Buyer's guide

Circuit breaker types: how to choose between them for LV and MV panels

12 August 2026 14 minute read

This covers low- and medium-voltage circuit breakers used in industrial panels and substations, not domestic consumer units. Choosing between circuit breaker types comes down to two decisions made together — the voltage class the breaker sits at, and the medium it uses to extinguish the switching arc — followed by matching its duty ratings to the fault level it must clear.

What "circuit breaker types" means in this guide

This guide covers low-voltage and medium-voltage breakers as they are specified for industrial panels, switchboards and substations. It does not cover the domestic-scale device: IEC 60898-1 defines a household and similar-installations breaker as rated up to 440 V between phases, up to 125 A, with a rated short-circuit capacity up to 25 kA. If a residential-scale question brought you here, that standard, not this guide, describes the device you are looking at.

A breaker of the kind discussed below is never the whole story. It is one component positioned somewhere along a longer distribution chain, from the utility intake down to the final circuits a plant has to protect. Understanding how breakers sit within a facility's power distribution chain explains why the same voltage class can call for different breaker families depending on where in that chain the breaker sits.

Decision one: what voltage class is the breaker for?

IEC 62271-1 defines "high voltage" as any rated voltage above 1000 V. Within that range, "medium voltage" is the term conventionally applied to the sub-range up to and including 52 kV — a usage convention rather than a separate defined term in the standard itself.

Stating the system voltage is the first filter a buyer applies, before the interrupting medium is even relevant. It already eliminates most of the catalogue.

Decision two: what medium extinguishes the arc?

Once the voltage class is fixed, circuit breakers are classified primarily by the medium used to extinguish the switching arc: air, oil, SF6 gas or vacuum. This is not an academic distinction. The medium drives the maintenance interval, whether the interrupting medium can be topped up or is factory-sealed, and — in SF6's case — an environmental handling obligation that the other three media do not carry.

Air and air-break breakers

Air circuit breakers remain in current use up to about 12 kV, generally as indoor, panel-mounted or draw-out switchgear. They work on the high-resistance principle, which is worth stating as an outcome rather than as a procedure: the arc is not waited out, it is made too expensive to sustain. The supply has a fixed voltage available; the arc chamber raises the voltage the arc demands until the two cross and the arc fails. Steel splitter plates and guide horns are the hardware that gets it there, by stretching the column, dividing it into several shorter arcs in series and drawing heat out of it. That mechanism suits an indoor low- and medium-voltage assembly rather than an outdoor transmission-class one.

It is worth separating this from air-blast breakers, an older and now largely obsolete technology that instead forces high-pressure compressed air through a nozzle onto the arc at the instant of contact separation. Air-blast breakers were used up to around 765 kV, but contemporary new-build high-voltage breaker technology has narrowed mainly to SF6 gas and vacuum.

Oil breakers, bulk and minimum

Two oil-based designs are worth recognising as legacy plant rather than something to newly specify. Bulk-oil, or dead-tank, breakers use oil both to extinguish the arc and to insulate the live parts from the earthed tank; this design is obsolete and phased out of new installations.

Minimum-oil, or live-tank, breakers use oil mainly for arc extinction rather than for insulation to earth. The tank itself is insulated from ground, the phases are separated, and the design was used up to about 72 kV. Like bulk-oil breakers, minimum-oil breakers are being phased out — a buyer is more likely to inherit one in an existing installation than to specify one new.

SF6 gas breakers

SF6 does the insulating and the interrupting at once, which is the reason it displaced oil at transmission voltages. It is a heavy synthetic gas that will not react with the parts it surrounds and does not break down at operating temperature, and its withstand at three atmospheres is in the region of 2.4 times air's — putting it alongside insulating oil — while it quenches an arc well. The catch is that this performance is a function of density, and density falls with pressure and with ambient temperature. Gas breakers are therefore built to sit at six to seven atmospheres, and some designs will refuse to operate below a density threshold rather than attempt an interruption on a weakened gap.

Construction splits into two families. Dead-tank designs put the interrupter inside a grounded enclosure, which makes interrupter maintenance easier at ground level, improves seismic withstand, and allows bushing current transformers for relaying — at the cost of needing more insulating gas. Live-tank designs put the interrupter at line potential, allow modular series interrupters and need less gas, but their higher centre of gravity raises seismic-mounting considerations.

The environmental side is worth stating plainly rather than as a scare line. SF6 has a global warming potential of roughly 24,000 times carbon dioxide over a 100-year horizon and an atmospheric residency exceeding 3,000 years, which is why utilities operating SF6-filled switchgear participate in voluntary emissions-management programmes rather than treating leakage as inconsequential. Under partial-corona discharges, spark discharges, normal switching arcs or abnormal failure arcs, the gas can also decompose into toxic byproducts such as hydrogen fluoride and various sulfur and sulfuryl fluorides. Documented occupational-exposure incidents — technicians exposed during equipment repair or after entering SF6 storage areas — have produced eye, nose, throat and respiratory irritation, and in at least one reported case, temporarily reduced lung capacity. None of this argues against specifying SF6. It argues for maintenance procedures that include gas-handling and detection steps, not electrical isolation alone.

