What is a Typical Meteorological Year (TMY) dataset and why is it used for solar design?

A TMY dataset is a synthetic annual dataset constructed by concatenating the most "typical" month from each calendar month across a multi-year historical record (typically 20–30 years). Each hour in the TMY represents statistically average conditions for that time of year — not the best or worst year on record. TMY data is used for solar system sizing because it produces a representative estimate of long-term average annual energy production. Using a single historical year (which might be unusually sunny or cloudy) would produce misleading projections. NREL TMY3 and TMY2 datasets are derived from the NSRDB and are the basis for PVWatts and most US solar design software.

What is the "NEC 705.12 120% rule" and how does it affect solar installations?

NEC Section 705.12(B)(2) allows a solar system to be connected to a residential load center using the "120% rule": the sum of the main breaker ampacity plus the solar breaker ampacity cannot exceed 120% of the bus bar rating. For a 200A bus bar panel with a 200A main breaker, the maximum solar interconnection breaker is 200A × 120% - 200A = 40A, which limits the inverter output current and thus system size without a panel upgrade. This rule can be circumvented by using a supply-side connection (line-side tap before the main breaker, per 705.12(A)), which requires a separate disconnect and utility notification but removes the bus bar limitation.

How much production does non-south azimuth orientation cost?

Production loss from non-south azimuth varies by latitude and tilt but follows consistent patterns in NREL PVWatts modeling. At a 30° tilt in Phoenix, AZ (33°N): south (180°) = baseline; southeast/southwest (135°/225°) ≈ 3–6% loss; east/west (90°/270°) ≈ 15–18% loss; north-facing (0°) ≈ 30–35% loss. However, in markets with time-of-use (TOU) rates where afternoon electricity is priced 2–3x higher, west-facing arrays can be financially competitive or superior to south-facing arrays despite lower energy yield, because the production profile aligns with peak pricing periods (typically 4–9 PM).

When is a single-axis tracker justified economically versus fixed-tilt?

Single-axis trackers (SAT) increase annual energy production by 15–25% compared to fixed-tilt at similar DC capacity. The economic justification depends on the module cost vs. tracker cost tradeoff. As module prices have fallen below $0.20/Wp, trackers have become cost-effective at utility scale because the incremental tracker cost (typically $0.05–0.08/Wp additional installed cost) is recovered through higher energy yield and lower LCOE. Ground-mounted systems of 500 kW or larger typically favor SAT in US sunbelt locations (DNI > 5.5 kWh/m²/day). Fixed-tilt remains preferred for rooftop systems (where trackers are impractical) and sites with space constraints or high wind loads that increase tracker foundation costs.

Engineering·9 min read·July 15, 2025

📐 Solar Site Assessment: Irradiance Data, Shading Analysis, and Tilt/Azimuth Optimization

Master the technical process of solar site assessment — evaluating irradiance resources using TMY data and PVWatts, performing shading analysis with SunEye and Solargis, and optimizing module tilt and azimuth for maximum annual energy production.

Why Site Assessment Is the Foundation of Solar Project Success

A thorough solar site assessment determines whether a project is technically feasible, predicts annual energy production with bankable accuracy, and identifies constraints that affect system design. Errors in site assessment cascade into undersized or oversized systems, permitting problems, and financial underperformance. Professional site assessment integrates solar resource analysis, shading evaluation, structural review, electrical infrastructure assessment, and utility interconnection evaluation.

NABCEP-certified professionals and experienced EPCs treat site assessment as a multi-step process, not a single-visit activity. Pre-site desktop analysis using satellite imagery and public datasets reduces on-site time and allows engineers to identify obvious constraints before deploying field teams.

Solar Irradiance Resources and Data Sources

Solar irradiance — the power of solar radiation per unit area (W/m²) — is measured and reported in three primary components:

Global Horizontal Irradiance (GHI): Total solar radiation on a horizontal surface. GHI = DNI × cos(θz) + DHI, where θz is the solar zenith angle. GHI is the most commonly available measurement and serves as the basis for most energy production models.
Direct Normal Irradiance (DNI): Solar radiation from the direct solar beam, measured perpendicular to the sun's rays. DNI is the primary resource for concentrating solar technologies (CSP, CPV).
Diffuse Horizontal Irradiance (DHI): Solar radiation from the sky dome excluding the direct beam, due to atmospheric scattering. DHI is particularly important in cloudy climates where diffuse radiation constitutes a larger fraction of GHI.
Plane of Array (POA) Irradiance: The actual irradiance incident on a tilted and oriented solar panel surface. POA is computed from GHI, DNI, and DHI using transposition models (Perez, Hay-Davies, Reindl).

