Neutral Grounding Resistor (NGR) Sizing

A US Engineering Guide to IEEE, ANSI, and NEC Practice

Power Systems Design  |  Technical Guide, FAQ and Case Studies  |  August 2026

NGR sizing looks like a one-line calculation. Divide line-to-neutral voltage by the ground-fault current you want, and you have your resistance. That formula is correct, and it is also about 15% of the actual engineering.

The other 85% is everything the formula does not tell you: whether your target current is defensible in the first place, whether the resistor must survive ten seconds or ten years, whether your relaying can actually see the current you selected, and whether the NEC will let you build it at all.



This guide works through the full sizing process on US voltage classes with US governing standards — IEEE C57.32, IEEE 3003.1, IEEE C62.92, and NEC Article 250 — with two complete worked examples: a 13.8 kV low-resistance grounded industrial bus and a 480 V high-resistance grounded system. It closes with a detailed FAQ and three anonymized case studies.

1.  What an NGR actually does

A neutral grounding resistor sits between a wye-connected source neutral — transformer secondary or generator — and ground. During a line-to-ground fault, it is the dominant impedance in the zero-sequence path, so it, not the system, decides how much ground-fault current flows.

Every benefit an NGR delivers traces back to that single fact:

That last row is the one most often skipped, and it is the one that determines whether the design works in service. An NGR does not merely limit current — it manufactures a predictable current that protection engineers can build a coordination scheme around. Get the value wrong in either direction and the resistor still limits current beautifully while the relays either never see the fault or trip on load unbalance.

The grounding spectrum

US practice recognizes a continuum, not a binary. Per IEEE Std C62.92.2-2017, in order of increasing available ground-fault current:

1. Resonant grounded (ground-fault neutralizer / Petersen coil) — rare in US industrial work
2. Ungrounded — no intentional connection; capacitively coupled
3. High-resistance grounded (HRG) — typically ≤ 10 A
4. Low-resistance grounded (LRG) — 100 A to 1000 A, 400 A typical
5. Low-inductance grounded
6. Effectively grounded (solid) — X₀/X₁ ≤ 3 and R₀/X₁ < 1

The 100–1000 A LRG range and the 400 A typical value are not folklore; they are stated in IEEE Std 142-2007 §1.4.3.2 and carried forward into IEEE Std 3003.1-2019.

2.  The formulas — and what the notation actually means

Basic sizing

R  =  V(L-N) / Ig        where  V(L-N)  =  V(L-L) / √3

Combined:   R  =  V(L-L) / ( √3 × Ig )

Two things to be careful about. First, use the maximum system voltage, not the nominal, if your utility or generator regulation can push the bus above nameplate — the resistor sees whatever the neutral shift actually is. Second, The ground-fault current that results is not exactly your target, because detailed short circuit analysis may be required when impedance effects become significant. At LRG levels the error is small; at HRG levels it is negligible. At low resistance values approaching solidly grounded, it stops being negligible and you need the full symmetrical-component calculation.

The charging-current constraint (HRG only)

This is the constraint most people get backwards, and it is the one that decides whether HRG is even feasible on your system. IEEE Std 142-2007 §1.4.3.1, repeated verbatim in IEEE 3003.1-2019:

"The value of the resistor is selected to limit the current, I_R, to a magnitude equal to or slightly greater than the total capacitance charging current, 3I_C0."

Ir  ≥  3 Ic0. The notation matters. Ic0 is the per-phase zero-sequence capacitive charging current. 3Ic0 is the system total. Writing "Ir ≥ Ic0" is only correct if you have quietly redefined Ic0 as the total, which contradicts IEEE usage and will confuse whoever reviews your calculation. Use 3Ic0 and state the definition.

Why the constraint exists: if the resistive component of ground-fault current does not at least equal the capacitive component, the arc at the fault can restrike and pump energy into the system L-C circuit. The resistor exists to damp that. Undersize it — meaning too high a resistance, too little current — and you have built an expensive ungrounded system.

Estimating 3Ic0. You sum contributions from every capacitive element. Typical screening values:

A cruder rule of thumb: 0.5 A per 1000 kVA at 600 V and below, 1.0 A per 1000 kVA above 1000 V. Use it for feasibility screening, not for a final specification — the cable footage drives everything, and two plants with identical transformer capacity can differ by an order of magnitude in charging current.



