Load List & Sizing

Transformer size is not the connected load. It is the coincident maximum demand in kW, divided by the expected power factor to give kVA, then checked against the largest motor start, the harmonic load and the contingency case. A plant with 1200 kW connected may need a 1000 kVA transformer or two 1250 kVA transformers, depending entirely on how much of that load runs at the same time and what has to keep running when one source is lost.

The rule that follows: every number in the chain must be traceable. Demand factor comes from plant history, meter data or a stated process assumption — never from a habit. Future margin comes from an identified expansion, not from a blanket 20%. And the incomer is sized from two independent checks, full-load current and prospective fault current, because a breaker correctly rated for 1391 A can still be wrong for the fault level behind it.

The Question Every Load List Has to Answer

A factory has:

Connected Load = 1200 kW

Does that mean the plant needs:

1200 kVA transformer?

No.

Maybe it requires:

1000 kVA

Maybe:

1600 kVA

Maybe two transformers.

The correct answer depends on much more than adding equipment nameplates.

A proper electrical load list considers:

• Connected load
• Actual operating load
• Demand factor
• Diversity
• Power factor
• Motor efficiency
• Starting current
• Load duty
• Operating scenarios
• Standby loads
• Future expansion
• Harmonic loads
• Redundancy philosophy

Equipment sizing — conductors, busbars and interrupting devices — is not simply a summation of connected load nameplates. Standard practice defines demand factor as maximum coincident demand divided by total connected load and emphasizes load diversity, load profile, motor starting, harmonic loads and future growth.

This guide explains how a load list should be converted into:

Transformer Rating → Incomer Rating → Busbar Rating → Distribution Architecture

What Is an Electrical Load List?

A load list is the master schedule of electrical loads connected to a power-distribution system.

It may include:

• Motors
• VFDs
• Pumps
• HVAC
• Lighting
• Utility equipment
• PLC systems
• Heaters
• Compressors
• UPS
• Battery chargers
• Process equipment
• Future loads

A professional load list should show more than:

Equipment Name + kW

Recommended Load List Columns

A useful industrial load list may include:

Parameter	Purpose
Tag Number	Equipment identification
Load Description	Pump, fan, conveyor etc.
Quantity	Number installed
Duty/Standby	Operating philosophy
Motor / Equipment kW	Rated power
Efficiency	Electrical input calculation
PF	Apparent-power calculation
Starting Method	DOL / Star-Delta / SS / VFD
Demand Factor	Expected simultaneous utilization
Running Quantity	Number expected to operate
Operating Scenario	Normal / peak / emergency
Criticality	Essential / non-essential
Harmonic Load?	VFD/UPS/rectifier etc.
Future Load	Identified expansion
Source	Transformer / DG / UPS
Remarks	Process assumptions

This makes the load list a design document rather than a simple inventory.

Connected Load

Connected load is the sum of rated connected equipment.

Example:

• Motors = 600 kW
• HVAC = 200 kW
• Lighting = 80 kW
• Utilities = 170 kW
• Miscellaneous = 50 kW

Connected Load:

1100 kW

But all 1100 kW may not operate simultaneously.

That is where demand and diversity become important.

Maximum Demand

Maximum demand represents the highest expected simultaneous demand during the defined operating period.

If:

Connected Load = 1100 kW

but:

Maximum coincident operating load = 720 kW

then sizing every upstream component directly from 1100 kW may lead to unnecessary oversizing.

Demand Factor

Demand Factor = Maximum Coincident Demand / Total Connected Load.

Example:

Connected:

1000 kW

Maximum simultaneous:

700 kW

Demand Factor:

700 / 1000 = 0.70

or:

70%

But demand factor should not simply be guessed.

It should come from:

• Actual plant history
• Process philosophy
• Duty/standby arrangement
• Utility meter data
• Similar operating plants
• Engineering assumptions

Diversity Factor

Individual loads do not always reach their individual peaks at the same time.

For example:

Pump system peaks in morning.

HVAC peaks in afternoon.

Production line peaks during another shift.

Their individual maxima may not coincide.

That is why:

Connected load is not the same as coincident maximum load.

Duty + Standby Loads

Suppose a pumping station has:

3 × 75 kW pumps

Operating philosophy:

2 Duty + 1 Standby

Connected motor load:

225 kW

But normal running load:

150 kW

If only two are ever allowed to run together, blindly sizing the transformer for all three as continuously running may be unnecessarily conservative.