Key data sources for solar resource assessment include:

NREL National Solar Radiation Database (NSRDB): 4 km × 4 km satellite-derived dataset covering the Americas, 1998–present. Provides hourly TMY (Typical Meteorological Year) data for over 2,000 US locations.
Solargis: Commercial satellite-derived dataset covering global locations with 2 km resolution and 20+ years of historical data. Industry standard for international project finance.
NREL PVWatts Calculator: Free web tool using NSRDB data that computes annual AC energy production, monthly output, and system performance metrics for any US location.
SolarAnywhere (Clean Power Research): Bankable satellite-derived TMY data accepted by major project finance lenders.

Shading Analysis Methods and Tools

Shading is the single largest source of energy loss variability in solar site assessment. Even small shading sources — a rooftop HVAC unit, a neighboring tree, or a chimney — can cause disproportionate production losses, especially in systems using string inverters without module-level power electronics.

Shading analysis tools and methodologies:

Solmetric SunEye / SunEye 210: A fisheye lens camera device that captures a full hemisphere of the sky and automatically calculates annual shading loss by projecting the sun's path onto the image. Provides shade measurements at each hour of each day of the year. Widely used for residential and small commercial assessments.
Solar Pathfinder: An analog sun path diagram tool using a convex reflective surface to record obstructions along the sun's path. More affordable than digital tools and does not require batteries, making it suitable for remote sites. Manual digitization of results adds analysis time.
Drone-based LiDAR and photogrammetry: 3D point cloud surveys enable precise shading modeling using software such as Aurora Solar or HelioScope, which import terrain models and compute hourly shading losses across the array.
Aurora Solar and HelioScope: Cloud-based design platforms that use satellite imagery (Nearmap, Google Solar API) combined with irradiance data to model shading, estimate production, and generate permit-ready designs. Aurora Solar's AI-based roof detection and shading engine has become the residential solar industry standard.

The key metric output of shading analysis is the Solar Access Value (SAV) or Annual Shading Loss (%). Sites with annual shading losses above 15–20% typically require design modifications (panel repositioning, microinverters, ground mounts) to achieve economic viability.

Tilt Angle Optimization

The optimal tilt angle for a fixed-tilt PV array maximizes annual POA irradiance. General guidelines:

For maximum annual energy, fixed-tilt arrays are typically set to approximately the site's latitude. A site at 35°N latitude performs best with tilt angles between 30–38°.
Steeper tilt angles (latitude + 10–15°) optimize for winter production and are preferred in heating-dominated climates where electricity demand peaks in winter.
Shallower tilt angles (latitude - 10–15°) optimize for summer production and are preferred in cooling-dominated climates or for peak demand shaving applications.
Single-axis trackers (SAT) outperform fixed-tilt systems by 15–25% in most US locations by following the sun from east to west throughout the day. Dual-axis trackers add marginal gains (5–8% over SAT) at significantly higher cost and maintenance burden.

PVWatts and energy modeling software (PVsyst, SAM from NREL) can optimize tilt angles numerically for any specific location and load profile.

Azimuth Optimization

Azimuth (compass orientation of the array face) has a significant impact on production. Key findings from NREL research:

True south (180° azimuth in the northern hemisphere) is optimal for annual energy maximization.
Arrays facing southeast (135°) or southwest (225°) produce approximately 5–10% less annual energy than true south at equivalent tilt.
East-facing arrays (90°) and west-facing arrays (270°) produce roughly 15–20% less than south, but west-facing arrays may be preferred for utilities with high afternoon peak demand or time-of-use (TOU) rate structures that reward afternoon production.
Dual-tilt "east-west" rooftop configurations — placing panels on both east and west-facing roof surfaces — reduce peak power output but spread production more evenly throughout the day, reducing inverter clipping and improving energy yield relative to one-sided arrays.

Structural and Electrical Site Assessment

Beyond solar resource and shading, a complete site assessment includes:

Structural assessment: Roof age, material (composition shingle, metal, tile, TPO membrane), rafters and sheathing condition, snow and wind load capacity per local building codes (ASCE 7). Structural letters from licensed engineers are required for most commercial permits.
Electrical infrastructure: Service panel capacity, main breaker ampacity, available bus bar space (NEC 705.12 120% rule for supply-side connections), subpanel locations, and existing electrical loads. Upgrades to the main service panel or meter socket are common cost drivers in residential retrofits.
Utility interconnection pre-screening: Available distribution feeder capacity, existing DER (Distributed Energy Resource) penetration, net metering availability, and interconnection application queue wait times. Some utilities have saturated circuits that require expensive system upgrades, fundamentally affecting project economics.

Topics covered

solar site assessmentirradiance datashading analysistilt optimizationazimuth optimizationTMY dataPVWattsSolargisSunEyesolar pathfinderpeak sun hoursGHIDNIPOA irradiancesolar resourceannual energy production

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