Wind power & hydrogen (electrolysis)

Initial symmetrical short-circuit current at the fault point (IEC 60909-0): the rms current the network drives into a bolted three-phase fault, with the voltage source replaced by the c·Un/√3 equivalent.

Why it matters: It is the number every device rating is compared with — Icw, breaking capacity and the cable thermal check all read against Ik. Under-estimate Ik and the panel you quote will be destroyed on the first fault; over-estimate it and the client pays for switchgear he does not need.

Single-phase-to-earth short-circuit current (IEC 60909-0), calculated from the zero-sequence impedance Z0 in addition to Z1 and Z2.

Why it matters: It sizes the earth-fault protection and the rated withstand of the neutral / earthing path. Depending on the transformer vector group and the earthing arrangement Ik1 can be smaller or larger than the three-phase Ik, so it must never be assumed equal to it.

Peak short-circuit current ip = κ·√2·I″k (IEC 60909-0): the highest instantaneous value of the fault current, reached about half a cycle after inception.

Why it matters: It is the number that generates the electrodynamic force on busbars, cable cleats and device terminals. Compare it with the rated peak withstand Ipk — quoting only Ik leaves the mechanical strength of the switchboard unchecked.

Rated short-time withstand current: the rms current a switchgear assembly can carry for a stated short time (commonly 1 s or 3 s) without damage (IEC 61439-1 / IEC 62271-1).

Why it matters: It is the acceptance criterion for the panel: the design rule is Icw ≥ Ik at the same point. A panel offered with Icw below the calculated Ik simply cannot be used, whatever the price.

Rated peak withstand current: the peak current the assembly and its busbars withstand without deformation (IEC 61439-1). The standard relates Ipk to Icw by a multiplier that depends on the rated short-time current — use the value from the standard table, not a guess.

Why it matters: It is the dynamic counterpart of Icw and must be ≥ ip. Because the two are quoted together and are easy to confuse, a quotation that gives only one of them is incomplete.

Two different withstand ratings of the same switchboard. Icw is a THERMAL rating: the rms current the assembly carries for 1 s (or 3 s) without overheating. Ipk is a MECHANICAL rating: the peak current the busbars and supports survive without being bent apart.

Why it matters: They are compared with two different calculated quantities — Icw against Ik, Ipk against ip. Comparing Icw with ip (or Ipk with Ik) is a frequent and expensive mistake: it either over-sizes the board or leaves it under-rated.

Peak factor κ = ip / (√2·I″k): the ratio of the first peak to the rms value, calculated in IEC 60909-0 from the R/X ratio of the equivalent impedance.

Why it matters: It is what converts a short-circuit current into a mechanical force. An inductive network (LV cables, transformers) pushes κ towards 2.0 and raises the peak force, which is why ip cannot be derived from Ik alone.

Ratio of the equivalent reactance to the equivalent resistance seen from the fault point (IEC 60909-0).

Why it matters: It fixes two things at once: the peak factor κ (hence ip) and the decay rate of the DC component. A high X/R (inductive LV feeds, generator sources) gives both a higher peak and a longer DC transient, which the breaker must interrupt.

Short-circuit apparent power of the upstream network at the connection point, Ssc = √3·Un·I″k, or the equivalent source impedance behind it.

Why it matters: It is the single input that says how "stiff" the grid is. Without it no fault-current figure can be computed, so it must be requested from the utility (or taken from a stated assumption) before any switchgear can be quoted.

Voltage factor c for short-circuit calculation (IEC 60909-0 Table 1): the ratio between the voltage assumed at the fault location and the nominal voltage — c > 1 for maximum currents, c < 1 for minimum currents (for LV: 1.05 / 0.95; for HV: 1.10 / 1.00).

Why it matters: It is the explicit safety margin of the calculation. The maximum-current factor drives the device ratings you quote; the minimum-current factor drives protection sensitivity. Using the wrong one shifts Ik by several percent in a way that is invisible in the report unless the factor is printed.

Aperiodic (DC) component of the short-circuit current, i_dc = √2·I″k·e^(−ωt·R/X) (IEC 60909-0): the decaying offset that rides on top of the symmetrical component.

Why it matters: It is the extra current the breaker has contact to interrupt at the moment of contact parting, and it is why the required breaking capacity is higher than I″k for fast (generator-close) faults. In a quotation it appears as the rated breaking capacity at that % DC component.