But check:

• Changeover overlap
• Maintenance mode
• Emergency operation
• Future operation

before excluding the standby unit.

Motor Nameplate kW Is Usually Mechanical Output

This is a commonly missed detail.

A motor rated:

75 kW

typically refers to mechanical shaft output.

Its electrical input is higher because motor efficiency is less than 100%.

Approximate electrical active input:

Pinput = Poutput / Efficiency

If:

Motor output = 75 kW

Efficiency = 94%

then:

Electrical input ≈ 79.8 kW

Therefore a detailed load list should distinguish:

Motor shaft rating

from:

Electrical demand

when accuracy matters.

Use actual motor datasheet efficiency rather than generic assumptions.

Power Factor Converts kW to kVA

Transformers are rated primarily in:

kVA

not kW.

For an approximate balanced load:

kVA = kW / PF

Suppose:

Electrical active demand:

700 kW

Power Factor:

0.90

Then:

Apparent Power ≈ 778 kVA

A transformer-selection decision should therefore not compare:

700 kW directly with 700 kVA.

APFC Changes kVA Demand — Not Process kW

If power factor improves:

kW stays approximately the same

while:

kVA and current reduce

for the same useful active load.

Therefore, when evaluating transformer demand, distinguish between:

• Existing PF
• Expected corrected PF
• APFC availability
• Worst-case APFC unavailable condition

Do not make transformer adequacy entirely dependent on an unrealistically perfect PF assumption.

Worked Load List Example

Consider an illustrative industrial plant.

Load Group	Connected kW	Demand Factor	Expected Demand
Process Motors	500	0.80	400 kW
HVAC	120	0.80	96 kW
Utilities	150	0.70	105 kW
Lighting / Small Power	50	0.90	45 kW
Identified Future Load	100	0.50	50 kW
Total	920 kW	—	696 kW

This is an illustrative engineering example—not a universal set of demand factors.

Assume expected operating PF:

0.90

Then:

Required operating kVA ≈ 696 / 0.90

≈ 773 kVA

Suppose the project deliberately carries an additional illustrative planning allowance of:

15%

Then:

773 × 1.15 ≈ 889 kVA

A standard:

1000 kVA transformer

could then be evaluated.

But:

15% is not a universal future-growth rule.

The margin should reflect actual project development.

Why Not Just Select a 1600 kVA Transformer?

Because bigger is not automatically better.

Excessive oversizing can lead to:

• Higher capital cost
• Larger switchgear
• Larger cables/busduct
• Higher available short-circuit current in some cases
• Unnecessary infrastructure

The goal is:

adequate capacity + justified spare margin

not:

largest possible transformer.

Future Expansion

Future load should be separated into:

Identified Future Load

A production line is planned in 18 months.

Possible Future Load

Plant may expand someday.

The first deserves stronger consideration than vague speculative growth.

A useful load list can therefore include separate columns:

• Existing load
• Phase-2 load
• Phase-3 load
• Ultimate load

This prevents an arbitrary spare factor from hiding all assumptions.

Motor Starting Can Control Transformer Selection

A transformer that can carry a motor after it reaches rated speed may still experience unacceptable voltage dip during starting.

Consider:

250 kW motor

starting DOL.

Starting current may be several times running current.

That can create:

• Transformer voltage dip
• Bus voltage dip
• Contactor dropout
• PLC reset
• Other motor disturbance

Therefore transformer sizing should also check major motor starts.

Put numbers on it before deciding. On a 1000 kVA, 415 V transformer at 5% impedance, the LV full-load current is approximately 1391 A and the prospective fault current at the transformer terminals works out to approximately 28 kA, a little less once the upstream source and cable impedance are included — a strong bus. A 250 kW motor at roughly 430 A full-load current, started DOL at 6 times that, draws about 2580 A for a few seconds, which is nearly twice the transformer's rated current. The resulting bus voltage dip is typically in the range of 8 to 12% depending on the actual impedance and cable run, and that is enough to drop out contactors held on 415 V coils elsewhere in the plant. Put the same motor on a 630 kVA transformer, where full-load current is approximately 877 A, and the dip grows by roughly half again. The real figure must come from the project system study, but the arithmetic tells you within a minute whether the study is worth commissioning.