Vacuum breakers

A vacuum interrupter works because there is almost nothing in the gap to ionise. What carries the arc is metal vapour boiled off the contacts themselves, and that vapour has somewhere to go: a shield around the contacts collects it as it condenses, so it is not still in the gap when the voltage returns. The gap is back to full withstand in the order of ten microseconds after current zero, which is quick enough that the arc gets no second attempt. Vacuum is the dominant choice for metal-clad switchgear up to the 36 kV class, and is often called close to maintenance-free — consistent with a sealed interrupter that needs no gas or liquid replenished across its service life.

SF6 against vacuum: the real trade-off at MV

Where both technologies cover the same voltage class, the choice is a genuine trade-off, not a strict hierarchy. They differ in the number of switching operations permitted between servicing, in whether the interrupting medium can be topped up or must be factory-sealed, and in how practically the interrupter's remaining condition can be supervised in service.

This is not a fully settled question even within a single voltage class. A peer-reviewed comparison of 36 kV-class SF6 and vacuum breakers has examined operating characteristics such as opening time, closing time, contact wipe and contact stroke between the two technologies, which is itself evidence that the comparison remains an active subject of applied engineering study rather than a closed question.

Selection table

The table deliberately omits domestic miniature breakers, which are out of scope, and omits current-limiting and solid-state types, which are covered further down as emerging technology rather than an established selection category.

Decision three: what the quotation has to state

For two suppliers' offers to be genuinely comparable, a circuit breaker specification needs to state a defined set of rated characteristics: rated voltage, rated insulation level, rated frequency, rated normal current, rated short-time withstand current, rated short-circuit breaking current, rated short-circuit making current, and rated operating sequence. A lower quoted price with fewer of these stated can hide a breaker rated for a lighter duty than the installation actually needs.

Why withstand and making current are not free choices

Two of those numbers are not independently negotiable. Rated short-time withstand current is set numerically equal to the rated short-circuit breaking current, for a standard-defined duration, and the rated peak withstand current is set equal to the rated short-circuit making current. A buyer does not choose these separately from the breaking and making ratings; they follow from them.

Rated short-circuit breaking current itself has two components: the rms value of the AC component, which is the headline kA figure usually quoted, and a percentage DC component that depends on how much time has elapsed between fault initiation and contact separation. The making rating follows from it at a fixed multiple, 2.5 times or more. The reason is that the hardest duty a breaker has is not opening. It is closing into a circuit where the fault is already present — the contacts meet at the point in the first cycle where current is greatest, and the force trying to blow them apart is at its maximum at exactly the moment the mechanism has to complete its stroke. The making rating is the guarantee that it completes rather than stalls.

At the lower end of the LV range these ratings sit on a thermal-magnetic trip mechanism, which is two sensing elements sharing one housing and answering two different questions. A bimetallic strip bends as sustained overload heats it, and answers whether the load has been too high for too long. A solenoid answers whether the current has just jumped, which is what a short circuit looks like.

What happens after the trip signal is a separate piece of construction, and it exists because one contact pair cannot be good at both jobs. A breaker of this type carries two. The main contacts are silver-plated and shaped for the lowest resistance a closed circuit can be given, so they are the wrong place to draw an arc — and they leave the circuit before one appears. The arcing contacts, made of heat-resistant material, take the current at that moment and carry the arc, which is then pushed into a stack of splitter plates, divided and cooled until it fails. Higher-rated breakers usually use an electronic trip unit instead.

Decision four: what changes when the fault level rises

Two ratings need correction above 1000 m altitude: both the insulation level and the continuous-current capability, because thinner air reduces dielectric withstand and reduces convective cooling of current-carrying parts at the same time.

The transient recovery voltage that appears across a breaker's contacts at the instant of arc extinction has a peak value and a rate of rise that both increase with the breaker's rated system voltage. The first-pole-to-clear factor — how much higher the recovery voltage is on the first pole to clear a three-phase fault than the normal per-phase value — is also higher for an unearthed three-phase fault than for a fault on an effectively earthed-neutral system.

One specific application sits outside the general high-voltage breaker standard entirely. Generator circuit breakers, installed directly between a generator and its step-up transformer, are covered by IEEE C37.013, because the fault-current and recovery-voltage duty at that location differs from a typical feeder or transmission-line position.

As fault level rises, it is the short-time withstand current — thermal stability over a standard-defined 1 s or 3 s duration — that has to keep pace. This is also where the assembly-level rating and the individual breaker's own ratings part company. IEC 61439-1, Clause 10 governs how a whole low-voltage assembly's design is verified, including how rated short-time withstand current is verified at the assembly level, which is a distinct exercise from the individual breaker's own figures.

Worked example: sizing breaking capacity from a transformer fault

Take a 2,000 kVA, 11 kV/415 V distribution transformer with 6% impedance. The three figures are chosen here purely to illustrate the arithmetic.

Step 1 — secondary full-load current.