Protection clearing time: the total time from fault inception to arc extinction — relay detection + intentional delay + breaker operating time.

Why it matters: In an arc-flash study the incident energy is almost proportional to the clearing time, and the PPE category is selected from it. Halving the clearing time usually halves the energy and can drop the required PPE by one step — which is a direct operating-cost item.

Zone selective interlocking: overcurrent relays in adjacent protection zones exchange a blocking / pilot signal, so a fault inside their own zone trips instantly while a downstream fault is left to the downstream device (IEC 60255 relay functions).

Why it matters: It buys back the time delay that selectivity normally costs: faults are cleared faster, the arc duration shortens and the incident energy drops. Because it changes the relay wiring and the communication scheme, it must be declared in the specification and priced.

Time multiplier setting of an overcurrent relay: the scale factor applied to the standard inverse-time characteristic defined in IEC 60255-151, moving the whole curve up or down in time.

Why it matters: It is the single number that positions each relay curve on the time axis during grading. Raising the TMS up the chain buys selectivity but lengthens fault duration — and therefore the arc energy the site has to survive.

Grading (coordination) time interval Δt: the intentional time difference between two cascaded overcurrent devices so that the downstream device alone clears the fault. Standard practice is of the order of 0.2–0.4 s depending on relay and breaker type — an engineering practice, not a standard-mandated figure, so the value used must be stated in the study.

Why it matters: Too small and both devices trip (loss of selectivity, the whole plant goes down on one branch fault); too large and every fault lasts longer, raising the arc-flash energy and the PPE requirement. It is a trade-off the report must show explicitly.

Short-circuit impedance voltage of a transformer: the primary voltage, in percent of rated voltage, that drives rated current through the short-circuited secondary winding (IEC 60076-1).

Why it matters: It fixes the LV fault level (approximately I″k ≈ In / uk) and at the same time the voltage drop under load. This is a real quotation trade-off: a larger uk lowers the fault level (cheaper switchgear downstream) but increases voltage drop and losses. Always quote uk together with the transformer rating.

No-load loss of a transformer: the power absorbed at rated voltage and rated frequency with the secondary winding open (IEC 60076-1). It is essentially the core (hysteresis + eddy) loss.

Why it matters: It runs continuously — about 8 760 h a year — so it dominates the lifetime energy bill. Tenders commonly capitalise it at a $/W figure, which means a lower P0 can justify a higher purchase price.

Load loss (short-circuit loss) of a transformer: the power absorbed at rated current with the secondary short-circuited, corrected to the reference temperature (IEC 60076-1). It includes the I²R loss plus stray and winding eddy losses.

Why it matters: It grows with the square of the load and is the basis of efficiency guarantees and of any loss-capitalisation clause. Pk and uk% come from the same test, so a datasheet giving one without the other is incomplete.

Ingress protection code (IEC 60529): the first digit is protection against solid objects and dust, the second against water (for example IP54 = dust protected, splash-proof).

Why it matters: It is an environment requirement, not an electrical one. An enclosure offered as IP23 fails in a washdown or outdoor installation, and the degree of protection drives the enclosure cost — so IP must be specified together with the electrical ratings.

Highest voltage for equipment Um: the maximum rms line-to-line voltage at which the equipment may be operated (IEC 60071-1).

Why it matters: Um anchors the whole insulation-coordination table: it decides which lightning-impulse and power-frequency withstand values are required. Buying equipment with too low an Um is not a saving, it is a non-conforming offer.

Lightning impulse withstand voltage: the peak of the standard 1.2/50 µs impulse wave that the insulation must withstand without breakdown (IEC 60071-1).

Why it matters: It is a named specification and type-test item for switchgear, transformers and bushings. It is one of the first parameters a cheap offer silently reduces, so it must appear explicitly in the datasheet you compare.

Power-frequency withstand voltage: the rms voltage the insulation withstands for the standard short-duration (1 min) test, and in the HV range also the switching-impulse withstand level (IEC 60071-1).

Why it matters: It is the routine test level used at the factory gate. Together with LI it defines the insulation level of the equipment being quoted — comparing two offers without these two numbers is comparing nothing.

Transformer vector group: the winding connections of the two sides plus the phase displacement between them, for example Dyn11 = delta HV, star LV with neutral brought out, 11 × 30° displacement (IEC 60076-1 connection symbols).