Our recommendation: ask for the starting method of every motor above about 10% of the transformer rating before the transformer is ordered. This is the item we push back on at clarification stage, because a client who accepts a soft starter on one 250 kW pump can often stay on a 1000 kVA transformer instead of moving to 1250 kVA — and the soft starter costs a fraction of the transformer upgrade plus the larger incomer, busbar and cabling that come with it.

Starting Method Matters

The same motor may behave very differently under:

DOL

High starting current.

Star-Delta

Reduced line current but also reduced starting torque.

Soft Starter

Controlled voltage/current start.

VFD

Controlled frequency/voltage start.

Therefore the load list should contain:

Starting Method

for major motors.

Sequential Starting

Suppose a plant has:

4 × 160 kW motors

They may all run together.

But do they start together?

If PLC logic ensures:

Motor-1 starts → delay → Motor-2 → delay → Motor-3

the transformer sees a different transient than simultaneous starting.

The control philosophy therefore affects source sizing.

VFD / UPS / Nonlinear Loads

Large concentrations of:

• VFD
• UPS
• Rectifiers
• EV chargers
• Power electronics

can affect:

• Harmonics
• Transformer heating
• Neutral current
• Power factor
• Power quality

Transformer sizing should not use kVA alone where nonlinear-load duty is significant.

Load Scenarios Are Better Than One Single Number

A professional design should evaluate multiple scenarios.

For example:

Case 1 — Normal Production

All essential production loads.

Case 2 — Peak Production

Maximum expected coincident operation.

Case 3 — Night Shift

Reduced production, lighting/utilities.

Case 4 — DG Operation

Only emergency/essential loads.

Case 5 — Transformer Outage

Bus-coupler transfer condition.

Case 6 — Future Expansion

Phase-2 loads included.

This is much stronger than one line:

Total Load = 1200 kW

Transformer Redundancy

Suppose:

2 × 1000 kVA transformers

Normal:

Transformer-1 load = 650 kVA

Transformer-2 load = 600 kVA

If one transformer fails and bus coupler closes:

Remaining transformer may be asked to carry:

1250 kVA

That exceeds its normal rating.

Therefore the project must decide:

• Full redundancy?
• Partial redundancy?
• Load shedding?
• Emergency overload permitted by transformer/OEM?
• Critical loads only?

This links directly with the 2 Incomer + Bus Coupler operating philosophy.

In our experience this is the single most common gap between a specification and reality. Two transformers and a bus coupler get called redundancy on the SLD, and nobody writes down what actually happens on the day one of them is lost. Our recommendation: decide the contingency answer at design stage and record it in the panel's control philosophy, because it drives real hardware. If the surviving 1000 kVA transformer must carry 1250 kVA, either the transformer needs a defined short-term overload capability confirmed by its manufacturer, or the PCC needs load-shedding logic and a non-essential feeder group that can be dropped automatically when the coupler closes. Retrofitting that logic into a finished PCC means new auxiliary contacts, new wiring and re-testing, so it is far cheaper to build it in. On pharma and chemical projects we usually end up with a short list of feeders tagged non-essential in the load list itself — that list is what the shedding logic uses.

Transformer Full-Load Current

For a three-phase transformer:

I = kVA × 1000 / (√3 × V)

Example:

1000 kVA

415 V

Approximate LV full-load current:

≈ 1391 A

At:

1250 kVA, 415 V

current is approximately:

1739 A

At:

2000 kVA, 415 V

approximately:

2782 A

These values provide an important starting point for incomer and busbar selection.

Does 1000 kVA Transformer Automatically Mean 1600 A ACB?

Not automatically.

A 1000 kVA, 415 V transformer has approximately:

1391 A rated LV current

A standard:

1600 A ACB

may be evaluated.

But final selection should also consider:

• Continuous loading
• Breaker ambient
• Enclosure
• Trip-unit rating
• Long-time pickup setting
• Short-circuit level
• Selectivity
• Cable/busduct rating
• Future load

Do not equate:

Breaker Frame Size = Required Operating Setting

Breaker Frame Rating vs Trip Setting

Suppose:

1600 A ACB frame

That does not mean protection must trip at exactly:

1600 A

Modern electronic trip units can provide adjustable:

• Long-time pickup
• Long-time delay
• Short-time pickup
• Short-time delay
• Instantaneous
• Earth fault

depending on model.

The final settings should follow the protection study and conductor/transformer limits.