2,000,000 VA ÷ (√3 × 415 V) ≈ 2,782 A

Step 2 — prospective symmetrical fault current at the secondary terminals, ignoring source and cable impedance for a first-pass, worst-case figure:

2,782 A ÷ 0.06 ≈ 46,367 A, call it 46.4 kA

Step 3 — apply the making-current rule from the ratings discussion above: rated making current must be at least 2.5 times the AC rms breaking current.

2.5 × 46.4 kA ≈ 116 kA peak

Step 4 — selection consequence. The breaker's rated short-circuit breaking current must be at least 46.4 kA rms, its rated short-time withstand current must be defined for that same 46.4 kA over the standard's 1 s or 3 s duration, and its rated making current must clear approximately 116 kA peak.

This mirrors, without reproducing, a recognised method rather than an ad hoc calculation. The simplified method set out in IEEE Std C37.010-1999 is the generally recommended way to turn a network fault-current study into a required breaker rating. That fuller method also requires checking both a three-phase ungrounded fault and a phase-to-ground fault, with the more severe of the two governing the selection — for a phase-to-ground fault, the required symmetrical interrupting capability is taken as 15% higher than the calculated fault current to allow margin. The figures worked through above are the illustrative three-phase case only, not a substitute for that fuller study on a real installation.

Coordinating clearing time: arc-flash energy and grid-code duty

Arc-flash incident energy tends to depend mainly on fault-current magnitude, fault-clearing time and working distance, rather than on system voltage alone — a faster clearing time lowers incident energy even at the same fault level. That is the practical reason breaking-capacity and short-time-withstand ratings need to be coordinated tightly with upstream protection settings, not treated as independent numbers picked off a datasheet.

At the transmission level, grid codes tend to specify circuit-breaker fault-clearing duty explicitly as part of substation connection requirements, coordinating the breaker's own interrupting time against the protection relay's operating time rather than leaving the split unspecified. Specific numeric clearing-time figures could not be independently verified from the primary grid-code document for this guide, so this is stated as a general coordination principle rather than a quoted number.

What a comparable quotation must state

Pulled together, a buyer can carry the following into an enquiry:

• Rated voltage
• Rated insulation level
• Rated frequency
• Rated normal (continuous) current
• Rated short-time withstand current
• Rated short-circuit breaking current
• Rated short-circuit making current
• Rated operating sequence (duty cycle)

One more thing worth checking: standard values of rated normal current and rated short-circuit breaking current are not chosen freely. They are drawn from a coordinated table of preferred value combinations set out in the applicable standard, which means a quoted breaker's current and breaking-capacity pairing can be checked against that table rather than taken on trust. A pairing that looks unusual is worth querying, not assuming.

Where the technology is still moving

A few developments are worth flagging, all at lower confidence than the material above. SF6-free alternatives — vacuum, and gas mixtures based on natural-origin gases with fluoronitrile or fluoroketone additives — are being extended toward higher voltage classes, with SF6-free switchgear reported at ratings up to roughly 170 kV.

Fully solid-state and hybrid circuit interruption is a separate, active area of ongoing research, distinct from the classical air, oil, SF6 and vacuum taxonomy above, and to date concentrated mainly on DC rather than AC industrial distribution.

Even inside the established taxonomy, the underlying physics is not a closed subject. Arc behaviour inside a low-voltage circuit breaker — from ignition at the separating contacts through to current limitation in the splitter-plate arc chute — remains an active subject of peer-reviewed plasma-physics research, because the macroscopic ratings a buyer works from describe the outcome of a physically complex process rather than a simple threshold effect.

Questions buyers ask

What is the difference between an air-break and an air-blast circuit breaker?

Air-break breakers interrupt by lengthening and cooling the arc until its resistance rises too high for the supply voltage to sustain it, and are used indoors up to about 12 kV. Air-blast breakers instead force compressed air through a nozzle onto the arc and were used up to about 765 kV; the technology is now largely obsolete.

Why are SF6 breakers still specified given the environmental concerns?

SF6 gives high dielectric strength and reliable arc-quenching up to very high voltages, which is why it remains dominant at the top of the voltage range. Utilities manage the gas's high global-warming potential through voluntary emissions programmes and leak and decomposition-byproduct monitoring rather than avoiding it outright.

What is the difference between rated breaking current and rated making current?

Breaking current is what the breaker can safely interrupt, expressed as an rms AC component plus a percentage DC component. Making current is what it can safely close onto, and must be at least 2.5 times the AC breaking-current value, because closing can happen into a circuit where the fault is already present.

When does a project need a generator circuit breaker?

When the breaker sits directly between a generator and its step-up transformer, at 15.8 kV and above with continuous current of 6.3 kA or more. That position carries different fault-current and transient-recovery-voltage duty than a typical feeder, so it is covered by IEEE C37.013 rather than the general high-voltage breaker standard.

What must a quotation state for two offers to be comparable?

Rated voltage, insulation level, frequency, normal current, short-time withstand current, short-circuit breaking current, short-circuit making current and rated operating sequence. Without all of these stated together, a lower quoted price can hide a breaker rated for a lighter duty than the installation actually needs.