Do you need a microgrid? Islanding, resilience, and what to specify

A microgrid is worth its cost when the site can name the load it must keep, the hours it must keep it, and the protection that still works once the utility is gone. Those three numbers decide the purchase. For a cold-storage building that must hold 282 kW of critical load through an outage, including a 75 hp code G compressor, the arithmetic gives a 500 kVA grid-forming inverter running at 66 percent, a 1041.7 kWh battery for a 4-hour island, and a starting check showing the compressor would take that inverter to 1.46 per unit across the line. It also shows that available fault current at the 480 V bus drops from 20,918 A with the utility to about 722 A when islanded, so feeder protection needs a second settings group. The kVA-to-ampere and transformer fault-current steps below are the same rules the transformer sizing calculator runs, and the code path runs through NEC Articles 705 and 706, IEEE 1547-2018 and, in Canada, the utility interconnection requirements.

What problem does a microgrid actually solve?

A microgrid is a local group of loads and on-site sources — battery storage, solar, sometimes a generator — that can run with the utility or disconnect and carry those loads alone. That disconnected mode is islanding.

The case starts with outage exposure. The U.S. Energy Information Administration reports that customers averaged about five and one-half hours of interruptions in 2022, and that the yearly total has held around two hours once major events are excluded. The major-event year is what a cold store or continuous process plant buys protection against, and that gap sets the runtime in the worked example.

The second driver is capacity: storage behind the meter adds headroom without a new service and cuts demand charges every grid-connected day. Sizing for that daily duty is covered in how to size a battery energy storage system; this article sizes for the island.

Which code sections govern a microgrid?

In the 2023 NEC, microgrids sit in Article 705, and earlier editions numbered the same provisions differently, so cite the edition the authority having jurisdiction has adopted: interactive and island operation in 705.50, connection to the primary source through 705.11, 705.12 or 705.13, the microgrid interconnect device in 705.70, and the microgrid control system in 705.76, which must monitor and control transitions with the utility. The storage itself follows Article 706.

Inverters are specified against UL 1741 (CSA C22.2 No. 107.1 in Canada) and storage against UL 9540 and NFPA 855 — see battery storage fire safety.

How do you size the island for a critical load?

Four quantities set the island, each with a formula:

S = P ÷ PF

S_start = S_other + hp × (kVA per hp from Table 430.7(B))

E_nameplate = P_avg × t ÷ (η × DoD × SoH)

I_island = k × S_inv × 1000 ÷ (√3 × V)

η is inverter discharge efficiency, DoD the usable state-of-charge window, SoH the capacity left at end of warranty, and k the inverter’s fault current in per unit — typically 1.1 pu to 2.0 pu per the IEEE Power System Relaying Committee.

Worked example — 480 V cold store, 4-hour island

A cold store takes 480Y/277 V service from a 1000 kVA, 5.75 percent impedance utility transformer. The load study separates 220 kW of critical load at 0.85 power factor from one 75 hp code G compressor drawing 62 kW at 0.86 power factor. Average critical demand over an outage, from interval data, is 180 kW; the island target is 4 hours.