Incomer Breaking Capacity

After current rating comes:

Fault rating

Two transformers can both have:

1000 kVA

but different impedances.

Their LV short-circuit currents can differ.

Therefore incomer selection must include:

• Prospective fault current
• Transformer impedance
• Upstream source contribution
• Parallel operation
• Motor contribution where relevant

Do not size the incomer only from:

1391 A full-load current.

Busbar Sizing

Once transformer and incomer current are selected, the main busbar must be engineered for:

• Rated current
• Temperature rise
• Ambient
• IP rating
• Fault duty
• Number of sources

A preliminary current-density calculation can help establish conductor area.

For WTS copper busbar preliminary design, an internal basis of approximately:

1.6 A/mm²

can be used as the initial sizing step, followed by complete thermal and short-circuit checks.

The final assembly rating still depends on IS/IEC 61439 verification and the actual assembly configuration.

Treat 1.6 A/mm² as a first pass only. It is a starting figure, not a rating, and it says nothing about the two things that actually decide the busbar: temperature rise inside a closed enclosure at the site ambient, and short-time withstand against the prospective fault current. In our FAT experience the most common failure here is a busbar chosen on current density alone and then let down by the joints — a bar that is thermally comfortable at 2000 A will still develop a hot spot at a bolted joint with the wrong torque or an unprepared contact face. We check joint torque against the busbar supplier's figures and record it, and on panels with significant continuous loading we look at the temperature-rise verification for the actual cubicle arrangement rather than assuming the bar rating transfers. A 40 °C design ambient on paper and 50 °C inside a panel room in a Gujarat summer are not the same busbar.

CT Ratio

The incoming CT ratio should reflect:

• Maximum operating current
• Meter requirement
• Protection requirement
• Accuracy/class
• Future load

For example:

A 1000 kVA transformer at 415 V has around:

1391 A

A practical CT selection may be evaluated around an appropriate standard primary rating above the expected operating range.

But the correct ratio should follow:

• Protection study
• Metering accuracy
• Relay requirement

rather than merely matching ACB frame size.

Should Transformer Be Sized From Maximum Demand Bill?

Historical utility maximum demand is extremely valuable.

But use it carefully.

Suppose existing plant shows:

Maximum Demand = 620 kVA

and new project adds:

400 kVA

Do not simply write:

620 + 400 = 1020 kVA

Check whether:

• Existing maximum already includes certain new/replaced loads
• Peak times coincide
• Future equipment operates simultaneously
• PF changes
• Production increases

Historical data is evidence—not a replacement for load engineering.

Utility Bill vs Load Logger

Utility bills show:

• Historical demand
• Energy
• PF data depending on tariff

A load logger can provide:

• Time profile
• Peak kW
• kVAr
• PF
• voltage/current
• phase imbalance
• harmonics depending on instrument

For brownfield plants, actual measurement can significantly improve confidence in transformer sizing.

Spare Capacity Should Be Measurable

Instead of saying:

“Transformer has spare.”

state:

Existing peak demand:

720 kVA

Transformer:

1000 kVA

Available nameplate margin:

280 kVA

Then separately evaluate:

• Starting
• Ambient
• Harmonics
• contingency
• future load

This is clearer.

DG Load List Is Different

During DG operation, many projects do not supply the whole plant.

Create a separate:

Emergency Load List

Classify:

• Life safety
• Process critical
• Utilities
• Essential HVAC
• Non-essential load

Generator sizing also involves transient response to motor starting and load steps.

Therefore:

Transformer kVA sizing method should not simply be copied to DG sizing.

Common Load List Mistakes

Mistake 1 — Adding All Motor kW

Ignores duty/standby and diversity.

Mistake 2 — Comparing kW Directly to Transformer kVA

PF matters.

Mistake 3 — Ignoring Motor Efficiency

Nameplate motor kW may be mechanical output.

Mistake 4 — Using One Demand Factor for Everything

Different load types behave differently.

Mistake 5 — No Operating Scenarios

Peak, emergency and contingency modes can differ.

Mistake 6 — Arbitrary 20–30% Future Margin

Use identified expansion where possible.

Mistake 7 — Ignoring Largest Motor Start

Steady-state capacity can be adequate while starting performance is poor.

Mistake 8 — Ignoring Harmonics

Nonlinear loads can affect transformer thermal performance.

