Solar PV Step-Up Transformer: How to Size It, Why Inverter Harmonics Drive the Spec, and What Changes Between 0.8 kV and 35 kV

The answer first: size a solar step-up transformer on inverter AC output and harmonic duty — not on the array's DC nameplate

A solar step-up transformer is sized on the inverter's AC output — derated for harmonic heating and high ambient — not on the array's peak DC rating. In a utility-scale PV plant the step-up transformer that follows the inverter is selected at roughly the inverter's rated AC power, raising 0.4 kV / 0.48 kV / 0.8 kV up to a 10–35 kV collector voltage in one stage, after which a main step-up transformer lifts the collector to 110 kV or 220 kV. Three inputs decide the real specification: the inverter's harmonic current (current THD held to about 5%, with DC injection limited to under 0.5%), the plant's part-load, all-day duty (the transformer is energised 8,760 hours a year but at high load only a few hours a day, so no-load loss dominates lifetime cost), and the outdoor environment (high ambient, solar gain, humidity and coastal corrosion). Get those three right and the transformer becomes a 25-year asset instead of the plant's weakest link at noon.

Key takeaways

• Size on AC output, not DC nameplate. The step-up transformer sits after the inverter, so the inverter's AC rating — not the array's peak DC kW — is the design basis. A DC/AC (over-panel) ratio above 1.0 raises yield but does not raise the transformer kVA.
• Inverter harmonics set the thermal derate. Modern PV inverters hold current THD near 5%, but their switching harmonics still add eddy-current and stray losses, so a K-factor rating (or a documented IEEE C57.110 derate) and an electrostatic shield belong in the specification.
• PV is a part-load, all-day load. No-load (iron) loss runs 8,760 hours a year while load loss runs only during daylight — which is why a higher loss grade (S13/S20) or an amorphous core often wins on lifetime cost.
• Voltage architecture decides how many transformers you buy. One step-up stage (0.8 → 35 kV) versus an LV step-up plus a 35/110 kV main unit changes both cost and losses; it is a system-design decision, not a catalogue choice.
• Grid-code compliance is a transformer requirement. Fault ride-through, DC-injection limits and fault-level coordination (set by the transformer's impedance voltage) all flow back into the transformer specification.

Why a solar step-up transformer is not a standard distribution transformer

A distribution transformer steps a low-voltage network down to a customer and runs at a roughly steady load. A solar step-up transformer does almost the opposite: it takes the inverter's low-voltage AC output and raises it to the collector voltage, under three conditions that change how it must be designed.

First, the load is harmonic-rich. A PV inverter is a power-electronics front-end that switches at high frequency and injects a current that is close to — but not exactly — a sine wave. Grid-connected inverters are required to keep current distortion low (current THD typically under 5%) and DC injection under about 0.5% of rated current, but even compliant inverters leave switching-frequency ripple and low-order harmonics (5th, 7th, 11th, 13th) that create extra eddy-current and stray losses in the windings. That is the same physics behind K-factor transformers, explained in our guides to transformer harmonics and K-factor transformer selection.

Second, the load follows the sun. Output ramps from zero at dawn to full at solar noon and back to zero at dusk, so the transformer spends most of the day at a fraction of its rating. A unit that looks oversized on an annual-energy basis is usually correctly sized on the thermal basis — but its no-load loss, not its load loss, is what accrues every hour. That asymmetry reshapes the efficiency argument.

Third, the environment is harsh. PV plants sit in fields, steppe, deserts and coastal sites: high ambient temperature, intense solar gain, wide daily temperature cycling, dust and (near the coast) salt-laden air. A transformer designed for a 25 °C indoor room is not automatically right for a 45 °C outdoor pad.

How to size a solar PV step-up transformer: a three-step method

The arithmetic is not the hard part; getting the inputs right is. The same load-side logic that governs any site applies here, as covered in our distribution system sizing guide.

Step 1 — Take the inverter's AC output, not the array's DC rating

Sum the AC output of the inverters the transformer will serve, at the site's design ambient temperature (inverter output derates with heat, so use the hot-day figure). A 1 MWac block whose central inverter outputs 1,000 kW at 0.8 kV presents 1,000 kW of AC power to the transformer — regardless of whether the array behind it is 1,200 or 1,400 kWp DC. A DC/AC ratio above 1.0 improves yield on cloudy days and in the morning and evening, but it does not raise the transformer rating: what flows through the transformer is AC power.