Why it matters: It decides the phase shift, whether a neutral is available for earth-fault protection, and where zero-sequence current can flow — the same kVA transformer with YNyn0 instead of Dyn11 gives a different single-phase fault current and needs a different protection scheme.

Total harmonic distortion: the rms value of all harmonic components divided by the fundamental, expressed in percent (measurement definitions in IEC 61000-4-7).

Why it matters: It is the headline power-quality number in a connection agreement, but "THD" alone is ambiguous: the voltage and current limits are different and are checked at different places. Always state whether THDv or THDi is meant, and where it was measured.

Voltage total harmonic distortion THDu = √(Σ Uh²) / U1 × 100 %, measured as required by IEC 61000-4-7.

Why it matters: It is the quantity a grid code or a utility limits at the point of common coupling (for reference: IEEE 519 sets 5 % THDv at the PCC, IEC 61000-2-2 gives 8 % for LV class 2). Exceeding it means filters, detuned banks or a larger transformer — a cost that appears only if the study is done before the order.

Current total harmonic distortion THDi = √(Σ Ih²) / I1 × 100 %: the harmonic content of the load current relative to its fundamental.

Why it matters: It is what sizes harmonic filters and detuning reactors and what drives cable and transformer derating. IEEE 519 limits it as a function of the ratio between the short-circuit current and the load current — so THDi is meaningless for a quotation unless the fault level is quoted with it.

Power factor cos φ: the ratio of active power to apparent power (displacement factor between voltage and current), with the distortion factor included when the current is distorted.

Why it matters: It sets the kVA that the transformer, generator or supply contract must provide for a given kW, and it is contractual: a low power factor triggers penalty charges or a mandatory compensation bank. It is therefore both a design input and a line in the price.

Reactive compensation rating Qc: the output of the capacitor bank, sized as Qc = P × (tan φ1 − tan φ2) to move the installation from its present to its target power factor.

Why it matters: It is the item being quoted, and its usable output drops in a harmonic-rich network unless a detuned (reactor-protected) bank is used. The target power factor is a customer input, not a default — quoting a bank without stating the target pf is not a complete offer.

Point of common coupling (PCC): the interface in the network where the customer installation and the utility network are coupled, and therefore where the connection conditions apply.

Why it matters: It defines what the utility may complain about and what you must prove: voltage band, harmonic distortion, flicker and voltage-dip behaviour are all specified at the PCC, not at the equipment terminals. Studies or measurements made somewhere else do not demonstrate compliance.

Per-unit bus voltage in a load-flow result: the node voltage divided by its base voltage, so 1.00 pu is nominal.

Why it matters: It is the acceptance number of every voltage-drop check (commonly 0.95–1.05 pu). A node below the band means equipment malfunction and a grid-code breach, and the answer is a larger cable, a different transformer tap or a compensation device — a quotation change, not a note.

Low-voltage ride-through: the duty (and the capability) of a generator or inverter to remain connected while the voltage at the PCC dips along a specified voltage-versus-time profile, instead of tripping off.

Why it matters: It is a grid-connection condition in most markets: a plant that cannot ride through the required curve cannot be connected or must be retrofitted. Confirm the required LVRT curve before sizing the inverters, because it decides the hardware class.

Maximum loadability factor λmax of the continuation power flow: the multiplier applied to all loads at the nose point of the PV curve, the point where the voltage collapses.

Why it matters: It is the loading margin of the design: λmax = 1.35 means the network only collapses at 135 % of today load. Planners require a minimum margin (the number differs between grid codes — state the criterion used), and it decides whether a line reinforcement or more reactive compensation has to be quoted.

State of charge of a battery or BESS: the remaining energy as a percentage of the rated (or usable) capacity.

Why it matters: It bounds what the storage can deliver at any instant, so it drives the protection settings, the dispatch strategy and the delivered-energy guarantee. A quoted availability figure is meaningless unless the SOC window it assumes is stated.

Depth of discharge: the complement of the state of charge — how much of the capacity is cycled out, normally quoted as a maximum in cycle-life specifications.

Why it matters: It is the trade between usable capacity and battery life: the same nominal kWh quoted at 80 % DOD delivers fewer cycles than one quoted at 60 %. Because it changes both the usable kWh and the replacement date, the DOD must be on the datasheet next to the price.

