NABCEP PV cheat sheet

Solar window is roughly 9 a.m. to 3 p.m. solar time; shade in this window has the largest production impact.

Azimuth is measured clockwise from true north; true south is 180° in the northern hemisphere, so correct compass readings for magnetic declination.

Fixed-tilt rule: tilt ≈ latitude for year-round yield, latitude − 15° for summer-weighted yield, latitude + 15° for winter-weighted yield.

Shading analysis at the array center: record horizon elevation every 15° of azimuth; include current and mature vegetation.

Roof structural allowance: PV adds about 2–4 lb/ft² for rack-mounted systems; ballasted systems add significantly more.

Service equipment data to record: busbar rating, main breaker rating, available breaker spaces, voltage, phase, and utility meter location.

Conductor route length = array to inverter + inverter to interconnection; add 10% for bends, terminations, and vertical runs.

Annual irradiance input: use TMY data or a validated local source; report kWh/m²/day and design-day irradiance separately.

STC: 1000 W/m², 25°C cell temperature, AM 1.5; PTC is typically 85–90% of STC.

Cold string voltage: Voc,max = N × Voc,STC × [1 + αVoc × (Tmin − 25)]; keep Voc,max below 600 V residential or 1000/1500 V commercial.

Hot string voltage: Vmp,min = N × Vmp,STC × [1 + αVmp × (Tcell,max − 25)]; keep above inverter minimum MPPT voltage.

Maximum string length: Nmax = floor(Vlimit / Voc,cold); minimum string length: Nmin = ceil(Vmppt,min / Vmp,hot).

DC/AC ratio = array STC kW / inverter AC kW; common range 1.0–1.3; check clipping loss against added yield.

Voltage drop: Vdrop = 2 × L × I × R / 1000 for single-phase DC; target ≤2% DC and ≤3% AC.

Rapid shutdown: NEC 690.12 requires limited voltage at the array boundary; module-level electronics or string-level shutdown may satisfy.

Battery bank energy = usable kWh / DoD; account for round-trip efficiency of 85–95% and C-rate limits.

Conductor ampacity: Isc × 1.25 for continuous PV current, then adjust for temperature, conduit fill, and sunlight exposure.

Module clamps: use only manufacturer-approved clamping zones and torque values; overtorque can crack frames or glass.

Rail cantilever: do not exceed racking manufacturer's maximum cantilever, commonly about one-quarter of the rail span.

Roof penetration: flashed standoff or lag screw into structural member; sealant is a secondary seal, not the primary waterproofing.

Equipment grounding: bond module frames, rails, and inverter enclosure with listed hardware; size EGC per NEC Table 250.122.

Conduit support: EMT every 10 ft and within 3 ft of boxes; PVC every 3 ft; use expansion fittings on long straight runs.

Wire management: use UV-rated, sunlight-resistant conductors and clips; keep wiring off roof surfaces and out of standing water.

Polarity check: measure each string Voc before connecting to inverter; reverse polarity can destroy inverter input stages.

Inverter clearance: maintain manufacturer minimum clearances for airflow; avoid direct sun where derating is likely.

Labeling at installation: apply DC/AC disconnect labels, rapid shutdown labels, and source-circuit identification before energization.

String Voc test: compare measured Voc to temperature-corrected expected value; deviations >5% indicate wiring or module issues.

Insulation resistance: test conductors to ground at 1000 V; acceptable result is generally ≥1 MΩ.

Ground continuity: verify ≤1 Ω from array frame and racking to the grounding electrode.

I-V curve: measure under stable irradiance; compare shape and key points to expected curve for mismatch or diode faults.

Anti-islanding: confirm inverter trips or stops export when grid is disconnected; record trip time and settings.

Rapid shutdown: operate the initiator and verify voltage at the array boundary drops to the required level.

Performance test: record irradiance, module temperature, AC power, and energy; normalize to STC for comparison.

Documentation: collect as-built drawings, serial numbers, test sheets, monitoring login, and warranty registrations.

Performance ratio = actual kWh / (irradiance × array area × module efficiency); use it to compare production over time.

Thermal camera scan under load reveals hotspots from cracked cells, failed bypass diodes, and high-resistance terminations.

Blown string fuse: measure string currents with a clamp meter; reverse polarity or shorted string is a common cause.

Ground fault: isolate positive and negative conductors, test insulation to ground, and repair before re-energizing.

Inverter fault: record fault code, DC voltage, AC voltage, frequency, and temperature; compare to operating window.

I-V curve step or staircase indicates bypass diode activation from shading or cell damage; a depressed curve indicates soiling or mismatch.

Cleaning: use water and soft brush in early morning; avoid abrasives, high pressure, and cleaning hot glass.

Vegetation: maintain the solar window by trimming trees; account for seasonal and mature growth.

PV modules are energized whenever illuminated; DC conductors remain live after AC disconnect and inverter shutdown.

DC arc flash: PV arcs do not self-extinguish; use rated PPE, insulated tools, and avoid opening energized DC circuits.

Fall protection: OSHA trigger is 6 ft for general construction; use guardrails, personal fall arrest, or nets.

Ladder setup: 4:1 slope, extend 3 ft above landing, secure top and bottom; maintain three-point contact.

Lockout/tagout: isolate AC and DC disconnects, verify zero voltage where possible, and tag; module side remains live.

Battery hazards: hydrogen venting, acid exposure, and high short-circuit current; use ventilation, PPE, and non-sparking tools.

Heat stress: schedule work, hydrate, and use buddy checks; roof surfaces can exceed ambient by 30°F or more.

Emergency response: know rapid shutdown location and array boundary; keep access paths clear for firefighters.

NEC 690 governs PV systems; Article 705 covers interconnection to utility sources.

Continuous current: Isc × 1.25 for conductor and overcurrent sizing per NEC 690.8.

120% rule: main breaker + PV breaker ≤ 120% of busbar rating in center-fed panels; otherwise use a line-side or supply-side connection.

Rapid shutdown: NEC 690.12 limits energized conductor voltage at the array boundary for firefighter safety.

DC arc-fault protection: NEC 690.11 requires listed DC AFCI for PV systems above the threshold voltage.

Disconnect requirements: NEC 690.13 and 690.15 require accessible, lockable disconnects for PV and inverter circuits.

Labeling: NEC 690.56 and 705.10 require permanent plaques identifying PV source, disconnects, and maximum voltage/current.

Grounding: NEC 690.41 and 690.43 require system and equipment grounding for systems over 50 V.

Utility interconnection: check state net-metering rules, utility application, and AHJ permit before installation.

Proposal content: system size, estimated annual production, savings assumptions, incentives, warranties, and payback.

Contract essentials: scope, price, schedule, payment milestones, change-order process, and cancellation rights.

Federal ITC: 30% of eligible system cost for qualified installations; verify current tax year rules and eligibility.

Net metering: review tariff for credit rate, cap, true-up, and whether export is compensated at retail or avoided cost.

Permit sequence: AHJ building/electrical permit, utility interconnection application, HOA approval, then installation and inspection.

Change order: written and signed before work changes; document cost, schedule, and scope impacts.

Warranty layers: workmanship 5–10 years, inverter 10–12 years, module performance 25–30 years.

Customer handoff: monitoring access, cleaning guidance, shutdown procedure, warranty contacts, and emergency information.