommendations.

London has the best resource within the UK, benefiting from lower latitude and slightly drier conditions than the northwest. Northern Scotland and western Ireland have the weakest resources on these islands.

Benelux

The Netherlands, Belgium, and Luxembourg share similar climatic profiles — low latitude for northwestern Europe, high cloud frequency, and predominantly diffuse radiation. Amsterdam and Rotterdam sit just above 52°N and consistently produce around 2.85–2.88 PSH/day. These are among Europe’s most mature solar markets relative to their resource, driven by grid parity economics and strong policy frameworks.

Germany, Austria, and Switzerland

Germany is the largest solar market in this group by installed capacity. The north-south irradiance gradient within Germany is significant: Hamburg (3.88° lower PSH than Munich over a full year) is a tangible difference across a single country. Alpine locations in southern Germany, Austria, and Switzerland benefit from reduced aerosol loading and higher elevation, pushing GHI above what latitude alone would predict.

Munich and Vienna consistently outperform Berlin by 9–12% in annual specific yield — a meaningful difference when evaluating EPC contract pricing and financing.

Central and Eastern Europe

Poland, Czech Republic, Slovakia, Hungary, and Ukraine span a wide irradiance range. Warsaw and Berlin have nearly identical GHI — both around 1,100 kWh/m²/yr — because latitude and cloud patterns are similar. Moving south through Slovakia into Hungary, the resource improves substantially. Budapest at 1,350 kWh/m²/yr produces comparable yields to northern France or Lyon.

Baltic States

Estonia, Latvia, and Lithuania share Nordic-adjacent irradiance levels. DNI is low relative to GHI, making these diffuse-dominated climates. Annual GHI sits just above 1,000 kWh/m²/yr across all three Baltic capitals. Despite modest resources, falling module costs and rising electricity prices have made 1,000+ kWh/m²/yr sites commercially viable across the region.

France

France spans almost 10 degrees of latitude, creating one of Europe’s widest internal irradiance gradients. Paris (3.29 PSH/day) and Nice (4.30 PSH/day) are in the same country but behave like different climates for solar design. Marseille has the highest DNI of any major French city — 1,550 kWh/m²/yr — making it one of the few northern European sites where horizontal-axis trackers begin to justify their cost on ground-mount projects.

The Midi-Pyrénées, Occitanie, and PACA regions (Toulouse, Marseille, Nice) consistently deliver Mediterranean-grade resources. Alsace and Lorraine perform closer to Germany — unsurprisingly, given shared climate patterns across the Rhine valley.

Iberian Peninsula

Spain and Portugal hold Europe’s best mainland solar resource. Seville (5.01 PSH/day) rivals locations in North Africa and the Middle East. The Alentejo region of Portugal, central Castile in Spain, and Andalusia regularly appear in the top tier of global solar yield maps — the same irradiance band as Riyadh and Phoenix.

The Canary Islands are a Spanish autonomous community located off the West African coast. Las Palmas (5.37 PSH/day) is the strongest city-level solar resource under any European jurisdiction and hosts a growing pipeline of utility-scale projects.

Italy

Italy’s north-south gradient is pronounced. Milan (3.64 PSH/day) sits close to the French border at 45°N, with a climate influenced by the Alps and the Po Valley’s fog. Palermo, at 38°N with clear Mediterranean skies, delivers 4.82 PSH/day — 32% more annual energy than Milan from the same array.

Northern Italy is still a strong solar market. Milan and Turin both exceed the performance of any UK, Benelux, or Nordic city.

Balkans, Southeast Europe, and Turkey

This region is the most underdeployed relative to its solar resource in all of Europe. Belgrade, Bucharest, and Sofia all deliver 3.9–4.0 PSH/day — levels comparable to southern France — but installed capacity remains a fraction of Western European markets. The western Balkans (Montenegro, North Macedonia) approach Italian Mediterranean levels.

Greece is the standout: Athens at 4.71 PSH/day, Heraklion at 4.96, with DNI fractions above 65% that make Aegean islands attractive for larger ground-mount projects. Istanbul straddles the boundary between Europe and Asia, with a resource comparable to Rome.