Measure it if you can. On a retrofit, the reliable method is a staged single-phase-to-ground connection through a known resistance with the system energized and unloaded, or a direct capacitance measurement. Estimated charging current has a wide error band, and HRG sizing has no margin to spare on the low side.

3.  Worked Example A — 13.8 kV low-resistance grounded industrial bus

Design intent: a 13.8 kV switchgear lineup feeding MV motors and unit substations in a process plant. Ground faults must be cleared quickly and selectively; running through a ground fault is not desired or permitted by the process.

Step 1 — Line-to-neutral voltage

V(L-N)  =  13,800 / √3  =  7,967 V

Step 2 — Select the target ground-fault current

400 A. This is the IEEE-stated typical value for LRG, and on a system with several thousand feet of 13.8 kV shielded cable it comfortably exceeds 3Ic0 (which will be on the order of 3–8 A here), so the resonance constraint is satisfied by an enormous margin. The binding constraint at LRG is not charging current — it is relay sensitivity and equipment damage.

Step 3 — Resistance

R  =  7,967 / 400  =  19.9 Ω   →   specify 20 Ω. At 20 Ω the initial ground-fault current is 7,967 / 20 = 398 A, which is fine.

Step 4 — Time rating

10 seconds. Ground faults on this bus are cleared by 51G in well under 1 second, and 10 s is the standard short-time rating that gives comfortable margin over breaker failure timing.

Step 5 — Thermal check

P(initial)  =  I²R  =  400² × 20  =  3,200,000 W  =  3.2 MW



Now read that number carefully, because this is where the widely circulated version of this calculation goes off the rails. 3.2 MW is not a rating. It is the instantaneous dissipation at t = 0, and it decays as the resistor heats and its resistance rises. A 400 A / 10 s unit can be down to roughly 250 A by the end of its rated 10 seconds. You will not find "3.2 MW" on any manufacturer data sheet, and you should not put it in a specification.

What actually goes on the nameplate:

Step 6 — Protection

• 51G on a dedicated CT in the NGR neutral connection. Pickup at roughly 10% of 400 A, coordinated with downstream feeder ground relays.
• 50G / 51G on feeders using core-balance (window) CTs, which give far better sensitivity than residual connection at these current levels.
• NGR continuity monitoring. An open NGR converts an LRG system into an ungrounded system silently, with no alarm and no operational symptom until the first ground fault produces overvoltages the system was never insulated for. Continuity monitoring is inexpensive and it is the single highest-value accessory on an LRG installation.
  

4.  Worked Example B — 480 V high-resistance grounded system

Design intent: a 480 V distribution system serving critical process and IT load. A single ground fault must alarm, not trip. Operations locate and clear it during the next planned window.

Step 1 — Line-to-neutral voltage



V(L-N)  =  480 / √3  =  277 V

Step 2 — Estimate total charging current, 3Ic0

Step 3 — Select Ir

Ir must be ≥ 3Ic0 = 2.5 A. Select 5 A — roughly 2× the estimated charging current, which covers estimation error and future cable additions without pushing the fault current high enough to cause meaningful damage at the fault point.

Step 4 — Resistance

R  =  277 / 5  =  55.4 Ω   →   specify 55 Ω  (Ir = 5.0 A)

Step 5 — Time rating: CONTINUOUS

This is the critical difference from Example A, and it is where the popular version of this calculation is simply wrong. HRG exists so the system can keep running with a ground fault on it while operations locate the fault. The resistor must therefore carry its full rated current indefinitely. IEEE C57.32 continuous duty limits temperature rise to 385 °C over 30 °C ambient, versus 760 °C for short-time ratings — a different resistor, a different thermal design, a different price.

Post Glover states it plainly: continuous-duty rating is required "when the service continuity (alarm only, first fault) is prime concern." Any guidance that says continuous duty is not normally required is describing LRG and mislabeling it as universal.

Step 6 — Power dissipation

P  =  I²R  =  5² × 55  =  1,375 W  ≈  1.4 kW, continuous



Compare: Example A produces 3.2 MW that exists for ten seconds and is not a rating. Example B produces 1.4 kW that exists forever and is a real, meaningful thermal design number. This is exactly why the industry specifies NGRs by voltage, current, and time — never by kilowatts.