Step 2 — Convert to kVA and apply the margin

Convert inverter AC kW to kVA using the inverter's output power factor (near unity, about 0.99 for modern three-phase units): 1,000 kW ÷ 0.99 ≈ 1,010 kVA. Then add a design margin for ambient and future re-powering — commonly 10–20% for a transformer sited in high ambient. The result (about 1,100–1,250 kVA) is rounded up to the next standard rating, for example 1,250 kVA or 1,600 kVA.

Step 3 — Set the harmonic and thermal class

Choose a K-factor (or a standard unit with a documented IEEE C57.110 derate) that matches the inverter's harmonic spectrum, and set the winding temperature rise, insulation class and cooling for the design ambient. On a PV plant a practical starting point is K-4 to K-9 for modern low-distortion inverters, with an electrostatic shield between the LV (inverter) and HV (collector) windings so grid-side surges do not reach the inverter. For dry-type units, IEEE C57.12.01 and IEC 60076-11 govern the general requirements.

The voltage architecture: from 0.8 kV to 35 kV in one stage or two

Where the transformer sits determines its voltage ratio and its size. Four architectures cover almost every PV plant.

Most utility-scale plants use one LV-to-MV step-up stage per inverter block (0.8 kV to 35 kV is common), then a single main step-up transformer from the 35 kV collector to 110/220 kV at the point of interconnection. Smaller commercial plants often stop at a single pad-mounted step-up to the local medium voltage (10/20/33 kV). Choosing one stage or two is a system trade-off: fewer stages mean fewer transformers and lower total no-load loss, but higher current and cable cost on the low-voltage side — a balance best struck with the plant's single-line diagram, the same discipline as the distribution system design workflow.

Inverter harmonics, DC injection and the K-factor / IEEE C57.110 rule

Three inverter characteristics matter to the transformer:

• Current harmonics. A grid-connected inverter must hold current THD to about 5% (IEC 61727 / IEEE 1547 territory), but the residual 5th, 7th, 11th and 13th components plus switching-frequency ripple still produce eddy-current and stray losses the transformer must dissipate as heat.
• DC injection. A small DC component in the inverter output (a common limit is 0.5% of rated current) can bias the core flux, raising magnetising current, losses and audible noise. Inverters limit it, but the transformer design should tolerate it rather than assume a perfectly symmetric waveform.
• Voltage distortion on the collector. Harmonic voltage on the medium-voltage collector makes the transformer operate at a slightly distorted flux, adding a little core loss on top of the inverter-side effect.

K-factor is a single number describing harmonic tolerance: K-1 (linear loads only), K-4, K-9, K-13 and K-20. For a modern low-distortion PV inverter a K-4 to K-9 unit is usually adequate; older inverters, several inverters paralleled on one transformer, or a transformer shared with other nonlinear loads push toward K-13. If only a standard transformer is available, IEEE C57.110 defines the allowable derating: at roughly 5–20% current THD expect a kVA derate in the low-to-mid teens of percent, growing with harmonic content and the transformer's eddy-loss factor. In round numbers a 1,250 kVA standard unit can behave as a ~1,100–1,200 kVA unit under harmonic PV duty. Fixing this at the order stage costs a modest premium; discovering it after commissioning costs a replacement.

Efficiency and no-load loss: the part-load economics of a PV plant

A PV transformer is energised before sunrise and stays energised after sunset, so its no-load (iron) loss runs for the full 8,760 hours of the year, while its load loss runs only during daylight and mostly at part load. Over a plant life of 20–25 years that flips the usual efficiency priority: cutting no-load loss with a higher loss grade (S13/S20) or an amorphous-core design often repays its extra first cost within a few years. Our loss-grade comparison and amorphous-core guide quantify the trade-off, and the total cost of ownership method turns it into a number you can put in a tender. Because the load sits at part load for most of the day, a slightly reduced flux-density design also lowers no-load loss and audible noise — a real benefit at residential-edge or noise-sensitive sites. To size the block and the budget in one pass, the engineering toolbox calculator takes the plant data and returns equipment and cost together.