Mistake 9 — Transformer Sized Correctly but Incomer Fault Rating Wrong

Current rating and breaking capacity are different checks.

Mistake 10 — Redundancy Assumed Because There Are Two Transformers

Check whether one transformer can actually carry the required contingency load.

Recommended Design Workflow

Step 1 — Build Complete Load List

Collect equipment data.

Step 2 — Identify Operating Philosophy

Duty, standby and sequence.

Step 3 — Calculate Electrical Input

Consider motor efficiency where applicable.

Step 4 — Apply Justified Demand/Diversity

Not arbitrary factors.

Step 5 — Calculate kW and kVA

Using expected PF.

Step 6 — Create Multiple Scenarios

Normal, peak, emergency, contingency.

Step 7 — Check Major Motor Starting

Especially DOL/high-inertia motors.

Step 8 — Consider Harmonics

VFD/UPS/rectifier concentration.

Step 9 — Add Justified Future Growth

Clearly identified.

Step 10 — Select Transformer Rating

From standard available ratings/project philosophy.

Step 11 — Calculate Transformer LV Current

For incomer/bus design.

Step 12 — Determine Fault Level

Select breaking/withstand ratings.

Step 13 — Select Incomer, Busbar and CTs

Then verify protection coordination.

Relevant Panel Standards

Where the resulting incomer and bus system forms an LV power assembly, IEC 61439-1:2020 and IEC 61439-2:2020 provide the current international assembly framework.

For India, BIS lists the corresponding IS/IEC 61439 Part 1:2020 and Part 2:2020 adoptions.

How Wisdom Techno Solutions Uses the Load List

For PCC, MCC, PMCC and other distribution panels, the approved load list gives WTS the engineering basis for:

• Incomer rating
• Main busbar
• Distribution bus
• Outgoing feeder rating
• Motor starter selection
• APFC requirement
• Metering
• CT ratio
• Spare feeders
• Future provisions

Wisdom Techno Solutions is a licensed partner for three design-verified switchgear platforms: Rittal Ri4Power (Rittal Solutions Partner since 2021 — the Ri4Power system carries Intertek ASTA design verification to IEC 61439-1 and -2 Edition 3, with copper and aluminium busbar systems up to 6300 A), C&S CX (Licensed Partner since 2023, up to Form 4B Type II) and Siemens SIEPAN Elite/8PU (IEC 61439 Solutions Partner since 2024). We build to each system's verified configuration and routine-verify every assembly in-house at our Vadodara, Gujarat facility, for industrial, EPC and infrastructure projects across India. That places the incomer and busbar current rating inside a verified design envelope.

A customer RFQ is much stronger if it provides:

• Approved load list
• Transformer details
• Maximum demand
• Fault level
• Operating modes

instead of only:

“Need 2500 A PCC.”

The main principle is:

Panel rating should emerge from the electrical-system requirement—not the other way around.

Conclusion

Transformer and incomer sizing begins with the load list.

But a load list is not simply:

Sum of all equipment nameplates.

The correct process is:

Connected Load

↓

Operating Philosophy

↓

Demand & Diversity

↓

Electrical kW

↓

Power Factor

↓

kVA

↓

Motor Starting + Harmonics + Contingency

↓

Future Growth

↓

Transformer Rating

↓

Incomer + Busbar + Protection

This is the core principle of power-distribution planning: load planning must reflect realistic coincident demand, not nameplate summation.

Correct transformer sizing is therefore not about selecting the smallest transformer that works today.

Nor is it about selecting an excessively large transformer “for safety.”

It is about:

Selecting a source and distribution system that can support the real operating load, credible contingencies and justified future expansion without unnecessary oversizing.

Related Guides

• Busbar sizing for LT panels
• Icu vs Ics vs Icw and panel fault rating
• APFC panel sizing and kVAr calculation
• 2 incomer + bus coupler interlocking
• Product page: PCC panel

Frequently Asked Questions

What is an electrical load list?

An electrical load list is a structured schedule of every electrical load in a plant, showing not just the rating and quantity but the operating duty, demand factor, power factor, starting method, criticality, source and any harmonic content. It is the document from which transformer rating, incomer rating, busbar current, CT ratios and feeder schedules are all derived. The difference between a useful load list and an inventory is the operating information: duty versus standby, which loads run in which scenario, and which are essential during a mains failure. Without those columns the list can tell you the connected load but not the demand, and demand is what sizes the source.