Step 7 — Code compliance check, NEC 250.36

In the 2023 NEC, 250.36 is titled "Impedance Grounded Systems — 480 Volts to 1000 Volts." (It was "High-Impedance Grounded Neutral Systems" in the 2020 and earlier editions — a retitle worth noting in any spec that cites it.) Three conditions must be met:

1. Only qualified persons service and maintain the installation
2. Ground detectors are installed
3. Line-to-neutral loads are not served

Condition 3 kills more HRG retrofits than any other single factor. If any 277 V lighting or single-phase load is fed line-to-neutral from that system, you cannot convert it to HRG without re-feeding those loads from a separate solidly grounded source. Confirm this before you design anything.

For systems above 1000 V, the governing section is 250.187, "Impedance Grounded Systems" — same three conditions, plus a requirement that the impedance grounding conductor be insulated for the maximum neutral voltage (57.7% of phase-to-phase on a three-phase wye).

Step 8 — Detection and fault location

• 59G / device 64 neutral overvoltage or ground detection for the alarm
• A pulsing contactor across part of the resistor, which modulates the ground-fault current so a clamp-on ammeter can trace the faulted feeder while the plant runs
• Do not install a trip on first ground fault. If you do, you have paid for HRG and built LRG.
  

5.  Side by side: HRG vs LRG

Figure 1, on the following page, summarizes the whole method: where the resistor sits, the grounding spectrum, the nine-step sizing sequence, both worked examples, and the IEEE C57.32 rating table.

FIGURE 1  —  NGR sizing to US / IEEE practice: placement, grounding spectrum, sizing sequence, worked examples, and rating table

Illustrative design guidance — not a substitute for a project-specific grounding and coordination study.

6.  Five things worth correcting in the popular NGR guides

Most of what circulates on this topic is directionally right. These specific items are not, and each of them has a cost.

1. The IEEE standard number has changed

IEEE Std 32-1972 (R1997) is superseded. The governing document is IEEE Std C57.32-2015, "IEEE Standard for Requirements, Terminology, and Test Procedures for Neutral Grounding Devices," with amendment C57.32a-2020 adding a neutral grounding resistors clause. Both are now listed as Inactive-Reserved by IEEE SA, which is a records-status flag rather than a withdrawal — they remain the referenced documents in practice, and specifications should cite them by number and year.

2. The standard time ratings are not 10 / 30 / 60 seconds

The IEEE-enumerated set is 10 seconds, 1 minute, 10 minutes, extended time, and continuous. ("Extended time" means 10 minutes or more, not exceeding 90 days per year in aggregate.) Vendors will build a 30-second unit, and there is nothing wrong with buying one, but do not present 30 s as a standard IEEE rating in a specification — it invites a bid clarification you do not need.

3. Temperature rise limits pair differently than commonly shown

Per IEEE C57.32, above 30 °C ambient: 10 s → 760 °C, 1 min → 760 °C, 10 min → 610 °C, extended → 610 °C, continuous → 385 °C.

4. "Continuous duty is not normally required" is wrong for HRG

See Example B. It is true for LRG and false for the application where the resistor matters most.

5. kW is a derived quantity, not a specification

Every manufacturer — Post Glover, I-Gard, Filnor, Powerohm — specifies by rated voltage, rated initial current, and rated time. Kilowatts appear on no data sheet. Publishing a "635 kW resistor" invites a procurement conversation that goes nowhere.

One thing the popular guides get right: the charging-current criterion Ig ≥ 3Ic is correct and matches IEEE 142 / 3003.1 exactly. It deserves more prominence than it usually gets, not less.

And one nuance about arc flash

NGRs dramatically reduce ground-fault arc energy — that is real, and it is the single strongest safety argument for HRG. But IEEE Std 1584-2018, "IEEE Guide for Performing Arc-Flash Hazard Calculations," models three-phase arcing faults only. Single-phase and line-to-ground arcing faults are explicitly outside its scope. Its stated applicability is 208 V to 15 kV, three-phase, with bolted fault current from 700 A to 106 kA.

The practical consequence: installing an NGR does not lower the calculated incident energy on your arc-flash labels, because those labels are computed from three-phase bolted fault current, which the NGR does not touch. The NGR reduces the likelihood and severity of the ground-fault event that initiates most arcing faults in the field. That is a genuine and valuable risk reduction. It is not a label change, and anyone who promises you one is confusing two different things.

7.  Design checks that catch real problems

Relay sensitivity

Can your ground relay actually see Ir? On a 5 A HRG system, a 5 A ground-fault current is below the pickup of most conventional overcurrent elements and well below normal residual unbalance on a phase-CT residual connection. HRG requires either neutral-connected sensing at the resistor or core-balance CTs on feeders — never a residual connection from phase CTs.