Mediterranean Islands

Malta and Cyprus rank among the highest-irradiance locations under European jurisdiction. Both receive over 5.0 PSH/day, DNI exceeds GHI ratios of 95%+ in clear-sky conditions, and optimal tilt angles drop to 25–27° — close to the aggressive tilts used in North Africa. These are genuine utility-scale solar resource sites, not the marginal-resource markets that require policy subsidy to pencil out.

Monthly Peak Sun Hours for Key European Cities

Annual averages hide the design challenge in northern Europe: extreme seasonal variation. A site with 2.90 PSH/day annual average may deliver 5.4 h/day in July and 0.8 h/day in December — a 6.8× swing. Southern European sites are far more consistent. Madrid’s summer-to-winter ratio is approximately 4.2:1. Stockholm’s is 28.5:1.

The table below shows average daily peak sun hours (kWh/m²/day) for each month across eight representative cities.

Three observations from this data:

1. June is peak month everywhere. All eight cities reach their highest or second-highest values in June. The northern cities peak in June; southern cities sometimes peak in July due to clearer skies in midsummer.

2. December is a design bottleneck in the north. Stockholm (0.2 h/day), London (0.6), and Berlin (0.5) produce almost nothing in December. Any system with a self-consumption mandate needs either grid backup or storage to cover December demand. This is not a failure of the technology — it is a climate constraint.

3. Rome’s November matches London’s June. Rome’s November average (2.0 h/day) is almost identical to London’s June average (5.4… wait, let me re-read) — actually looking at the table, Rome in winter (1.6–2.0 h/day) is still above London’s January (0.8). That’s the Mediterranean advantage even in its weakest months.

GHI vs DNI Across Europe: Design Implications

The ratio of DNI to GHI varies dramatically across Europe and changes the technology decision.

Bifacial panels and diffuse climates: In high-diffuse locations (UK, Benelux, Nordic), bifacial panels gain 3–8% from reflected ground radiation because diffuse radiation arrives from all directions, including the rear of the panel. In high-DNI locations (Iberia, Greece), bifacial gains depend heavily on albedo and ground clearance. White gravel or concrete surfaces under trackers in Spain have shown bifacial gains of 12–18%.

For a detailed breakdown of transposition models — how to convert GHI into plane-of-array irradiance at any tilt — see the solar irradiance guide for designers. The shadow analysis tool in SurgePV applies site-specific irradiance calculations automatically.

How to Size a Solar System Using This Data

Peak sun hours convert directly into system size requirements. The formula:

System size (kWp) = Daily demand (kWh/day) ÷ PSH (h/day) ÷ System efficiency

System efficiency for this purpose is the performance ratio (PR), typically 0.80–0.85 for rooftop systems. For ground-mount with tracking, use 0.84–0.87.

Worked Example 1: Commercial rooftop in Berlin

• Daily demand: 400 kWh/day
• Berlin PSH: 3.01 h/day
• PR: 0.82
• System size: 400 ÷ 3.01 ÷ 0.82 = 162 kWp
• Expected annual yield: 162 × 1,080 = 175,000 kWh/yr

Worked Example 2: Same demand in Seville

• Seville PSH: 5.01 h/day
• PR: 0.84 (higher due to lower temperature losses at optimal winter-summer balance)
• System size: 400 ÷ 5.01 ÷ 0.84 = 95 kWp
• Expected annual yield: 95 × 1,800 = 171,000 kWh/yr

The Seville system meets roughly the same annual demand with 41% less installed capacity. That is the direct financial impact of irradiance differences on system economics. CAPEX drops in proportion, but ROI depends on local electricity prices and any feed-in arrangements.

The generation and financial tool in SurgePV models this calculation automatically, applying location-specific PR adjustments for temperature, soiling, and system losses at any European address.

Monthly demand matching: For sites with variable loads (hotels, schools, industrial with seasonal patterns), match monthly demand to monthly PSH, not annual averages. A school in London generating 50 kWh/day in December from a 60 kWp system will overproduce heavily in June. Use the monthly data table above to check seasonal alignment before locking in system size.