1. Running apparent power. Other critical load: 220 ÷ 0.85 = 258.8 kVA. Compressor: 62 ÷ 0.86 = 72.1 kVA. Running total: 258.8 + 72.1 = 330.9 kVA, or 220 + 62 = 282 kW.
2. Inverter continuous rating. The grid-forming block must carry 330.9 kVA continuously. A 500 kVA block runs at 330.9 ÷ 500 = 66.2 percent; the role of the grid-forming source is set out in grid-forming vs. grid-following inverters.
3. Motor starting check. Table 430.7(B) gives code G as 5.60 to 6.29 kVA per horsepower; take the top of the range. Locked-rotor kVA: 75 × 6.29 = 471.75 kVA, which is 471 750 ÷ (√3 × 480) = 471 750 ÷ 831.4 = 567.4 A. With the other load running, the inverter sees 258.8 + 471.75 = 730.6 kVA, or 730.6 ÷ 500 = 1.46 per unit.
4. Starting method. If the vendor’s short-time rating is 1.2 per unit, the start may draw at most 1.2 × 500 − 258.8 = 341.2 kVA, which is 341.2 ÷ 471.75 = 72 percent of locked-rotor kVA. A soft starter or drive set below that limit, or a larger inverter, is required.
5. Energy at the AC terminals. 180 kW × 4 h = 720 kWh.
6. Battery nameplate energy. 720 ÷ 0.96 = 750 kWh at the DC bus; ÷ 0.90 usable window = 833.3 kWh at beginning of life; ÷ 0.80 end-of-life capacity = 1041.7 kWh nameplate.
7. Inverter rated current and its overcurrent device. 500 000 ÷ (√3 × 480) = 500 000 ÷ 831.4 = 601.4 A. NEC 706.30(A): 1.25 × 601.4 = 751.8 A, so the next standard rating in NEC 240.6(A) is 800 A.

Efficiency, window and end-of-life are example datasheet inputs, not code values; a 70 percent end-of-life warranty gives 720 ÷ (0.96 × 0.90 × 0.70) = 1190.5 kWh. The kVA and current steps match the transformer sizing calculator.

What runtime costs in battery energy

The same 180 kW load, the same three factors, five runtimes:

Energy scales with hours while inverter kVA stays fixed, which is why long islands add solar or generator recharge — the PV-storage-diesel arrangement of a DC-coupled grid-forming hybrid system.

What happens to fault current when the site islands?

With the utility connected, the bus sees whatever the transformer impedance allows — the infinite-source screen from sizing transformer overcurrent protection:

I_sc = I_FLA ÷ (%Z ÷ 100)

The 1000 kVA transformer has 1 000 000 ÷ 831.4 = 1202.8 A full-load current, so 1202.8 ÷ 0.0575 = 20,918 A at the 480 V bus. Islanded, the only source is the inverter: 1.2 × 601.4 = 721.7 A, about 29 times less.

That collapse is the protection problem. A 400 A feeder breaker with instantaneous pickup at 10 times rating (4000 A) clears a grid-connected fault instantly; islanded, 721.7 A is 1.8 times rating and lands on the long-time curve, and 2.0 per unit (1202.8 A) is only 3.0 times. The inverter may trip first and drop the island. The PSRC report’s microgrid case, a 1.25 MVA inverter at 480 V limited to about 3008 A (2.0 per unit), uses an inverse-time relay coordinated with that limit. The fix is a second settings group the controller selects on transition, a coordination study run for both modes (when a coordination study is needed), and a bus rating still checked against the grid-connected figure (available fault current and equipment ratings).

Motor locked-rotor reference, code G

Code F tops out at 5.59 kVA/hp and code H at 7.09, so read the nameplate letter before running the check.

Where Canada differs

The arithmetic is unchanged in Canada; the authority is not. The Canadian Electrical Code covers storage in Section 64, revised for energy storage systems in the 2024 edition, and interconnection in Section 84, but whether a site may island at all is written into the utility’s interconnection requirement, which references the CSA C22.3 No. 9 interconnection standard. Manitoba Hydro’s requirement is a clear example: protection must detect loss of any phase and cease to energize or isolate in less than 2.0 seconds, customer anti-islanding protection is required “regardless of whether intentional islanding is allowed”, load-displacement systems of 250 kW or more will require a reverse-power relay, systems of 500 kW or more require transfer trip, and grid-forming inverters are considered case by case. Transfer switches that parallel for less than 100 ms are exempt from anti-islanding but need automatic synchronization.