Resistance drift with temperature

Relay coordination depends on the fault current staying near its rated value. IEEE C57.32 caps the resistance increase at 67%, but the alloy matters: purpose-made resistance alloys run around 0.00024–0.00036 Ω/°C, while general-purpose stainless (AISI 304 at 0.00092, AISI 430 at 0.00146) drifts several times more. Specify the temperature coefficient, not just "stainless steel."

Transient overvoltage

On an ungrounded system, restriking ground faults are cited in IEEE Std 242 (Buff Book) as capable of producing overvoltages of six to eight times normal phase voltage. IEEE 142-2007 §1.4.3.2 states that both high- and low-resistance grounding are designed to limit transient overvoltages to 250% of normal. Keep these separate from the steady-state effect: during a sustained single line-to-ground fault, the unfaulted phases rise to line-to-line voltage — 173% of normal line-to-ground — on any impedance-grounded or ungrounded system. That 173% is why cable and surge arrester insulation levels must be checked before an HRG conversion.

Cable and arrester insulation rating

Because the unfaulted phases sit at 173% during a sustained fault, an HRG system needs 133% or 173% insulation-level cable depending on how long faults are permitted to persist, and surge arresters rated for an ungrounded-system duty. This item alone has stopped more than one HRG retrofit at the cable-schedule review.

Neutral conductor insulation

NEC 250.187 requires the impedance grounding conductor be insulated for the maximum neutral voltage — 57.7% of phase-to-phase.

Effectively grounded verification

If a utility interconnection agreement requires an effectively grounded source, you must demonstrate X₀/X₁ ≤ 3 and R₀/X₁ < 1 (coefficient of grounding ≤ 80%). Resistance grounding by definition does not meet this. This is a frequent and expensive collision on generation interconnection projects — see Case Study 3.

Generator neutrals

IEEE C62.92.2-2017 recommends limiting generator ground-fault current to 5 A to 15 A under high-resistance grounding, because "iron burning and damage depend mainly on fault current magnitude and duration." A solidly grounded generator can see ground-fault current exceeding its three-phase fault current, since zero-sequence impedance is typically the lowest of the three sequence impedances — and the damage lands in the laminated stator core, which is the most expensive thing in the machine to repair. Where generators are paralleled, use separate NGRs per machine to avoid circulating third-harmonic current.

8.  Anonymized case studies

The following are anonymized and composited from typical engagements. Figures are representative of the scenarios described and have been rounded and adjusted; they do not identify any specific client or facility.

Case Study 1 — Colocation data center: HRG retrofit blocked by 277 V lighting

Situation. A 30 MW Mid-Atlantic colocation facility operated its 480 V mechanical and house distribution as a solidly grounded system. Two unplanned outages in eighteen months traced to ground faults in pump-room conduit that tripped upstream and dropped mechanical cooling. The client asked for a high-resistance grounding conversion to eliminate first-fault trips.

What the analysis found

Charging current was manageable — roughly 3.5 A total on the mechanical distribution — so a 5 A HRG design at 55 Ω continuous was straightforward on paper. The problem was NEC 250.36 condition 3: the same 480Y/277 V system fed several hundred 277 V lighting fixtures line-to-neutral across the building. HRG was not permissible on that system as built.

What was done

Rather than abandon the conversion, the system was split. The mechanical and process distribution — where the ground faults were actually occurring, and where uptime mattered — was re-fed from a dedicated 480 V transformer with no line-to-neutral loads and high-resistance grounded at 5 A continuous, with pulsing fault location and 59G alarm to the BMS. The 277 V lighting load stayed on a separate, solidly grounded 480Y/277 V transformer where trips were operationally tolerable.

Outcome

Ground faults on the mechanical system now alarm instead of tripping, and are located during business hours using a clamp meter and the pulsing contactor. The additional transformer added meaningful cost relative to a straight NGR installation, which is exactly why the code check belongs at the front of the project, not at the permit review.

Engineering takeaway

Check NEC 250.36 condition 3 before you size anything. The resistor calculation is the easy part; the load inventory is what determines whether HRG is buildable.

Case Study 2 — Gulf Coast refinery: the 13.8 kV NGR that had been open for two years

Situation. A refinery experienced simultaneous cable terminator failures at two locations on a 13.8 kV bus during what should have been a routine single line-to-ground fault. The immediate damage was contained, but the failure pattern — multiple remote flashovers from one initiating fault — did not match a resistance-grounded system.

