NABCEP PVIS key terms

Laboratory reference conditions for rating a PV module: 1000 W/m² irradiance, 25°C cell temperature, and an AM 1.5G spectrum. Nameplate power on a module's label is measured here, so real-world output usually differs.

The instantaneous power density of sunlight falling on a surface, expressed in watts per square meter. It drives module current, so a doubling of irradiance roughly doubles output current while voltage changes only slightly.

A measure of how much atmosphere sunlight passes through before reaching a surface, with AM 1.0 at the sun directly overhead. Higher air mass means more scattering and absorption, shifting the spectrum and reducing usable energy.

The irradiance measured in the plane of the modules, accounting for tilt and orientation rather than a horizontal sensor. It is the value that actually drives array production and is used in performance modeling.

The compass direction a module surface faces, usually given in degrees from true north. In the northern hemisphere, true south is optimal for annual yield in most fixed-tilt designs, though utility load profiles may favor other orientations.

The angle between a module's surface and horizontal. It sets how much beam irradiance the array captures seasonally and affects snow shedding and self-cleaning by rain.

The maximum voltage a module or string produces with no load connected, measured in volts. It rises as cell temperature falls, so cold-weather design must use the temperature-corrected Voc to stay within equipment voltage limits.

The current that flows when module terminals are connected through a near-zero resistance, measured in amperes. It scales with irradiance and is used to size conductors and overcurrent protection.

The operating point on a module's current-voltage curve where the product of current and voltage is greatest. Inverters continuously track this point because it shifts with irradiance and temperature.

The ratio of a module's maximum power to the product of its open-circuit voltage and short-circuit current. A high fill factor indicates a sharp, square I-V curve and lower series resistance losses.

The percentage change in module power for each degree Celsius away from 25°C cell temperature. It is typically negative, meaning output falls as cells heat up in the field.

The rate at which open-circuit voltage changes per degree Celsius, usually a negative value per cell. Because voltage climbs in cold conditions, it governs the worst-case maximum string voltage used in design.

The cell temperature a module reaches under defined field-like conditions: 800 W/m² irradiance, 20°C ambient air, and 1 m/s wind. It helps estimate real operating temperatures and derated output.

A diode wired across a group of cells inside a module that provides an alternate path for current when those cells are shaded or faulty. It limits hot-spot heating and preserves string output during partial shade.

A diode placed in series with a module or string to prevent reverse current from flowing back into it, for example from a parallel string or battery at night. It costs a small forward voltage drop during normal operation.

A localized overheated area in a module caused when a shaded or damaged cell is forced to dissipate power produced by neighboring cells. Persistent hot spots can degrade encapsulant and create safety hazards.

A voltage-driven degradation mechanism in which current leaks through the module packaging to the grounded frame, especially at high system voltages. It reduces power output and can often be mitigated by grounding or voltage-limiting strategies.

A series connection of PV modules that adds their voltages while sharing the same current. String length must be set so that cold-weather open-circuit voltage stays below equipment ratings and hot-weather voltage stays above inverter start thresholds.

The highest voltage a module or system component is rated to withstand, commonly 600 V, 1000 V, or 1500 V. Designers must confirm that cold-temperature string voltage never exceeds this rating.

An inverter function that continuously adjusts its operating voltage to keep the array at its maximum power point as irradiance and temperature change. Multiple MPPT inputs allow strings with different orientations to operate independently.

A central inverter that converts DC from one or more parallel strings to AC grid power. It relies on the array's string configuration and MPPT channels to optimize harvest.

A small inverter mounted at each module that converts DC to AC locally. It provides per-module MPPT and reduces the effect of shading, at higher cost and with more rooftop electronics.

A code-required function that reduces conductor voltage at the array to a safe level for firefighters within a specified time after activation. It is typically achieved with module-level electronics or a shunt trip device.

The conductor that connects the grounding electrode system to the service equipment or system grounding point. It provides a low-impedance path to earth for fault current and lightning-related surges.

A conductor that bonds non-current-carrying metal parts such as module frames, racking, and enclosures together and back to the grounding point. It ensures fault current trips protective devices.

An unintended current path from an energized conductor to earth or to grounded metal. PV systems require ground-fault protection that detects the fault and disconnects or isolates the faulted circuit.

A protective circuit in a PV system that senses leakage current to ground and interrupts the faulted circuit. It is a required safety feature for many grounded and ungrounded array configurations.

A switch or device that isolates equipment from its power source for service or emergency. PV systems need clearly labeled DC and AC disconnects accessible to service personnel and first responders.

A safety procedure that physically locks an energy source in the off position and tags it to prevent accidental re-energization during service. It is essential when working on PV circuits that remain energized in daylight.

A dangerous release of energy caused by an electrical arc between conductors or to ground. PV systems can sustain arcs because the array remains energized whenever illuminated, so arc-fault protection and safe work practices are required.

A protective function that detects the signature of a dangerous series arc in DC wiring and interrupts the circuit. It reduces fire risk from loose connections or damaged conductors in PV arrays.

Systems and practices that prevent workers from falling from roofs or elevated structures, such as harnesses, anchors, guardrails, and ladders. OSHA-style requirements apply to residential and commercial rooftop installation.

The period a PV system must operate to generate the energy consumed in manufacturing, transporting, and installing it. It is a sustainability metric, not a financial one, and is typically a few years for modern modules.

The average net present cost of generating one unit of electricity over a system's life, accounting for capital, financing, operations, and production. It allows comparison of PV with other generation sources.

The ratio of a system's actual energy output to the output it would produce at STC irradiance for the same period. It captures temperature, soiling, wiring, and inverter losses and is a standard commissioning and monitoring metric.

Accumulation of dust, pollen, bird droppings, or snow on module glass that blocks irradiance and reduces output. Regular cleaning or tilt-based self-cleaning mitigates the loss, which varies strongly by location.

The process of identifying obstructions that will cast shadows on an array and quantifying their effect on production. Tools include solar pathfinders, software modeling, and site observation at different times of year.

The DC circuit conductors connecting a PV module or string to the next combiner or inverter input. Its ampacity and overcurrent protection must account for continuous current and irradiance-enhanced current.

The manufacturer's labeled power, voltage, and current values for a module or inverter under specified test conditions. Designers apply temperature, soiling, and mismatch derates to translate nameplate values into expected field performance.