Cooling, ambient and outdoor/coastal hardening

Outdoor PV duty means designing for the worst ambient, not the average. A transformer rated for 40 °C ambient at the standard temperature-rise limit derates above that; a hot-day design ambient of 45–50 °C is normal for desert and tropical sites, and the same rules that govern any high-temperature installation apply — see our high-altitude and high-temperature derating guide. Practical requirements:

• Cooling class: ONAN for standard PV blocks; ONAF where a compact footprint under high ambient is required, as covered in our cooling methods guide.
• Corrosion protection: C4 (or C5 for coastal and salt-laden sites) per ISO 12944, with hot-dip-galvanised tanks and stainless hardware.
• Ingress protection: IP54 or better for outdoor and pad-mounted enclosures; sealed, gasketed designs for humid tropical sites.
• Thermal cycling: daily full-range cycling stresses gaskets and seals; a hermetically sealed design avoids the breathing that draws moisture into the oil, compared in our sealed vs conservator guide.

Protection, fault current and grid-code compliance

Three protection points flow directly from the transformer specification:

• Impedance voltage (Uk%) sets the fault level. A low-Uk% transformer gives tighter voltage regulation but a higher short-circuit current at its terminals; a high-Uk% unit limits fault current but worsens regulation and raises losses. Grid-code fault ride-through (the plant must ride through a voltage dip without tripping) is met by coordinating the inverter's control with the transformer's impedance — worked through in our short-circuit current guide.
• Surge protection. PV plants are lightning-exposed and the collector is long; surge arresters on both sides, plus an electrostatic shield between windings, protect the inverter from grid-side transients. Our lightning protection guide covers BIL and the 1.2× margin.
• Interconnection rules. IEEE 1547 (North America) and IEC 61727 plus national grid codes (for example GB/T 19964 in China) set the voltage/frequency ride-through, DC-injection and power-quality limits the plant must meet — limits the transformer must not undermine through poor regulation or excessive fault let-through.

Solar PV step-up transformer specification checklist

• Design basis is inverter AC output at hot-day ambient (not array DC nameplate), with the DC/AC ratio stated separately.
• Voltage ratio and architecture fixed — 0.4/0.48/0.8 kV LV to 10/20/33/35 kV MV, one stage or two.
• K-factor (or documented IEEE C57.110 derate) chosen for the inverter's harmonic spectrum.
• Electrostatic shield between LV and HV windings to protect the inverter from grid-side surges.
• Impedance voltage (Uk%) selected to balance fault-current coordination against voltage regulation and ride-through.
• Cooling class and design ambient matched to the site (45–50 °C hot-day design for hot climates).
• Loss grade or amorphous core selected on the 8,760-hour no-load-loss economics, not first cost alone.
• Corrosion class (C4/C5 per ISO 12944), IP rating and sealed design for outdoor, coastal or humid sites.
• Surge arresters and LV/MV protection coordinated with the transformer fault level and the inverter ratings.

Sources / 资料来源

• Source: IEC 60076 series — Power transformers (general requirements, insulation levels and dielectric tests)
• Source: IEC 60076-11 — Power transformers — Dry-type transformers
• Source: IEC 60076-16 — Transformers for wind turbine applications (renewable-duty reference)
• Source: IEEE C57.110 — Recommended practice for establishing transformer capability when supplying nonsinusoidal load currents
• Source: IEEE C57.12.01 — General requirements for dry-type distribution and power transformers
• Source: IEEE 1547 — Standard for interconnection and interoperability of distributed energy resources
• Source: IEEE 519 — Recommended practice and requirements for harmonic control in electric power systems
• Source: IEC 61727 — Photovoltaic (PV) systems — Characteristics of the utility interface
• Source: IEC 62109-1 / 62109-2 — Safety of power converters for use in photovoltaic power systems
• Source: UL 1741 — Inverters, converters, controllers and interconnection system equipment for use with distributed energy resources
• Source: GB/T 19964 — 光伏发电站接入电力系统技术规定 (Technical requirements for connecting photovoltaic power stations to the power system)
• Source: GB 1094 series — 电力变压器 (Power transformers)
• Source: NEC Article 690 (NFPA 70) — Solar photovoltaic (PV) systems
• Source: ISO 12944 — Corrosion protection of steel structures by protective paint systems
• Source: QDTB Engineering Team — industry experience for typical inverter AC ratings, K-factor selection and hot-day design ambient