Quick answer
Harmonics are AC waveform components at whole-number multiples of the fundamental frequency; power quality also covers voltage and other supply disturbances, assessed with defined metrics and connection requirements.
Answer: Harmonics are waveform components at whole-number multiples of an AC system’s fundamental frequency. Power quality also includes voltage changes, flicker and other supply disturbances. For solar projects, evaluate voltage and current separately, identify the measurement point and operating conditions, and compare the correct metric with the applicable connection requirements. An inverter datasheet percentage alone does not establish whole-site compliance.
What are harmonics in a solar electrical system?
A distorted periodic waveform can be described as a fundamental component plus higher-frequency components. On a 50 Hz system, the third harmonic is 150 Hz and the fifth is 250 Hz; on a 60 Hz system, they are 180 Hz and 300 Hz. Nonlinear loads and power converters can contribute to distortion. Harmonic current passing through network impedance can produce voltage distortion, as explained in Schneider Electric’s harmonic definitions.
Solar inverters use switching and control circuits to convert DC into AC, with filtering to shape the output. The resulting harmonic spectrum depends on the equipment, operating point and connected network. Existing drives, chargers and other loads must also be considered; a distorted waveform measured after PV installation does not by itself establish that PV caused it.
Power quality is a wider subject. A voltage sag, voltage rise, flicker event or frequency excursion needs its own measurement and explanation. Harmonics are one part of that investigation, rather than a catch-all diagnosis.
THD, TDD and power factor: keep the denominators visible
| Metric | What to record | Important distinction |
|---|---|---|
| Voltage THD | Harmonic voltage RMS relative to fundamental voltage RMS, by phase and voltage connection | Different from current THD |
| Current THD | Harmonic current RMS relative to the fundamental current RMS at that operating point | A small denominator can produce a large percentage |
| Total demand distortion (TDD) | Harmonic current relative to the specified demand-current reference | Record how the demand reference was established |
| Individual harmonics | Magnitude and order, with the specified reference | A combined percentage hides the spectrum |
| True power factor | Active power divided by apparent power | Not the same as fundamental displacement power factor |
For the fundamental-referenced definition:
THD (%) = 100 × sqrt(sum of squared harmonic RMS components) / fundamental RMS component
Apply the expression to voltage or current consistently. Record the harmonic range and instrument method. Schneider’s PM5100 TDD documentation explains why high current THD during low demand can have a different interpretation from the same percentage at full demand.
Hypothetical measurement example: assume only two nonzero measured harmonic-current components, 3 A and 4 A RMS. Their combined harmonic RMS is 5 A. With a fundamental current of 100 A, current THD is 5%; with 20 A fundamental current and the same components, it is 25%. If the explicitly chosen demand-current reference is 100 A, TDD remains 5% in both examples. These are calculations, not pass/fail results or a real site record.
A power-factor measurement also needs its definition. Schneider distinguishes true and displacement power factor: correcting the fundamental voltage/current phase relationship does not automatically remove waveform distortion.
Which harmonic limit applies?
IEEE 519-2022’s published scope addresses steady-state waveform distortion at the point of common coupling (PCC). It does not justify one universal “below 5% THD” rule for every voltage, every current measurement and every PV inverter.
Before interpreting a result, obtain the utility or network operator’s actual requirements and the applicable standard edition. Ask the project’s electrical reviewer to identify:
- The PCC or other required assessment point, and who defines it.
- Whether the requirement concerns the installation or a particular device’s test conditions.
- Voltage distortion, current distortion, individual harmonics, DC injection and other separately specified criteria.
- The normalization reference, relevant network data and measurement/aggregation periods.
- Required evidence, acceptance process and responsible reviewer.
The IEC 61000 family covers multiple electromagnetic-compatibility topics and scopes. Naming the family alone is not evidence that a specific installation meets a particular requirement. Follow the actual grid-code and connection documents for the project.
Investigating a concern without assuming the cause
Keep the original spectrum, timestamps and operating records with the report. A useful assessment compares documented states: existing loads with PV disconnected through an authorized procedure, low and high PV output, and relevant combinations of drives, chargers or capacitor banks. Measurement and switching belong to qualified personnel using the approved safety plan; this glossary is not a procedure for accessing energized equipment.
Record the measurement location, phase, instrument configuration, load/PV output, topology and any recent equipment changes. Do not add individual devices’ THD percentages together: harmonic phase relationships and the changing fundamental current affect the combined waveform.
Where analysis identifies a problem, potential remedies include equipment/settings changes or properly engineered passive or active filtering. Resonance and interactions with capacitor banks require project-specific assessment. Phase balancing, an inverter marketed as “smart,” or adding a filter is not an automatic harmonic cure. Nor does reactive-power support establish active harmonic filtering capability.
Guidance for designers, installers and sales teams
Designers: request relevant network information, compare exact inverter documentation and test conditions, and identify where a specialist study is needed. Do not impose a blanket transformer K-factor, short-circuit-ratio cutoff or filter selection from system size alone.
Installers and commissioning teams: preserve the approved measurement plan and document deviations. Report unexplained distortion or equipment symptoms for investigation rather than changing protection or control settings to suppress an alarm.
Sales teams: explain what the assessment actually covers. Avoid promising power-factor-penalty savings, longer equipment life or a percentage reduction in distortion without the site study, equipment capability and tariff evidence.
For a product evaluation, discuss the project workflow with SurgePV and ask which outputs are supported. Keep power-quality studies and connection approval explicitly assigned to their responsible specialists.
Frequently asked questions
Are inverter harmonics always the cause of poor power quality?
No. Existing loads, network conditions and other equipment can contribute. Compare measurements and operating states before attributing a problem to a PV inverter.
Is 5% THD always an acceptable limit?
No. Confirm whether the criterion is voltage THD, current THD, TDD or an individual harmonic, along with its reference, location and applicable connection requirements.
Does improving displacement power factor remove harmonics?
No. Fundamental phase displacement and harmonic distortion are different. True power factor reflects the complete waveform; compensation and filtering require separate evaluation.
Can harmonic percentages from several inverters be added?
No. Percentages have denominators, and harmonic components have phase relationships. Use a properly defined aggregate measurement or study rather than adding datasheet percentages.
Related Glossary Terms
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