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

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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.

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