The same island at 600 V

At 600Y/347 V the inverter’s rated current falls to 500 000 ÷ (√3 × 600) = 500 000 ÷ 1039.2 = 481.1 A; 125 percent is 601.4 A. The compressor’s locked-rotor current is 471 750 ÷ 1039.2 = 453.9 A, and grid-connected fault current through a 1000 kVA, 5.75 percent transformer is 962.3 ÷ 0.0575 = 16,735 A. Islanded at 1.2 per unit:

The ratio between modes is the same 29 to 1, so the second settings group is needed at either voltage, and on a Manitoba Hydro load-displacement connection a storage block discharging 282 kW is already past the 250 kW reverse-power threshold.

What to specify

• Critical load in kW and kVA, separated from the largest motor — 258.8 kVA plus 72.1 kVA here, from the load study, sized by S = P ÷ PF.
• Largest motor horsepower and code letter — 75 hp, code G, 471.75 kVA locked-rotor from NEC Table 430.7(B) and the motor nameplate, with the starting method that holds the start inside the inverter’s short-time rating.
• Grid-forming inverter continuous kVA and short-time rating in per unit and seconds — 500 kVA and the vendor’s declared short-time figure, against the 1.1 to 2.0 per unit range the IEEE PSRC reports; inverters specified against UL 1741 or CSA C22.2 No. 107.1.
• Battery nameplate energy with its three factors stated — 1041.7 kWh for 4 hours from datasheet efficiency, usable window and warranted end-of-life capacity; storage specified against UL 9540 and sited under NFPA 855.
• Overcurrent device and conductors at 125 percent — 751.8 A, rounded to 800 A, under NEC 706.30(A), 706.31 and 240.6(A).
• Microgrid interconnect device and control system — NEC 705.70 and 705.76 (2023), with controller functions to IEEE 2030.7 and testing to IEEE 2030.8.
• Protection settings for both modes — grid-connected (20,918 A) and islanded (721.7 A), from a coordination study, plus the anti-islanding time from the utility letter (2 seconds under IEEE 1547-2018).

Common mistakes

• Sizing the inverter to the service, not the island. A 1000 kVA inverter on a 1000 kVA service is twice the 500 kVA that 330.9 kVA of critical load needs. The load study and S = P ÷ PF catch it.
• Leaving out the motor start. A 500 kVA inverter with 66 percent running load looks comfortable until a code G 75 hp compressor asks for 471.75 kVA and the block sees 1.46 per unit. Table 430.7(B) and the vendor’s short-time rating catch it; the start must be held to 341.2 kVA at 1.2 per unit.
• Buying kWh from the load-times-hours product. 180 kW × 4 h is 720 kWh, but the battery has to be 1041.7 kWh to still deliver it in the final warranty year. The datasheet efficiency, window and end-of-life figures catch it.
• Keeping grid-connected protection settings in island mode. A 4000 A instantaneous pickup never sees 721.7 A of inverter fault current, so a feeder fault becomes an island collapse. A two-mode coordination study catches it.
• Treating anti-islanding and intentional islanding as the same function. IEEE 1547-2018 still requires the source to stop energizing the utility within 2 seconds; the island forms behind an open NEC 705.70 interconnect device. Manitoba Hydro keeps anti-islanding mandatory even where islanding is permitted.

Where Entogo fits

Entogo, a Toronto-headquartered company backed by its own source factory, builds the storage, power-conversion and distribution blocks a microgrid is assembled from: the battery energy storage system, the containerized battery energy storage system, the DC-coupled grid-forming hybrid system and the MW-level grid-connected and off-grid system, which integrates BMS, PCS and EMS control with a built-in static transfer switch. Each package is specified against UL 9540, UL 1741 and the NFPA 855 siting rules for the project; UL (cULus)/CSA certifiable on request.

At the point of common coupling, the new-energy grid-connection cabinet and the low-voltage switchboard, designed and built to UL 891, carry the protection and separation. The transformer sizing calculator runs the kVA and fault-current steps above; commercial and industrial storage, renewable grid connection and the energy storage catalogue cover scoping.

A microgrid is four numbers before it is a controller: running kVA, the largest motor start, battery energy for the runtime, and the fault current it can deliver alone. Take them from the load study and datasheets, then let the utility requirement decide how the island may form.