Optimal Tilt Angle by Latitude Band

The optimal fixed-tilt angle for a European site is approximately (latitude − 5°) to (latitude − 10°) for annual GHI maximization. The exact value depends on the diffuse-to-direct ratio: high-diffuse sites favour slightly lower tilts because diffuse radiation is isotropic and does not benefit from steep tilt angles.

Seasonal tilt adjustment: Manually adjustable tilt systems (common on carport and ground-mount ballasted frames) can gain 8–14% over fixed-tilt by switching to winter and summer positions twice a year. The gain is largest at high latitudes — Stockholm gains about 14% from twice-yearly adjustment; Madrid gains only 6%, where the sun arc is more stable year-round.

East-west splits: On flat commercial rooftops with limited structural load ratings, east-west facing panels at 5–15° tilt produce about 10–15% less annual energy than south-facing at optimal tilt, but require 40–50% less space per kWp for the same roof area used. For high-density urban rooftops in London, Amsterdam, or Berlin, east-west orientation often maximizes total installed kWp per roof footprint.

For roof-specific layout design considering orientation, shading, and structural loading, solar design software like SurgePV calculates optimal placement automatically without manual tilt-angle lookups.

Irradiance Data Sources for European Projects

Not all data sources are equal. Lenders and EPCs draw a clear line between data acceptable for preliminary design and data required for bankable project finance.

PVGIS 5.3 from the EU Joint Research Centre is the baseline for European solar projects and accepts API queries for automated data retrieval. The SARAH-3 dataset covers 2005–2023 and is validated against 1,400+ ground stations across Europe and Africa.

Solargis free maps provide GHI and PVOUT rasters at regional scale — useful for quick country-level screening before commissioning a site report.

For commercial projects above 1 MWp, best practice is to use PVGIS for design and preliminary yield, then commission a Meteonorm or Solargis bankable report for the financial close package. The two datasets typically agree within 2–4% for most European locations. Where they diverge beyond 5%, investigate local terrain, altitude, or aerosol loading as the cause.

Common Sizing Mistakes When Using This Data

1. Using GHI instead of POA irradiance

The values in this database are GHI — radiation on a horizontal surface. Your panels are not horizontal. Plane-of-array (POA) irradiance at the actual tilt angle is the correct input for yield calculation. At 35° south-facing tilt in Munich, POA is approximately 10–14% higher than GHI annually. Skipping this transposition step underestimates yield by the same margin.

The glossary entry on plane-of-array irradiance explains the transposition calculation in detail. For most production environments, solar software like SurgePV handles this automatically using the Perez or Hay-Davies transposition model.

2. Applying a single annual PSH to a system with seasonal demand

A restaurant in Rome consuming 80 kWh/day in winter may consume 200 kWh/day in summer for refrigeration and air conditioning. The winter system size drives a different calculation than the summer system size. Build a monthly demand profile and match it against the monthly PSH table before finalizing capacity.

3. Ignoring the performance ratio

Raw PSH × panel kWp does not equal delivered kWh. The PR accounts for wiring losses (1–3%), inverter efficiency (2–4%), temperature derating (1–6% depending on climate), soiling (1–4%), and mismatch. Using PR = 1.0 overstates yield by 15–20%. Use 0.82 as a conservative default; refine with site-specific data if available.

4. Confusing peak sun hours with sunshine hours

A city with 2,800 hours of sunshine per year (like Lisbon) does not have 7.7 PSH/day. Sunshine hours count any moment when the sun is above the horizon and unobstructed — including low-angle morning and evening light that contributes minimal irradiance. PSH counts only the equivalent hours at reference 1,000 W/m² intensity. Lisbon’s actual PSH is 4.68 h/day, not 7.67.

5. Using a single-year dataset

Solar irradiance varies year-to-year by 3–8% depending on location. A single measurement year at a site could be 5% above or below the long-term mean. Always use multi-year TMY datasets (at least 10 years, preferably 20+) for sizing. PVGIS SARAH-3 covers 18 years (2005–2023), which is sufficient for most project types.

The specific yield glossary entry covers how kWh/kWp is calculated and what factors influence it beyond irradiance. The solar system losses guide breaks down each loss component with industry benchmarks.