What is the difference between connected load and maximum demand?

Connected load is the total installed load. Maximum demand is the highest expected coincident demand over the relevant period.

What is demand factor?

Demand factor is maximum coincident demand divided by total connected load. If a plant has 1000 kW connected and the highest simultaneous operating load is 700 kW, the demand factor is 0.70, or 70%. It is always less than or equal to 1, and it should be derived per load group rather than applied as one number across the whole plant, because process motors, HVAC, lighting and utilities behave differently. The value must come from plant history, utility meter data, the process operating philosophy or a stated engineering assumption — a demand factor carried over from another project is the most common source of an oversized transformer.

Should transformer kVA equal connected kW?

No. Demand/diversity and power factor must be considered, along with motor starting, harmonics and project margins.

How is transformer LV current calculated?

For a three-phase transformer, I = kVA × 1000 / (√3 × V), where V is the LV line voltage. A 1000 kVA transformer at 415 V therefore gives approximately 1391 A of rated LV current. This is the rated current of the transformer, not the plant's operating current, so it sets the upper bound for the incomer and busbar rather than the expected load. Use the actual LV voltage from the transformer nameplate — working at 433 V instead of 415 V changes the same 1000 kVA to roughly 1334 A.

What is the current of a 1000 kVA transformer at 415 V?

Approximately 1391 A, from I = kVA × 1000 / (√3 × V). For reference, 1250 kVA at 415 V gives about 1739 A and 2000 kVA at 415 V about 2782 A. These are rated transformer currents and are the starting point for incomer frame selection, busbar current and CT primary ratings. They are not by themselves enough to select the incomer — the prospective fault current at the LV bus, which depends on the transformer impedance, is a separate and equally important check.

Does 1000 kVA transformer always require 1600 A ACB?

Not automatically. A 1600 A frame may be evaluated, but actual selection/settings also depend on continuous load, fault level, ambient, coordination and conductor/bus rating.

Should standby motors be included in transformer sizing?

Standby motors are excluded from the steady-state demand only if the control system genuinely prevents them running with the duty units. In a 2-duty-plus-1-standby pumping arrangement of 3 × 75 kW, the normal running load is 150 kW rather than the 225 kW connected — but check the changeover overlap, the maintenance mode where an operator may run all three briefly, and any emergency scenario before excluding the third machine. Where overlap is possible even for a few seconds, size the source for it or interlock it out in the PLC logic. State the assumption in the load list remarks column so the decision is traceable later.

Should future load be included?

Yes, but only where the expansion is identified — a production line planned in 18 months with known equipment deserves capacity; a general possibility of growth does not. Keep identified future load in its own column with its own demand factor, so the assumption stays visible instead of disappearing into a blanket percentage. An arbitrary 20 to 30% spare margin applied on top of a demand calculation that already contains conservative demand factors compounds twice and produces a transformer that runs lightly loaded for years. The cleaner approach is to state the present demand, the identified future demand and the resulting selection separately, and to provide spare feeders and physical extension provision in the panel rather than spare transformer kVA.

Why is motor starting important?

A transformer may comfortably carry a motor's steady-state load and still produce an unacceptable bus voltage dip while that motor starts. A 250 kW motor at roughly 430 A full-load current, started DOL at about 6 times that, draws in the region of 2580 A — nearly twice the 1391 A rated current of a 1000 kVA, 415 V transformer. The dip lasts only a few seconds but is enough to drop out contactors, reset PLCs and disturb other motors on the same bus. Check the largest motor start, and the worst credible simultaneous start, against the transformer impedance before finalising the rating; the actual dip figure must come from the project system study.

Do VFDs affect transformer sizing?

Yes. A large concentration of VFDs, UPS input stages or rectifiers draws non-sinusoidal current, and the resulting harmonic content causes additional transformer heating that a plain kVA demand calculation does not capture. Triplen harmonics also add in the neutral instead of cancelling, so the neutral conductor and neutral busbar need attention alongside the transformer. Where nonlinear load is a significant share of the total, the load list should flag it in its own column and the sizing should account for the thermal effect, with harmonic mitigation such as line reactors or filters evaluated as part of the same exercise. The transformer's permissible harmonic loading must be confirmed with its manufacturer rather than assumed.

If I have two transformers, do I automatically have redundancy?

No. The surviving transformer must have adequate capacity for the required contingency load, or load shedding must be provided.