Round-trip efficiency of a storage system: the energy returned during discharge divided by the energy absorbed during charge over a complete cycle.

Why it matters: It decides how much of the energy you pay for actually comes back out, and therefore the real cost per delivered kWh. Watch the boundary of the figure (DC-DC looks much better than AC-AC) — comparing two offers on different boundaries is a common source of wrong quotations.

Capacity factor: the energy actually produced over a period divided by the energy the plant would have produced running at its rated power for the whole period (for PV this is dominated by irradiance and temperature, not by the inverter).

Why it matters: It is the number that converts a nameplate kWp into annual kWh, and therefore into revenue and payback. A quotation that gives only the kWp figure does not say what the plant will actually deliver — ask for the assumed capacity factor.

Arc-flash boundary: the distance from a prospective arc at which the incident energy falls to 1.2 cal/cm², the level at which arc-rated PPE becomes necessary (IEEE 1584-2018 / NFPA 70E).

Why it matters: It defines the barricade and the approach boundary on site: a larger AFB means more barricading and heavier PPE for the same work. It is a safety deliverable that also has a direct operating cost.

Arcing current: the rms current that actually flows in the arc, predicted from the bolted-fault current by the IEEE 1584-2018 model using electrode configuration, gap and enclosure factors.

Why it matters: Everything in an arc-flash study — incident energy, boundary, PPE category — is driven by Iarc, not by Ik. Iarc is markedly lower than the bolted-fault current, so substituting Ik for it grossly over-estimates the energy and the required PPE.

Bolted-fault current Ibf: the three-phase short-circuit current at the equipment location, taken as the input current of the IEEE 1584-2018 arc-flash model.

Why it matters: It is where the arc-flash study starts, so it must be produced with the same voltage, transformer and cable assumptions as the short-circuit report. A mismatch between the two documents is one of the most common audit findings.

Incident energy: the thermal energy per unit area that would reach a surface at the working distance during an arc, as defined by IEEE 1584-2018.

Why it matters: It is the number that selects the PPE (NFPA 70E thresholds at 1.2 / 4 / 8 / 25 / 40 cal/cm²) and that must be printed on the equipment label. An under-estimated incident energy is a safety liability, not a commercial rounding difference.

Personal protective equipment category: the arc-rated clothing and equipment class required for a task, selected from the calculated incident energy according to NFPA 70E-2021.

Why it matters: It is a safety and legal deliverable: the category decides what the field team must wear, what the work permit says and whether work needs de-energisation. It follows directly from the arc-flash calculation, so it must be reproducible for the assumed upstream fault level.

Per-unit value: a quantity expressed as a fraction of a chosen base value (1.00 pu = nominal voltage or rated power), the standard language of power-system studies.

Why it matters: It lets a 0.4 kV LV board and a 110 kV network be compared on one axis and one chart. Voltage 0.95–1.05 pu is the usual acceptance band, so any per-unit figure in a report can be read directly against the criterion.

N-1 (single-contingency) criterion: the network must remain within its operating limits with any one single element (line, transformer, generator) out of service.

Why it matters: It decides how much redundancy — parallel feeders, duplicated transformers, busbar sections — goes into the quotation. If it is not stated explicitly, the design tends to be single-radial and the customer finds out during commissioning.

Loading: the current (or power) carried by a branch expressed as a percentage of its rated capacity.

Why it matters: It is the acceptance number for cables and transformers. Above 100 % the element will trip or have to be derated, and the margin left at the design case is exactly what the customer is paying for — so it must be shown with the assumption (load factor, ambient temperature) that produced it.

Voltage unbalance: how far a three-phase voltage set departs from symmetry, expressed as the ratio of the negative-sequence (or zero-sequence) component to the positive-sequence component.

Why it matters: Motors and converters derate and overheat on unbalanced supply — limits are set by standard or by the machine vendor (for reference: IEC 61000-2-2 gives 2 % for LV networks), so the applicable limit must be named. Reducing it usually means redistributing single-phase loads or resizing the neutral.

Simple payback period: the capital cost divided by the annual net saving, without discounting or price escalation (a screening figure, not a financial model).

Why it matters: It is the number that decides whether the customer buys now. Because it is a simple ratio, the two inputs that drive it (energy price and unit capex) must be shown next to it — otherwise nobody can tell which assumption the figure stands on.