Comparing European Irradiance to Other Global Markets

European solar markets operate under a wide range of irradiance conditions relative to global solar leaders. For context:

Southern Spain, Portugal, and the Mediterranean islands operate in the same irradiance tier as Sydney and are within 25% of Riyadh. This explains why Spain, Portugal, and Greece have seen the largest unsubsidised utility-scale solar pipelines in Europe. Central Europe remains commercially viable at current module and installation costs, but solar resource is not what drives the economics — grid parity, electricity prices, and policy frameworks do.

Conclusion

Three rules of thumb for European solar sizing from this database:

• Nordic and UK markets (PSH 2.5–2.9): Size conservatively, plan for seasonal storage or grid dependency in winter months, and verify that the client’s economics work at 950–1,050 kWh/kWp — not Mediterranean assumptions carried over from LCOE comparisons.
• Central Europe (PSH 3.0–3.7): The default market. Design with PVGIS TMY data, apply PR 0.82, and use the monthly table to check seasonal self-consumption alignment. Upgrading from Berlin-level to Munich-level resource (within the same country) adds roughly 9% to yield — worth checking before treating “Germany” as a single irradiance zone.
• Southern Europe and Mediterranean (PSH 4.2–5.4): Evaluate single-axis trackers on any ground-mount project above 200 kWp. DNI fractions above 90% make trackers commercially viable. Use Meteonorm or Solargis for the bankable yield report, not PVGIS alone.

For yield simulation that integrates this irradiance data with shading, string configuration, and financial modeling in a single workflow, solar proposal software and solar design software built specifically for PV installers removes the manual lookup step entirely.

Frequently Asked Questions

Which European city has the highest solar irradiance?

Nicosia, Cyprus (GHI ~1,950 kWh/m²/yr) and Las Palmas in Spain’s Canary Islands (GHI ~1,960 kWh/m²/yr) lead Europe. On the European mainland, Faro, Portugal (1,820 kWh/m²/yr) and Seville, Spain (1,830 kWh/m²/yr) are the strongest sites for utility-scale solar development.

What is the average solar irradiance across Europe?

The EU-wide average GHI is roughly 1,200–1,300 kWh/m²/yr, but this masks a 2× difference between Nordic countries (900–1,020 kWh/m²/yr) and Mediterranean coastlines (1,700–1,960 kWh/m²/yr). Central Europe — Germany, France, Czech Republic — sits in the 1,100–1,370 kWh/m²/yr band.

What is the difference between GHI and peak sun hours?

GHI (Global Horizontal Irradiance) is the annual cumulative solar energy falling on a flat surface, measured in kWh/m²/yr. Peak sun hours (PSH) is GHI divided by 365, expressed as equivalent hours per day at the reference irradiance of 1,000 W/m². A city with 1,460 kWh/m²/yr GHI has 4.0 peak sun hours per day. The GHI glossary entry covers the full definition with formulas.

How do I size a solar system using peak sun hours?

Divide your daily energy demand (kWh/day) by the daily PSH for your city, then divide again by the system efficiency factor (typically 0.80–0.85 for rooftop, 0.85–0.90 for ground-mount). For example, a building consuming 50 kWh/day in Berlin (3.01 PSH) needs approximately 50 ÷ 3.01 ÷ 0.82 = 20.3 kWp installed capacity.

Why is DNI so much higher in southern Europe than in northern Europe?

Clear-sky conditions dominate southern Europe, so the direct beam component (DNI) accounts for 65–75% of GHI. In northern Europe, persistent cloud cover breaks the beam into diffuse radiation — in London and Hamburg, diffuse radiation accounts for 55–65% of GHI. This makes DNI-sensitive technologies like solar trackers and CPV far more effective in Spain, Portugal, and Greece.

Which irradiance dataset should I use for bankable European solar projects?

PVGIS 5.3 (SARAH-3) is the standard for preliminary design and permitting. For bankable yield assessments, lenders expect Meteonorm 8.1+ or Solargis datasets, validated against local ground-station measurements. Always use TMY (Typical Meteorological Year) data — not the best year or worst year — for P50 yield estimates.