What the analysis found

The NGR on the source transformer neutral had failed open. Post-incident resistance measurement confirmed an open element. Comparison against maintenance records indicated the resistor had most likely been open since the previous turnaround, roughly two years earlier. During that period the 13.8 kV system had been operating ungrounded, with no alarm, no indication, and no operational symptom of any kind. The terminator failures were consistent with restriking-arc transient overvoltages in the range IEEE 242 describes for ungrounded systems — six to eight times normal phase voltage.

What was done

The NGR was replaced with a 20 Ω, 400 A, 10-second unit (7,967 V line-to-neutral rating) and continuity monitoring was installed on every NGR in the facility — a fleet of eleven resistors across the MV system, none of which had monitoring. Ground relay settings were reverified against the restored 400 A design value. Cable terminations at the two failure points and at three other locations showing partial-discharge indications were replaced.

Outcome

The monitoring retrofit cost a small fraction of the terminator replacements from the single event, and detected a second developing high-resistance condition on a different unit within the following year.

Engineering takeaway

An NGR is the only major protective device in a substation that can fail completely, silently, and without consequence — right up until the moment it matters. Continuity monitoring is not an accessory. Treat an unmonitored NGR the same way you would treat a relay with no self-test.

Case Study 3 — 120 MWac utility-scale solar: HRG was never an option

Situation. A 120 MWac PV project in ERCOT proposed high-resistance grounding on its 34.5 kV collector system, reasoning that a single ground fault should not curtail the whole plant. The utility's interconnection requirements simultaneously called for an effectively grounded source at the point of interconnection.

What the analysis found

Two independent problems.

First, charging current. The collector system comprised roughly 28 miles of 35 kV-class shielded cable. Scaling from published 13.8 kV values by voltage and cable capacitance put total charging current on the order of 150 A. To satisfy Ir ≥ 3Ic0, the resistor would have had to pass at least 150 A — which is squarely in the low-resistance band. High-resistance grounding was arithmetically impossible on this system, independent of anyone's preference.

Second, the interconnection requirement. Effective grounding requires X₀/X₁ ≤ 3 and R₀/X₁ < 1. Resistance grounding does not meet that criterion by definition. The two requirements in the project documents were mutually exclusive as written.

What was done

The two requirements were separated by where they apply. The GSU was configured to provide an effectively grounded zero-sequence source at the point of interconnection, satisfying the utility. The collector system was low-resistance grounded at 400 A through a 50 Ω, 10-second NGR (19,919 V line-to-neutral rating), giving fast, selective clearing of collector-circuit ground faults. Feeder ground protection used core-balance CTs at each collector circuit breaker so that a single faulted circuit trips and the remaining circuits keep producing — delivering most of the availability benefit the project had wanted from HRG, through selectivity rather than through riding out the fault.

Outcome

A ground fault on one collector circuit now curtails that circuit only, typically 8–12 MW rather than the full plant. The design cleared utility review without an exception request.

Engineering takeaway

"We want HRG" is a statement about desired behavior, not a design. On large collector systems the charging current usually decides the question before anyone gets to state a preference. And where an interconnection agreement demands effective grounding, the resolution is almost always to satisfy it at the GSU rather than to argue about the collector system.

9.  Frequently asked questions

10.  Standards reference

Closing

The NGR sizing formula is trivially simple and almost never the reason a grounding design fails. Designs fail because charging current was estimated instead of measured, because a continuous-duty application was specified with a short-time resistor, because a 277 V lighting circuit made the whole scheme non-compliant, because nobody monitored a device that fails silently, or because two contract documents demanded incompatible grounding classes and nobody reconciled them until the design review.

At Keentel Engineering, system grounding studies are part of the power system studies we deliver alongside substation design, POI interconnection engineering, and owner's engineering for renewable and industrial projects. If you have an NGR specification to review, a grounding class to select, or an interconnection requirement that appears to contradict your plant design, we would be glad to look at it.

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keentelengineering.com   ·   contact@keentelengineering.com   ·   813-389-7871

Engineering note: standards editions, section numbers, and quantitative limits cited here were verified against current published sources at time of writing. NEC section numbers are given for the 2023 edition; confirm against the edition adopted in your jurisdiction. Nothing here substitutes for a project-specific grounding and coordination study.